February 2018 TransAtlantic Petroleum Investor Update Presenting the Potential of TransAtlantic’s Asset Base Exhibit 99.1

Disclaimer (1/2) 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, 2016, 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 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 1P, 2P, and 3P reserves based on a reserve report prepared by Degolyer & MacNaughton as of December 31, 2017 using forward strip pricing (“YE2017 D&M Strip-Pricing Reserve Report”) and a reserve report prepared by Degolyer & MacNaughton as of December 31, 2017 using SEC pricing (“YE2017 D&M SEC Reserve Report”). 1P reserves refer to proved reserves. 2P reserves refer to proved reserves plus probable reserves. 3P reserves refer to proved reserves plus probable reserves plus possible reserves. 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. 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. 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. 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. 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.

Disclaimer (2/2) 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 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 PV10 and PV20: 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 PV10 future net revenues have been discounted at an annual rate of 10% and the PV20 future net revenues have been discounted at an annual rate of 20% 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 or the oil and natural gas reserves TransAtlantic owns. 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 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. PV10 and PV20 are not measures of financial or operating performance under GAAP. Neither PV10 nor PV20 should be considered as an alternative to the Standardized Measure as defined under GAAP. The Standardized Measure represents the PV10 after giving effect to income taxes. 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.

This presentation reflects TransAtlantic’s Management’s opinions of a logical and appropriate production, development and exploration program, which balances the following objectives: Increasing production income by drilling proved undeveloped locations Advancing testing of high-value resource and prospective prospects to a state where continuous development could be commenced in mid-2019 following reservoir testing of wells drilled in 2018 and early 2019 Constructing the necessary and justified production facilities to support the continuous development described in 2) above All activities in 1) and 2) located and timed to conserve and expand TransAtlantic’s production licenses in the greatest realistic manner Making fair estimates of costs and production results based upon prior history and expected practices The drilling and exploration activities discussed in this presentation seek to provide investors with information to better understand the value potential of TransAtlantic’s current properties and opportunities This presentation depicts an accelerated work-plan that exceeds TransAtlantic’s current cash flow and credit facilities and therefore this presentation should be read as a description of the “potential” of TransAtlantic’s assets rather than as a description of actual intended operations. TransAtlantic intends to commence the previously announced marketing process through Tudor, Pickering, Holt & Co. the week of February 19, 2018. Important Notice

TransAtlantic Corporate Profile Corporate Headquarters Dallas, TX Domicile Bermuda Employees Turkey: 111 (80 field) United States: 28 Listed Exchanges and Tickers NYSEAMEX: TAT TSX: TNP Share Price as of 16-Feb-2018 $1.67 Common Shares Outstanding 50.3 MM Common Share Equivalent of Convertible Preferred Shares(1) 42.1 MM Fully-Diluted Market Capitalization(1) $154 Enterprise Value(1) $164 1P – PV10(2) $336 2P – PV10(2) $570 Non-Affiliated Ownership Float(1) 21% TransAtlantic has formed a strategic committee of the board of directors in order to conduct a marketing process of TransAtlantic In January 2018, the strategic committee engaged Tudor Pickering Holt & Co. to act as financial advisor. Please see the press release from January 16, 2018 on the TransAtlantic website for further information on the strategic committee and the marketing process Overview Strategic Alternatives Process Assumes preferred shares treated as equity. Cash of ~$23MM and total debt of ~$33MM per Q3’2017 10-Q filing and term loan announced November 2017 Pre-tax values based on YE2017 DeGolyer & McNaughton Strip-Pricing Reserve Report Note: PV10 values calculated using SEC prices are as follows: 1P: $266 MM and 2P: $464 MM assuming a flat price of $54.89/bbl. Please see slides 46-47 for reconciliation of PV10 values to the most comparable GAAP measure. ($ in millions of USD, except per share numbers) Exploration and Development Program TransAtlantic has funded an eight-well drilling program in 2018, consisting of six wells in its Selmo field, one Bahar well, and one Yeniev exploration well. The remaining drilling and exploration activities discussed in this investor presentation are unfunded and contingent upon access to sufficient capital. There is no assurance that TransAtlantic will be able to access sufficient capital to undertake any or all of the unfunded drilling and exploration activities discussed herein

TransAtlantic Portfolio Overview Strategically positioned in established basins with access to open energy markets Black Sea Aegean Sea December 2017 DeGolyer & McNaughton Prospective Resource Report May 2017 NSAI Prospective Resource Report TAT exploration license TAT production license BCGA Play (Thrace) Dolni Dabnik Leads (Bulgaria) Production Exploration SE Turkey 6 licenses in the Southeast 5 operated, 1 non-operated 4 main producing fields, including: Şelmo, Molla, Arpatepe & Goksu Significant exploration running room 207 mmboe prospective resources(2) Dadas Sand/Shale resource plays NW Turkey 3 leases 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 102 – 205 mmbbls(1) of condensate resources in BCGA fairway 50,000 net acres in BCGA fairway 15 leases in the Northwest Production from shallow gas fields Bulgaria 163,000 net acre concession 1 production license $40MM cost recovery pool High impact exploration potential 4-way closures identified on 3D Deventci R-1ST expected to test 25 mmbbls in ‘18 Similar sized follow-ons mapped

