TransAtlantic Petroleum (TAT) 8-K Applying old lessons to new frontiers

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

Thank You