2015 Annual Meeting June 10, 2015 Exhibit 99.1

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.’s own 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; 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 we carry 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, and 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, 2014, which is available on our website at www.transatlanticpetroleum.com and on 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 as of any future date. 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 the Company. The information published herein is provided for informational purposes only. The Company 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 The information contained herein is current as of the date hereof, but may become outdated or subsequently may change.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 SEC has generally permitted oil and gas companies, in their filings with the SEC, to disclose only 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 that the SEC’s guidelines may prohibit us from including in filings with the SEC. 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 the Company. 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. Note on Adjusted EBITDAX: Adjusted EBITDAX is a non-GAAP financial measure that represents earnings from continuing operations before income taxes, interest, depreciation, depletion, amortization, impairment, abandonment, and exploration expenses, unrealized derivative gains and losses, foreign exchange gains and losses, non-cash share-based compensation expense and significant non-recurring expenses. The Company believes Adjusted EBITDAX assists management and investors in comparing the Company’s performance and ability to fund capital expenditures and working capital requirements on a consistent basis without regard to depreciation, depletion and amortization and impairment of oil and natural gas properties and exploration expenses, which can vary significantly from period to period. In addition, management uses Adjusted EBITDAX as a financial measure to evaluate the Company’s operating performance. Adjusted EBITDAX is also widely used by investors and rating agencies.  Adjusted EBITDAX is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP. Net income, income from operations, or cash flow provided by operating activities may vary materially from Adjusted EBITDAX. Investors should carefully consider the specific items included in the computation of Adjusted EBITDAX. The Company has disclosed Adjusted EBITDAX to permit a comparative analysis of its operating performance and debt servicing ability relative to other companies. Note on Internally Generated Reserve Estimates: We have included in this presentation internally generated estimates of non-proved or P3 reserves, potential resources or potential reserves, potential well locations for non-proved or P3 reserves and production potential. These estimates are inherently more speculative than our estimates of proved reserves or the estimates included in our December 31, 2014 reserve reports, which were prepared by DeGolyer and MacNaughton and Deloitte. There is no assurance that we will drill these wells, recover the estimated quantities of oil and gas or reach certain levels of production. Our ultimate performance and recovery will be dependent upon numerous factors, including actual geological conditions, oil and gas prices, exploration and drilling costs, and our future drilling decisions and budgets based on our future evaluation of risk, returns and the availability of capital. 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. Forward looking statements

Good fiscal terms and respect for rule of law Deep inventory of low risk projects High quality 3D seismic, horizontal wells, multistage stimulations Experienced management team Transatlantic Petroleum: Dallas, TX Applying proven, North American technology to known international hydrocarbon basins Note: Turkish reserves are fully engineered by DeGolyer and MacNaughton. Albanian reserves are fully engineered by Deloitte and were acquired on 11/18/2014. 12/31/2014 Turkish reserves are based on SEC prices of $94.53/barrel and $8.71/Mcf. 12/31/2014 Albanian reserves are based on SEC prices of $69.55/barrel and $10.00/Mcf. Natural Gas 24.5 BCF 1P Reserves (12% YE 2014) 8.6 MMCFPD Net Production (23% Q1 2015) Crude Oil 28.7 MMBO 1P Reserves (88% YE 2014) 4,825 BOPD Net Production (77% Q1 2015) Ticker: NYSE-Mkt/TSX TAT/TNP 41.0 million shares outstanding Share Price (6/9/15) $5.62 Q1’15 Net Production (BOE/D) 6,122 Market Cap (6/9/15) $229 mm 1P Reserves (MMBOE) (12/31/2014) 32.7 Net Debt (3/31/2015) $121 mm NAV of 1P Reserves (12/31/2014) $885 mm Current Enterprise Value $364 mm Debt Adj. NAV/Share $18.65

TRANSATLANTIC BOARD OF DIRECTORS Name Select Experience Brian Bayley Former President & CEO of Sprott Resource Lending (formerly Quest Capital Corp.), President and Director of Ionic Management Corp. Mel Riggs Chief Operating Officer, President of Clayton Williams Energy, Inc. (22 years with the company have included roles of CFO, Treasurer, Secretary and Financial Analyst) Bob Alexander Founder, Former Chairman, President & CEO of Alexander Energy Corporation, Former President & CEO of National Energy Group, Inc., Former VP and General Manager of Reserve Oil, Inc., Former President of Basin Drilling Corporation Charles Campise Former CFO, SVP of Toreador Resources Corporation, Former Corporate Controller of Transmeridian Exploration Incorporated, Financial roles with Sovereign Oil & Gas Company, Apache Corporation and Ocean Energy, Inc. Marlan Downey Founder and Chairman of Roxanna Oil Company, Former President of Shell International (Pecten International, 30 years with Shell), Former President of ARCO International Greg Renwick Former President & CEO of East West Petroleum, Former Director Of Business Development for Dana Gas PJSC, Senior management roles during 25 years with Mobil Oil Corporation including Business Development Manager of CIS and Middle East, Managing Director of Mobil Oil Turkmenistan, Exploration Advisor and Geophysical Manager N. Malone Mitchell 3rd Chairman & CEO of TransAtlantic Petroleum, Founder and former President & COO of Riata Energy (SandRidge Energy), Founder, Partner and Managing Member of Riata Corporate Group (Longfellow Energy, Dalea Partners, Viking International)