TransAtlantic Market Valuation in Context TransAtlantic offers exposure to high margin barrels at an attractive valuation Source: TransAtlantic filings, FactSet as of 16-Feb-2018. Reserves as of YE 2016. Netback defined as revenue less operational expenses per net boe of production; pre-tax Current EV/2P Reserves versus Q3 2017 Netback ($/boe) $0 - $10 Current EV / 2P Reserves ($/boe) Q3 2017 Netback(1) ($/boe) Profitability Public Market Value $10 - $30+ $0 - $10 $10 - $30+ TransAtlantic EV / YE2017 2P of $4.80/boe and 2017YE netback of $34.02/boe

Returning to Growth Mode Source: Factset as of 16-Feb-2018 Production and Capex values based on Q3 2017 10Q filings; EBITDAX values based on 9 months at Q3 2017 Financial Results & Operational Update 2018 and 2019 production is based on an unconstrained development of the portfolio at $55/bbl Brent flat $24 MM fully funded under the 8-well 2018 work program and $27 MM subject to funding Subject to funding EBITDAX is a non-GAAP financial measure. Please see slide 50 for a reconciliation for EBITDAX. Forecasts of Adjusted EBITDAX for 2018 and 2019 assume access to sufficient funding, successful execution of the drilling program, and Brent crude oil prices of $55/bbl. Forecasts of Adjusted EBITDAX are for illustrative purposes only and should not be relied upon as (and are not) an indication of future results. Actual results are subject to change. 3D seismic being fully utilized to better identify prospects Thrace Basin Centered Gas Accumulation Play evolving; updated report at ~2x original resource estimates Balance sheet de-levered and G&A optimized Credit availability remains tight Geopolitical concerns subside; no operational downtime Oil prices continue to improve 3D seismic acquired; not yet fully processed for use Development cut due to balance sheet constraints Geopolitical issues limit TAT’s access to credit Balance sheet stressed Credit markets tighten, cash flow dedicated to debt reduction Oil prices fall, bottoming in early ‘16 Geopolitical tensions increase in surrounding countries Navigating the oil price downturn Repositioned for growth Average production (boepd) Capex ($ MM) $112 ~$183(4) $23 $10 $14(1) ~$51(3) EBITDAX(5) ($ MM) $90 $125(4) $65 $41 $23(1) $36(3)

An Attractive Value Proposition High margin conventional production from Southeast Turkey combined with the transformational growth potential of the BCGA play in Northwest Turkey and high impact exploration in Bulgaria Robust high margin conventional production in Southeast Turkey Expected to average 3.4 mboepd in 2018 Scope to ramp up to >10 mboepd by 2020 through accelerated drilling, subject to funding SOLID FOUNDATION 4 – 8 Tcf and 102 – 205 mmbbls of certified gas and condensate resources in the BGCA(3) Higher confidence due to Statoil / Valeura’s Yamalik-1 results and recent resource updates Low cost tight sand gas development TRANSFORMATIONAL PRODUCTION GROWTH Program to test 85 mmboe of resources, commencing with Yeniev well in Q2 2018(4) 122 mmboe of recoverable resources identified in the Dadas Sand/Shale(4) High impact conventional exploration in Bulgaria, targeting ~26 mmbbls, in Q3 2018, subject to funding(4) HIGH IMPACT EXPLORATION Upside resulting from 50,000 net acre BCGA position, potentially worth $6,200/acre(1) SEC 2P PV10 of $570 MM(2) exceeds EV of $164 MM, after adjusting for 22% income tax Attractively valued high margin barrels vs. peers in less fiscally attractive jurisdictions VALUATION UPSIDE Based on Valeura Energy’s February 2018 equity offering price of $5.70 per common share Pre-tax values based on YE2017 DeGolyer & McNaughton Strip-Pricing Reserve Report Based on December 2017 DeGolyer & McNaughton Prospective Resource Report Based on May 2017 NSAI Prospective Resource Report

TransAtlantic Sum-of-the-Parts Billion Barrel and Billion $ NAV Potential Pre-tax values based on DeGoyler & MacNaughton Strip-Pricing Reserve Report. Note: PV10 values calculated using SEC prices are as follows: 1P - $244 MM and 2P - $464 MM assuming a flat price of $54.89/bbl. PV20 values calculated using SEC prices are as follows: 3P $124 MM assuming a flat price of $54.89/bbl. Please see slides 46-47 for reconciliation of PV10 values to the most comparable GAAP measure. Based on TransAtlantic’s 50,000 net acre position in the BCGA at $6,200/acre, calculated based on Valeura Energy’s market value using Valeura Energy’s February 2018 equity offering price of $5.70 per common share as noted previously in this presentation Bulgaria, Dadas Sand and Molla conventional exploration resource values per May 2017 NSAI Prospective Resource Report, Dadas Shale and Selmo Deep potential excluded from analysis (Values are in millions of USD, unless otherwise noted) Catalysts: Dadas frac of Cavasulu Yiniev well Q2 2018 in the Molla area Koynare re-entry Q3 2018 in Bulgaria Bulgaria ~26 net mmboe Molla Conventional ~85 net mmboe Dadas Sand ~122 net mmboe Conventional and Unconventional Exploration Upside(3)

Deliberate Turkey-Focused Strategy Subsurface Proven and well understood petroleum systems Opportunity to deploy North American D&C techniques Untapped unconventional resource plays Upstream business landscape Excellent fiscal regime 12.5% royalty and 22% net income tax Fair and easy to navigate regulatory environment on par with United States onshore Paid regularly and in USD for oil sales, with no government interference Infrastructure In-situ oil and gas transportation infrastructure Access to local and international markets Established crude oil and gas marketing practices Macro OECD member country Energy hungry, short supply; >$5/mcf domestic gas prices 95% of oil & gas demand satisfied by high cost by imports Security Benign environment, with minimal above ground issues Operated continuously without any geopolitical or security related disruptions Precautionary security costs add ~$1/bbl to opex in SW Why Turkey? Advantageous Fiscal Terms (% Company Take) Source: Rodgers Oil & Gas Consulting, Journal of World Energy Law & Business and Palantir.

