SE Basin, Turkey ‘11 Applying old lessons to new frontiers April 11 Permian Basin, TX ‘38 2011 Analyst Day Meeting 2011 Analyst Day Meeting April 12, 2011 April 12, 2011 Exhibit 99.1 |
2 Disclaimer 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 changes in long-term oil or gas prices or other market conditions affecting the oil, gas, and petrochemical industries; reservoir performance; timely completion of development projects; war and other political or security disturbances; changes in law or government regulation; the outcome of commercial negotiations; the actions of competitors; unexpected technological developments; the occurrence and duration of economic recessions; unforeseen technical difficulties; 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, 2009 and our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2010, June 30, 2010 and September 30, 2010 available at our website at www.transatlanticpetroleum.com and www.sec.gov. See also TransAtlantic’s 2009 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. No Offer, Solicitation or Recommendation 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 The information contained herein is current as of the date hereof, but may become outdated or subsequently may change.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. Notes Regarding SEC Reserves Data and Other Oil and Gas Information The Company uses in this presentation the terms proved, probable and possible reserves. Proved reserves are reserves 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 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. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. Estimates of probable and possible reserves which may potentially be recoverable through additional drilling or recovery techniques are by nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company. In addition, in this presentation the Company uses certain broader terms such as “contingent resource estimate,” or “potential” or “upside” or other descriptions of volumes of resources potentially recoverable through additional drilling or recovery techniques that may include probable and possible reserves as defined by the SEC’s guidelines. The Company has not attempted to distinguish probable and possible reserves from these broader classifications. The SEC’s rules prohibit us from including in filings with the SEC these broader classifications of reserves. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. Contingent resource estimate refers to the Company’s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques and have not been reviewed by independent reserves evaluators. Contingent resource estimates do not constitute reserves and do not include proved reserves. Area wide unproven, unrisked resource potential has not been fully risked by our management. Actual quantities that may be ultimately recovered from the Company’s interests will differ substantially. Factors affecting ultimate recovery include the scope of the Company’s drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, drilling results, license expirations, transportation constraints, regulatory approvals, field spacing rules, recoveries of gas in place, length of horizontal laterals, actual drilling results, including geological and mechanical factors affecting recovery rates and other factors. Estimates of resource potential may change significantly as development of our resource plays provides additional data. DeGolyer and MacNaughton evaluated the Company’s reserves as of December 31, 2010 in accordance with the reserves definitions of Rule 4-10(a) (1)-(32) of Regulation S-X of the Securities and Exchange Commission (“SEC”) and in accordance with National Instrument 51-101 (“NI 51-101”) and the Canadian Oil and Gas Evaluators Handbook (“COGEH”). DeGoyler and MacNaughton evaluated reserves at the Company’s Selmo oil field, Arpatepe oil field, Bakuk license, and Thrace Basin gas fields, all of which are located in Turkey. In this presentation, the Company uses the term “barrels of oil equivalent” (“Boe”). Boe is not included in the DeGolyer and MacNaughton report and is derived by the Company 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 to 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. |
Agenda 3 N. Malone Mitchell, 3 rd , Chairman Matthew McCann, CEO matt.mccann@tapcor.com Phone: 214-265-4738 |
Overview South East Turkey Drilling Rig at the Selmo Oil Field 5/14/10 4 |
Capitalize Good Ideas 5 Application of advanced technologies Vertically integrated Diverse inventory of projects in core areas Competitive Advantage |
