Presentation in Denver, Colorado October 7, 2013
FORWARD LOOKING STATEMENTS 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 , 2012 and our Quarterly Report on Form 10 - Q for the three months ended June 30 , 2013 , which are available on our website at www . transatlanticpetroleum . com and 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 . 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 . 2
TRANSATLANTIC BOARD OF DIRECTORS 3 Name Select Experience Malone Mitchell 3 rd 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) Mel Riggs Chief Operating Officer, VP and Director of Clayton Williams Energy, Inc. (22 years with the company have included roles of CFO, Treasurer, Secretary and Financial Analyst) Michael Winn President of Seabord Capital Corp., Former President of Terrasearch Inc. Brian Bayley Advisor, Former President & CEO of Sprott Resource Lending (formerly Quest Capital Corp.), President and Director of Ionic Management Corp. 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. 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 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
TRANSATLANTIC TEAM 4 Name Position Select Experience Malone Mitchell 3rd Chairman & CEO Founded Riata Energy (SandRidge Energy), Riata Corporate Group (Longfellow Energy, Dalea Partners, Viking International) Ian Delahunty President Occidental Petroleum Corp., Schlumberger Wil Saqueton Vice President, CFO Just Brakes (CFO), PricewaterhouseCoopers LLP Caty Albert Chief Technical Officer Longfellow Energy, Riata Energy, Texaco, Chevron Taylor Miele Director, Investor Relations QR Energy, Seahawk Drilling, Touradji Capital, Solstice Equity Management, Donaldson, Lufkin & Jenrette
OBJECTIVE 5 Optimize Assets to Increase Production and Cash Flow • Utilize North American technology to more efficiently produce assets - Horizontal drilling, stimulation and 3D seismic • Manage from Dallas headquarters • Deploy capital using proven industry expertise and decrease costs • 2013 capital budget: $130 million
6 125 miles 200 kilometers FOCUS AREAS HAVE KNOWN PRODUCTION 12.5 Bcf Proved Reserves (18% YE12) 9.0 MMcf/d Production (37% 2Q13) 9.5 MMBoe Proved Reserves (82% YE12) 2,527 Bbl/d Production (63% 2Q13) Note: Production is average for 2Q13. Proved reserves are DeGolyer and MacNaughton as of 12/31/2012, based on $ 108.30/barrel and $8.94/Mcf .
1) MOLLA AREA 7 Ş elmo Field Idil Prospects May 2013 Acquisition Bakuk Field Arpatepe Field TPAO Discovery Bahar Field Ambarcık Well Göksu Field Molla Field Perenco’s Kastel Field (EUR 15 MMbo) Batı Raman Field Largest oil field in Turkey Shell Oil Dadaş Test
Demonstrated horizontal success with Göksu - 3H at 250 Bbl/d after 9 months of production Vertical discovery Bahar - 1 IP ~600 Bbl/d post frac Bahar - 2 tested 170 Bbl/d Potential resource play 1) MOLLA GEOLOGICAL TARGETS 8 Target Zones Şelmo producing zone
1) MOLLA 3D SEISMIC PROGRAM 9 Seismic data shot as of September 4, 2013. Molla 3D seismic program encompasses approximately 800 km 2 (300 square miles). TransAtlantic’s Molla Field TransAtlantic’s Göksu Field Perenco’s Kastel Field TransAtlantic’s Bahar Field TPAO Discovery Bostanpinar Shell Oil Dadaş Test
