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UNLOCKING TURKEY’S TIGHT GAS POTENTIAL CORPORATE PRESENTATION MARCH 2015

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Corporate Profile Valeura Energy Inc. (VLE – TSX) is a Canada-based oil and gas company with assets in

Turkey

Interests in 21 leases & licences in Turkey: 1.0 MM acres (gross); 0.42 MM acres (net) (1)

Focused on development of conventional gas & tight gas in the Thrace Basin

Applying latest 3D seismic, horizontal drilling & multi-stage frac technologies

Pursuing new 3D seismic & drilling strategy on 100% owned Banarli licence in 2015

Q4 2014 sales in Turkey 1,180 boe/d, up 18% from Q3 2014:

− 7.0 MMcf/d (net) in Turkey at average natural gas price realization of $10.62/Mcf

− Average operating netback $46.22/boe (2)

Significant discovered resource base in Turkey:

− 2P reserves 5.8 MMboe (company gross) at YE 2014 (3)

− 2C contingent resources 108.7 MMboe (company gross) at YE 2012 (3)(4)

Turkey 1P and 2P reserves value $40 MM ($0.68 per share) and $108 MM ($1.86 per share), respectively, at YE 2014 (NPV10 before tax) (3)(5)

$10.0 MM working capital surplus at YE 2014; no debt (1) As at February 28, 2015, reflecting interim conversion status of existing licences to new licences and leases under terms of the new Petroleum Law adopted in May 2013. (2) See Slide 28 "Reader Advisories – NON-IFRS MEASURES". (3) See Slide 28 "Reader Advisories – D&M RESERVES AND RESOURCES DISCLOSURE". (4) See Slide 28 "Reader Advisories – CONTINGENT RESOURCES". (5) Based on a $Cdn/$US exchange rate of 0.86 at December 31, 2014 to convert US$ denominated reserves values in the 2014 D&M Reserves Report.

Basic shares outstanding at March 1, 2015 57,906,135

Common shares purchasable pursuant to outstanding:

Financial warrants ($5.50 exercise price per share) 13,269,217

Options ($0.82 weighted average exercise price per share) 3,174,000

Fully diluted shares 74,349,352

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Capital Structure March 1, 2015

Retail ~ 64%

Institutions ~ 30%

Management & Directors

5.9% (7.4% FD)

Q4 2014 Financial & Operating Highlights (1)

RESULTS

3 MONTHS ENDED

DEC 31, 2014

3 MONTHS ENDED

SEPT 30, 2014

YEAR ENDED

DEC 31, 2014

Production

Crude oil & NGLs (bbl/d) 10 7 8

Natural gas (Mcf/d) 7,022 5,943 6,812

boe/d 1,180 997 1,143

Financial (Canadian $ M, except per boe amounts)

P & NG revenues (net) 6,921 5,330 24,998

Funds flow from operations (2) 3,654 3,011 13,586

Net income/(loss) 697 (171) 1,090

Capital expenditures (net) 2,822 2,515 10,846

Average operating netback ($/boe) (2) 46.22 43.85 45.01

Net working capital surplus 10,044 9,865 10,044

Cash & cash equivalents 5,928 5,974 5,928

(1) The above table includes figures from continuing operations in Turkey only. Prior period figures have been reclassified to remove discontinued operations in Canada. See Valeura’s most recent MD&A for further discussion on discontinued operations.

(2) See Slide 28 "Reader Advisories – NON-IFRS MEASURES".

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Why Turkey?

Prospective

Proven petroleum systems

Under-explored & under-exploited conventional & unconventional plays

Opportunity to deploy modern technology

Thrace Basin main gas producing region

Anatolia Basin main oil producing region

Major IOCs returning to Turkey (offshore; onshore unconventional)

Positive Business Environment

G-20 country, NATO member and democracy with moderate Islamic party in power

Attractive royalty (12.5%) & corporate tax (20%)

New Petroleum Law passed May 30, 2013 (removes restrictions on maximum acreage holdings; conversion of some existing licences & award of new leases under new terms progressing)

Available infrastructure & oil field equipment

Heavily reliant on imports of oil & gas

Strong product pricing linked to world oil prices & Russian gas prices

Energy corridor to Europe from Middle East, Russia and neighbouring countries

Thrace Basin (natural gas)