We’ve Set the Stage to Execute Acquired rigs & equipment. Acquired production and reserves (Incremental) when oil was < $40/bbl Acquired Energy Operations Turkey, LLC (Paleozoic Trend) Closed acquisition of Zorlu’s E&P operations First Fracture Stimulation in Thrace Basin Exercised option to acquire Thrace Basin Natural Gas Turkiye Corporation and Pinnacle Turkey Inc. and acquired 100% ownership of Direct Bulgaria & Direct Morocco Mar 09 Dec 08 Jul 09 Aug 10 Oct 10 6 Feb 11 * A boe conversion ratio of 6 mcf to 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. Execution Plan for 2011 Increase production to 10,000 Boepd in Turkey by year end $125 - $150 MM CAPEX in 2011 • 50% dedicated to Thrace Basin Focus where we have control within our established inventory Emphasize tying in production TransAtlantic Acreage Position Gross Net Turkey 6,385,000 5,980,000 Bulgaria 600,000 600,000 Morocco 766,000 766,000 Romania 1,440,000 720,000 Total 9,191,000 8,066,000 Reserves Proved Developed Total Proved plus Proved plus Probable plus Possible Proved Probable Oil and Condensate, Mbbl 5,588 12,936 18,277 31,080 Gas, Mmcf 16,560 22,425 60,737 234,863 Total Oil and Gas, Mboe* 8,346 16,674 28,400 70,224 Year End Reserves (12/31/10) |
Operations 7 VGS Seismic Survey Temrez Area, Thrace Basin |
Why Turkey? Royalty 12.5% Tax 20.0% Investment in Turkey increasing: Chevron Exxon Petrobras Turkey imports >70% of its gas consumption from Russia Gas priced at ~$8/mcf Known petroleum systems and attractive geology Opportunity for modern technology to make a difference No stimulation history 8 |
Becoming Turkey’s Best Public Oil & Gas Company 9 * A boe conversion ratio of 6 mcf to 1 bbl us based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Land Approximately 6.4 mm gross acres Development & exploration balance Oil & Gas balance Investment Thesis Technology 3D seismic PDC & directional drilling Fracture stimulation Integration Oil field services Midstream capacity Cost – availability – value capture Reserves MMBOE* Proved Proved +Probable Proved + Probable +Possible Selmo 12.1 16.8 29.3 Thrace 3.5 9.5 38.1 S.E. Turkey (other) 1.0 2.0 2.7 Total 16.6 28.3 70.1 Thrace Basin Syrian Trend |
Thrace Basin Edirne Year end production target for the Thrace Basin: 35-40 Mmcfpd: Alpullu (4861) Joint Area TBNG 10 * Does not include acreage from pending TBNG acquisition Total Acreage* Gross Net 1,064,433 779,206 2011 Capex $60-$70 MM Drilling Plans 50-60 Wells Upside Deep prospects with large structural closures Extension of shallow gas play with 3D 1,500 sq km 3D Prospect inventory building Fracture Stimulation |
Thrace Basin Fracture stimulation program underway Technology delivers value Deep Inventory of Re-entries, which set up full scale development Net gas production at year-end ~ 35- 40 Mmcf/d Reserves * Oil & Gas Proved - 3.4 MMBoe / 20.5 Bcf Probable - 6.0 MMboe / 36.0 Bcf Possible - 28.6 MMBoe / 171.8 Bcf 11 Successfully fractured stimulated Kepirtepe-1 well with an initial flow rate of approximately 4.0 mmcf/d Joint Venture Block with TPAO (National Oil Company of Turkey ) A boe conversion ratio of 6 mcf to 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. |
Type Log Conventional Pays Osmancik Intervals Danismen Intervals 12 • Stacked pays – high drilling success • 100 – 1,200 m (320 – 4,000 ft) depth • Thick quality sands • Deltaic depositional environment • Blocky character • Porosities 25 - 27% • Permabilities 30 - 50 mD • S W 40% Economics • Quick to drill • $300-$600K to drill and complete • Estimated .15-.50 bcf reserves per well, with some outliers |
Thrace Unconventional Gas Fracing Unlocks The Potential 13 Thick sedimentary basin with tremendous upside from fracture stimulation of tight sands and “show wells” Reservoirs Hamitabat (3500-4500 m) Ceylan (3000-4000 m) Mezardere (2000-3500 m) “Tuffs” (found throughout Mezardere & Ceylan) Thrace Basin Formations |
Unconventional Gas Play: Potential in the Mezardere and Hamitabat Potential Gas in Place in Mezardere Potential Gas in Place in Hamitabat Calculations are based on the area below: Area: 640 Acres (internal estimates) Hamitabat formation 14 Mezardere (for License # 3791) Prososity: 0.06 Sw: 0.5 Pay: 250 ft Depth: 2,100 m 6,900 ft Pressure 3,400 psi Temp. 190 of 40 BCF/section Hamitabat (for License # 4861) Prososity: 0.06 Sw: 0.5 Pay: 250 ft Depth: 4,600 m 15,100 ft Pressure 7,500 psi Temp. 350 of 55 BCF/section |
Focus on Conventional Gas Edirne Area (55% on 3839 / 100% on 4037) 2011 Plan • 12 new structures identified from new 3D • 12 mmcfpd exit rate • 20 wells planned 15 |
Conventional Structure at a Glance Ortakci Structure – Volumetric Reserves Ortakci Structure Volumetrics Drainage Area 710 acres Net Pay 10 meters Bulk Volume 23288 acre-ft Initial Reservoir Pressure 360 psia Initial Reservoir Temperature 89 F Gas Gravity 0.59 Bg 25 v/v Sw 0.50 dec Porosity 0.30 dec Recovery Factor 0.80 dec Total RGIP 3.0 bcf Estimated Ultimate Recovery Ortakci 1 0.45 bcf Ortakci 2 0.70 bcf Ortakci 4 0.15 bcf Kisla 1 0.45 bcf Kisla 2 0.14 bcf Drilling Cost $400K per well for about 0.4 bcf/ well 16 |
Alpullu Area (License 4861) 17 2011 Plan Build out gathering system Develop Alpullu Test Temrez and Avlu Fracture stimulate 10 mmcfpd exit rate 8 wells |
Osmancik Structure 18 |
