March 2015 COMPANY UPDATE Exhibit 99.1
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, 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 Possible Reserves: possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. 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. Cover Photo: Şelmo field in southeastern Turkey.
Declines in share price and increases in intrinsic value have exaggerated value gap Deep inventory of profitable projects in current commodity environment Proven success in reserves growth UNDERVALUED Sources: DeGolyer and MacNaughton and Deloitte Year-End 2014 reserve reports (SEC Case), Company data and financials; Note: Enterprise Value calculated as market cap plus net debt at year end, IRR is the discount rate required to make the present value of expected net revenue from production equal single well CAPEX, Reserves growth in 2014 includes addition of 15.6MM 1P reserves in Albania and 40% organic growth in Turkey 18% 4-YR CAGR Reserves Growth Value Gap Profitable Inventory 200%+ Upside in 1P NAV 50%+ IRR for 4 main areas @ $60 Brent
POSITIONED FOR FUTURE GROWTH In 2014, we demonstrated operational success and positioned ourselves for future growth. Record production and reserves growth 24% YOY Production growth, 168% 1P reserves growth (40% organic growth) Strengthened project economics and inventory using 3D seismic Over 20 new field leads identified Completed acquisition of projects in Albania Three oil fields and one gas field 15.6 MMBOE of 1P reserves; and $236 Million PV-10(1) Large unreserved potential Established Dadaş production in Southeast Turkey with Bahar 6 completion Increased production from waterflood pilot in Şelmo SEC CASE
ADAPTIVE TO CHANGE IN PRICE ENVIRONMENT We are adapting to current prices while remaining focused on value generation. Well prepared with a beneficial hedge position Value of $32 million at year end 2014 Increased liquidity through issuance of $55 million convertible notes Reduced CAPEX in 2015 Plan to drill within cash flow Targeting cost reductions in G&A and LOE $10 million reduction in run rate targeted by Q3 2015 Optimizing well costs, negotiating improved pricing, utilizing existing inventory Repurchase shares of TransAtlantic (TAT) stock as cash flow allows
FOCUSED ON ESTABLISHED, UNDEREXPLORED PETROLEUM SYSTEMS TransAtlantic Petroleum (NYSE-MKT: TAT) (TSX: TNP) is an international oil and gas company based in Dallas, Texas Applying proven, North American technology to known international hydrocarbon basins High quality 3D seismic, horizontal wells, multistage stimulations Seek favorable commodity prices, royalty and tax rates, low production vs. consumption Achieved year-end 2014 guidance of more than 6,000 BOEPD in Turkey in November 2014 (~7,000 BOEPD including Albania) Natural Gas 24.5 BCF 1P Reserves (12% YE 2014) 8.4 MMCFPD Net Production (23% Q4 2014) Crude Oil 28.7 MMBO 1P Reserves (88% YE 2014) 4,564 BOPD Net Production (77% Q4 2014) 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.
DEMONSTRATED PRODUCTION GROWTH Avg. Netback/BOE: 1Adjusted EBITDAX is for continuing operations. Photo: Bahar field in southeastern Turkey.
IMPROVED COSTS Note: Per barrel costs calculated using WI volumes; restated for 2010 & 2011. Photo: Bahar Field in southeastern Turkey. -11% 4-yr CAGR; -13% YOY G&A LOE -15% 4-yr CAGR; -13% YOY
BASIC EPS FINANCIAL METRICS Net Debt/Adj. EBITDAX Note: NAV is SEC Case; Adj. EBITDAX is for continuing operations; NAV per share calculated as SEC Case PV-10 less YE 2014 net debt divided by shares outstanding at 12/31/2014, enterprise value calculated as market cap plus net debt at December 31 of the respective year. Adj. EBITDAX 42% 4-yr CAGR; 16% YOY NAV/EV NAV/share: $18.69 (1P), $36.21 (2P) $0.77 per share in 2014
TURKEY
SOUTHEASTERN TURKEY 593,000 gross, 385,000 net acres, area is mostly oil, except Bakuk field 350,000 acres of proprietary 3D seismic in SE Turkey 19 wells drilled and spud in 2014 Perenco’s Kastel Field EUR 15 MMBO Şelmo Field Bahar Field Batı Raman Field Largest oil field in Turkey Idil Prospect Bakuk Field Arpatepe Field Molla Field Göksu Field Shell-TPAO Dadaş Shale Drilling
ŞELMO FIELD DEVELOPMENT Implemented horizontal drilling for the first time in Şelmo field in 2013 Targeting undrained Middle Şinan Dolomite (MSD) zone (1,700m/5,550’ vert. depth) New wells IP up to 700 BOPD; ~77 locations(1) identified 50% increase in oil production in first year of horizontal drilling (1) Source: Degolyer and MacNaughton
ŞELMO FIELD SECONDARY RECOVERY Commenced secondary recovery in Şelmo in 2014 Converted 4 wells to injection in 2014 as part of waterflood pilot test Infrastructure in place for expansion Pilot estimated to add ~400 MBO incremental EUR as of 12/31/2014 Şelmo Field Waterflood Conversions Şelmo Field Waterflood Pipelines and Wells Phase #1 – April 2014 Phase #2 – June 2014 Phase #3 – October 2014 Injectors Operational as of Q1 2015 Experienced incremental production
Migration Dadas Maturity line Migration Migration Migration Migration Dadas Maturity line Migration path Dadaş maturity line Producing field Prospect TransAtlantic lease outline MOLLA AREA 3D PROSPECTS 278,000 acres of proprietary 3D seismic over the Molla area Gross production is >1,700 BOPD within 4,300 acres Dadaş formation producing in Bahar-6 well 4.1 MMBOE of reserves from 7 producing wells and 12 PUDs(1) Growth of 156% from 1.6 MMBOE at year end 2013 (1) Degolyer and MacNaughton year end 2014 reserve report, reserve figures do not include Arpatepe.