Deep Reserve and Resource Inventory Total working interest reserves and unrisked resources of 1.0 – 1.8 Bnboe Source: YE2017 DeGoyler & MacNaughton Strip-Pricing Reserve Report (Şelmo, Molla), December 2017 DeGoyler & MacNaughton Prospective Resource Report (Thrace BCGA), May 2017 NSAI Prospective Resource Report (Koynare, Molla conventional exploration, Dadas Sand) Net resource number attributable only to the Dadas Sands Pre-tax values based on YE2017 DeGolyer & McNaughton Strip-Pricing Reserve Report Note: PV10 values calculated using SEC prices are as follows: 1P: $266 MM, 2P: $464 MM and incremental 3P: $218MM, assuming a flat price of $54.89/bbl. Please see slides 46-47 for reconciliation of PV10 values to the most comparable GAAP measure. Dadas Sand/Shale ~122 net mmboe Thrace Basin – Basin Centered Gas Accumulation Play ~4 – 8 net Tcf gas ~102 – 205 net mmbbls condensate Molla conventional exploration ~85 net mmboe Incremental 3P Reserves ~13 mmboe (Strip Pricing PV10 - $245 MM) 2P Reserves ~29 mmboe (Strip Pricing PV10 - $570 MM) Bulgaria Prospect ~26 net mmboe Near-term Testing & Potential Development Thrace BCGA Production Şelmo Molla Bahar Goksu Arpatepe Exploration North Koynare Yeniev Hazro Mardin Bedinan Dadas play (1) (2) (2)

Multi-year drilling opportunity(1) Underpinned by low-risk resource inventory The activity presented herein (with the exception of the fully funded 2018 work program) is for illustrative purposes. It depicts the activity level the company, or its successor, could undertake if sufficient capital was available Net resource number attributable only to the Dadas Sands Assumes unconstrained access to capital Note: BOTAS is the Turkish national gas transmission network Source: YE2017 DeGoyler & MacNaughton Strip-Pricing Reserve Report (Şelmo, Molla), December 2017 DeGoyler & MacNaughton Prospective Resource Report (Thrace BCGA), May 2017 NSAI Prospective Resource Report (Koynare, Molla conventional exploration, Dadas Sand) Base conventional (Şelmo/Bahar) SE Turkey conventional exploration (Molla) Thrace Basin/BCGA Dadas Sand/Shale Bulgaria Drill the Yeniev exploration well in Molla Complete Pinar & Catak wells Fully integrate newly acquired 3D seismic data Commence Basin Centred Gas Accumulation Play (BCGA) test in Thrace Basin Initiate 3 well program to de-risk ~4-8 Tcf resource potential Frac Cavaslu-1 well in Dadas Sand/Shale Establish productivity of the Dadas Sand/Shale Further de-risk Dadas Sand/Shale development Re-enter and re-drill Deventci R-1 well Test the 25 mmboe Lower Triassic Dolni Dabnik feature Drill 6 horizontal wells at Şelmo Drill 2 development wells in the Bahar field Begin development of discoveries Drill further exploration wells in the Molla area Ramp-up BCGA drilling Up to 1,200 potential locations based on 40-acre spacing Ongoing development of conventional fields Ongoing development of the Dadas Sand/Shale Build out gas infrastructure Drill 4-way closures identified on existing 3D Potential of 25 mmboe in each Dolni Dabnik lead Fully develop the Bahar field Capex(3): ~$51 MM Drill Hazro horizontal development well in Bahar field Begin development of Yeniev, if successful Drill 3-5 exploration wells, targeting 5 – 15 mmboe each Commence 4-6 mmcfd of conventional gas sales Build pipeline to connect BCGA to the BOTAS network Initiate continuous development of the BCGA Drill Dadas Sand/Shale play 43 prospects identified with 122 mmboe(2) potential Test well and initiate production Acquire 3D data over eastern portion of the block Drill development well in Koynare Concession Negotiate license extension at Şelmo Continuous Şelmo drilling to develop reserves before 2019 Drill Şelmo deep to confirm productivity of Gomaniibrik frm. Capex(3): ~$183MM 2018 2019 2020+

2018 Drilling Schedule(1) Expected to grow production at Şelmo by +50% and set stage for transformational 2019 growth Represents current fully funded 2018 work program except for wells noted as “contingent on funding” herein Contingent on funding