19 Alpullu Field • Alpullu-1 (2004) made a gas discovery in the Danismen and Osmancik sands in the shallow section. • The Alpullu shallow structure is defined by a series of stacked amplitude and AVO anomalies within Danismen and Osmancik formations in a NW-SE trending positive flower structure which can be clearly defined both on 2D and 3D seismic data. • The structure is intersected by a series normal faults within the positive flower structure which form the compartmentalization. |
3D Seismic is a key exploration tool Alpullu Structure - 3D time-slice @ 0.544 seconds: 20 |
4861 – Avlu Structure: 21 • The Prospect is defined by a series of amplitude and AVO anomalies within Osmancik Fm. • The Avluobasi-Alacaoglu structure is a thrust roll-over anticline which straddles from 3599 AOI into 3589 TPAO. • Alacaoglu-1 (1993) drilled on the license border and tested oil/gas in Osmancik and Mezardere formations. • TPAO made a gas discovery 500 meters away from license boundary in Osmancik sands with Alacaoglu-3 (2008) and Alacaoglu-4 (2009) wells based on 3D seismic data. • The same structure and Osmancik sands extends into 3599 AOI license based on 2D seismic data. |
Temrez Prospect 22 |
Kara Structure 23 |
Joint Area with TPAO (50%) 24 2011 Plans • 8-10 mmcfd exit rate • 10 wells planned • 3 producing areas |
25 Conventional and Unconventional Gas Play Thrace Basin Natural Gas “TBNG”* 4201 3734 3858 3931 3934 4126 Possible 3D Possible 3D Proposed 175 km2 Current Production Approximately 25.0 million cubic feet per day TAT share approximately 9 million per day $8/Mcf gas and $1/Mcf opex 2011 Plans • 20 wells • Re-enter and fracture stimulate Mezardere • Acquire 3D • Maintain production in 2011 * The TBNG acquisition is pending and is expected to close in the second quarter. TransAtlantic will issue 18.5 million shares of common stock for approximately 35% of the acreage and production and may elect to acquire an additional 6.5% for $10 million in cash |
Introduction to Southeast Turkey Paleozoic Trend Syrian Trend Selmo TransAtlantic Application Bakuk Exposure to over 2.1mm and 1.6mm gross/net acres, respectively Southeast Turkey is the northern extension of the Arabian Basin Large anticlines hold large opportunities in Turkey, Syria, and Iraq 26 |
27 Twin of S-04 New/Sidetracked Wells Previous Producers Current Producers SWD SELMO Oil Field (100%) Mar-2011 average: 2760 BOPD WC: 80% 39 producers Upcoming wells to drill Directional Currently Drilling Reserve Summary (MMBbls) Total Proved Probable Possible Rsvs Rsvs Rsvs 12.1 4.7 12.5 Total 16.8 29.3 |
SELMO PRODUCTION History 28 Modest decline on legacy production |
Transitional facies and/or diagenetic boundary MSD LSL LSD ? Garzan Facies and/or diagenetic boundary ? Campanian Unconformity ? ? A Highly Productive Reservoir: SELMO - SINAN RESERVOIR MODEL A Highly Productive Reservoir: SELMO - SINAN RESERVOIR MODEL Hydrothermal Fluids Sucrose Dolomite (hydrothermal origin, saddle dolomite) Sucrose Dolomite (cooled burial fluids) Dolomite, coarse-crystalline, often saddle dolomite, sucrosic; inferred to result from hydrothermal fluids migrating along faults and fractures (Mardin / deeper source?) Dolomite (green), fine-crystalline, early diagenetic/meteoric; bacterial sulfate reduction or shale compaction & Limestone (blue) Grainstone Dolomite, coarse-crystalline, sucrosic; inferred to originate from cooled hydrothermal fluids away from the reservoir entry points/faults Solution caverns, cm to dm size Crackle Network (alteration from dolomitization?) Regional Shear Fractures (strike-slip) Probably Bedding-related Open (vuggy) Fractures (strong calcite growth, origin unknown) Fractures parallel to Thrust-related Folds Thrusting and related Fracturing (Riedel shear) Bedding-related fractures Young Shear Fractures (isolated, sigmoidal) 29 |
Wells are Productive at High Water Cuts SELMO WELLS-CUM. OIL PROD. ABOVE 90%WC Fracture stimulation and gelled acid summary 30 FROM TO S-1 53,888 Nov-98 Jun-02 S-2 1,353,038 Jun-77 Jun-05 S-6 326,853 Oct-74 Aug-89 S-13 285,186 Nov-03 Jan-10 S-15 709,794 Jul-81 Jun-86 Nov-92 Apr-96 S-16 959,880 Mar-82 Mar-92 S-19 182,469 Feb-01 Oct-10 S-20 1,052,375 Jun-87 Feb-07 S-21 522,504 Apr-95 Nov-10 S-23 162,061 Jun-91 Jun-01 S-25 74,135 May-04 Nov-10 S-26 623,406 May-88 Apr-08 S-29 449,571 Jan-91 Jun-08 S-33 56,782 Sep-99 Jul-00 Apr-03 Dec-03 Jun-08 May-09 S-35 111,435 Jun-03 Nov-10 S-37 355,577 Mar-02 Dec-09 S-39 45,054 Feb-03 Jun-04 Total: 7,324,008 bbls Modern Stimulation Enhances Productivity * As of March 16, 2011 Oil Production Rate, BPD Well Operation Before After Current* S-57 Fracture stimulation 0 120 20 S-45ST Fracture stimulation 7 170 120 S-62 Fracture stimulation 82 250 155 S-50A Fracture stimulation 0 25 0 S-56 Gelled acid 0 (new drill) 260 257 S-2 Gelled acid 0 300 275 S-60 Gelled acid 0 (new drill) 300 63 S-71 Gelled acid 0 (new drill) 366 just online |
Much of Future Development will Focus on the MSD, though LSL still has Potential 31 MSD Potential at Selmo 0 10 20 30 40 50 60 70 80 90 100 0.00 0.05 0.10 0.15 0.20 Porosity (RF: 20%) SW=10% SW=20% SW=30% SW=40% SW=50% SW=60% SW=70% SW=80% SW=90% 30 MMSTB MSD cum :9.0 MMSTB Remaining:21.0 MMSTB LSL has also some potential The MSD is largely undeveloped |