TBNG-PTI Acquisition opportunity

TBNG-PTI acquisition (natural gas & light/medium oil)

Anatolian Basin (medium oil)

Turkey YE 2014 Reserves (Company Gross) (1)

5% and 9% year-over-year increase in 1P and 2P reserves, respectively, in Turkey

Primarily natural gas reserves in Thrace Basin on TBNG-PTI JV lands (Valeura 40% WI) and Edirne Licence (Valeura 35% WI)

Growth in reserves driven by:

− Conventional gas discoveries

− Additional tight gas drilling

Turkey reserves values (NPV10 before tax) at YE 2014 (1)(2)(3)

− 1P $40 MM or $0.68 per share

− 2P $108 MM or $1.86per share

− 3P $192 MM or $3.32 per share

(1) See Slide 28 "Reader Advisories – D&M RESERVES AND RESOURCES DISCLOSURE". (2) See Slide 28 "Reader Advisories – FUTURE NET REVENUE". (3) Based on a $Cdn/$US exchange rate of 0.86 at December 31, 2014 to convert US$

denominated reserves values in the 2014 D&M Reserves Report.

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YE RESERVES

0

2

4

6

8

10

12

14

2013 2014

Possible

Probable

Proved

10.3

5.3

1.6

10.4

5.8

1.7

MMboe

2P

3P

1P

7

Thrace Basin Transactions (1)

3934

4126

3858 3860 3931

3861

3659 5122

50 km

Bulgaria

Turkey

Greece

2010 Otto asset purchase (Edirne) (Valeura 35% WI)

2011 TBNG-PTI acquisition (Valeura 40% WI onshore; Valeura 15% WI offshore)

2926

Black Sea

Sea of Marmara

2013 Banarli licence award

(Valeura 100% WI)

5104

5151

5147

2013 Copkoy licence award

(Valeura 100% WI)

F18-c4-2

F18-c3-1

F19-d4-1

F19-d4-2

E17-c1-1 E17-c2-1

E17-b4-1

(1) New production leases issued to date by the GDPA upon conversion of all or part of some old exploration licences under the New Petroleum Law are shown in the red outline.

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I-8 Rig Drilling at TDR-9

TBNG-PTI JV (Valeura 40% WI - Non-Operated)

9

TBNG-PTI JV

Interests in 14 leases & licences in Thrace Basin (0.51 MM gross acres onshore)

Established shallow gas production and marketing business:

- ~65 producing wells (gross) in 15 gas fields in onshore lands

- Owned compression facilities & distribution lines

- Direct sales to 50+ commercial & end user customers

- Pursuing workovers, recompletions and selective re-entry fracs on existing wells and drilling selectively on new 3D seismic acquired in 2011 and 2013

Exposure to a significant tight gas resource play in the Thrace Basin in deeper sands in the Mezardere, Teslimkoy and Kesan Formations:

- Applying multi-stage fracture stimulation technology, and deeper vertical and horizontal drilling

Large discovered natural gas resource base:

- 2P reserves 84.7 Bcf (TBNG-PTI JV gross); 33.9 Bcf (Valeura gross) at YE 2014 (1)

- 2C contingent resources 1,676 Bcf (TBNG-PTI JV gross); 652 Bcf (Valeura gross) at YE 2012 (2)

Q4 2014 gas sales 17.3 MMcf/d (gross) & 6.9 MMcf/d (net):

− $10.64/Mcf average natural gas price realization in Q4 2014

(1) See Slide 28 "Reader Advisories – D&M RESERVES AND RESOURCES DISCLOSURE". (2) See Slide 28 "Reader Advisories – CONTINGENT RESOURCES".

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TBNG-PTI JV Shallow Gas Business 2013 shallow gas program:

− Spudded 1 new drill (evaluating) − Completed 14 workovers (11.0 MMcf/d aggregate initial 7-day rate (1)); 3 well re-entry fracs − Acquired 232 km2 of new 3D seismic in Osmanli area

2014 shallow gas program:

− Spudded 1 sidetrack & 5 new drills on Osmanli 3D seismic (5 producing; 1 evaluating) − Completed 21 workovers (9.3 MMcf/d aggregate initial 7-day rate (1)); 2 well re-entry fracs

2015 YTD shallow gas program:

− Completed 3 workovers (1.3 MMcf/d aggregate initial 7-day rate (1)) − Spudded 1 new drill on Osmanli 3D seismic (producing)

(1) See Slide 28 "Reader Advisories – INITIAL ON-STREAM PRODUCTION RATES".