Formation Overview • Conventional sandstone targets immediately above and below Dadaş; expect to shoot 3D seismic in September 2013 • 1P reserves: 1.4 MMbbls (1) ; 2P reserves: 2.5 MMbbls (1) Çatak - 1 (Vertical, 11,000’ depth ) • Oil shows in Mardin, Hazro, Dada ş & Bedinan • Primary Bedinan target 100’ high to Bahar - 1 • Analyzing Hazro, Bedinan cores in Houston • Currently completing well Bahar - 2H (Horizontal, plugged back at 8,700’ ) • Difficulty encountering and staying within target zone on initial lateral; plugged back • Hazro t ested 170 - 200 Bbl/d with no water • Currently installing production equipment Bahar - 1 (Vertical discovery, 10,500’ depth ) • Cum. production > 60,000 bbls • ~6.5 month payback at current vertical well cost • IP ~600 Bbl/d post frac; f lowing ~230 Bbl/d after 10 months of production (1) DeGolyer and MacNaughton reserves as of 12/31/2012, based on $ 108.30/barrel and $8.94/Mcf. Payback period assumes oil price of $100.00/barrel. 1) MOLLA HAZRO AND BEDINAN DISCOVERIES 10 Bahar - 1 Ç atak - 1 Bahar - 2
1) MOLLA BAHAR - 1 BEDINAN TARGET 11 Dadaş 1 Oil & gas shows Bedinan H1 Sand 600 Bbl/d – Bahar - 1 Cored – Ç atak - 1
1) MOLLA BAHAR - 1 HAZRO TARGETS 12 150 Bbl/d – Bahar - 1 170 Bbl/d – Bahar - 2 Cored – Çatak - 1
2) ŞELMO FIELD REMODELING 13 Remodeling Has Resulted in Improved Targeting • Extensive work done to remodel Ş elmo and identify bypassed oil; field is extremely fractured • New dynamic model incorporates updated substructure mapping with production and pressure histories to determine areas of the field that will benefit most from horizontal drilling campaign • Horizontal wellbores will likely allow more uniform pressure drawdown across the wellbore length and prevent water coning or premature breakthrough of water
3) THRACE BASIN STRUCTURE 14 T EKIRDA Ğ O SMANLI Y ILDIRIM H AYRABOLU
3) THRACE BASIN GEOLOGICAL TARGETS 15 Conventional gas 400 – 1,500 meters (1,300 – 5 ,000 feet) Unconventional gas IP 1.5 MMCFD post frac Unconventional gas IP 4 MMCFD post frac Target of BTD - 4H (Drilling) Unconventional gas IP 1 MMCFD post frac Target of DTD - 19H (Completing) Target Zones
3) THRACE BASIN SOUTH: OSMANLI 3D SEISMIC 16 TransAtlantic expects to shoot 234 km 2 ( 9 0 square miles) of 3D seismic over the Osmanlı area in the Thrace Basin, northwestern Turkey in the fourth quarter of 2013.
BULGARIA UPDATE – NEW PARTNER 17 Action Plan Joint venture agreement in place; partner to fund $30 million of initial $40 million investment, then participate with 50% interest 1 Koynare Concession – First in Recent Bulgaria History • Expect to spud Deventci - R2 in October 2013 • Conventional gas discovery in Jurassic - aged Orzirovo • If successful, plan to build pipeline to connect to central grid at +/ - $9/Mcf, shoot additional 3D seismic of the multiple structures along Koynare fault trend • Sales expected to begin in 2014 Stefanetz Concession Application • November 2011 drilled ~10,500 foot Peshtene - R11 exploration well to core and test Etropole formation • Awaiting revision to parliamentary legislation regarding hydraulic fracture stimulation Near the best oil and natural gas fields in the country and existing natural gas infrastructure E TROPOLE S HALE K OYNARE C ONCESSION 160,000 ACRES 10 miles D EVENRCI - R1 P ESHTENE - R11 S TEFENETZ C ONCESSION A PPLICATION 395,000 ACRES (1) Assignment of interest is subject to Bulgarian government and other approvals.