Plenty of Drilling Room Beyond 2011 32 |
SELMO LOCATION LAYOUT 33 40 acre spacing Old producing well New infill producing well |
Attractive Economics 34 Per Well CAPEX: $1.35 MM Oil $90 LOE <$13> Transportation <$3> Income Tax <$9> Royalty <$11> $54/ barrel net back 25,00 Barrels to payout MSD with LSD (Gelled Acid Used) Well Name: Selmo-56 Field: Selmo Country: Turkey, District-X Date: 11/19/2010 Classification: PostDrill Est. type Volumetric Formation: MSD+LSL+LSD Perforations: Input parameters Drainage area (acres) 45 Net pay thickness (ft): MSD 42 LSL 0 LSD 10 Bulk volume (acre-ft) 2340 Porosity (%): MSD 9 LSL 0 LSD 5 Water saturation (%) 45 Initial reservoir pressure (psia) 2,610 Reservoir temperature (oF) 160 Oil gravity (oAPI) 34 Formation volume factor (rb/STB) 1.06 Recovery factor 0.20 Output parameters OOIP (STB/ac-ft) 564 OOIP (STB) 1,318,714 EUR (STB/ac-ft) 113 EUR (STB) 263,743 Cum oil (STB) 0 RRR (STB) 263,743 Strategy 2011 Vertically integrated to reduce costs by half Directional drilling (underway) Continuing Fracture stimulation and Gelled Acid program Converting to electricity from diesel will save $1MM/year Year End exit rate 4,000 Bbls/d 24 wells |
Paleozoic Trend 35 |
95,869 acres ARPATEPE LICENCE (50%) 2011 Plan 3D being processed Potential NNE-SSW favorable depositional trends Find more wells like Arpatepe-1, 2, and 3 (400K+ EUR Avg.) 5 wells planned in 2011 Year end exit rate ˜ 600 Bbls/d 36 |
ARPATEPE Field 37 Expected Recovery per 10' of pay Reserve Summary (MMBbls) Total Proved Probable Possible Rsvs Rsvs Rsvs 1.0 1.0 0.7 Total 2.0 2.7 Input parameters Drainage area (acres) 80 Net pay thickness (ft): Bedinan 10' Porosity (%): Bedinan 17% Water saturation (%) 30 Initial reservoir pressure (psia) 3,150 Reservoir temperature (oF) 142 Oil gravity (oAPI) 40 Recovery factor 0.3 Recovery / 10' pay 150,000 barrels |
Are there more wells like the ARPATEPE-1? 7946 7987 2 Dadas Bedinan 8002 8019 7978 8002 7946 7968 7945 -5562 DST-2: 61 bbls 40.9 API OIL T: 142 F OIL: ? OIL: ? OIL: 326 bbls/d 365 bbls /d Well Name: Arpatepe-1 Field: Arpatepe Country: Turkey Date: 12/1/2010 Classification: PostDrill Est. type Volumetric Formation: Bedinan Perforations: Input parameters Drainage area (acres) 80 Net pay thickness (ft): Bedinan 60 Bulk volume (acre-ft) 4800 Porosity (%): Bedinan 17 Water saturation (%) 30 Initial reservoir pressure (psia) 3,150 Reservoir temperature (oF) 142 Oil gravity (oAPI) 40 Formation volume factor (rb/STB) 1.33 Recovery factor 0.30 Output parameters OOIP (STB/ac-ft) 694 OOIP (STB) 3,331,857 EUR (STB/ac-ft) 208 EUR (STB) 999,557 RRR (STB) 999,557 38 |
Arpatepe 3D Coverage: Time Slice @ 1.2 seconds on “Dip of Max Similarity” Attribute 3D Makes a Difference in Finding the Right Spot 39 |
Arpatepe 3D – Inline 2750: PSTM 3D Makes a Difference 40 |
Arpatepe 3D – Inline 2750: 1 st Velocity Stack 3D Makes a Difference 41 |
Arpatepe 2D – ARV-09-02: PSTM 42 Compare to 2D |
43 Syrian Trend Area Bakuk Gas Discovery TransAtlantic 50% interest No oil leg found in re-entry of Bakuk-2 Gas Pipeline to South and North (South pipeline now being tested) 3D acquired on S. Bakuk Next well being planned Modest sales expected in 2011 |
44 Potential Bakuk Pipeline to the North Approximately 50 miles |
License 4642 (Idil) 2D Survey: 110km Ebyat Anticline Midyat Lmst Basalt 45 Syrian Trend |
4350 4273 46 236 kms currently in processing Adana Licenses 2011 Plan • Process 2D (raw stack follows) • Drill 2 wells • Similar to Thrace |
Brute stack 47 |
Brute stack 48 |
Gaziantep Area SE Turkey 49 |
4656 4607 4638 4648 4649 Gaziantep Area SE Turkey SYRIA TURKEY 50 |
51 Gurun License (Central Turkey) Frontier Exploration |
TransAtlantic Turkey Ltd.-SE Turkey Licenses 3969,3970,3971,3972 (Midyat Area) 3971 3972 3970 3969 3118 SYRIA TURKEY ARPATEPE DISCOVERY BAKUK DISCOVERY BATI RAMAN FIELD 500MMBOR RAMAN FIELD 200MMBOR IRAQ TransAtlantic’s Selmo Field 600 MMBOIP “Shell” Trend Souedieh 2 BBOR Karatchok 258 MMBOR Rumilan 111 MMBOR Sazaba 253 MMBOR 52 Midyat Area (Syrian Trend) 500,000 acres |
Midyat-Mardin Uplift-Similarities to other major oil and gas provinces UK North Sea Forties-Montrose High UK North Sea East Central Graben UK North Sea West Central Graben West Texas Central Basin Platform Paleozoic sources Migration into younger Permian carbonates outside of the kitchen United Kingdom North Sea Forties-Montrose High Upper Jurassic source rocks Migration from kitchen into younger Paleocene/Eocene Sandstones 53 |
Tuz Golu Basin 54 |
Tuz Golu Basin-2010 survey TG-2 Post Stack Migration Prospect Area (10 km) Tuz Golu Post Stack Migration 55 |
FRONTIER TERTIARY BASINS Thrace Cum >1 TCFe Sivas 1 Well Malatya No Wells Tuz Golu 56 |
•The Sivas Basin (~8600 sq km)is the same geologic age and formed under similar tectonic settings as the San Joaquin basin (~50,000 sq km). •Both basins are “pull apart” basins related to major active strike slip faults. Sivas Basin 57 |
