Global Resources Conference October 16, 2012 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, 2011 and our Quarterly Report on Form 10-Q for the quarters ended March 31, 2012 and June 30, 2012 available at our website at www.transatlanticpetroleum.com and www.sec.gov. See also TransAtlantic’s 2011 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 being actually 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 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 |
Company Overview TransAtlantic Petroleum Ltd. is an international energy company engaged in the acquisition, development, exploration, and production of crude oil and natural gas in Turkey, Bulgaria and Romania. 3 NYSE-AMEX: Toronto: TAT TNP Share Price (1) : $0.96 Market Cap (1) : $353.4 million Enterprise Value (1) : $358.3 million Proved Reserves (2) : 13.4 MMboe SEC PV10 (3) : $645.8 million (1) Priced as of market close on 10/12/2012. (2) Reflects DeGoyler and MacNaughton (“D&M”) reserve report, effective 12/31/2011 based on $108/barrel and $7.18/Mcf. (3) Please see slide 28 for a reconciliation of our PV10 to our standardized measure. Executive Management Chairman & CEO: N. Malone Mitchell, 3rd COO: Mustafa Yavuz VP, CFO: Wil F. Saqueton VP, Bus. Dev.: Ian Delahunty |
Asset Characteristics 4 Natural Gas 16% Undeveloped 47% Natural Gas 45% Thrace 43% Other 9% (1) Reflects DeGoyler and MacNaughton (“D&M”) reserve report, effective 12/31/2011 based on $108/barrel and $7.18/Mcf. BOE conversions are calculated by the Company. Reserve Profile (1) 2Q12 Production Profile Growth Profile (1) |
Track Record of Success 5 Riata Energy and Lariat Energy Strategic Partners 1985 Malone Mitchell 3 founded Riata Energy with $500. 1991 Acquired interest in Pakenham Field (West Texas). Birth of vertical integration strategy. 1994 After drilling 34 wells, sold Pakenham Field to Chevron for $97 million. 1995 Purchased > 200,000 prospective acres in Pinon Field. 1999-2006 Refined vertical integration strategy. 2006 Sold controlling stake to Chesapeake Energy co-founder for $500 million. Riata is renamed SandRidge Energy. 2008 Mr. Mitchell and family sold an additional $500 million stake in SandRidge Energy. 2008 Mr. Mitchell and family make an initial strategic investment in TransAtlantic Petroleum and begin bringing vertical integration strategy to Turkey. rd |
Crude Oil Supply/Demand Why Turkey? 6 Opportunity Set Undersupplied: • Produces ~7% of crude oil consumed. • Produces ~2% of natural gas consumed. Underexplored: • Known petroleum systems and attractive geology. • Opportunity for modern technology to make a difference. Pro-Business: • Relatively laissez faire • 12.5% royalty, 20% corporate tax. Rapid Growth: • 2011 GDP growth of 5.7% • 5-year GDP CAGR of 4.5% (10yr = 14.2%) Source: US Energy Information Administration (EIA) Source: US Energy Information Administration (EIA) Source: World Bank Natural Gas Supply/Demand Gross Domestic Product |
Turkey: Acreage Overview 7 Thrace Basin Southeast Central More than 5 million net acres in an under-explored region with attractive fiscal terms. |
Turkey: Thrace Basin 8 TBNG Northwest Joint Area • 41.5% working interest. • 13.2 MMcf/d (gross) • Frac results encouraging. Transitioning to development program in 4Q12. • 50-100% working interest. • 0.4 MMcf/d (gross) • Initial drilling in process. • 60 prospects identified with 10-60 Bcfe targets (1) . • 50% working interest. • 5.7 MMcf/d (gross) • Identified 25 Bcf (1) of shallow prospects on 4288. • 55-100% working interest. • 4.2 MMcf/d (gross) • Several prospects identified from latest seismic. (1) Internal prospective resource estimate prepared 6/30/11 Kayi Deep-1 West Joint Area Northwest West TBNG |