RECENT OPERATIONS UPDATE 18 Third Quarter 2013 Achievements • Exit rate exceeded 4,500 Boe/d compared to guidance 4,350 Boe/d • Reiterated year - end exit rate of at least 5,000 Boe/d • Spudded 18 wells in the third quarter; Expect to spud 11 wells in fourth quarter to attain 2013 goal of 38 wells • Numerous well completions in progress • Significant progress on Molla 3D seismic program in southeastern Turkey • Preparing to add drilling rig in Bulgaria Preparation of the Deventci - 2 well site in Bulgaria (Photo by Stefan Anastasov). Drilling the Goksu - 5H horizontal well in SE Turkey (Photo by Gary Nilson).
THREE - PART STRATEGY UNDERWAY TO INCREASE PRODUCTION AND CASH FLOW IN TURKEY 19 2) Selmo Field Redevelopment (Southeast, Oil) • Remodeled field using 3D seismic and increased well control, identified undepleted fault blocks • Recent success on first horizontal well into most prolific formation in the field; drilling third horizontal 1) Molla Horizontal Program (Southeast, Oil) • Completing fifth horizontal well in Molla • Six additional wells planned in Molla area this year • Acquiring 3D seismic over Molla area 3) Thrace Basin Development (Northwest, Natural Gas) • Completing two horizontal wells in Thrace Basin South (recent vertical IP: 2.5 - 3 MMcf/d) • Effectively utilizing hydraulic fracturing in productive intervals of Thrace Basin South • Recent discovery in Thrace Basin Central
Demonstrated horizontal success with Göksu - 3H at 250 Bbl/d after 9 months of production Vertical discovery Bahar - 1 IP ~600 Bbl/d post frac Bahar - 2 tested 170 Bbl/d Potential resource play 1) MOLLA GEOLOGICAL TARGETS 20 Target Zones Şelmo producing zone
1) MOLLA MARDIN DISCOVERIES 21 Formation Overview • Fractured carbonate present across the region; i nitial vertical discoveries bolstered by horizontal drilling • 1P reserves: 0.6 MMbbls (1) ; 2P reserves: 2.9 MMbbls (1) Göksu - 5H (Horizontal, 3,000’ lateral) • AFE: $3.5 million; currently completing Göksu - 4H (Horizontal, 2,200’ lateral) • Cost: $2.5 million; ~6 month payback • Cum. production ~ 18,000 bbls in 5 months Göksu - 3H (Horizontal, 1,600’ lateral) • Cost: $3.5 million; Cum. production > 110,000 bbls • ~3.5 month payback • Flowing ~500 Bbl/d currently Göksu - 2 (Vertical, 5,700’ depth) • Cost: $2.0 million; Cum. production > 60,000 bbls • ~3.5 month payback; IP 400 - 500 Bbl/d in Feb. 2012 (1) DeGolyer and MacNaughton reserves as of 12/31/2012, based on $108.30/barrel and $8.94/Mcf . Payback periods assume oil price of $100.00/barrel. 0 20,000 40,000 60,000 80,000 100,000 120,000 0 500 1000 1500 2000 2500 3000 3500 10/1/2012 12/1/2012 2/1/2013 4/1/2013 6/1/2013 8/1/2013 10/1/2013 BBL OIL (CUM) BOPD, BWPD, PSI, % Water GOKSU - 3H (Mardin) BOPD BWPD FTP WC Cum Oil