Atakoy

10 km

5122

Osmanli

Kazanci/ Hayrabolu

Gurgen

Kayi

Yagci/ Nusratli

Aydede

Tekirdag Gazi

Bekirler

Kilavuzlu/ Karaevli

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Osmanli Area Conventional Gas Drilling

Seven (gross) conventional gas wells drilled on merged Osmanli & Tekirdag 3D seismic targeting Osmancik formation (also Mezardere formation in Dogu Osmanli-1)

WELL WELL TYPE TD (m)

NET PAY (m)

POROSITY (%)

IP30 RATE (MMcf/d) (gross) (1)

STATUS MARCH 10, 2015

Biyikali-2ST Exploration 900 5 24 0.8 Producing

Gurgen-1 Exploration 2,100 57 17 3.3 Producing

Tavanli-1 Exploration 1,300 9 24 1.4 Producing

Guney Osmanli-3 Development 1,080 6 22 0.7 Producing

Dogu Osmanli-1 (2) Exploration 2,100 6 12 Nil Evaluating

Gurgen-2 Appraisal 2,000 52 17 3.3 Producing

Gurgen-3 Appraisal 1,803 18 18 1.1 Producing


Yagci

Osmanli

Kayi

Banarli 5104

3931

Gurgen-1

Tavanli-1

Dogu Osmanli-1

Biyikali-2 ST

Guney Osmanli-3

Tekirdag

Karaevli

Gazi

3934

5 km

Merged Osmanli & Tekirdag 3D seismic

area

New drills

Mezardere Depth Structure

Gurgen-2 Gurgen-3

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TIGHT GAS

Mezardere, Teslimkoy & Kesan

50 well re-entry fracs since mid-2011

20 new drills in 2012-2015 YTD (14 vertical & 6 horizontal) of which 18 fracked

SHALLOW GAS

Danismen & Osmancik

5 re-entry fracs since mid-2011 (Osmancik)

54 workovers & 17 new drills in 2012-2015 YTD

Recent Osmancik discoveries in Osmanli area indicate new play type potential

TBNG-PTI JV Shallow Gas & Tight Gas Plays

ND-1 Aydede-1 Inecik-2

Akcahalil-1 TDR-2 YAGCI-8 TS-18 DTD-1 KAYI-7 BATI KARAEVLI-1

BATI GAZI-1

DANISMEN

OSMANCIK

MEZARDERE

TESLIMKOY and

KESAN

50

0 m

50 km

CEYLAN

SOUTHWEST NORTHEAST

PERFED ZONE

Gamma Ray

Total Gas

1. Recompletion fracs (750-2,000 m depth)

− Identify gas bearing zones in Mezardere, Teslimkoy & Kesan formations that require fracs to achieve commercial rates focusing initially on areas within structural closure

− Initiated new Mezardere laminated sand/shale play in Q2 2013

− 55 re-entry fracs: 8 in H1 2011; 16 in 2012; 25 in 2013; 6 in 2014

2. Drill & fracs (1,500-4,054 m depth)

− Deeper unconventional drilling on new 3D seismic on existing structures

− 11 unconventional wells spudded in 2012: 10 producing; 1 evaluating

− 6 unconventional wells spudded in 2013: 5 producing; 1 evaluating

− 3 unconventional wells spudded in 2014: 3 producing

− 5 new unconventional wells fracked in 2012



3. Multi-stage fracs in vertical wells

− 22 multi-stage fracs completed since mid-2011

4. Multi-stage fracs in horizontal wells

− 6 horizontal wells drilled in 2013 & 2014: 6 completed with multi-stage fracs

5. Explore for potential pervasive gas outside structures and in deeper formations

− Drilled 4,054 m exploration well at Hayrabolu (evaluating possible fracking)

TBNG-PTI JV Tight Gas Proof-Of-Concept Program Phases

13

1.7

4.5

5.35.8

YE 2011 YE 2012 YE 2013 YE 2014 YE 2012

108.7

593

15131767

14861245

1059 924774 797

9511135 1268

1115 9901170

THRACE BASIN Program

NATURAL GAS PRODUCTION boe/d (net)