2019 Drilling Schedule(1) Contingent on funding Assumes the Devenci 1R-ST well is successful

Northwest Turkey - Thrace Basin

TransAtlantic’s Thrace Basin Position Significant operated position in the core of the BCGA TransAtlantic is the only independent E&P with an operated position in the BCGA fairway TransAtlantic has a 100%(1) interest in the Temrez leases, covering an area of 120,000 acres in the Thrace basin >40% of the Temrez acreage position (~50,000 net acres) lies in the over-pressure deep area of the basin, which is optimally located to exploit the BCGA Surrounded by abundant gas transport infrastructure An initial 5 year exploration period is currently underway, with an option to extend to 11 years in 2 year tranches TransAtlantic owned 12” pipeline connecting to Valeura system Subject to funding, TransAtlantic intends to commence a 3-well delineation program in Q4 2018 Up to 40 years production lease available for commercial developments Outside of the Temrez area, TransAtlantic produces ~1 mmcfd (net) of gas from conventional reservoirs in its other leases within the Thrace Basin TransAtlantic’s Thrace Basin Position TransAtlantic’s Acreage 950+ wells drilled, targeting the conventional Oligo-Miocene play Turkish gas production only satisfies <1% of Turkish natural gas demand Deep wells in the basin demonstrate characteristic overpressure and gas saturation and define the onset of overpressures at ~2,500m (0.7 psi/ft) Statoil and Valeura’s Yamalik-1 well, on the flanks of the basin, has confirmed the veracity of the play The group plans to drill 3 additional tests in 2018 Thrace Basin Overview Bulgaria Northwest Turkey TransAtlantic acquired its Thrace Basin leases from Zorlu Enerji, which has the option to either a 5% NPI or participate with a 25% WI on all future wells drilled on the Temerez Blocks. TAT Exploration acreage TAT Production acreage BCGA Boundary

Material Upside within the Thrace BCGA Closest peer $/BCGA acre trading metric supports significant TransAtlantic valuation uplift Thrace Basin TAT Exploration Acreage Valeura Acreage 3D Seismic BCGA Boundary The BCGA is potentially worth ~$6,200/acre or ~ $300MM in total, based on Valeura Energy’s market value. TranstAtlantic owns 50,000 net acres in the core of the BCGA Sea of Marmara Black Sea Turkey Based on Valeura Energy’s February 2018 equity offering price of $5.70 per common share Source: TransAtlantic filings, FactSet as of 7-Feb-2018 10 miles

Basin Centered Gas Accumulation Play An emerging world-class gas play Structural Depth in the Thrace Basin Yamalik-1: Aggregate test rates of 2.9 mmcfd with condensate of 20-70 bbls/mmcf from four test intervals (eight fracs) in the Keşan Formation at ~0.7 psi/ft

Nearby deep wells establish the presence of significant amounts of gas saturated sand across TransAtantic’s Temrez licenses The Karakavak-1 encountered 1,235m and Pancarkoy-1 encountered 1,315m of net sand within the Teslimkoy and Keşan section Both the Hayrabolu-10 and the Alacaouglu-1 wells found considerable sand despite not drilling the entire Keşan section Both of these wells tested gas but were never fracture stimulated. Pressure tests from the Hayrabolu-10 and Alacaoglu-1 wells, as well as several other deep wells in the basin, help establish the over-pressure boundary of the BCGA Valeura reports almost 500m of net sand from the Teslimkoy and Keşan intervals 1,000m of Gas Saturated Sand Thrace Basin TAT Exploration Acreage Valeura Acreage BCGA Core Fairway Pancarkoy-1 Karakavak-1 Hayrabolu-10 Alacouglu-1 F17b3 F18b4 F18a4 F18a3 Limit of over-pressured area (0.7 psi/ft)

The Hayrabolu-10 (TD 4,054m) and Alacaoglu-1 (TD 3,760m) wells demonstrated the presence of pay sand adjacent to TransAtlantic’s Temrez acreage TransAtlantic interprets 625m of sand in Hayrabolu-10 with gas shows below 2,440m; limited testing produced gas (96% methane) but the section was not fracture stimulated Basin Cross Section Valeura reported almost 500m net sand from the Teslimkoy and Keşan intervals

TransAtlantic BCGA Volumetrics(1) Substantial low risk resource inventory DeGoyler & McNaughton’s mean estimate of productive acreage is 23,019 net acres out of TransAtlantic’s ~ 50,000 net acres within the overpressured boundary Total represents the statistical aggregate Total represents the arithmetic summation Source: December 2017 DeGoyler & MacNaughton Prospective Resource Report Note: See appendix for December 2017 DeGoyler & MacNaughton Prospective Resource Report notes Total (2) Total (2) Total (3) Total (3)

160 acres F17b3 F18b4 F18a4 F18a3 Thrace Basin Activity Outlook Subject to funding, TransAtlantic intends to commence an initial 3-well program in late 2018, the objectives include: Testing the BCGA in arch and trough locations Converting existing exploration licenses to production licenses Providing key data to plan a longer term drilling program to exploit the play As the license terms permit the production of hydrocarbons in the exploration phase, successful wells could be quickly tied-in to existing infrastructure and provide early cashflow Drilling Program Development Concept Around 50,000 net acres of the BCGA (based on a 2,500m cut-off depth) lie within the Temrez Licenses Over 300 drilling locations identified, based on a conservative 160 acre spacing and up to 1,200 locations on 40 acre spacing Development wells envisaged to be vertical, drilled from pads and to employ multistage fracs Ramping up to 10-12 drilling rigs is possible, without losing efficiency 2018 production would utilize existing gas infrastructure to transport gas to market Expect to construct and connect TransAtlantic pipeline to BOTAS in 2019 to facilitate large-scale development Development concept Representative unconventional well site(1) Source: Equinox Engineering Limited Note: BOTAS system is the Turkish national gas transmission network Thrace Basin TAT Exploration Acreage Valeura Acreage BCGA Core Fairway