Name Position Select Experience N. Malone Mitchell 3rd Chairman & CEO Riata Energy (renamed SandRidge, NYSE: SD), Longfellow Energy; owns 36% of TransAtlantic Todd Dutton President Longfellow Energy; Texas Pacific Oil Company; Coquina Oil Corporation; BEREXCO Inc.; Riata Energy, Inc. James Huling COO Longfellow Energy; founded Kiamichi Energy Corp.; Kerr-McGee Corp., Encore Acquisition Company; Ovation Energy Partners; Riata Energy Inc. Wil Saqueton VP & CFO PWC; Intel Corporation; Just Brakes Lee Muncy VP Geosciences Bass Companies; Fina Oil & Chemical Company; TransTexas Gas Corp; Mobil Oil Corporation Matt McCann General Counsel & Corporate Secretary Longfellow Energy; Riata Corporate Group; SandRidge Energy, Inc.; Sprouse Shrader Smith PLLC Justin Davis VP Engineering SandRidge Energy: Piceance Basin operations manager, Permian Basin stimulation design William Bentley VP Land Sandero Resources; Ted W. Walters & Associates Noah M. Mitchell 4th Vice President Longfellow Energy, Viking Services, Viking Coil Tubing MANAGEMENT TEAM

A year in review September 2014 Announce Stream acquisition November 2014 Acquisition of Stream Waterflood response seen in Selmo Establish Dadaş production with Bahar 6 well, TAT’s best well yet October 2014 Serious oil price decline Public placement of $150 mm high yield notes pulled May 2014 Changes in senior management December 2014 Hit year end production guidance Private placement of $55mm convertible notes Deactivate drilling June 2014 All phases of Molla 3D Seismic delivered operational success since last annual meeting February 2015 Record reserves and production growth Announce target of $10mm in run rate annual cost savings Installed new management in Albania Over 20 new field leads identified June 2015 Achieve target reduction in run rate of cost savings 80 new field leads identified Reactivated rigs in Delvina & Molla In final discussions regarding Albania Amending Agreements

Transatlantic Relative Share performance Correlated to peers Source: Bloomberg; 1 year data as of June 3, 2014 -37% One Year +4% Year To Date

Company Growth Production is sales volumes, includes Albanian uplift Annual Net Reserves - Turkey 27% 28% 55% 32% Growth PD PUD P2 Quarterly Net Production(1)

Reserve accuracy is improving (downey curve) Combination of management decisions and asset understanding * Internal estimates. Refer to Note on Internally Generated Reserve Estimates 2013 Pre and Post Drill Reserve Estimates* 2014 Pre and Post Drill Reserve Estimates* 50% 115%

The Good News! Production Potential (Net) * Internal estimates. Refer to Note on Internally Generated Reserve Estimates Requires More CapEx

The Bad news - Cumulative drilling investment What we have to spend

Production Vs. cash flow To achieve that growth

With Current cash flow and debt service This is more like what we can do Assuming: No additional liquidity Pay debt to zero Drill only with incremental cash flow

projects across all stages of development Reserves Internal Unbooked Prospective Reserves Delvina Gas Pinar Bahar & Goksu Thrace (Basin Centered Model) Albanian Oil Fields Selmo (still 50+ locations) Thrace (Shallow) Cash Flow Stage Acquisition and Exploration Limited Drilling Drilling Outspend Rapid Production Growth Cash Flow Positive Constant Production Selmo Waterflood + (-) Thrace Deep Molla Area (Excludes Dadaş Shale) Cash Flow & Investment Size of circle is relevant size of reserves

So here is our plan Sell This And Spend This

6 Transactions – Nearly every area Sale- VPP: $40 - $80 million cash proceeds Estimated required loan paydown: $20 - $30 million Carry-Loan: $50 - $90 million September 2015 – July 2016 closings Sensitivity effects on Balance Sheet are at JV’s “expected” and “lowest proceeds” values Production risking held constant Prices held constant at Brent $65/bbl through 2016 and $75/bbl thereafter (less Discounts) We will sell joint ventures (jv’s) and Improve: • Production income •Balance SheeT • Value Per Share

Area Strategy SELMO Expedite Selmo development to maximize returns prior to 2025 MOLLA Grow Molla assets through drilling to validate 3D then expedite development blocks to establish primary revenue source ALBANIA Redevelop Albanian oil fields to access bypassed reserves, initiate gas sales GAS ASSETS Diversify portfolio through high impact gas exploration BULGARIA North Koynare prospect Core corporate Strategies (Detailed strategies in appendix)