Thrace Basin Frac Program: Assessment Timeline 9 Development Test Off-structure Potential Test Horizontal Potential Test Multi- Stage Verticals Test Deep & New Structures Prove Frac- ability |
Thrace Basin Frac: Tekirdag Development Program 10 Development Program Characteristics: • Initial 88-well development program covering approximately 5,000 acres of the Tekirdag Field Area. • Two rig drilling program carries activity into 2015. • Gross well costs expected to range between $2.0 million and $3.0 million, depending upon total depth and completion design. • TransAtlantic and its partners have designed a multi-year development program for the Tekirdag Field Area which is expected to kick-off during 4Q12. Tekirdag (1) Internal estimate prepared 10/1/12 Hayrabolu Gross expected ultimate recovery expected to exceed 70 Bcf (1) . |
Thrace Basin Frac: Tekirdag Development Program 11 |
Thrace Basin: Long-term Development Concept 12 For illustrative purposes only. Not to scale or representative of a specific location.. Ceylan Horizontals Mezardere Horizontals Teslimkoy Horizontals Multi-stage Verticals |
Turkey: Southeast 13 Overview • Extension of prolific Iraqi and Syrian oil trends. Houses Turkey’s most productive fields including TransAtlantic’s Selmo field. • Conventional oil production provides low decline base. • New field discoveries in 2011 and 2012 (Goksu and Bahar wells). • 14 well Selmo frac program began mid- September. • Conventional and unconventional upside opportunities including large shale play potential. Numerous large anticlines identified. • Bedinan, Dada , Hazro, Jurassic, Mardin, and Triassic targets. Dada Shale • Upper Silurian (Woodford equivalent) • Roughly equal in size to the Barnett. • Source rock for conventional fields. • Early work indicates oil, liquids and gas windows. Evaluating second core. |
Turkey: Southeast – Molla – Goksu 14 Goksu Overview • Goksu-2 (Mardin Lime) has produced almost 50,000 barrels in less than 9 months. • Goksu-3H completing as TAT’s first horizontal producer and TAT’s second horizontal drilled in Turkey. • Planning Dada horizontal to spud later in 2012 or early 2013. Bahar-1 Goksu 1 & 2 Kastel field |
Turkey: Southeast – Molla – Goksu 3H 15 Goksu 3H ST actual trajectory Goksu 3H planned trajectory Goksu 2 actual trajectory |
Turkey: Southeast – Molla – Goksu 3H 16 Goksu 3H ST Planned Trajectory Goksu 3H ST Actual Trajectory Total Gas Curve SUMMARY: Planned 1,625’ total penetration within the Reservoir; Achieved 1,515’ total penetration Drilled @ -3,635’/-3,651’ subsea depth range TDed 8’ above Goksu-2Kbb-C Top; Goksu-1 Kbb-C Top is @ -3,645’ TD is 585’ away from Goksu-2 Kbb-C Top Top Kbb-C Goksu 3H (P&A) |
Turkey: Southeast – Molla – Bahar Discovery 17 Molla Overview (100% Working Interest) • Bahar-1 located in northwestern portion of original Molla licenses. Recent license award extends potential inventory. • New field discovery in the Bedinan o Same producing horizon as Arpatepe. o Has not previously been productive in the area. o Productivity inhibited by heavy skin damage. Has produced 25-30 bbl/d oil (36 0 ) and 1,200 btu gas unstimulated. • Shows in Hazro, Mardin, Bedinan, and Dada . • Dada and Bedinan are overpressured. Bahar-1 Bedinan Structure Map Bahar-1 |
