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Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934


Date of Report (Date of earliest event reported): May 10, 2019




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16803 Dallas Parkway

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Item 7.01 Regulation FD Disclosure.

On May 10, 2019, TransAtlantic Petroleum Ltd. (the “Company”) posted its CEEC Scout Meeting presentation to its website at www.transatlanticpetroleum.com.  A copy of the presentation is attached as Exhibit 99.1 to this Current Report on Form 8-K.

The information in Item 7.01 of this Current Report on Form 8-K, including Exhibit 99.1 attached hereto, is being furnished and shall not be deemed “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), nor shall it be deemed incorporated by reference in any filing of the Company under the Securities Act of 1933, as amended, or the Exchange Act, whether made before or after the date hereof, except as shall be expressly set forth by specific reference to Item 7.01 of this Current Report on Form 8-K in such filing.

Item 9.01 Financial Statements and Exhibits

(d) Exhibits.

Exhibit No.

Description of Exhibit


TransAtlantic Petroleum Ltd. CEEC Scout Meeting Presentation








Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.



May 10, 2019

















/s/ Tabitha T. Bailey




Tabitha T. Bailey




Vice President, General Counsel, and Corporate Secretary


























Slide 1

CEEC SCOUT MEETING Constanta, Romania Corporate activity update May 10, 2019 Photo: SE Turkey, Bahar Field – Fracture Stimulation Operations Exhibit 99.1

Slide 2

disclaimer Outlooks, projections, estimates, targets, and business plans in this presentation or any related subsequent discussions are forward-looking statements. Actual future results, including TransAtlantic Petroleum Ltd. (“TransAtlantic” or “TAT”) production growth and mix; financial results; the amount and mix of capital expenditures; resource additions and recoveries; finding and development costs; project and drilling plans, timing, costs, and capacities; access to capital; revenue enhancements and cost efficiencies; industry margins; margin enhancements and integration benefits; and the impact of technology could differ materially due to a number of factors. These include market prices for natural gas, natural gas liquids, and oil products; estimates of reserves and economic assumptions; the ability to produce and transport natural gas, natural gas liquids, and oil; the results of exploration and development drilling and related activities; economic conditions in the countries and provinces in which TransAtlantic carries on business, especially economic slowdowns; actions by governmental authorities; receipt of required approvals; increases in taxes; legislative and regulatory initiatives relating to fracture stimulation activities; changes in environmental and other regulations; renegotiations of contracts; political uncertainty, including actions by insurgent groups or other conflict; the negotiation and closing of material contracts; shortages of drilling rigs, equipment, or oilfield services; and other factors discussed here and under the heading “Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2018, which is available on our website at www.transatlanticpetroleum.com and at www.sec.gov. See also TransAtlantic’s audited financial statements and the accompanying management discussion and analysis. Forward-looking statements are based on management’s knowledge and reasonable expectations on the date hereof, and we assume no duty to update these statements contained in our Form 10-K as of any future date, except as required by law. The information set forth in this presentation does not constitute an offer, solicitation, or recommendation to sell or an offer to buy any securities of TransAtlantic. The information published herein is provided for informational purposes only. TransAtlantic makes no representation that the information and opinions expressed herein are accurate, complete, or current. The information contained herein is current as of the date hereof but may become outdated or subsequently may change. Nothing contained herein constitutes financial, legal, tax, or other advice. The Securities and Exchange Commission (“SEC”) requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We may use the terms “estimated ultimate recovery,” “EUR,” “probable,” “possible,” and “non-proven” reserves, “prospective resources” or “upside” or other descriptions of volumes of resources or reserves potentially recoverable through additional drilling or recovery techniques. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by TransAtlantic. There is no certainty that any portion of estimated prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the estimated prospective resources. This presentation includes proved reserve volumes based on a reserve report prepared by Degolyer & MacNaughton as of December 31, 2018 using SEC pricing (“YE2018 D&M Reserve Report”). Proved reserves are 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. This presentation also includes prospective resource estimates from the Netherland, Sewell & Associates, Inc. Prospective Resource Report dated as of May 31, 2017 (“May 2017 NSAI Prospective Resource Report”) and the DeGloyer and MacNaughton Prospective Resource Report for the Thrace Basin dated as of December 31, 2017 (“December 2017 D&M Prospective Resource Report”). Prospective resources are not the same as reserves or contingent resources. Prospective resources are those quantities of oil and gas estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Risks associated with the estimate of prospective resources contained in this presentation include, but are not limited to: The Thrace Basin Centered Gas Accumulation (“Thrace BCGA”) play is in the early exploration and delineation cycle with limited well control and limited fracture stimulation and testing data. Prospects evaluated in the May 2017 NSAI Prospective Resource Report are developed largely using seismic interpretation. Limited well control data is available to support the prospects. The volumes associated with the May 2017 NSAI Prospective Resource Report are all the unrisked high estimate, meaning there is no more than a 10% probability that the volumes discovered will exceed the estimate. There is no long-term well production performance from the Thrace BCGA or the May 2017 NSAI Prospective Resource Report prospects to establish a production type curve specific to the prospect, thereby requiring use of analogue information to establish development plans and to confirm the chance of commerciality. Recovery efficiencies are uncertain given the absence of site-specific long-term well production performance data. The limited deep drilling carried out in the Thrace Basin and Bulgaria provides limited visibility on future costs to drill, frac, and complete deep development wells to exploit prospects in those regions and the associated impact on the chance of commerciality. Although oil and gas activity has been underway for many decades in Turkey, as activity levels increase, timelines may increase to achieve government and local landowner approvals. Note on BOE: BOE (barrel of oil equivalent) is derived by converting natural gas to oil in the ratio of six thousand cubic feet (Mcf) of natural gas to one barrel (Bbl) of oil. BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 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.