Lee Muncy Geological discussion VP GEOSCIENCES

These geologists and geophysicists have a variety of experience working many diverse basins and plays throughout the world They are all seasoned veterans working in the oil and gas industry with a proven track record of finding hydrocarbons They also bring experience utilizing a lot of the modern improvements in technology currently being employed by the major oil and gas companies 150 years of G&G Experience added in last 12 months

This marks a significant increase in the number or exploratory prospects from a year ago and these numbers are expected to grow as the evaluation of SE Turkey and Albania continues Additionally, the number of development locations will increase dramatically if any success is encountered through the drilling of the exploratory prospects Potential reserve additions from exploratory prospects total more than 350 MMBO* plus between 270 to 970 BCF* of gas Geological discussion 82 exploratory prospects & 210 YE 2014 2P development locations identified * Internal estimate. Refer to Note on Internally Generated Reserve Estimates

SE Turkey Molla 3D conventional prospects (200 MMBO*) Dadaş Sand Play (107 MMBO*) Dadaş Shale Play (Potential reserves undefined at this time) NW Turkey Various Danismen, Osmancik, Sogucak, and Hamitabat Prospects (70 BCFG*) Albania Delvina (200 to 900 BCFG) Cakran, Ballsh, & Gorisht (~150 MMBO*) Bulgaria North Koynare Prospect (30 MMBO*) Exploration projects * Internal estimate. Refer to Note on Internally Generated Reserve Estimates

SE Turkey Molla 3d area

22 Bedinan, Hazro or Mardin structural prospects 49 Dadaş Sand stratigraphic prospects SE Turkey – Molla 3D area 71 conventional prospects have been identified in the Molla 3D area * The southern, western, and far eastern portions of the 3D seismic survey have not been evaluated for the Dadaş Sand at the time of preparation of this presentation. Dadaş Sand Prospects & Leads* Bedinan, Hazro & Mardin Prospects & Leads Evaluation is ongoing with many additional prospects & leads expected as the evaluation continues

SE Turkey – Molla 3D area 22 bedinan, hazro and mardin prospects identified, so far * Internal estimate. Refer to Note on Internally Generated Reserve Estimates Bahar Field is the analog for many of the Bedinan prospects Cavasulu Prospect - Bedinan Structure Bahar Field - Bedinan Structure 18 MMBO* Recoverable Reserve Potential 17 MMBO* Recoverable Reserve Potential

SE Turkey – Molla 3D area * Internal estimate. Refer to Note on Internally Generated Reserve Estimates 44 MMBO* Recoverable Reserve Potential Molla SE / Karagoz Prospect Area – Bedinan Structure

SE Turkey – Molla 3D area Cavasulu Prospect Bahar Field Molla SE Prospect 1 3 6 Bedinan Karababa A Hazro F4

Dadaş Sand Play Conventional stratigraphic prospects Characterized as sand channels and fans encased within the Dadaş Shale Identified from 3D seismic as amplitude “bright spots” Can be exploited with vertical and/or horizontal wells Dadaş Shale Play Unconventional play targeting silica rich zones within the Dadaş Source Rock Horizontal drilling with large fracture stimulation is needed to generate economic wells Located basin wide and targets the areas not identified within the sand bodies associated with the Dadaş Sand Play True “resource play” SE turkey – Dadaş sand & shale plays There are two types of plays within the Dadaş shale

SE turkey – Dadaş sand play: the concept Sandstone bodies encased within the shale source rock Top of Dadaş Shale Target package of sandstone reservoirs Base of Dadaş Shale

SE turkey – Dadaş sand play Oil bearing zones Major source rock for Diyarbakir Basin Çatak #1 Petrophysical Evaluation Log of Dadaş Shale Section

SE turkey – Dadaş sand play Identified from 3d seismic data as amplitude bright spots AVO analyses of these “bright spot” anomalies indicate they are associated with Type II and Type III AVO anomalies comparable to AVO anomalies found productive in other basins worldwide

SE turkey – Dadaş sand play Bahar field area – example of seismic amplitude & location of gathers 1 2 4 5 3 Gather 1 Gather 3 Gather 2 Gather 4 Gather 5 Points 3 & 4 show good AVO response and should be productive while points 1, 2, and 5 fall outside the seismic anomaly.

49 reflector packages, interpreted to be sand bodies within the Dadaş Shale, have been mapped from the Molla 3D seismic data………so far! Based on 160 acre spacing, there are approximately 175 drilling locations if all of the seismic anomalies are drilled Potential to recover 107 MMBO* from these sand packages located on TransAtlantic’s acreage in the Molla 3D area Identification of additional anomalies is expected as the evaluation of the Molla 3D area continues SE turkey – Dadaş sand play * Internal estimate. Refer to Note on Internally Generated Reserve Estimates

Nw turkey Thrace basin prospects

NW Turkey – thrace basin Not shown are leads & prospects in the Edirne Area and on recently nominated license blocks Structure map on top of Mezardere Formation showing license blocks and TransAtlantic’s prospect areas within the Thrace Basin .