2P RESERVES / 2C CONTINGENT RESOURCES (3)(4)

MMboe (net)

Thrace Basin Tight Gas Learning Curve 2011 – 2014

Cumulative funds flow from operations (2)

≈ $55MM (net)

Cumulative capex (1) ≈ $64MM (net)

Shallow gas decline

Tight gas growth

(1) Excludes $53.7MM acquisition cost. (2) See Slide 28 "Reader Advisories – NON-IFRS MEASURES". (3) See Slide 28"Reader Advisories – D&M RESERVES AND RESOURCES DISCLOSURE". (4) See Slide 28"Reader Advisories – CONTINGENT RESOURCES".

GROW

CONVERT RESOURCES TO RESERVES

Exploration3 OSMANLI

DISCOVERIES

5 OSMANCIK

Horizontal Drills

& Fracs

Vertical Drills &

Fracs12 VERTICAL TESLIMKOY/KESAN DRILL & FRACS

Studies 413KM2 3D SEISMIC CORE WORK: BAGLIK-1, HAYRABOLU-10232KM2 3D

SEISMIC

6 Hz MEZ/TES/KESAN DRILL & FRACS

Re-Entry Fracs 31 TESLIMKOY/KESAN 19 MEZARDERE

DEVELOP

TBNG ACQ.

20142011 2012 2013

14

2P 2C

Teslimkoy/Kesan Multi Frac Type Curves (Vertical Wells) (1)(2)

15

(1) Refers to "type curve" forecasts developed by D&M to project well production rates and 2P reserves/well as at December 31, 2014 in their reserves report dated March 10, 2015 for vertical multi frac tight gas wells associated with the Tekirdag development area.

(2) 2P refers to Proved + Probable.

0

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80

100

120

0

100

200

300

400

500

600

700

800

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1000

1100

1200

0 12 24 36 48 60 72 84 96 108 120 132 144 156 168 180 192 204 216

CUM

MU

LATI

VE

RECO

VER

Y -%

OF

EUR

PRO

DU

CTIO

N R

ATE

-Mcf

/d

MONTHS

Type Curve - Vertical Wells

D&M Vertical Well, 2P - 0.8 Bcf, Rate vs. Time

D&M Vertical Well, 2P - 0.8 Bcf, Cum. Recovery vs. Time

Mezardere Multi Frac Type Curve (Horizontal Wells) (1)(2)

16

(1) The Valeura HZ Type #2 “type curve” forecast is based on average performance of Teslimkoy horizontal wells BTD-4H and BTD-5H that have been on production for 17 months and 14 months as of March 1, 2015, respectively.

(2) The D&M Teslimkoy Hz “type curve” forecast was developed by D&M to project well production rates and 2P reserves/well as at December 31, 2014 in their reserves report dated March 10, 2015 for Teslimkoy horizontal tight gas wells associated with the Tekirdag development area.

0

20

40

60

80

100

120

0

500

1000

1500

2000

2500

3000

0 12 24 36 48 60 72 84 96 108 120 132 144 156 168 180 192 204

CUM

MU

LATI

VE

RECO

VER

Y -%

OF

EUR

PRO

DU

CTIO

N R

ATE

-Mcf

/d

MONTHS

Type Curve Comparisons - Horizontal Wells

VLE HZ Type #2, Reserves - 1.0 Bcf, Rate vs. Time

D&M Teslimkoy Hz, 2P - 1.35 Bcf, Rate vs. Time

VLE HZ Type #2, Reserves - 1.0 Bcf, Cum. Recovery vs. Time

D&M Teslimkoy Hz, 2P - 1.35 Bcf, Cum. Recovery vs. Time

Tekirdag Area Horizontal Drilling (1)

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BTD-3

1st HZ well DTD-19H U. Kesan

425 m lateral 7-stage frac

IP30 rate 0.4 MMcf/d

2nd HZ well BTD-4H Teslimkoy



3rd HZ well BTD-5H Teslimkoy



4th HZ well BTD-2H Mezardere



BTD-5

TDR-14

Baglik-1

DTD-19

5th HZ well TDR-11H Mezardere



400 m

400 m

DTD-6

6th HZ well TDR-5H Teslimkoy



Tekirdag Area 2011-2014 Mezardere/Teslimkoy/Kesan Frac Results & Potential Vertical Well Development (1)(2)