Slide 3

240,081 gross acres Tertiary reservoirs 3 exploration licenses (Temrez) over Basin Centered Gas Accumulation Play (BCGA) Only independent E&P with an operated position in the BCGA fairway ~4-8 Tcf of gas and ~100-200 MMBbls of condensate resources (2) 50,000 net acres in core BCGA fairway Production from shallow gas fields (~1 MMcfd) Jonah Field analogue The joint venture between Valeura Energy Inc. (“Valeura”) and Equinor ASA (“Equinor”) announced that they expect to spend +/- $100MM testing on adjacent block in 2019 162,800 gross acres Jurassic, Triassic reservoirs 1 production concession ~USD$50 MM cost recovery pool Drilled Koynare prospect 2019 4 similar sized follow-ons mapped on 2D TransAtlantic Portfolio Snapshot Southeast Turkey 175,520 gross acres Cretaceous, Permian, Devonian, Ordovician reservoir 6 production leases and 2 exploration licenses in southeast Turkey 4 main producing fields Şelmo, Bahar, Yeniev, and Arpatepe Current production of ~3.0 MBoepd (NRI) Significant exploration running room 400+ MMBoe prospective resources (1) Silurian (Dadas) Sand and Shale resource plays Recent Deep Bedinan data on adjacent block Restored security on Syrian border, restarting Bakuk Northwest Bulgaria Northwest Turkey Thrace Basin Northwest Turkey TAT Exp. acreage TAT Prod. acreage BCGA boundary Bulgaria Production concession 3D Seismic North Koynare Prospect Identified leads Ozirovo structure Other core oil and gas fields Bulgaria 30 mi / 50 km 60 mi / 100 km Source: May 2017 NSAI Prospective Resource Report Source: December 2017 D&M Prospective Resources Report

Slide 4

Exploration & production activity in turkey Proven and prospective development opportunities 4 Main Oil Producing Fields 3,000 Bbl Oil per Day (NRI) 10.4 MMBbl of Proved Reserves (1) 28 Prospects in Southeast Turkey 3 Main Exploration Horizons 20.3 MMBbl of Risked Recoverable Oil (2) Emerging Unconventional Gas Resource Play 4.1 Tcf & 101 MMBbl of Recoverable Hydrocarbon Resource (3) New Equipment and Infrastructure Opening Opportunities for Growth Enhanced Seismic Processing to Explore Dadas Sands 33.4 MMBbl of Risked Recoverable Oil (2) Source: YE2018 D&M Reserve Report Source: Internal volumetric analysis Source: December 2017 D&M Prospective Resources Report

Slide 5

Mardin Prospects Dadas Sand Prospects Bedinan Prospects TransAtlantic Fields Other Fields Molla area Operations update Yeniev Field – Expanding 2018 Discovery Both the Yeniev-1 and West Yeniev-1 wells continue flowing naturally with little water from the Ordovician Bedinan. The East Yeniev-1 resulted in a discovery in the Cretaceous Mardin formation. Bahar Field Southeast Bahar-1 well was spud in March 2019 with oil shows in the Mardin, Hazro, and Bedinan. Completion operations expected to begin in the second quarter of 2019. East Molla Exploration Blackeye-1 well was spud in January 2019. The well was completed in the Devonian Hazro formation and put on production in the first quarter of 2019. 2 1 3 1 2 3 Test a Deep Bedinan target in 2019 Further delineate Yeniev discoveries in the Bedinan and Mardin Near-Term Exploration Goals Exploitation Next Steps Build Molla Central Gathering Facility Interconnect fields with trunk lines, and overhead power lines Build oil sales tie-in and sales pipeline Expect to bring on-stream first Bedinan water-flood in Turkey in 2019

Slide 6

Focus on execution performance Last 5 Well Ave. Spud to RR = 45 days Last 5 well CDC Capex = $2.7 MM Previous 5 well CDC Capex = $3.9 MM Previous 5 well Ave. Spud to RR = 63 days ~29% Improvement in Drilling Times ~31% Improvement in D&C Cost Step-Change In D&C Well Cost Continuous Improvement in Deep Drilling Performance

Slide 7

Bedinan water salinity Salinity ranges from 56,ooo to 120,000 ppm across project area Paleozoic Water Study Proposal Phase 1 – Create inter-company water salinity study to more accurately define salinity changes across the basin. Phase 2 – Develop a geological explanation Salinity (NaCl) ppm 120,000 100,000 80,000 60,000 Rw at Res Temp Deg. F 0.028 0.032 0.039 0.049 Por % 14% 14% 14% 14% Rt ohm-m 8.0 8.0 8.0 8.0 Sw % 42.0% 45.0% 50.0% 56.0%