13.2’ 4.0 m 14.1’ 4.3 m 25.0’ 7.6 m 27.1’ 8.3 m 26.1’ 8.0 m 30.4’ 9.3 m 0 1 2 3 4 5 6 7 8 9 10 0 5 10 15 20 25 30 35 Göksu-3H Bahar-2 Göksu-4H Oba-1 Çatak-1 Göksu-5H Penetration Rate (meters per hour) Penetration Rate (feet per hour) Mardin Intermediate Hole Performance 11.7’ 3.6 m 11.5’ 3.5 m 25.5’ 7.8 m 25.9’ 7.9 m 9.7’ 3.0 m 42.8’ 13.0 m 0 2 4 6 8 10 12 14 0 5 10 15 20 25 30 35 40 45 Göksu-3H Bahar-2 Göksu-4H Oba-1 Çatak-1 Göksu-5H Penetration Rate (meters per hour) Penetration Rate (feet per hour) Mardin Surface Hole Performance 1) MOLLA DRILLING PROGRESS 22 Molla penetration rates have increased significantly over the past 12 months with well repetition. Spud Date: 8/2012 1/2013 3/2013 4/2013 6/2013 7/2013 Spud Date: 8/2012 1/2013 3/2013 4/2013 6/2013 7/2013
$240 /ft $786 /m $101 /ft $331 /m 0 0.2 0.4 0.6 0.8 1 1.2 0 50 100 150 200 250 300 Bahar-2 Çatak-1 $ per meter $ per foot Bedinan Surface Hole Cost $129 /ft $423 /m $87 /ft $285 /m $60 /ft $196 /m $59 /ft $193 /m 0 50 100 150 200 250 300 350 400 450 0 20 40 60 80 100 120 140 Göksu-3H Göksu-4H Oba-1 Göksu-5H $ per meter $ per foot Mardin Surface Hole Cost 1) MOLLA DRILLING PROGRESS, CONTINUED 23 Molla surface drilling costs have decreased with well replication. Spud Date: 8/2012 3/2013 4/2013 7/2013 Spud Date: 1/2013 6/2013
2) ŞELMO FIELD REDEVELOPMENT 24 Şelmo Background • Second largest field in Turkey (~600 - 800 million barrels of oil in place, ~87 million barrels cumulative production) • 100% working interest • Discovered by Mobil in 1964 • 2012: drilled 9 development wells; performed 10 fracture stimulations, average production 2,222 Bbl/d of oil • ~50 producing wells in the field • Drilling third horizontal well in Şelmo Field • 2013 budget includes five horizontal wells; likely to drill more due to success in LSD zone (Şelmo - 13H) Ş elmo vertical pad drilling site.
2) ŞELMO FIELD REMODELING , CONTINUED 25 Ş elmo Horizontal Well Location
3) THRACE BASIN GEOLOGICAL TARGETS 26 Conventional gas 400 – 1,500 meters (1,300 – 5 ,000 feet) Unconventional gas IP 1.5 MMCFD post frac Unconventional gas IP 4 MMCFD post frac Target of BTD - 4H (Drilling) Unconventional gas IP 1 MMCFD post frac Target of DTD - 19H (Completing) Target Zones
3) THRACE BASIN SOUTH: HORIZONTAL DRILLING 27 Tekirdağ Horizontal Drilling • Completing second horizontal well (BTD - 4H, 41.5% working interest) • Targeting Teslimkoy formation (2,500’, productive zone) ; $3.3 million • Plan to drill two additional Tekirda ğ horizontal wells Completing first horizontal well in the Thrace Basin, the DTD - 19HK.
Molla Area Selmo Field Thrace Basin Bulgaria Total 1H13 Horizontal Vertical 3 - - - - 3 - - 3 3 2H13 Horizontal Vertical 7 4 5 - 4 11 - 1 16 16 Total Horizontal Vertical 10 4 5 - 4 14 - 1 19 19 Grand Total 14 5 18 1 38 2013 PLANNED DRILL WELLS 28 Drilling rig on location in the Thrace Basin. Note: Based on completion date. If we drill and complete our proposed well count in the second half of 2013, we expect to have a year - end exit rate of more than 5,000 Boe/d.