Vertical stacking of Mezardere, Teslimkoy & Kesan sands (>75 locations @ 40 acre spacing)

Exploit with multi-stage fracs

400m X 400 m 40 acres

Mezardere Re-entry Fracs Teslimkoy Producers Upper Kesan Producers Mezardere/Teslimkoy/Kesan Potential Locations

KAYI-14 5.0 MMcf/d

TDR-14 0.75 MMcf/d

TDR-2 0.6 MMcf/d

TDR-4 1.6 MMcf/d

TDR-7 0.16 MMcf/d

TS-18 1.0 MMcf/d TDR-8

0.8 MMcf/d

ND-3 1.2 MMcf/d

Yagci-5 0.9 MMcf/d

BTD-5 1.4 MMcf/d

TDR-5 3.0 MMcf/d

BTD-2 4.3 MMcf/d

BTD-4H 3.3 MMcf/d

BTD-3 1.8 MMcf/d

DTD-6 2.1 MMcf/d

DTD-19H 0.6 MMcf/d

DTD-19 0.7 MMcf/d

Baglik-1 2.9 MMcf/d

DTD-7 0.4 MMcf/d

DTD-4 1.3 MMcf/d

(1) Rates shown are initial peak 24-hour on-stream rates . See Slide 28 "Reader Advisories – INITIAL ON-STREAM PRODUCTION RATES". (2) See Slide 28 "Reader Advisories – DRILLING LOCATIONS".

KAYI-14 5.4 MMcf/d

KAYI-6 0.9 MMcf/d

KAYI-12 1.6 MMcf/d

Yagci-6 0.5 MMcf/d BTD-5H

2.3 MMcf/d

Guney Kayi-1 1.8 MMcf/d KAYI-7

3.4 MMcf/d

DTD-11 1.5 MMcf/d

Kayi Derin-1 0.7 MMcf/d

18

BTD-2H 2.3 MMcf/d

TDR-9 0.6 MMcf/d

TDR-11H 2.0 MMcf/d BTD-1

1.2 MMcf/d

KAYI-16 0.9 MMcf/d

TDR-5H 2.0 MMcf/d

Potential Mezardere Play Fairway

19

Alacaogl

u

Mezarder

e Kitchen

Base Mezardere Depth Structure

Tekirdag

10 km

Prospective Mezardere

play fairway

5104

Tekirdag area Mezardere

exploitation program

Hayrabolu

New slope fan play in Mezardere Formation showing encouraging results

Tekirdag area Mezardere exploitation program (500 – 1,500 m depth); area 250 km2

− 19 well re-entry fracs completed in 2013 and 2014

− 1.1 MMcf/d/well average IP30 rate for 15 wells (1)

− 30+ recompletion candidates identified

− 2 Mezardere horizontal wells drilled and fracked in 2014

Basin fairway (500 – 4,800 m depth); area 3,800 km2

Plan to also test Mezardere in Hayrabolu-10 well in deeper part of basin


27

I-8 Rig Drilling at TDR-9

Banarli Licence (Valeura 100% WI - Operated)

20

Banarli Seismic Acquisition – June 2013

21

Potential Basin-Centered Gas Play Fairway

Banarli licence awarded to Valeura (100% WI) in April 2013 (480 km2; 185 square miles; 185 sections)

Potential basin-centered, over-pressured, pervasive gas play in deepest part of basin where Mezardere shale may be in active hydrocarbon generating "kitchen" below 2,500 m

Recent Osmancik drilling success at Osmanli has led to new Banarli strategy to pursue shallow horizon (2,500 m) on a 100% basis and fund up to 150 km2 of 3D seismic & up to 3 exploration wells in 2015

15+ leads identified on 92 km of new 2D seismic (June 2013) merged with >200 km of vintage 2D

Application submitted to GDPA to convert Banarli licence to new licencing regime, which could be approved by mid-2015, thereby extending initial term to 5 years & deferring drilling to late 2015

Seeking partner to fund deep exploration; Moyes & Co. assisting farm-out process

Alacaogl

u

Mezarder

e Kitchen

Base Mezardere

Depth Structure

Tekirdag

10 km

Kazanci-5

Mezardere Potential

kitchen area

Hayrabolu-10 5104

Temrez

Banarli

Gurgen-1

Recent Osmancik & Mezardere Results & Potential Extension of Play Types into Banarli

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(1) Rates shown are IP30 rates for fracked Mezardere ("Mez") or Teslimkoy ("Tes") formation completions and un-fracked Osmancik ("Osm") formation completions. See Slide 28 "Reader Advisories – INITIAL ON-STREAM PRODUCTION RATES".