Bahar Molla Area in South East Turkey TransAtlantic lease outline 3P Reserve area Prospect area SIGNIFICANT UNBOOKED RESERVES IN MOLLA Molla Goksu Arpatepe 3P reserves constitute a small footprint TransAtlantic licenses encompass 212,694 gross, 164,708 net acres in Molla
DADAŞ POTENTIAL Bahar 6: Comingled Dadaş and Bedinan production: 63.6 MBbl in 107 days Bedinan & Dadas Bahar Field Well Results Bedinan Bedinan Bedinan 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 1: Bedinan production: 152.2 MBbl in 775 days
DADAŞ DETAIL Every well encounters oil shows within the Dadaş (Silurian) formation in this mature area Seismic anomalies correspond to quality sand depositions in the Dadaş Dadaş sands were deposited in low areas flanking anticlinal structures These sand depositions are expected to yield higher production and reserves than less sandy or shaley areas Bahar Field Molla Area Proposed Drilled Drilled in seismic anomaly amplitude TransAtlantic Wells: Bahar 6 Colors indicate discrete amplitude anomalies
MOLLA AREA 3D SEISMIC CROSS SECTION C’ C Dadaş
THRACE BASIN, NORTHWESTERN TURKEY G.Resisdere-1 Kumlar-1 Gurgen Derin-1 D.Gurgen-1 B.Kilavuzlu-2 Koseilyas-2 Aydede-3 Sariyer-1 B.Adatepe-1 TAT Licenses & JVs Tekirdağ Development Wells 2015 Prospects 1.5 million gross, 804,000 net acres in Northwest Turkey, area mostly gas 877,000 acres of proprietary 3D seismic in Northwest Turkey New geological basin model (confirmed by Gurgen discovery) has resulted in many new prospects to be tested
ALBANIA
ALBANIAN ASSETS HAVE SIGNIFICANT POTENTIAL Many existing wells have only penetrated 6-15m / 20-50’ of the reservoir, which may be as large as 700m / 2,300’ thick Oil fields are structurally trapped carbonate reservoirs, like TransAtlantic’s Şelmo field, but significantly thicker Properties lack North American technology and sufficient capital investment; significant untapped resource Expect to double gross production to 3,000 BOEPD TransAtlantic Properties Gas Pipeline
ALBANIAN OIL FIELDS Photo: Gorisht field in Albania. Gorisht Field Discovered 1965, 25,000 BOPD peak 13 – 16 degree API 3,000 net acres (1,214 net hectares) (100% WI) YE 2014 ~150 wells: ~750 BOPD gross, ~330 BOPD net Depth: 1,000 – 2,500 meters (3,300 – 8,200 feet) Producing formations: Cretaceous, Eocene carbonates Cakran Field Discovered 1977, 6,000 BOPD peak 14 – 37 degree API, condensates 53 degree API 6,000 net acres (2,428 net hectares) (100% WI) YE 2014 ~30 wells: ~460 BOPD gross, ~260 BOPD net Depth: 3,000 – 4,500 meters (9,800 – 15,000 feet) Producing formations: Cretaceous, Eocene carbonates Ballsh Field Discovered 1966, 7,500 BOPD peak 12 – 24 degree API 6,000 net acres (2,428 net hectares) (100% WI) YE 2014 ~15 wells: ~100 BOPD gross, ~90 BOPD net Depth: 1,000 – 3,000 meters (3,300 – 9,800 feet) Producing formations: Cretaceous, Eocene carbonates
GROWTH PLAN FOR ALBANIAN OIL FIELDS In each of the three Albanian oil fields (Gorisht, Cakran, Ballsh) we plan to deepen, core and log two wells Will core the complete reservoir to create a petrophysical model Developing the fields on layers with remaining oil saturation will improve accuracy of reserves Expect to optimize wells with recompletions and workover activity, anticipate cost reductions with upgraded equipment and technology (artificial lift, modern stimulations) Modify infrastructure: expanding storage facilities will result in a higher oil price, debottlenecking surface production facilities will decrease costs Source: Albanian National Agency of Natural Resources.