8 exploratory prospects are currently identified on TAT acreage within the Thrace Basin The prospects target the Danismen, Osmancik, Sogucak, and Hamitibat formations An example of the Thrace Basin Prospects is illustrated on the following slides NW Turkey – thrace basin 70 BCF* recoverable reserves from new prospects * Internal estimate. Refer to Note on Internally Generated Reserve Estimates

2,900 meter drill depth with 38 BCF* of recoverable gas reserves Sogucak LS, Ceylan Tuff, and Hamitibat SS targets NW Turkey – thrace basin Guney Reisdere prospect * Internal estimate. Refer to Note on Internally Generated Reserve Estimates Structure Map – Sogucak Limestone

NW Turkey – thrace basin Target Level Osmancik Fm. M.Dere Fm. Teslimkoy Fm. Ceylan Fm. Sogucak Fm. Hamitabat Fm. The prospect is a down thrown 3-way structure trapped against a major fault. The reservoirs are adjacent to the kitchen area located in the center of the Thrace Basin.

albania Delvina Prospect

Discovered in 1987 Four wells have been drilled on the structure with two of the four productive The Delvina 12 and Delvina 4 wells will require relatively simple workovers to restore production A fifth well, the Delvina 34, was spud in April 2014 and drilled to 2,346 feet before the previous operator ran out of funds TransAtlantic has resumed drilling the Delvina 34 The limits and size of the field are unknown at this time Chevron published a resource report with estimates ranging from 200 BCF to 1.2 TCF of recoverable GIP There is considerable condensate associated with the gas (50 Bbls per MMCF) albania – delvina prospect

albania – delvina prospect There appear to be multiple structures present beneath the Delvina Block Current plans: Complete the drilling of the D-34 well Drill a new well on one of the adjoining structures Evaluate full field development, processing and gas marketing Line of sections shown on the following slides Proposed Location Production License

Geological Profile Across Delvina Field Showing Delvina 34 Location Illustrated on the previous map as the green cross-section albania – delvina prospect

albania Ballsh, gorisht & cakran

These oil fields were discovered in the 1960-70’s Vast majority of wells only drilled into producing zone until first good flow of oil For example, only 4 wells drill the entire 750m column in the Gorisht Field So far only a small percentage of oil in place has been recovered from these fields Revitalization of these three fields by recompleting existing wells, reactivating wellbores, drilling deeper to new zones, and drilling horizontal wells in proven productive zones as well as secondary recovery may lead to the recovery of another 150 MMBO* Near term activity from a geological perspective includes deepening, selectively coring, and logging wells to develop a petrophysical model that can be utilized to construct a development drilling plan for each field albania – Ballsh, Gorisht, & Cakran * Internal estimate. Refer to Note on Internally Generated Reserve Estimates

albania – Ballsh, Gorisht, & Cakran In the Gorisht Field, 269 wells penetrated the Eocene Limestone section, however, only 4 of those wells penetrated the entire thickness of prospective reservoir. It is anticipated that the Ballsh, Gorisht, and Cakran fields contain multiple reservoir zones vertically and likely highly compartmentalized at every level creating numerous opportunities for discovering significant additional reserves in each field.

albania – Ballsh, Gorisht, & Cakran Frac Barrier Frac Barrier Frac Barrier Frac Barrier Frac Barrier Kocul 44 Gorisht 240 Most of the wells only penetrated the top 50 M of limestone reservoir and were completed only in the shallowest portion of the reservoir Deeper wells show oil saturation throughout the entire limestone section with impermeable “frac” barriers between potentially productive zones Part of TransAtlantic’s plan is to develop the fields in layers. To do this, many of the wells within each oil field will be deepened to develop the isolated reservoir units that are separated by frac barriers within the 700+ meter thick carbonate section

albania – Ballsh, Gorisht, & Cakran Gorisht Ballsh Cakran Initial deepening candidates New drill locations Structure maps on the top of the Eocene Limestone. Plan to deepen wells Ballsh and Gorisht are relatively shallow fields, drilling new wells may be a better option than deepening older and potentially problematic wells

bulgaria North Koynare Prospect

Bulgaria – north koynare prospect North Koynare Prospect North Koynare Prospect is seismically tied and analogous to the Dolni Dabnik and Gorni Dabnik fields located 23 KM to the northeast The potential exists for numerous prospects throughout the 163,000 acre (66,000 hectare) production concession. If North Koynare Prospect is successful, then a 3D seismic program would be acquired to cover the entire production concession 15,200 Ft/4,600 M Depth 30 MMBO of recoverable reserves* Dolni Dabnik is the primary objective * Internal estimate. Refer to Note on Internally Generated Reserve Estimates

Bulgaria – north koynare prospect A A’ B B’ R1 R2 Proposed Location 1400 Acres (570 Hectares) Dolni Dabnik Structure Map 3D seismic defined structure (62 km2 3D seismic survey) Prospect is located on a different structure than what was targeted in the Deventci R1 and R2 wells

Bulgaria – north koynare prospect Dolni Dabnik is primary objective B B’ Dolni Dabnik Triassic Unconformity PROPOSED LOCATION A A’ R1 Dolni Dabnik PROPOSED LOCATION 200M CLOSURE HEIGHT Triassic Unconformity It is a Lower Triassic aged vuggy, fractured dolomite with possible hydrothermal dolomite properties

Selmo field Development projects

Drilling locations have been “high-graded” using 3D seismic data Production performance has been tied to the seismic data for all of the wells in the field There is a correlation between high amplitude peak responses and better production. These high amplitude peak responses are indicating zones where better porosity exists Areas within the field have been identified that appear to be “undrained” by existing wells Future wells will preferentially target the locations where high amplitude peaks are seen in the 3D seismic data and “undrained” areas within the field SE Turkey – Selmo Field What has changed since last year?