Kayi-7 IP30: 2.6 MMcf/d (Mez)

Kayi-14 IP30: 4.1 MMcf/d (Mez) IP30: 3.2 MMcf/d (Tes)

Hayrabolu-10

TDR-5H1 IP30: 1.3 MMcf/d (Tes)

IP30 rates (1)

2014/15 new drills

Banarli exploration

leads on 2D seismic

Guney Osmanli-3 IP30: 0.7 MMcf/d (Osm)

Biyakili-2ST IP30: 0.8 MMcf/d (Osm)

BTD-2H IP30: 1.5 MMcf/d (Mez)

Tavanli-1 IP30: 1.4 MMcf/d (Osm)

Planned 3D: 150 km2

Gurgen-1 IP30: 3.3 MMcf/d (Osm)

Gurgen-2 IP30: 3.3 MMcf/d (Osm)

Gurgen-3 IP(30): 1.1 MMcf/d (Osm)

Dogu Osmanli-1 Cased (Mez)

TDR-11H IP30: 1.3 MMcf/d (Mez)

Banarli

Potential Pressure

Seal

Robust Netbacks & Competitive Costs Drive Attractive Natural Gas Economics in Turkey

Operating Netbacks – $/boe (1)

(1) See Slide 28"Reader Advisories – NON-IFRS MEASURES". (2) Vertical well: 2,000 m TD; tie-in to new facilities (e.g. Banarli) (3) Typical re-entry fracs in Mezardere Formation. (4) Vertical wells: 1,400 m TD; four-stage frac; tie-in to existing facilities. (5) Horizontal wells: 1,000 m TVD (Mezardere); 800 m lateral length; 10-

stage frac; tie-in to existing facilities.

CURRENT FUTURE

POTENTIAL

CONVENTIONAL GAS VERTICAL WELL (2)

Drill & Case 1.7 1.7

Tie-in (new facilities) 0.5 0.5

Total 2.2 2.2

TIGHT GAS RE-ENTRY FRAC (3)

Single-stage Frac 0.5 0.5

TIGHT GAS VERTICAL WELL (4)


Multi-stage Frac & Tie-in 1.4 1.3

Total 2.2 1.8

TIGHT GAS HORIZONTAL WELLS(5)


Multi-stage Frac & Tie-in 1.3 1.3

Total 2.4 2.1

Cost Structure – US$MM (gross)

23

29.06

38.9543.62 45.01

6.78

7.85

10.02 6.81

5.53

7.27

8.368.10

0

10

20

30

40

50

60

70

2H 2011 Avg 2012 2013 2014

Royalty

Opex

Netback

Sales Price

41.36

54.07

62.00 59.92

24

PROGRAM

PHYSICAL PARAMETERS PER WELL ECONOMICS PER WELL – BEFORE TAX (5)

RESERVES (2)

(Bcf) IP30 (3)

(MMcf/d) CAPEX (4)

(US$MM) IRR

(%) PAYOUT

(MONTHS) NPV10 (6)

(US$MM)

RECYCLE RATIO (7)

Thrace Basin - Gas

Shallow Gas Drilling (500 m) with Tie-in to Existing Facilities

0.3 0.8 0.8 >100 8 1.0 2.5

Shallow Gas Drilling (2,000 m) with Tie-in and New Facilities (2,000 m) 1.3 2.2 2.2 >100 8 5.1 3.9

Tight Gas Well Re-Entry Frac 0.1 0.8 0.5 80 7 0.2 1.5

Tight Gas Vertical Drilling & Multi-Stage Frac with Tie-in and New Facilities

0.8 0.9 2.2 >100 22 1.5 2.4

Tight Gas Horizontal Drilling & Multi-Stage Frac with Tie-in to Existing Facilities

1.0 2.3 2.4 >100 10 2.7 2.8

Turkey Natural Gas Indicative Well Economics (1)

(1) This chart illustrates potential well economics assuming the physical parameters per well set forth above, including reserves, initial production and capital costs. This is not intended to be an estimate of future well results. The reserve amounts set forth above are for illustrative purposes and are not indicative of, and should not be interpreted as, estimates of existing reserves or resources. Valeura's actual well economics, including the amount of any oil or gas resources which are capable of being economically recovered, production rates, costs and expenses, may differ materially from those set forth above.