TRANSATLANTIC PETROLEUM NYSE - MKT: TAT, TSX: TNP • $288 million market capitalization • Oil and natural gas properties in Turkey, Bulgaria • Significantly increasing development activity (+500% in 2H 2013) 29 Market data as of October 3, 2013. Ownership data as of June 30, 2013. TransAtlantic Ownership Management 40.4% Retail 41.5% Institutions 18.1%
OPERATING AND FINANCIAL HIGHLIGHTS 30 Results for three months ended: 6/30/2013 3/31/2013 6/30/2012 Net p roduction Oil (BBLD) Natural Gas (MCFD) BOED % Oil 2,527 8,967 4,022 63% 2,660 8,904 4,144 64% 2,560 11,879 4,538 56% Prices Oil (BBL) Natural Gas (MCF) $94.13 9.57 $103.00 10.12 $97.49 8.49 Average Netback BOED $71.39 $72.92 $65.00 Financial ($ millions) EBITDAX (1) Net income (1) Capital Expenditures Net debt Net debt/book capitalization $17.6 2.9 28.1 23.8 10% $19.5 3.0 18.7 20.3 8% $21.7 8.6 13.8 4.9 2% (1) EBITDAX and net income are for continuing operations. Note: Commodity prices are unhedged. Netbacks are calculated as follows: oil and natural gas revenues after royalties less pr odu ction expenses divided by net production.
VALUATION 31 Current Valuation Current Position • 51% PV - 10 (1P) • ~$64,000 per Boe/d 1 (60%+ oil) • $70.00+ netbacks • 10% net debt/ capitalization at 6/30/13 • Increasing activity 1 Based on reported production of ~4,500 Boe/d on October 1, 2013. Market data as of October 3, 2013. Photo of Bekirler - 2 by Sertaç Eraslan, Senior Drilling Engineer.
INVESTMENT THESIS • Significantly increased drilling activity in 2H13 • Capital deployed on most favorable projects • Three - part strategy in Turkey provides clear path to grow production and cash flow • Resuming activity in Bulgaria with new partner • Expert team in place to execute capital plan 32
INVESTOR CONTACT INFORMATION Taylor B. Miele Director of Investor Relations (214) 265 - 4746 taylor.miele@tapcor.com Wil F. Saqueton VP - Chief Financial Officer (214) 265 - 4743 wil.saqueton@tapcor.com Ian J. Delahunty President (214) 265 - 4780 i an.delahunty@tapcor.com 33
EBITDAX RECONCILIATION 34 $US millions For the three months ended: 6/30/2013 3/31/2013 6/30/2012 Net income from continuing operations $2.9 $3.0 $8.5 Less : Interest and other, net 0.7 0.5 1.7 Income tax expense 0.2 2.3 4.6 Exploration, abandonment, and impairment 11.9 3.9 6.9 Seismic 1.0 0.1 0.8 Foreign exchange loss 2.5 0.5 (1.1) Share - based compensation 0.5 0.4 0.6 Unrealized derivative gain (4.8) (0.5) (15.1) Accretion of asset retirement obligation 0.1 0.1 0.2 Depreciation, depletion and amortization 9.6 9.0 9.4 Revaluation of contingent consideration (5.0) - - Net o ther items (2.0) 0.2 3.0 Adjusted EBITDAX from continuing operations $17.6 $19.5 $21.7 This presentation references estimated EBITDAX, which is a non - GAAP financial measure that represents earnings from continuing operations before income taxes, interest, depreciation, depletion, amortization, impairment, abandonment and exploration expense. The Company believes 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, impairment of natural gas and oil properties and exploration expenses, which can vary significantly from period to period. In addition, management uses EBITDAX as a financial measure to evaluate the Company’s operating performance. EBITDAX is also widely used by investors and rating agencies. 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 EBITDAX. Investors should carefully consider the specific items included in the computation of EBITDAX. The Company has disclosed EBITDAX to permit a comparative analysis of its operating performance and debt servicing ability relative to other companies.
PV - 10 RECONCILIATION 35 The PV - 10 value of the estimated future net revenue are 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 following table provides a reconciliation of our PV - 10 to our standardized measure: $US thousands Total PV - 10: $563,757 Future income taxes: (121,806) Discount of future income taxes at 10% per annum: 36,647 Standardized measure: $478,598