(50 km/31 miles) Sivas Basin-Turkey License Area-6414 sq km/ 1,584,928 acres 1 well to 3643 meters(Celalli-1; 1965) Basin is up to 10 km deep Thick Sediments(>10km) Thin Sediments(<2km) 58 2011 Plan • Seek Partner • Develop Prospects |
Malatya Basin (716,288 Acres) 59 |
Karaca Anticline Closure=33 sq km/8132 acres Line 1 Line 3 60 2011 Plan • Seeking to Partner • Well likely late in year |
Asilah-1 Asilah-2 Tselfat Acreage Asilah 543,644 Tselfat 111,197 654,841 2011 Plan • Complete GRB-1 and connect and develop if successful • Test HR-33 and possibly develop • Drill 3D prospect TKN-1 next • 2011 CAPEX $10-$17.5 MM 61 Morocco |
Location map of Asilah prospects Gas seep GRB deep GRB shallow Friska Rissana Source Rock GRB-1 well 62 |
63 GRB-1 (Completion Attempt Planned) |
Lower Case surface: 11.2 sq km Mid-Case surface: 15.4 sq km Upper Case surface: 21.5 sq km GRB-1 GRB-1 structure Parameters: (Mid-Case) •Reservoir: Asilah sandstone •Objective: 1850 m • Surface: 15.4 km² •Thickness: 40 m, • Porosity: 10%, •Water saturation 40% • Unrisked potential exceeds 100 bcf • Close to pipeline 64 |
TEKNA-1 GNE-1 Haricha field Boudraa field Tselfat field 65 Tselfat Prospects |
66 Produced 4 mmboe from 1957-1990 from 20 productive wells HR-33 bis drilled to reactivate field Testing now underway 1-2 mmboe potential remaining Haricha Field |
Cross-line 470 showing Tekna-1 and Haricha field Tekna prospect Haricha field SW NE Top of Jurassic Tekna look alike structure… 67 Tekna Prospect (TKN-1) |
Tekna-1 on arbitrary line A NW SE Tekna Prospect … that closes. 68 |
TKN-1 prospect Closure2.4 km2 (590 acres) Unrisked potential 8 mmbbl TKN-2 Proposal location Closure 0.65 km2 (162 Acres) Haricha field Closure 1.3 km2 (321 Acres) Tekna prospect (TKN-1): Next well to be drilled Tekna prospect (TKN-1): Top Jurassic Structure Map with extent to Haricha structure Risks from chances of success Parameters Cos Comments Structure 0.80 Structure and closure well defined using 3D seismic Reservoir 0.60 Exploration zone, small risk to drill Nappe instead of Burdigalian-Dogger reservoirs Seal 1 Proven seal in the area, example Haricha field sealed by Nappe Source rock 0.60 Proven source rock in the area, but HC charge factor not very high in surrounding fields (Haricha, Boudraa and Tselfat) Prospect CoS 0.29 Tekna-1 Chance of Success 69 |
Bulgaria Complementary to operations in Turkey and Romania w/o diverting resources Gas Discovery at Deventci R-1 Minimizes Risk Upside from Etropole Shale and Aglen field re- development Attractive for JV Near term Catalyst with Deventci R-2 “Drill Ready” Attractive fiscal terms promoting development of gas resources End user gas prices approximately $10.00 /mcf Royalty 2.5% - 30% (oil) 2.5% - 30% (gas) Tax 10% Large acreage with gas discovery, field re-development and conventional and unconventional upside Close proximity to the existing Bulgarian gas pipeline system Bulgaria imports ~ 90% of its energy from Russia ’09 Average BOPD Consumption 125k Production 3k Net Imports 122k Crude Oil Consumption vs. Production ’09 Average BCF/d Consumption 0.26 Production 0.02 Net Imports 0.24 Natural Gas Consumption vs. Production 70 |
General location of DPE License Area 71 DPE Bulgaria’s license areas are located in close proximity to the existing Bulgarian gas pipeline system cutting across the southeastern portion of the A-Lovech Block. The block is within driving distance from TransAtlantic’s yard in the Thrace Basin. The oil service industry in Romania provides additional access to services and supplies. The port of Varna on the Black Sea is well placed for the importation of materials as is the Danube River. |
A-Lovech Block (Approximately 600,000 acres) 72 |
Seismic Coverage 73 |
Seismic Type Section Rakita half graben Hydrothermal fluids Carboniferous coals Bachiishte Shale Etropole Shale Aglen Ridge Play Lukovit Prospect Deventci Type Play Ozirovo 74 |
Koynare Production Concession Contingent Resources* for Deventci Area P(90) 92 Bcfe P(50) 245 Bcfe P(10) 586 Bcfe Structure Map on Top of Ozirovo 75 Deventci Discovery (P90) (P10) (P50) Direct Petroleum has completed the filing for the Koynare Production Concession (“KPC”), covering some 160,000 acres on the A-Lovech Block. The KPC is comprised of the primary development area to be known as Deventci and three prospective resource areas along the geological trend as shown above with the brown labels. Final approval of the KPC is expected late in the second quarter. *Resource evaluation was prepared internally by Direct Petroleum and has not been evaluated by a third party reservoir engineer. |
76 Koynare 3D through the Deventci R-1 well Projected area of hydrothermal alteration HTD alteration noted in Deventci R1 High block in Middle Triassic Carbonate with apparent 4-way closure |