SE Turkey – Selmo Field 53 development locations have been identified in the selmo field MSD Horizontal (43) LSD Horizontal (2) MSD/LSD Vertical (8) MSD Top Depth Structure map (BSL-ft)

SE Turkey – Selmo Field High amplitude peak responses shown here as continuous reflectors suggest porosity typically associated with dolomitic facies Model validated in the Selmo 35 H-2 well with EUR of 276 MBO (D&M) from MSD section S 35 H-2 MSD Reflector Proposed S 35 H-1 MSD Reflector

bahar field Development Projects

SE turkey – Bahar Field 11 bedinan development locations identified in bahar field Existing Well Proposed Well Bahar Field – Structure Map Top Bedinan

Plan to drill a horizontal well in the Bahar Field to further test the Hazro F4 proven productive in the Bahar 1 and Bahar 2 ST wells SE turkey – Bahar Field Further potential in the hazro Bahar Field – Structure Map Top Hazro Bahar 3 Bahar 2 ST Bahar 6 Bahar 4 Bahar 1 ST Bahar 2

James huling Engineering discussion CHIEF OPERATING OFFICER

2009: Acquired mature legacy field with many infrastructure problems Upgraded facilities and infrastructure and doubled production with infill drilling and exploitation Started horizontal redevelopment in 2013 and realized 167% production growth from acquisition Over 50-proved locations remain Commenced pilot waterflood in 2014 To date the pilot is yielding approximately 105 BOPD with an incremental EUR of 400 MBO* Proven Reserves Growth Selmo Field – Acquire and Exploit * Internal estimate. Refer to Note on Internally Generated Reserve Estimates Selmo Field Waterflood Conversions Selmo Field Waterflood Pipelines and Wells Phase #1 – Q1 2014 Phase #2 – Q2 2014 Phase #3 – Q3 2014 Injectors Production Response Planned 2015 Injectors

Proven Reserves Growth Selmo Field Case history: Acquire and Exploit BOPD Well Count MBOE Oil Well Count

Selmo Waterflood: Expansion in progress Waterflood yielding ~105 bopd & incremental EUR of 400 MBO* Started Waterflood Pilot BPD Water Cut (%) * Internal estimate. Refer to Note on Internally Generated Reserve Estimates

Using state of the art technology with proven exploitation techniques TransAtlantic continues to increase reserves from this fifty year old field Selmo field as a case Mature legacy fields provide years of project harvesting CUM Oil (Bbls) Since March of 2009 we have produced 5.4 MBO TAT Acquisition Selmo Field Production

Organic growth from proprietary 3D seismic inventory Commenced production in 2013 Proved reserve growth from inception to 3.2 MMBOE at YE2014 3P Reserves growth to 6.4 MMBOE at YE2014 Conventional production from the Hazro and Bedinan Resource and conventional potential in the Dadaş Significant conventional and resource potential Anticipate additional reserves growth Organic Reserves Growth Bahar field Case history: Explore & Develop Contour Interval = .005 6 Bahar Field – SE Turkey

Organic Reserves Growth Bahar field case study: Explore & Develop Demonstrated Production Growth BOPD MBOE

Bahar 6 was completed in both the Dadaş and Bedinan formations Production is outperforming the average curve of Bedinan only production All wells are vertical Bahar Field Bahar 1: Gas Lift; Bahar 3, 4 & 6: Artesian flowing wells Bahar 6: Comingled Dadaş and Bedinan production: 113 MBbl in 200 days Bahar 1: Bedinan production: 164 MBbl in 870 days Bahar Field Well Results

Organic Growth from 3-D Seismic using modern completion techniques. Currently realizing growth through development. Future horizontal development, secondary potential, Dadaş resource potential. Organic Reserves Growth Bahar field case study: Explore & Develop Demonstrated Production Growth Oil (Bbls)

Proven EFFICIENT OPERATOR improving efficiencies and lowering operating costs (USD/BOE) Thousand USD/Month -48%

ALBANIA Growth POTENTIAL Albanian production excludes gas LEGACY FIELDS – Exploitation Opportunity EXHIBIT A: “SELMO FIELD”

ALBANIA Transition Roll-out New Organization Remove Prior Management Strike Starts Power Turned Off Transformer Failure Transformer Repair Transformer Failure Replace Gorisht Field Manager Stabilized Production Final discussions regarding Albania Amending Agreements BOPD