Southeast Turkey - Producing Assets

Overview of Southeast Turkey Production Assets Proven conventional plays with low-risk additional development potential TransAtlantic’s license areas in SE Turkey comprise multiple well delineated conventional oil fields with significant undeveloped or bypassed resource remaining To more efficiently and effectively exploit the proven resource, TransAtlantic has utilized common North American development practices Multi-well pad drilling development Modern horizontal rigs and completion equipment 3D seismic across entire licensed position Low-risk locations offsetting existing modern wells provide highly economic near-term development ability 8 wells planned in 2018 Şelmo Field 2P reserves(1): 11.9 mmboe 2P PV10(2): $236 MM Molla Area 2P reserves(1): 15.6 mmboe 2P PV10(2): $321 MM Asset Summary Map of TransAtlantic Proven Fields Bahar field Goksu field Arpatepe field Şelmo field TAT Molla Area TAT Şelmo Area TransAtlantic license outline 3D coverage outline Recent 3D acquisition outline Producing field outline Molla field Based on YE2017 DeGolyer & McNaughton Strip-Pricing Reserve Report Pre-tax values based on YE2017 DeGolyer & McNaughton Strip-Pricing Reserve Report Note: PV10 values for all reserves calculated using SEC prices are as follows: 1P: $266 MM and 2P: $464 MM assuming a flat price of $54.89/bbl. Please see slides 46-47 for reconciliation of PV10 values to the most comparable GAAP measure.

Şelmo Overview Second largest oil field in Turkey with 700 mmboe in place and 91.4 mmboe produced since 1964 discovery ~36° API gravity crude; oil sold into Ceyhan, indexed to Brent, paid in $U.S., less gravity and transport deducts 8,000 acres, 100% covered by 3D seismic 100% working interest, 87.5% net revenue interest Production license expires in 2025 TransAtlantic has no P&A liability at expiration Two primary productive targets (Late Cretaceous): Middle Sinan Dolomite (“MSD”): tight dolomite with tank depletion; historically undrained Lower Sinan Dolomite (“LSD”): Highly fractured dolomite, responsible for majority of the field’s production to-date; significant bypassed pay to capture through horizontal development Current production of ~1.9 mboepd from 66 wells 16 hz. MSD and 3 hz. LSD wells drilled by TAT 39 drilling locations identified with 4.5 mmbbls of P1 reserves Asset Overview Typical Şelmo Lithology Primary productive targets

TransAtlantic is currently running 1 rig and intends to drill 6 horizontal wells in 2018 Subject to funding, TransAtlantic would add a second rig in Q3 2018, drilling up to an additional 33 wells through 2019 The Şelmo lease expires in 2025 However, TransAtlantic will make reasonable efforts to secure a new lease extension Upside potential Şelmo has an existing 4 well waterflood project that could be optimized to add additional near-term production volumes Future prospectivity TransAtlantic is to test highly prospective deep reservoir development in the field TransAtlantic currently has 57 potential locations on 40-acre spacing in Şelmo Deep Şelmo Opportunities Proven horizontal redevelopment of an established conventional field Near-Term Plans Identified PUD Locations Şelmo Reservoir Depth (SSTVD) MSD horizontal well

Şelmo (MSD) – Type Curve & Economics Rate – Time Production Plot Economic Summary Results significantly outperform DeGolyer & McNaughton type curve Note: DeGolyer & McNaughton oil type curve has an 24-hour IP of 185 bbl/d and is based off assumptions that result in a curve below TAT’s observed well performance in the area

TransAtlantic currently has 7 active producing wells, 5 PUD locations in the Bedinan, 6 PUD locations in the Hazro F4, 3 probable locations and 1 produced water disposal well in Bahar Current field production of 1.2 mboepd TransAtlantic operates Bahar with 100% working interest 40 years remaining on production licenses Includes a central gathering facility, production & disposal pipeline infrastructure and produced natural gas power generation for field consumption Bahar Field produces from multiple horizons including the Bedinan Sands, Dadas Sand/Shale, Hazro F-3 Sands, and the Hazro F-4 Dolomite Bahar Overview Asset Overview Typical Bahar Lithology Primary productive targets

The oil/water contact has not been established yet indicating that the field may be larger than initially believed Downdip limit may extend further than current results indicate 17 potential locations and secondary recovery opportunities Multiple benches of stacked potential Oil shows in Mardin remain untested Scope to reduce opex through the replacement of diesel-fired power generation by natural gas power generation Upside Potential Bahar Opportunities Bahar 3 Bedinan Development Mardin

Bahar (Bedinan) – Type Curve & Economics Rate – Time Production Plot Economic Summary

Southeast Turkey – Exploration Upside

Unconventional - Dadas Sand/Shale Overview Further prospectivity identified within the Dadas Sand/Shale intervals Shows observed while drilling the Dadas Section throughout the Diyarbakir Basin 43 “bright spots” mapped on 3D – sizes range from 50 to 3,000+ acres (~25,000 acres total) Potential for more than 250 drilling locations on 100-acre spacing Identified sands are expected to have minimum thickness of 50 ft Porosities expected to average 12-15% TransAtlantic plans to frac the Dadas Sand/Shale in the Cavasulu vertical well to test the play Full field development will be undertaken via horizontal wells with multi-stage fracture stimulations in the Dadas Sand/Shale intervals NSAI estimates 122+ mmboe of net recoverable resources in the Dadas Sands only(1) Dadas Sands/Shale Overview Dadas Sand/Shale Mapped Amplitude Packages (Packages with the same color represent stratigraphic equivalent zones within the Dadas Sand/Shale) TransAtlantic’s position is the only option for entry into the Dadas Sand/Shale with other prospective areas held by TPAO & Perenco Based on May 2017 NSAI Prospective Resource Report