Turkey: Southeast – Dada Shale Overview 18 Dada Shale Characteristics • Devonian-Silurian age. Areal extent similar to Barnett Shale core. • Basal member (Dada 1) is the primary oil source rock for regional hydrocarbon production. • Indications of oil window (south) transitioning to gas window (north). • TransAtlantic’s acreage primarily in expected oil and liquids windows. • Plan to spud first horizontal test later in 2012 or early 2013. Goksu-1R Core Analysis • Approximately 30 feet of core taken (2010). • Vertical depth: 8,350 feet (2,500 meters) • Total Organic Content: 7-9% • Porosity: 0.5-6.0% • T max : 435 0 C • R 0 : 0.7-0.8% Shale Comparison Attribute Dada Woodford Eagle Ford Bakken Age Silurian Silurian Cretaceous Mississippian Depth (ft) 7,000-10,000 6,000-14,500 4,000-14,000 8,000-11,000 Gross Thickness 300-800 300-400 100-350 150 TOC (%) 3.0-12.0 6.0-6.5 4.0-5.5 6.0-8.0 T max ( 0 C) 350-460 300-400 425-455 420-430 R 0 (%) 0.5-1.0% 1.1-3.0% 0.5-2.6% 0.4-1.7% Porosity (%) 0.5-10% 3-12% 4-15% 8-12% Permeability 0.3-1.0 md 0.2 md <0.13 md 0.005-0.2 md Oil Gravity (API) 40-60 30-65 40-60 40-45 EUR (Mboe) TBD 150-2,000 300-1,500 500-1,500 |
Southeast – Dada Shale – Industry Activity 19 Shell/TPAO Dada Joint Venture TransAtlantic’s Molla Field TransAtlantic’s Arpatepe Field TransAtlantic’s Selmo Field TransAtlantic New Exploration License Anatolia Energy Dada Core TPAO Dada Test Well TransAtlantic’s Bahar-1 TransAtlantic’s Goksu 1 & 2 Shell/TPAO Saribugday-1 |
Turkey: Southeast – Molla Development Concept 20 For illustrative purposes only. Not to scale or representative of a specific location.. |
Turkey: Central 21 Overview • Frontier basins offer under-explored, high potential, oil and gas opportunities. • Seeking exploration partners. Sivas • • ~1.6 million acres • Relatively unexplored tertiary basin with working petroleum systems. • Seismic and aeromag in process. Gaziantep • 61.5%-100% working interest. • ~450,000 acres • Prospective for Mardin Lime. First horizontal awaiting completion. Other • Multiple petroleum systems. • Identified shallow amplitude play in untested Miocene sands • Biogenic gas and deeper Miocene carbonate potential. Adana in via exploration agreement (Shell). 100% working interest, subject to farm- |
Turkey: Central – Gaziantep – Alibey-1H 22 Overview • Re-entry of vertical oil show well. Lateral drilled into Mardin Lime. • Similar concept/target as plan for Goksu 3H. • TAT’s first in-country horizontal. • Logging concluded, well awaiting completion. Alibey-1H |
Bulgaria 23 Overview • The A-Lovech exploration license covers approximately 565,000 acres (2,288 square kilometers) in NW Bulgaria. • All acreage is prospective for the Etropole shale formation. • Proximal to existing natural gas infrastructure. • Attractive terms: 2.5%-30% royalty and 10% corporate tax. Koynare (Deventci) • 160,000 acres (648 square kilometers) • Conventional gas discovery in the Jurassic-aged Orzirovo. • Deventci R-1, is currently producing ~250 Mcf/d on a limited test basis. Waiting on award of production license. Surface casing set on Deventci-R2. • Seeking a development partner. Bulgaria’s Energy Profile 2011 Population: 7,037,935 2011 GDP: $53.5 billion 2010 Oil Consumption: 91.0 Mbbls/d 2010 Oil Production: 2.9 Mbbls/d 2010 Nat Gas Consumption: 211 MMcf/d 2010 Nat Gas Production: 0 MMcf/d Source: The World Bank, CIA World Factbook & Energy Information Administration Peshtene R-11 • November 2011 drilled a ~10,500 foot (3,200 meter) exploration well to core and test the Etropole formation. • Core currently being evaluated. • Rock properties similar to prolific US shale plays, with more favorable terms (royalty and taxes) and commodity pricing. • Etropole position is estimated to hold gross unrisked best estimate prospective resources of 11 Tcfe (1) . • Awaiting revision(s) to recent Parliamentary legislation. (1) Internal estimate prepared as of November 2010 - represents potentially recoverable hydrocarbons from undiscovered accumulation(s) which are subject to both risk of discovery and development. |