(2) Assume 40 acre drainage area for vertical gas wells and 80 acre drainage area for horizontal wells. (3) Valeura’s type curves for new drills reflect IP30 sales rates as shown for the various well types and up to a 75% decline rate in the 1st year. Type curves utilized for illustrative

economics include: vertical well - D&M 2P curve; horizontal well - Valeura HZ Type #2 (per Slides 15 &16). (4) Targeted cost (per Slide 23) to drill, complete and equip a vertical well to the following TD: shallow conventional gas 500 m or 2,000 m; tight gas 1,400 m completed with a 4-

stage frac. Targeted cost to drill, complete and equip a horizontal well to a TVD of 1,000 m and an 800 m horizontal lateral completed with a 10-stage frac. (5) Utilizing the following natural gas price deck: US$9.10/Mcf in 2015 and 2016, escalated 2%/year thereafter per 2014 D&M Reserves Report. (6) See Slide 28 "Reader Advisories – FUTURE NET REVENUE". (7) See Slide 28 "Reader Advisories – RECYCLE RATIO". First year operating netback based on: 12.5% government royalty + 1% gross overriding royalty on TBNG-PTI JV lands;

operating costs: Shallow gas and re-entry frac – US$0.90/Mcf + US$2,500/well month; tight gas - US$1.00/Mcf + US$3,500/ well month. F&D cost includes front end capital only.

25

Turkey Net Capital Budget Outlook 2015 (1)

(1) Outlook as at March 10, 2015. These work programs include firm and contingent items. See Slide 27 "Reader Advisories – FORWARD-LOOKING STATEMENTS". (2) Represents a best estimate of the ultimate firm program within a possible range up to $18 to $20 MM (net). (3) Licence retention well has been delayed to 2015 given that the licence conversion process remains underway with the GDPA, which is expected to be concluded by mid-

2015. The planned 2015 program of one exploration well in Banarli is a licence retention well.

BUSINESS SEGMENT

DRILLING AND COMPLETIONS NON DRILLING TOTAL (2)

GROSS WELLS (#)

NET WELLS (#)

WI AMOUNT ($MM)

WI AMOUNT ($MM)

WI AMOUNT ($MM)

TBNG-PTI JV – THRACE BASIN

Vertical Conventional Gas Wells 4 1.6 2.4 - 2.4

Vertical Tight Gas Wells 6 2.4 3.7 0.4 4.1

12 Workovers & 6 Re-entry Fracs - - - 1.9 1.9

Other - - - 0.6 0.6

TOTAL TBNG-PTI JV– THRACE BASIN 10 4.0 6.1 2.9 9.0

BANARLI

Banarli (3) 1 1.0 2.1 7.9 10.0

OTHER

Edirne - - - 0.3 0.3

GRAND TOTAL TURKEY 11 5.0 8.2 10.8 19.3

2015 work program and budget targeting to:

− Achieve 2015 sales from the TBNG-PTI JV lands of 1,200 – 1,250 boe/d (5 to 10% growth on 2014)

− Drill balanced program of up to 10 new conventional gas & tight gas wells on the TBNG-PTI JV lands

− Acquire 150 km2 of 3D seismic & drill at least one conventional gas exploration well at Banarli (licence retention well); seek partner to pursue deep, basin-centered gas play

26

Summary

Owning Valeura provides exposure to a natural gas-focused, pure play in Turkey, which benefits from: $10.62/Mcf natural gas prices, 12.5% government royalty & $46.22/boe operating netbacks (Q4 2014)

Large land position of 1.0 MM acres (gross); 0.42 MM acres (net)

Applying latest 3D seismic, horizontal drilling and multi-stage frac technologies to develop under-exploited conventional gas and tight gas plays in the Thrace Basin

Pursuing new 3D seismic & first drilling on Banarli licence (100% WI – operated) in 2015, which provides conventional and tight gas upside potential