Slide 8

Selmo – Permian test Operations update Re-entered the Selmo-1 well to test the Permian formation. Established productivity of new horizon in 2019. Oil = 29 Bopd, 45.6 API condensate Gas = 8.5 MMcf/d natural gas containing a high CO2 Production test from Middle Gomanibrik only. Expansion of perforations may yield much higher gas rates. Selmo 26 Gomanibrik Test (1986) Upper Gomanibrik Oil = No Oil Reported Gas = 3.5 MMcf/d @ 1,300psi whfp, 22% C1, 78% CO2 Middle Gomanibrik Oil = 70Bopd, 36 API Gas = 0.9 MMcf/d @ 340psi whfp, 29% C1, 71% CO2 Lower Gomanibrik Gas tested @ 95% C1, 5% CO2 Reported as tight 1 1 2 2 Next Steps Evaluate down-dip oil leg potential Look at options for internally utilizing or marketing CO2 Drill down-dip oil appraisal well (2020+)

Slide 9

Thrace basic center gas aCCUMULATION Operations update Yamalik-1 exploration well operated by Valeura and Equinor. In the first quarter of 2019, Valeura and Equinor announced that they drilled and cased a second well in the Thrace Basin BCGA, the Inanli-1 well and encountered 1,615 meters of high net-to-gross sandstone, which they interpreted to contain over-pressured gas. Completions started in the first quarter of 2019. Valeura and Equinor announced that they drilled the Devepinar-1 appraisal well to a total depth of 4,796 meters and encountered 1,066 meters of high-pressure gas saturated rock. TransAtlantic plans to commence operations on our first well targeting the Thrace Basin BCGA in the fourth quarter of this year. 1 2 3 Alacaouglu-1 0..73 Kazanci-5 0.77 Hayrabolu-10 0.75 Yildirim-1 0.56 Inanli-1 Yamalik-1 0.82 Kanadamis-1 0.77 Baglik-1 0.43 Kayi Derin 0.43 Kepirtepe-1- 0.60 Structural Depth in the Thrace Basin 1 2 3

Slide 10

BULGARIA – DEVENTCI R1ST OPERATIONS UPDATE TransAtlantic re-entered the Deventci R-1 well in December 2018, targeting the Ozirovu and Dolmi Dabnik formations. The well was drilled to a total depth of 16,450 feet. Formations came on within 250’ of prognosis; however the reservoir quality was not sufficiently developed to be productive. TransAtlantic is currently evaluating future activity in Bulgaria. North Koynare Prospect 1 1

Slide 11

Se turkey emerging plays Deep bedinan Dadas Hot Shale Deep Bedinan Bedinan Dadas Hazro Ambarcik-2 Next Steps TransAtlantic has plans to drill a deep test in the Bahar field in 2019. Only 5 wells drilled and tested a Deep Bedinan sand ~1,000’ below the top Bedinan ~1000’ thick Ordovician source rock below High API oil was tested but was before hydraulic fracturing was a common practice in tight oil reservoirs TransAtlantic has made multiple attempts to test deeper Bedinan sands however did not have sufficient horsepower TransAtlantic drilled the Ambarchik-2 well and Pinar-1ST well and encountered a ~400 thick Deep Bedinan Zone

Slide 12

Se turkey emerging plays Bakuk gas field Bakuk-1 Bakuk-101 25,000 net acres New Major Pipeline Under Construction Adjacent to Field Pipeline ROW crossing anticline Next Steps 25,000-acre anticline Single producing well is conservatively estimated to contain ~4.2 Bcf of PDP gas reserves (1) Major gas infrastructure now crossing license opens up license for development Tap BOTAS gas line prior to pipeline commissioning Plan inter-connect trunk line off structure utilizing high-resolution imagery Move to further delineate structure with additional wells Estimate between 10 and 25 subsequent wells Current Status Source: YE2018 D&M Reserve Report

Slide 13

Arpatepe field – EOR project First bedinan water-flood pilot in turkey planned for 2019 Arpatepe, Caliktepe, and Bati Caliktepe fields are upthrown 3-way closures along wrench faults. They serve as analogs along with Yeniev for prospects located in similar structural settings. Çaliktepe Field Arpatepe Field Arpatepe North Prospect Bati Çaliktepe Field Bedinan Structure (Depth) Field has 7 producing wells which have produced ~1MMBbl of oil cumulatively. Estimate 500 Mbo incremental oil potential through water-flood. (1) Implications across region for improved recoveries and economics. Next Steps Cumulative production 1.2 MMBbl Oil Planned water-flood injection in Q4 2019 on first injector well Phase 2 – Q1 2020 expand to second injection well Phase 3 – Q3 2020 move to full field flood and central facility Current Status Implications 400-800 MBbl Incremental recoverable oil reserves expected (1) Source: Internal estimates

Slide 14

Thank You Photo: Bahar Central Production Facility