Romania 24 Overview • 50% interest in 1,000,000 acres (400,000 with unconventional potential) • Sterling Resources-operated joint venture. Seeking additional joint venture partner(s). • Prospective for Silurian shale (natural gas). Also holds Jurassic oil potential. • Awarded license for Phase 2 Exploration Period. • Commitment of 200 km 2D seismic may be shot during 2012. • Chevron has acquired exploration licenses straddling the eastern Bulgarian/Romanian border. Romania’s Energy Profile 2011 Population: 21,848,504 2011 GDP: $189.8 billion 2010 Oil Consumption: 196.0 Mbbls/d 2010 Oil Production: 107.1 Mbbls/d 2010 Nat Gas Consumption: 1,247 MMcf/d 2010 Nat Gas Production: 1,025 MMcf/d Source: The World Bank, CIA World Factbook & Energy Information Administration (EIA) |
2Q12 Financial & Operating Results 25 Three Months June 30 June 30 Mar 31 (in millions, except per share) 2012 2011 2012 Revenues (millions) $32.5 $31.6 $34.8 Production expense $5.0 $4.2 $3.6 Exploration, abandonment, impairment, and seismic 7.7 6.2 3.5 Contingent consideration & contingencies 1.3 - General and administrative expense 9.6 9.3 9.7 Depletion, depreciation, amortization & accretion 9.6 8.8 9.4 Total Cost & Expense $31.9 $29.7 $26.2 Net Operating Income (loss) $0.6 $1.9 $8.7 Net income (loss) from continuing operations $7.9 ($1.9) ($2.6) Net income (loss) from continuing operations per share $0.02 ($0.01) ($0.01) Adj. EBITDAX (non-GAAP) from continuing operations $21.2 $17.7 $22.4 Adj. EBITDAX (non-GAAP) per diluted share $0.06 $0.05 $0.06 * Totals may not sum due to independent rounding |
EBITDAX Reconciliation 26 For the three months ended (in millions) June 30. 2012 June 30, 2011 Mar 31, 2011 Net income (loss) from continuing operations $7.9 ($1.9) ($2.6) Add back: Interest and other, net $1.7 $3.4 $3.0 Income tax benefit (expense) 4.1 0.7 0.1 Exploration, abandonment, and impairment 6.9 4.5 2.8 Seismic and other exploration 0.5 0.9 0.2 Foreign exchange gain (loss) 1.3 (0.2) (4.3) Share-based compensation 0.6 0.4 0.5 Derivative (gain) loss (14.3) (0.2) 12.4 Depreciation, depletion, amortization, and accretion 9.4 8.5 9.4 Revaluation of contingent consideration 0.0 1.3 0.0 Other 3.0 - 0.8 EBITDAX For the Period Ended* $21.2 $17.7 $22.4 * Totals may not sum due to independent rounding 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. Information regarding income taxes, interest, depreciation, depletion, amortization, impairment, abandonment and exploration expense is unavailable on a forward looking basis. 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. |
Hedge Profile 27 As of 6/30/2012 |
PV10 Reconciliation 28 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 PV10 to our standardized measure: US $ thousands Total PV 10: $645,837 Future income taxes: (171,592) Discount of future income taxes at 10% per annum: 57,522 Standardized measure: $531,797 |
Investor Contact Information Chad W. Potter, CFA VP – Finance / Investor Relations (214) 265-4746 chad.potter@tapcor.com Wil F. Saqueton VP – Chief Financial Officer (214) 265-4743 wil.saqueton@tapcor.com 16803 Dallas Parkway P.O. Box 246 Addison, TX 75001-0246 29 |