Dadas Sand/Shale Geology Silurian source rock: Approximately 1,000 to 1,100 ft in Molla Area Source for almost all of the oil production in the Diyarbakir Basin Three members (Upper, Middle, and Lower / III, II, and I) Mainly Type-II kerogen located within the oil & gas window with TOC content ranging from 1% to 10% Cores show the presence of hydrocarbons in fractures High gas readings or shows encountered while drilling Goksu 1 and Bahar 6 completions support productivity of the shales Dadas Sand/Shale Geology DA-1 to DA-4 Amplitude Extraction Target packages of Dadas Sand/Shale reservoirs

Molla Area Conventional Prospectivity Over >85 mmboe of net conventional prospective resources have been identified in the Molla Area of Southeast Turkey(1) Multiple targets and stacked plays, including the Bedinan and Hazro Sandstones, as well as the Mardin Carbonates Drill depths are <4,000m, with the shallowest pay zones starting at 1,500m Wells are expected to cost ~$2–3 MM to drill and complete vertically Discoveries can be rapidly monetised, given proximity to existing infrastructure A drilling program has been established to test the Molla Area prospectivity, commencing with the Yeniev-1 exploration well in Q3 2018 Prospectivity Overview Molla Area Prospecitivity Overview Based on May 2017 NSAI Prospective Resource Report

Bulgaria

Complementary Bulgaria Interests Commercial framework Attractive fiscal terms Corporate income tax – 10% Royalty – 2.5 to 30%, subject to R-factor(1) Current cost pool of ~$40 MM Open and free oil market Domestic gas prices linked to import parity prices Macro EU member country 95% of gas demand satisfied through imports Abundant gas transportation capacity and connectivity to larger European markets Geology and operating environment Low cost access to established petroleum provinces, including the Moesian Platform Scope to leverage 3D seismic and modern D&C techniques Significant unconventional resource potential, although government instituted frac-ban currently hinders exploitation By drilling vertical or horizontal wells with open-hole completions, this restriction is overcome, as the reservoirs have good permeability Why Bulgaria? Attractive Fiscal Terms (% Company Take) Source: Rodgers Oil & Gas Consulting, Journal of World Energy Law & Business and Palantir. Calculated by dividing the total cumulative revenues from a production concession by the total cumulative costs incurred for that production concession

TransAtlantic in Bulgaria High impact exploration drilling slated for Q3’18 TransAtlantic operates the Koynare concession with a 100% working interest(1) The concession was awarded in 2013 The lease covers 163,000 acres and runs till 2048 The cost recovery pool stood at $40MM as of YE2017 Subject to funding, the Deventci R-1 ST well is planned as a side-track and would delineate the Ozirovo and test a 25 mmbbls four-way dip-closed prospect, North Koynare The well is estimated to cost $5-7MM, depending on pressures and possible flow while drilling overlying Ozirovo formation Multiple similar follow-on leads along trend have been identified on 2D seismic and provide significant low risk potential. Success on the Deventci R-1 ST would lead to acquiring 3D over leads Koynare is situated on the Moesian Platform, a well-known prolific and mature province Bulgaria position Geological Setting Subject to a 3.02% overriding royalty interest Production concession 3D Seismic North Koynare Prospect Identified leads (~25 mmbbls each) Ozirovo structure Other core oil and gas fields

The North Koynare Prospect Prospect features North Koynare – Dolni Dabnik Time Structure 3D defined 1,400 acres (5.6 km2) four-way dip-closed prospect with 200m of relief at Dolni Dabnik dolomite level First structure out of the basin which is optimum for charging Potentially 73.9 mmbbls STOOIP, with recoverable resources of 25.5 mmbbls (42o API), per NSAI estimates(1) Potential upside if larger fault-related closure is effective Drill depth is ~4,600m sidetracking out of the Deventci R-1 well and deviating to the North Koynare Prospect North Koynare is expected to have excellent reservoirs and will not require fracture stimulation Upper Ozirovo gas zone Based on May 2017 NSAI Prospective Resource Report

Conclusion

The TransAtlantic Investment Rationale Transformational resource upside underpinned by high margin oil production and 2P reserves Established North American drilling & completion techniques can deliver value across portfolio of onshore Europe Material positions in the Thrace Basin Centred Gas Accumulation play (BCGA) in Northwest Turkey with 4 - 8 Tcf and 100 - 200 mmbbls of independently certified (net) prospective gas and condensate resources(1) and the SE Anatolian Basin with ~200 mmbbls of prospective oil resources(2) Sophisticated operations in Turkey, with a supportive regulatory environment, attractive fiscal framework and high energy demand On-going drilling campaign underway expected to grow production more than 50% in Şelmo oilfield in 2018 and the potential to more than double overall production by end of 2019 December 2017 DeGolyer & McNaughton Prospective Resource Report May 2017 NSAI Prospective Resource Report