Albania Oil fields Plan Gorisht & Ballsh then Cakran Existing Wells Field Development Strategy (1) Lower high capacity pumps to formation level (3) Drill horizontally into data-rich upper oil zones (4) Drill horizontally into lower oil saturated zone (2) Drill deep, vertical, multi-stage test wells with modern logs, cores, current oil saturation model (5) Drill injector wells 1 2 3 4 5 Capacity: 75 – 150 bfpd

Installed flow meters for custody transfer of oil sales which provides check on volume & weight measurements ALBANIA transition Flow meters Inlet Flowmeter Outlet Flowmeter

ALBANIA Transition Started 14-well PCP Installation Campaign Replacing dilapidated artificial lift Utilizing existing PCP inventory with replacement tubing and rods “Working” with existing infrastructure Source: Kudu

ALBANIA Finalizing work program 2015 Focus: Finalize Albania Amending Agreements Take over remaining Ballsh wells Return wells to production Upgrade production facilities Upgrade power infrastructure Upgrade SWD infrastructure Improve artificial lift Focus reinjection of water Replace testing facilities Upgrade roads Replace high priority flow lines Set stage for deepenings and exploitation

Todd dutton Current activity PRESIDENT

Albania Oil Fields – Switching out and lowering pumps on 14 wells Delvina 34 Gas Well – Drilling ahead at 6,117 Ft Pinar 1 Completion (Molla) – Slim Hole Tools - in progress South Gosku Completion – TD above pay zone with rig. Drill pay with pulling unit. Spud Bahar 9 – Currently running surface casing at 2,430 Ft Current Activity

Bahar Field map Well Locations (Current Drilling Order: 9, 7, 5, 2H-1) Bahar 2ST Bahar 2 Bahar 3 Bahar 4 Bahar 6 Bahar 1ST Bahar 2H Bahar 9 Bahar 5 Bahar 11 Bahar 8 Bahar 10 Bahar 12 Bahar 7

Molla project lifecycle Vertical Horizontal Lease Acquisition Basin Position Regional Geology (Gravity) Initial 2D Seismic Reentry & Discovery 3D Seismic & Analysis Completion Evolution Development drilling from 3D (100%) Prospect Drilling Using 3D Active Development Drilling Additional 2D and new wells (Success 33%) Acid Initial Fracs Frac evolution size Horizontal Multi-Stage Well Costs Well Productivity

Bahar Field – 3 String Casing Design MARDIN HAZRO DADAS BEDINAN 100’ MD/TVD 2,640’ MD/TVD TOC @ 7,700’ Setting Depth TVD/MD (rkb) RKB Elev. 2276’ Hole Size Casing 20” 13 3/8” 5 ½” @ 10,550’ TD 8 ½” Hole 12 ¼” Hole 9 5/8” 17 ½” Hole 8,200’ MD/TVD TOC @ 7,100’ TOC @ 1,800’ 2013 & Prior 4 to 5 string casing design used 2014 3 string casing design successfully used

2015 Plan to attempt this casing design on the #9 and #7 wells Why this design? Less expensive Less pipe Smaller pipe One logging run Faster well time – twice as many wells for same cost over an extended period More wells, more production Plan for horizontal wells 5 ½” is optimal size pipe for reservoir Bahar Field – 2 String Casing Design 100’ MD/TVD 2,400’ MD/TVD TOC @ 7,350’ Setting Depth VD/MD (rkb) RKB Elev. 2126’ Hole Size Casing 13 3/8” 9 5/8” 5 ½” @ 10,575’ TD 8 ½” Hole 12 ¼” Hole MARDIN HAZRO DADAS BEDINAN

What is Microseismic? Utilizes 3D seismic technology Indicates where frac starts and where it goes (logs say NNE-SSW, but we really don’t know) Allows measurement of stimulated and “propped” reservoir rock Why is it important to run on Bahar wells? More precise estimate of drainage with current frac design – optimum well spacing Optimum frac size Current U.S. Frac’s average 240,000# sand per stage Current Bahar frac is 90,000# per stage Orientation for Horizontal wells and frac stage spacing Microseismic Surveys

Microseismic Survey Image Source: MicroSeismic Surface Arrays

Microseismic Survey Image Source: MicroSeismic Fracture Orientation - Horizontal Wellbore Direction

Microseismic Survey Image Source: MicroSeismic Frac Width Frac Height Stage Coloring Legend UP DOWN N E S W

Microseismic Survey Stimulated Rock Volume Results Image Source: MicroSeismic Stimulated Reservoir 14 Stages 102,000#/Stage 11 Stages 31,000#/Stage IP 1884 BOEPD IP 978 BOEPD Propped Reservoir

Microseismic Survey Image Source: MicroSeismic Frac Height Frac Width Distance from Stage Center X (feet) Distance from Stage Center Z (feet) Propped Fracture Volume (ft3) UP DOWN Distance from Stage Center X (feet) Distance from Stage Center Y (feet) Propped Fracture Volume (ft3) N E S W