Planned Koynare/Aglen Pipeline and Proximity to Existing Infrastructure Discovered Gas fields Known structures to be drilled The historical facilities serving the 2 previously producing wells on Aglen have been abandoned including the original gas plant. A new interconnect to the Bulgarian gas transit system is needed as well as modern production facilities Initial Portion of Koynare Production Concession Aglen Field Redevelopment Project 77 |
Etropole Shale Potential 78 |
Normal pressure gradient 0.097 atm/m Ozirovo to Late Triassic Test Pressure Gradient Map (atm/m) ETROPOLE SHALE POTENTIAL 79 |
Etropole Fm Shipkovo mbr Lopjan or Nefela mbr Ozirovo Fm Bukorovtsi mbr Borima Fm Dolni Lukovit mbr Perfs in Deventci Gas shows Shale potential Etropole Shale Play 80 |
Aglen Field Re-development 81 |
Depth Structure Map – Dolni Dabnik Member Producers (P&A) Reservoir Wet Tested Gas 82 Aglen Field Redevelopment |
Romania Meosian Platform in Southern Romania Map of Sud Craiova Block Cross section between Girlmare 1111 and Oprisoru 1112 within the Sud Craiova Block showing the thickness of the Upper Triassic and Silurian Shale in the NWM. Cross section of the NWM, NCM, SEM and NEM. The variation in depth of the Silurian in the NWM and the SEM is due to development of intra-Moesian faulting across the block. 83 2011 Plan • Silurian shale test • Possible Jurassic oil test • $5-$7.5 MM CAPEX North West Moesian (NWM) North Central Moesian (NCM) South East Meosian (SEM) North Eastern Moesian (NEM) |
Base Silurian Maturity & Depth Contour Map Maturity Window 5000 Depth below surface (m) Sweet spot 84 • Sweet spot area 580,000 acres • 200’ Average thickness • Overpressured • Large potential resource |
Coyote Coyote Prospect 85 Information on cumulative production was obtained from sources outside the company believed to be reliable, including governmental agencies and industry papers. The data is relevant in that the system is believed to truncate on the Sud Craiova Block. |
Bulgarian source basins regional migration is to the north Oil Field Coyote Prospect P50 :closure 1670 acres OGIP : 58 BCF (unrisked) 86 |
Mid Triassic Units NE SW Coyote Prospect Mid Jurassic Units 87 |
Summary 88 South East Turkey |
89 CAPEX US $ MM Thrace $60-$70 Selmo $30 Turkey Other $15 Romania $5-$7.5 Morocco $10-$17.5 Other $5-$10 Total Reserve Growth * DeGolyer and MacNaughton evaluated the Company’s reserves as of December 31, 2010 in compliance with SEC and the Canadian Oil and Gas Evaluators Handbook (“COGEH”) (“51-101”). D&M evaluated reserves at December 31, 2009 (51-101). RPS evaluated reserves at December 31,2008 (51-101) |
Why Reaching 10,000 Boed is important… TransAtlantic at 10,000 boepd net (year end 2011 run rate) Annual Revenue at 45/55 oil/gas mix $238,162,500 LOE at $10/boe -$41,714,286 Cash G&A -$35,000,000 Interest Expense -$15,000,000 Income Tax -$25,000,000 Available Cash for Capex $120,000,000 Assumes $90 oil and $7.50 gas Sources and Uses for 2011 2011 Capex -$140,000,000 Cash at 12/31 $35,000,000 Credit Line Availability* $30,000,000 TBNG increase* $15,000,000 Available Cash for Capex $65,000,000 Ending Cash $5,000,000 * Anticipated availability after redetermination of our Borrowing Base and after inclusion of TBNG in the Borrowing Base (expected mid-year) Can largely self fund 2012 90 2011 Execution Plan Increase production to 10,000 Boepd in Turkey by year end $125 - $150 MM CAPEX in 2011 50% dedicated to Thrace Basin Focus where we have control within our established inventory Emphasize tying in production Development Maximizing returns by reducing drilling and operating costs Pursuing projects that permit development from existing cash flow Exploration Prioritizing opportunities, balancing risk with reward and near-term with longer-term projects Working to reduce costs by utilizing our own quipment Joint Venture Opportunities Seek to lower risk and accelerate activity GOAL Create a fully funded, international, vertically integrated E&P company We can see sufficient liquidity to meet our 2011 CAPAEX program |
TransAtlantic Proved, Probable, Possible Reserves as of December 31, 2010 (SEC Case) Proved Reserves Developed Producing Developed Nonproducing Undeveloped Total Proved Proved plus Probable Proved plus Probable plus Possible Oil and gas Condensate, bbl 4,775 813 7,348 12,936 18,277 31,080 Sales Gas, Mcf 7,820 8,741 5,865 22,425 60,737 234,863 Total boe 6,078 2,270 8,326 16,674 28,400 70,224 Future Capital Cost, U.S. $ (000’s) 0 2,145 78,110 80,255 29,010 228,400 Future Net Revenue, U.S. $ (000’s) 322,562 107,226 387,350 817,138 1,407,181 3,228,267 Present Worth at 10 Percent, U.S. $ (000’s)* 216,695 72,220 247,368 536,283 894,381 1,828,347 Note: Probable and possible reserves have not been risk adjusted to make them comparable to proved reserves. 91 Pre-tax PV10% is considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. Pre-tax PV10% is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future income taxes. We believe pre-tax PV10% is a useful measure for investors for evaluating the relative monetary significance of our oil and natural gas properties. We further believe investors may utilize our pre-tax PV10% as a basis for comparison of the relative size and value of our proved reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our oil and gas properties and acquisitions. However, pre-tax PV10% is not a substitute for the standardized measure of discounted future net cash flows. Our pre-tax PV10% and the standardized measure of discounted future net cash flows do not purport to present the fair value of our proved oil and natural gas reserves. The following is a summary of TransAtlantic’s changes in quantities of proved oil and gas reserves for the year ended December 31, 2010: |