Appendix

Management Team Name Malone Mitchell III Todd Dutton Fabian Anda Chad Burkhardt Selami Uras Lee Muncy David Mitchell Title Chairman & CEO President VP, Finance VP, GC & CS VP, Land VP, Geosciences VP, Engineering Experience 33 years 37 years 18 years 17 years 30 years 38 years 10 years Biography Founded Riata Energy in 1985; saw it through numerous deals and operational evolutions Purchased National Energy Group in 2006 and with Riata renamed it to SandRidge Energy Oklahoma State University BS President of Longfellow Energy since 2007 Held various positions at Texas Pacific Oil Co., Coquina Oil Corp., BEREXCO and Riata Energy University of Oklahoma BBA (Petroleum Land Management) Certified Professional Landman Management roles in a variety of multicultural roles Began his career at ConocoPhillips in operational and financial positions University of Saint Thomas at Houston (Finance and Business Administration; International Finance) Joined TAT from Baker Botts where he served as Partner in the Corporate division Duke University School of Law, JD Texas A&M BA (Anthropology and English) Serves as the TAT representative in Turkey, since 2006 Previously was the Resident Rep. and General Manager for ARCO O&G Started his career at Geophysical Services in Turkey Faculty of Economical & Commercial Sciences Financial Advisor Certificate and Certified CPA Oversees TAT’s geological and geophysical efforts Previously served as VP of Exploration at Bass Companies Began his career as a geologist with Mobil Oil Corp. Ohio State University BS, MS (Geology & Mineralogy) Joined TAT in 2013 and has served in several operations and engineering roles Began his career at Talisman Energy as an engineer in a variety of positions University of British Columbia BASC (Engineering) Registered Professional Engineer (Alberta) TransAtlantic Management

TransAtlantic Organizational Structure Malone Mitchell III Chairman & CEO Todd C. Dutton President Noah Mitchell Vice President Chad D. Burkhardt VP Legal & General Counsel H Lee Muncy VP of Geosciences Cort Boecking IT Director Morte Bell Midstream David Mitchell VP of Engineering James Follis Drilling Manager Ozan Ülker Turkey CFO Javier Gonzalez VP of Operations Frances Mitchell Human Resources Director Fabian Anda VP of Finance Selami Uras VP of Land & Country Manager Dallas Based Turkey Based Rotational Time allocated between private and public operating companies

Low, best, high and mean estimates follow the PRMS guidelines for prospective resources Low, best, high and mean estimates in the preceding tables are P90, P50, P10 and mean, respectively Pg is defined as the probability of discovering reservoirs which flow petroleum at a measurable rate Pg has been rounded for presentation purposes. Multiplication using this presented Pg may yield imprecise results. Dividing the Pg-adjusted mean estimate by the mean estimate yields the precise Pg Application of any geological and economic chance factor does not equate prospective resources to contingent resources or reserves Recovery efficiency is applied to prospective resources in this table Arithmetic summation of probabilistic estimates produces invalid results except for the mean estimate. Arithmetic summation of probabilistic estimates is presented in this table in compliance with PRMS guidelines Summations may vary from those shown here due to rounding There is no certainty that any portion of the prospective resources estimated herein will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources evaluated The range in gas Pmean for the statistical aggregate Pg-adjusted mean estimate is 0.19 to 0.28 Notes to DeGoyler & McNaughton Resource Report December 2017

DeGolyer and MacNaughton did not estimate the Standardized Measure. PV10 and PV20 values 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 PV10 and PV20, 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. PV10 and PV20 are not measures of financial or operating performance under U.S. GAAP. PV10 and PV20 should not be considered as an alternative to the Standardized Measure as defined under U.S. GAAP. The following table provides a reconciliation of our 1P-PV10 at SEC pricing to our Standardized Measure: Value of Proved Reserves The following table shows our estimated future net revenue of 1P Reserves at SEC Pricing, Standardized Measure, 1P-PV10 at SEC Pricing, 1P-PV10 at forward strip pricing, 2P-PV10 at forward strip pricing, 3P-PV10 at forward strip pricing, and Incremental 3P-PV20 at forward strip pricing as of December 31, 2017: Reserves Reconciliation (1/4) Turkey Total (in thousands) Future net revenue of 1P at SEC pricing $ 411,920 $ 411,920 Total Standardized Measure (1) $ 229,050 $ 229,050 Total 1P-PV10 at SEC pricing (2) $ 266,358 $ 266,358 Total 1P-PV10 at strip pricing (2) $ 336,471     $ 336,471 Total 2P-PV10 at strip pricing (2) $ 569,729     $ 569,729 Total 3P-PV10 at strip pricing (2) $ 815,292     $ 815,292 Incremental 3P-PV20 at strip pricing (2) $ 140,566     $ 140,566 DeGolyer and MacNaughton did not estimate future income taxes, the discount of future income taxes at 10% per annum or the Standardized Measure. Turkey Total (in thousands) Total 1P-PV10 $ 266,358 $ 266,358 Future income taxes (1) (51,334 ) (51,334 ) Discount of future income taxes at 10% per annum (1) 14,026 14,026 Standardized Measure (1) $ 229,050 $ 229,050