Microseismic Surveys What will Horizontal wells do for us in Bahar? Horizontal Play Average Stage Count Average # Prop/Stage Average 12 mo Prod MBOE Average Prod/Stage MBOE Average Prod/# Prop BOE Eagle Ford 25 224,400 558 22.3 0.099 Bone Springs 15 280,000 176 11.7 0.042 Wolfcamp 35 161,714 135 3.9 0.024 Woodford 15 292,800 344 22.9 0.078 Averages 22.5 239,729 303 15.2 0.061 Bahar - vertical 2 71,500 103 51.5 0.720 Bahar - Horizontal 10 150,000 515* 51.5 0.343 Bahar - Horizontal 10 150,000 1080* 108 0.720 Source: IHS, Management estimates * Internal estimate. Refer to Note on Internally Generated Reserve Estimates Note: Proppant and production data for North American plays includes top 25 wells (based on First 12 month production) from the top counties in each play. (Eagle Ford: De Witt, Gonzales, Karnes, Live Oak, McMullen; Wolfcamp: Reeves; Bone Spring: Eddy, Lea, Loving, Ward; Woodford: Canadian, Garvin, Grady, Stephens), Stage counts are management estimates.

Year Wells Gross CapEx BOE/D Gross TAT CapEx BOE/D Net Partner CapEx(2) Partner BOE/D 2015E(1) 7 $28.4 7,520 $25.6 5,430 $2.8 1,144 2016E 44 $135.4 9,440 $74.7 5,570 $60.7 2,687 2017E 57 $203.5 17,630 $94.6 10,430 $108.9 4,999 2018E 44 $205.1 23,320 $124.3 15,320 $80.8 5,078 2019E 42 $204.3 23,910 $114.7 15,190 $89.6 5,729 2020E 39 $193.5 24,030 $100.8 14,394 $92.7 6,628 Drilling investment Total 233 $970.2 $534.7 $435.5 2015 does not include year-to-date CapEx of ~$11 million USD Excludes purchase proceeds

Year Wells Gross CapEx Net of Sales BOE/D Gross TAT CapEx Net of Sales BOE/D Net Partner CapEx Net of Sales(2) Partner BOE/D 2015E(1) 7 $0.3 7,520 - 5,430 $0.3 1,144 2016E 44 $44.6 9,440 $21.4 5,570 $23.2 2,687 2017E 57 $30.2 17,630 - 10,430 $30.2 4,999 2018E 44 $6.7 23,320 - 15,320 $6.7 5,078 2019E 42 - 23,910 - 15,190 - 5,729 2020E 39 - 24,030 - 14,394 - 6,628 Total 233 $81.8 $21.4 $60.4 Drilling investment (NET) That’s a lot of money, but reinvesting the resulting cash flow makes this the NET: 2015 does not include year-to-date CapEx of ~$11 million USD Excludes purchase proceeds

Production wedge * Internal estimate. Refer to Note on Internally Generated Reserve Estimates Selmo Albania Gas Albania Oil Molla Exploration Molla Development Current Wells

Financial Wil Saqueton CHIEF FINANCIAL OFFICER

Have implemented actions that will generate ~$9mm annualized cash cost savings across G&A and LOE Turkey at ~$10mm annualized cash savings Dallas costs up slightly due to investment of G&G staff build up Albania cost reduction opportunities still to be implemented Completed semi-annual redetermination of our Reserve Based Loan in April 2015. Bank group holding $45 Brent price for H1 2015 and $49 for H2 2015 Finalized negotiations with Yapi Kredi bank to re-term credit facility resulting in ~$900k lower monthly principal payments through remainder of note Have negotiated settlements with numerous vendors resulting in ~$3mm of payment discounts on goods/services already provided Placed additional hedges on our Turkey oil production in 2H’15 and 2016 Zero Premium Collar at $66.50 net floor and $70 ceiling 2H’15 through 2016 Hedge position = ~2,700 bopd (68% of projected Turkey net oil production) Prior hedges worth approximately $23 million as of June 3, 2015 2015 Cost savings & cash management accomplishments

The following slides portray a simplified Balance Sheet (Cash, Debt) under several scenarios Key assumptions modeled Brent at $65 through 2016 and at $75 from 2017 through 2020 2014 actual realized discounts to Brent Production risking held constant Joint ventures (JVs) realized at “Expected” pricing and “Lowest Proceeds” pricing Financial model overview

PUD drilling, no exploration Production remains relatively flat at ~6,000 BOE/D All Free Cash Flow allocated to debt pay down Cash balance hovers near nil $55mm Convertible Debt bullet maturity in June 2017 would require refinancing Conversion to equity would require significant increase in Brent price which we cannot count on Balance sheet (simplified) -- Current Cash flow & Debt Cash/Debt BOE/D

JV proceeds and FCF allocated to asset development and debt pay down Cash balance significantly improved JVs provide more options to address Convertible Debt bullet maturity Expect to improve debt capacity by 2017 through production growth and balance sheet improvement Balance sheet (simplified) – Joint ventures Cash/Debt BOE/D