TransAtlantic Petroleum Ltd. Standardized Measure of Oil & Gas Quantities Year Ended December 31, 2010 (Unaudited) The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows (in thousands): Future cash inflows $ 1,197,740 Future production costs (300,347) Future development costs (80,255) Future income tax expense (143,000) Future net cash flows 674,138 10% annual discount for estimated timing of cash flows (235,771) Standardized measure of discounted future net cash flows related to proved reserves $ 438,367 A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves is as follows (in thousands): Balance, beginning of period $ 250,009 Net change in sales and transfer prices and in production (lifting) costs related to future production 53,003 Changes in estimated future development costs (63,040) Sales and transfers of oil and gas produced during the period (50,033) Net change due to extensions and discoveries 11,321 Net change due to purchases of minerals in place 79,478 Net change due to revisions in quantity estimates 121,101 Previously estimated development costs incurred during the period 29,659 Accretion of discount 31,249 Other 7,471 Net change in income taxes (31,851) Balance, end of period $ 438,367 92 * Note: This Standardized Measure of Oil and Gas Quantities is unaudited and remains subject to changes which could be material. |
2011 Calendar Catalysts 93 Thrace Basin • Fracture Program • Continue shallow low risk drilling program • • YE production 35-40 mmcf/d Selmo • Bopd YE SE Turkey • Tselfat • Testing the HR-33 bis • Drilling TKN-1 Asilah • GRB -1 well completion • Evaluating the Silurian Shale and possiible Jurassic Oil Play • • Q2 Q 4 Q 3 Q1 ‘12 Complete pipelines to bring shut-in gas to market Continue with drilling program, with 2 rigs 4,000 Arpatepe drilling Drill the Deventci R-2 well Possible Aglen Well |
Appendix South East Turkey 94 |
95 Exchange / Ticker NYSE-AMEX / TAT Toronto / TNP Market Capitalization (1) $1.02 billion Shares outstanding (2) Float 336.34 MM 150 MM Shareholder Breakdown Institutional: Retail: Directors & Officers: 27% 24% 49% 52-week High Low $4.10 $2.68 Average volume (3 months) 1,197,020 (1) As of April 7, 2011closing stock on the NYSE-AMEX price $3.04 (2) As of 9/30/10 |
Morocco’s Energy Profile Crude Oil Consumption vs. Production Wells 168 105 74 75 14 26 ’09 Average BOPD Consumption 187.0k Production 0.4k Net Imports 186.6k BOPD 0000 Area 446,550 km² Comparative Area Slightly larger than California ‘09 Population Est. 31.3 mm ’09 GDP (Nominal) $88.9 billion Fitch Sovereign BBB- with stable outlook Risk Rating ‘09 Proved Reserves 750k BBLS / 53 BCF ‘09 Daily Consumption 187k BOPD ‘09 Daily Production 0.5k BOPD Royalty 10% (oil), 5% (gas) Tax 10-year tax holiday, then 30% Oil is sold at world market prices Gas is deregulated for end user sales, regulated if sold to the Moroccan government for power generation 96 Onshore Drilling History – Morocco Is Underexplored Source: IEA, CIA - The World Fact Book, and IHS |
Turkey’s Energy Profile Crude Oil Consumption vs. Production 000 BOPD BCF/d Natural Gas Consumption vs. Production ’09 Average BOPD Consumption 580k Production 53k Net Imports 527k ’09 Average BCF/d Consumption 3.39 Production .08 Net Imports 3.29 Area 783,562 km² Comparative Area Slightly larger than Texas ‘09 Population Est. 76.8 million ’09 GDP (Nominal) $617.1 billion Fitch Sovereign BB, with positive outlook Risk Rating ’09 Proved Reserves 0.3 billion BBLS / 300 BCF ‘09 Daily Consumption 580k BOPD / 3.39 BCF/d ‘09 Daily Production 53k BOPD / .10 BCF/d ‘09 Gas Import Partners Russia (74%), Iran (21%) Royalty 12.5% Tax 20% Gas is currently priced at ~ $8/MCF, BOTAS Oil is sold at world market prices Investment in Turkey increasing: Chevron Exxon Mobil Petrobras 97 Source: IEA, CIA - The World Fact Book, and IHS |
Thrace Basin Geologic Section THRACE BASIN GENERALIZED STRATIGRAPHY After, Huvaz, AAPG Bulletin, v. 89, no. 10 (October 2005), pp. 1373–1396 98 |
Romania’s Energy Profile Area 238,391 km² Comparative Area Slightly larger than Oklahoma ‘09 Population Est. 22.2 million ’09 GDP (Nominal) $161.5 billion Fitch Sovereign BB+ with stable outlook Risk Rating ‘09 Proved Reserves 0.6 billion BBLS / 2.2 BCF ‘09 Daily Consumption 214k BOPD / 1.63 BCF/d ‘09 Daily Production 117k BOPD / 1.10 BCF/d Royalty 3.5% - 13.5% (oil) 3.0% - 13.0% (gas) Tax 1-year tax holiday, then 16% Oil is sold at world market prices Gas is deregulated; priced at 80% of imported price (Gazprom) Crude Oil Consumption vs. Production 000 BOPD EU Member Natural Gas Consumption vs. Production BCF/d ’09 Average BCF/d Consumption 1.63 Production 1.10 Net Imports 0.53 ’09 Average BOPD Consumption 214k Production 117k Net Imports 97k 99 Source: IEA, CIA - The World Fact Book, and IHS |