DeGolyer and MacNaughton did not estimate future income taxes, the discount of future income taxes at 10% per annum or the Standardized Measure Note: 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. Reserves Reconciliation Continued (2/4) Prepared Strip Prices to SEC PV10 and SMOG (1) Proved (1P) (in thousands) Total PV-10 at Strip Pricing $ 336,471 Adjustments Relating to Strip Pricing and Terminal Volumes $ (70,112) Total PV-10 at SEC Pricing $ 266,358 Future Income Tax Discounted at 10% per annum(1) $ (37,308) Standardized Measure(1) $ 229,050 Proved + Probable (2P) (in thousands) Total 2P PV-10 at Strip Pricing $ 569,729 Adjustments Relating to Incremental Probable Volumes $ (233,258) Total Proved (1P) PV-10 at Strip Pricing $ 336,471 Adjustments Relating to Strip Pricing and Terminal Volumes $ (70,112) Total PV-10 for Proved (1P) at SEC Pricing $ 266,358 Future Income Tax Discounted at 10% per annum(1) $ (37,308) Standardized Measure(1) $ 229,050 Proved + Probable + Possible (3P) (in thousands) PV-20 of Incremental Possible at Strip Pricing $ 140,566 Adjustment Relating to Change in Discount Rate from 20% to 10% $ 104,997 PV-10 of Incremental Possible at Strip Pricing $ 245,564 Total 2P PV-10 at Strip Pricing $ 569,729 Total 3P PV-10 at Strip Pricing $ 815,292 Adjustments Relating to Strip Pricing and Terminal Volumes $ (133,770) Total 3P PV-10 at SEC Pricing $ 681,522 Adjustments Relating to Incremental Probable and Possible Volumes $ (345,051) Total Proved (1P) PV-10 at Strip Pricing $ 336,471 Adjustments Relating to Pricing and Terminal Volumes $ (70,112) Total PV-10 for Proved (1P) at SEC Pricing $ 266,358 Future Income Tax Discounted at 10% per annum(1) $ (37,308) Standardized Measure(1) $ 229,050 The following table provides a reconciliation of our 1P-PV10 at forward strip pricing to our Standardized Measure: The following table provides a reconciliation of our 2P-PV10 at forward strip pricing to our Standardized Measure: The following table provides a reconciliation of our 3P-PV20 at forward strip pricing to our Standardized Measure:

Reserves Reconciliation Continued (3/4) Overview – SEC Pricing vs. Forward Strip YE2017 SEC Reserves YE2017 Forward Strip Reserves

Reserves Reconciliation Continued (4/4) Pricing Data

Adjusted EBITDAX from continuing operations ("Adjusted EBITDAX") is a non-GAAP financial measure that represents net (loss) income from continuing operations plus interest and other net, current and deferred income tax expense, exploration, abandonment and impairment, seismic and other exploration expense, foreign exchange (gain) loss, share-based compensation expense, loss (gain) on commodity derivative contracts, cash settlements on commodity derivative contacts, accretion of asset retirement obligation, depreciation, depletion, and amortization, loss on sale of TBNG, and net other items. TransAtlantic believes Adjusted EBITDAX assists management and investors in comparing TransAtlantic's performance on a consistent basis without regard to depreciation, depletion, and amortization and impairment of oil and natural gas properties and exploration expenses, among other items, which can vary significantly from period to period. In addition, management uses Adjusted EBITDAX as a financial measure to evaluate TransAtlantic's operating performance. Adjusted EBITDAX is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income or income from continuing operations prepared in accordance with GAAP. Net income or income from continuing operations may vary materially from Adjusted EBITDAX. Investors should carefully consider the specific items included in the computation of Adjusted EBITDAX. Reconciliation for EBITDAX Note: Forecasts of Adjusted EBITDAX for 2018 and 2019 assume access to sufficient funding, successful execution of the drilling program, and Brent crude oil prices of $55/bbl. Forecasts of Adjusted EBITDAX are for illustrative purposes only and should not be relied upon as (and are not) an indication of future results. Actual results are subject to change. Proved + Probable + Possible (3P) (in thousands) 2014 2015 2016 09.2017 2018E 2019E Adjusted EBITDAX from continuing operations(1,2,3) $ 90,338 64,746 40,888 23,401 36,100 124,700 Adjusted EBITDAX Reconciliation:             Net Income (loss) from continuing operations $ 29,214 (26,665) (22,445) (19,836) (9,663) 41,993 Interest and other income expense, net $ 4,920 12,222 9,295 6,318 9,000 9,000 Deferred income tax benefit $ 13,659 22,229 6,046 3,856 1,700 - Exploration, abandonment and impairment $ 19,864 21,544 5,963 249 15,000 3,500 Seismic and other exploration $ 4,076 370 104 3,046   10,000 Foreign exchange gain (loss) $ 6,523 5,653 3,871 1,055     Share based compensation $ 1,434 1,688 629 556 1,000 1,000 (Gain) loss on commodity derivatives $ (37,454) (27,457) 3,257 (299)     Cash Settlement on commodity derivatives $ (2,100) 57,076 4,188 32     Accretion of asset retirement obligation $ 406 368 373 144 300 300 Depreciation, depletion and amortization $ 48,594 37,707 29,025 13,024 18,763 58,907 Net other items $ 1,202 (39,989) 582 15,256 - - Adjusted EBITDAX from continuing operation (1,2,3) $ 90,338 64,746 40,888 23,401 36,100 124,700

Thank you For process inquiries, please contact: Tudor Pickering Holt & Co. TransAtlantic@tphco.com London: +44 20 7268 2857 TransAtlantic, Malone Mitchell III Chairman & CEO Dallas: +1 972 590 9913 TransAtlantic, Chad Burkhardt VP, General Counsel & Secretary Dallas: +1 214 265 4705