ALBANIAN PRECEDENT: BANKERS PETROLEUM Average Historical Production in Patos-Marinza Field Albpetrol Bankers AAP 20,000 16,000 12,000 8,000 4,000 1939 1944 1949 1954 1959 1964 1969 1974 1979 1984 1989 1994 1999 2004 2009 2014 Source: Bankers Petroleum, August 2014 corporate presentation. Bankers signed a concession for the Patos-Marinza oil field in 2004; grew the asset from 400 BOPD to more than 20,000 BOPD over a ten-year period Development included reactivations, horizontal drilling, optimizations, secondary recovery, modernization of surface facilities, field electrification, expansion of export capabilities, preparing to initiate tertiary recovery (steam) Same oil source, carbonate reservoir breached into shallower sandstones Stream oil is higher quality (higher gravity), should receive higher price Fields produced at a higher original rate than Patos-Marinza TransAtlantic Properties Gas Pipeline Bankers Oil Properties
DELVINA GAS FIELD, ALBANIA Photo: Delvina field in Albania. One of the largest gas structures in southeast Europe Discovered 1987 60,000 net acres (24,000 hectares) covering Delvina and three undrilled structures (100% WI) Gas condensate, 63 degree API Depth: 2,800 – 4,000 meters (9,200-13,100 feet) Four structures, two existing vertical wells, currently non-producing
DELVINA FIELD MINIMUM 2015 PLAN Delvina is a proven gas condensate field Will finish drilling the D-34 well and complete it with a multi-stage stimulation Significant gas condensate field with complex drilling and production requirements Source: Stream Oil & Gas, 2013 (modified). D-34 location
CONCLUSION Good execution and growth in 2014 Building prospect inventory to improve future potential Quickly adapted to low price environment TransAtlantic (TAT) is significantly undervalued
Appendix
HIGH QUALITY 3D SEISMIC Significant amount of proprietary 3D seismic, all of which has been expensed Area Kms2 Miles2 Acres Hectares Northwest Turkey 3,548 1,370 876,730 354,800 Southeast Turkey 1,417 547 350,148 141,700 Bulgaria 63 24 15,568 6,300 Total 5,028 1,941 1,242,446 502,800
FISCAL TERMS AND PV-10 RECONCILIATION TURKEY 12.5% royalty, no production tax VAT exempt on exploration licenses, refunded on production leases Pro-business and respect for rule of law Produces <5% of oil and gas consumed ALBANIA 12% royalty until 100% cost recovery 13-17% royalty and 50% net profit tax thereafter VAT refundable Produces <60% of oil consumed, consumes all available gas BULGARIA 2.5% royalty until 150% cost recovery; graduated royalty thereafter to 35% No production tax Produces <5% of oil and gas consumed Photo: Saranda, Albania 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 SEC P1 PV-10 to our standardized measure: $US MM TAT Total P1 PV-10 $884.4 Future income taxes (392.2)1 Discount of future income taxes at 10% per annum 179.91 Standardized measure $672.1 1 TransAtlantic Petroleum is not a U.S. domiciled corporation.
Name Position Select Experience N. Malone Mitchell 3rd Chairman & CEO Founded Riata Energy (renamed SandRidge, NYSE: SD) and built it to 1 TCF proved reserves, 43 rigs operated; founded 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 Matt McCann General Counsel & Corporate Secretary Longfellow Energy; Riata Corporate Group; SandRidge Energy, Inc.; Sprouse Shrader Smith PLLC Lee Muncy VP Geosciences Bass Companies; Fina Oil & Chemical Company; TransTexas Gas Corp; Mobil Oil Corporation Noah M. Mitchell 4th Vice President Viking Services, Viking Coil Tubing Justin Davis VP Engineering SandRidge Energy: Piceance Basin operations manager, Permian Basin stimulation design William Bentley VP Land Sandero Resources; Ted W. Walters & Associates MANAGEMENT TEAM
CONTACT Lizzy Chesnut Investor Relations (214) 265-4716 Lizzy.Chesnut@tapcor.com www.TransAtlanticPetroleum.com