Bulgaria’s Energy Profile Crude Oil Consumption vs. Production 000 BOPD EU Member Natural Gas Consumption vs. Production BCF/d ’09 Average BOPD Consumption 125k Production 3k Net Imports 122k ’09 Average BCF/d Consumption 0.26 Production 0.02 Net Imports 0.24 Area 110,879 km² Comparative Area Slightly larger than Tennessee ‘09 Population Est. 7.58 million ’09 GDP (Nominal) $50.6 billion Fitch Sovereign BBB Stable Risk Rating ‘09 Proved Reserves 15 million BBLS / 0.55 BCF ‘09 Daily Consumption 125k BOPD / 0.33 BCF/d ‘09 Daily Production 3.2k BOPD / 0.02 BCF/d Royalty 2.5% - 30% (oil) 2.5% - 30% (gas) Corporate Tax 10% Oil is sold at world market prices Oil and Gas imports from Russia Only 10% demand met by domestic supply 100 Source: IEA, CIA - The World Fact Book, and IHS |
Description of Bulgarian Licenses R-Factor DPE has run economic calculations on the royalty percentages for ranges of “R.” These are guidelines only as actual percentages are determined by the Production Concession Bonuses: No bonuses paid during production concession Taxes: Income tax of 10% Royalty - 1.50 2.50% 1.50 1.74 5.00% 1.75 1.99 10.00% 2.00 2.49 12.50% 2.50 2.99 22.50% 3.00 10.00 30.00% R-Factor Range 101 License Holder: DP Bulgaria (100%) Term & Work Program: Prospecting and Exploration Permit for A-Lovech Block • Appraisal extension granted till end of November, 2011. • Each commercial discovery within the block can hold the entire geological trend portion of the block by converting into long term Production Concession. • Application for the Koynare Production Concession was made on 11 November 2010. • Exploration Permit for Aglen Block • Primary term with extensions through April 2014. • Initial work commitments for first 3 years have been fulfilled. • Commitment to drill 2 wells (2,500 meter minimum) in years 4-7 (2010 thru 2014). have a primary term of 35 years with a possible 15 year extension. Royalty:State of Bulgaria Based on “R” factor and calculated by: R=TCR/TCC, where: • TCR is the amount of the total cumulative revenues from the work, connected to the object of concession, for all periods under review, where the paid concession remuneration is deducted • TCC is the amount of total cumulative costs for the work connected to the object of concession (exploration, prospecting, valuation, exploitation, development) for all periods under review. Production Concessions |
HTD found in the Deventci well Etropole Fm Bachiishte Fm Carboniferous coal Bulgarian Stratigraphic column 102 |
Hydrothermal Dolomite - A Major Reservoir Type for Bulgarian Licenses Thin Section showing Extensive Porosity in Triassic HTD Zebra Fabric in Triassic HTD Reservoir from the Aglen Field Porosity (blue) Saddle Dolomite Fracturing Pyrobitumen (black) coating porosity 500µm Note: the thin section to the left is not from the core shown above but rather from the Triassic reservoir in the Gorni Dabnik field to the north. 103 • Hydrothermal Dolomite (“HTD”) is a significant reservoir type recognized world-wide as being a major contributor to giant hydrocarbon accumulations including Ghawar and Tengiz. • These types of reservoirs are high quality due to the fractures, vugs and general high porosity inherent in HTD (see graphic lower left). • The most common characteristic is the formation of large dolomite crystals sometimes referred to a “Saddle Dolomite” a phrase coined by the Canadian geologists who did some of the early work on these lithologies. • HTD also is often accompanied by the formation of sulfide minerals including pyrite and other minerals common to lead- zinc deposits. Also common is the appearance of pyro-bitumen coating the pore throats. This gives HTD its common “Zebra fabric” of alternating bands of white dolomite crystals and dark pryo-bitumen (see graphic in lower right). • The seismic expression of the dolomite can take two different paths: • Identification of the fault systems through which the hydrothermal fluids move from deeper sources, and; • In some cases, the HTD presents itself on seismic in the form of disrupted reflectors and changes in amplitudes indicating a change in the character of the rock due to the alteration of the original limestone to dolomite. |
This diagram, excerpted from the seminal paper on Hydrothermal Dolomite by Taury Smith and Graham Davies, is provided to show how hydrothermal dolomite forms in the presence of fractures and faults. Of special note is the vertical distribution of alteration zones along with a horizontal separation between these alteration zones. From G. Davies and L Smith 2006 104 Geometries of Hydrothermally Altered Reservoirs |
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