EBITDAX projected at ~$2.00/share when convertible notes mature In this scenario, we believe conversion of convertible notes to equity would be likely Ebitdax with joint ventures (expected case) EBITDAX/Sh ~$5.50 $55mm Convertible Notes bullet maturity EBITDAX Per Share

Convertible debt converting to equity results in Same debt balance curve but Significantly more cash Even JV LP case provides ~sufficient funding However, this is not our primary plan Balance sheet (simplified) – convert to equity $55mm Convertible Notes convert to Equity Cash/Debt (USD)

Closing two significant JVs provides catalyst to enable 5-7 yr $150mm bond issuance We believe we can accomplish this by end of 2015 to 1H’16 at which time leverage ratio projected at ~1.0X Provides sufficient cash for JV LP case to comfortably refinance Convertible Notes Excess cash generated to be used for accelerated development, accretive acquisitions, share buybacks, etc. This is our primary plan to fund our 5 year vision Balance sheet (simplified) – joint ventures & bond issue Early redemption of Convertible Notes by issuing 5-7 year Bond Cash/Debt (USD) Leverage Ratio

So what’s different now? Much more “Proof” than 2 years ago More reasonable terms for partner “Buyer’s market” issues Some accept terms but desire operations Some don’t want operations but less technical What can go better? Execute JV’s sooner Prices rise Well costs and/or operating expenses lower than forecast What can go wrong? Prices decline JV’s done at lower value than expected case Geological risk Political risk Jv marketing process

AKP (Erdogan) highest vote but not absolute control Kurds win parliament representation – likely greater peace in SE Turkey 4 parties over 10% Waiting on coalition or minority agreement No forecast change in Oil & Gas industry Turkey elections Democracy working, No Contested results

N. Malone Mitchell 3rd Chairman & CEO Todd Dutton President James Huling COO Wil Saqueton VP & CFO Lee Muncy VP Geosciences Q&A

Lizzy Chesnut Investor Relations (214) 265-4716 lizzy.chesnut@tapcor.com Contact www.TransAtlanticPetroleum.com

Area Strategy SELMO Expedite Selmo development to maximize returns prior to 2025 MOLLA Grow Molla assets through drilling to validate 3D then expedite development blocks to establish primary revenue source ALBANIA Redevelop Albanian oil fields to access bypassed reserves, initiate gas sales GAS ASSETS Diversify portfolio through high impact gas exploration BULGARIA North Koynare prospect Core corporate Strategies

Area Strategy Timing SELMO Monetize via sale, VPP, JV 20% - 30% 3-6 months Follow through with Phase II of waterflood 3-6 months Use proceeds / carry from transaction to expedite drilling with 2 rigs 6-9 months MOLLA Continue internal Bahar-Goksu development 3-6 months Execute a JV for Molla exploration acreage 6-9 months ALBANIA Evaluate reservoir and geologic properties through low cost science 3-6 months Begin infrastructure and facilities upgrades to allow for production increases while completing low cost workovers / recompletions 3-6 months GAS ASSETS Monetize via sale, VPP, developed reserves 3-6 months Execute JV for Basin Centered Gas (BCG) exploration in Thrace Basin & Delvina Gas Field 3-6 months Complete Delvina-34 well to determine potential for new gas field 3-6 months BULGARIA JV North Koynare Prospect 3-6 months Near term execution strategies Maximize cash flow in low price environment

Area Strategy Timing SELMO Aggressively drill up PUD locations with 2 rigs (40-50 wells) 9-18 months Complete Phase III & IV waterflood projects 9-18 months MOLLA Complete Bahar development (10-15 wells) 6-12 months Initial Molla exploration to de-risk identified structures (7 wells) 9-18 months ALBANIA Ramp up facilities and infrastructure upgrades based on reservoir understanding and in preparation for new well drilling 6-12 months Begin implementation of new technology and higher reservoir draw down with newly upgraded infrastructure 9-18 months GAS ASSETS Drill BCG wells in Thrace, through JV, to determine potential (2-4 wells) 9-18 months Execute JV for Albania Gas acreage to expedite exploration 6-12 months Finalize gas marketing strategy for Albania 6-12 months BULGARIA Drill North Koynare Prospect 9–12 month Mid Term Execution strategies Strategic operations to set up long term growth

Area Strategy Timing SELMO Complete development drilling and WF projects 2-3 years Produce field with minimal investment until 2025 3-5+ years MOLLA High Grade and begin multi-field development based on exploration success 2-3 years Full scale, multi-rig development of conventional and unconventional resources 3-5+ years ALBANIA Complete facilities and infrastructure upgrades and aggressively increase reservoir draw down 1-2 years Begin redevelopment drilling through horizontal and vertical wells to access isolated fault blocks and bypassed reserves 2-5+ years GAS ASSETS Prove / Disprove BCG play in Thrace Basin and either exit the basin or begin further exploration and development 1-3 years Bring Delvina fully online with newly executed gas marketing strategy 1-2 years Further gas exploration in Albania, Bulgaria, Other regions 2-5+ years BULGARIA If North Koynare successful develop field and shoot additional seismic, if not-exit license 2-5 years Long term execution strategies Growth through exploration and development