Q4 2014 sales in Turkey 1,180 boe/d, up 18% from Q3 2014

Turkey 2P reserves value $108 million ($1.86 per share) at YE 2014 (NPV10 before tax) (1)(2)

New Osmancik discoveries and Mezardere slope fan play on TBNG-PTI JV lands (Valeura 40% WI - non-operated) has significantly expanded opportunity portfolio

Planning 2015 capital budget of up to $18-20 MM (net) in Turkey, contingent on level of cash flow, up significantly from $10.8 MM in 2014

$10.0 MM working capital surplus at YE 2014; no debt

(1) See Slide 28"Reader Advisories – D&M RESERVES AND RESOURCE DISCLOSURE". (2) See Slide 28 "Reader Advisories – FUTURE NET REVENUE".

27

Reader Advisories

Forward-Looking Statements: This presentation contains certain forward-looking statements and forward-looking information (collectively, "forward-looking statements") as defined by applicable securities legislation including, but not limited to: Valeura’s 2015 work program and budget, operational plans (seismic, drilling, fracking and workovers) and capital expenditures on the TBNG JV lands and the Banarli licence 5104; expected production growth on the TBNG JV lands in 2015; the planned seismic and drilling program on the Banarli licence in 2015 and the associated timelines; the ability to negotiate a transportation and marketing arrangement with the TBNG JV to tie-in at least one well at Banarli, assuming drilling success; the potential to frac the Guney Osmanli-1 well to achieve commercial gas production; the availability of operating cash flow and the ability to finance development; tieing-in new wells and getting these on-stream; the timing, estimated costs and ability to fund each of the foregoing; the plans to attract a joint venture partner to drill the deep, potential basin-centered gas play on the Banarli licence; the plans to attract a farm-in partner on the deeper horizons in certain of the TBNG-PTI JV lands; and, the ability to convert the Banarli Licence under the new licencing regime in Turkey. Forward-looking statements typically contain words such as "anticipate", "estimate", "expect", "target", "potential", "could", "should", "would" or similar words suggesting future outcomes. Valeura cautions readers and prospective investors in the Corporation’s securities to not place undue reliance on forward-looking statements, as by their nature, they are based on current expectations regarding future events that involve a number of assumptions, inherent risks and uncertainties, which could cause actual results to differ materially from those anticipated by the Corporation. Statements related to "reserves" or "contingent resources" are deemed forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources can be profitably produced in the future.

Forward-looking statements are based on management's current expectations and assumptions regarding, among other things: continued political stability of the areas in which the Corporation is operating and completing transactions; continued operations of and approvals forthcoming from GDPA in a manner consistent with past conduct; future seismic, drilling, fracking and recompletion activity; the prospectivity of the Osmanli area on the TBNG JV lands and follow-on drilling locations; the prospectivity of the Banarli licence; future production rates, capital efficiencies and associated cash flow; future cost reductions; future capital and other expenditures (including the amount and nature thereof); the ability to meet drilling deadlines and other requirements under licences and leases, including spudding deadlines under the Banarli licence 5104 and Copkoy licence 5147; the ability to attract partners and negotiate farm-in arrangements, in particular for deep exploration on the Banarli licence 5104; future sources of funding; future economic conditions; future currency and exchange rates; and the Corporation's continued ability to obtain and retain qualified staff and equipment in a timely and cost efficient manner. In addition, the Corporation’s 2015 work program and budget are based upon the current work programs proposed by partners and associated exploration, development and marketing plans and anticipated costs and sales prices, which are subject to change based on, among other things, the actual results of drilling and related activity, availability of fracking and other specialized oilfield equipment and service providers, and unexpected delays and changes in market conditions. Although Valeura management believes the expectations and assumptions reflected in such forward-looking statements are reasonable, they may prove to be incorrect.

Forward looking statements involve significant known and unknown risks and uncertainties. Exploration, appraisal, and development of oil and natural gas reserves are speculative activities and involve a significant degree of risk. A number of factors could cause actual results to differ materially from those anticipated by the Corporation including, but not limited to: risks associated with the oil and gas industry (e.g. operational risks in exploration, inherent uncertainties in interpreting geological data, and changes in plans with respect to exploration or capital expenditures, the uncertainty of estimates and projections in relation to costs and expenses, and health, safety, and environmental risks); uncertainty regarding the sustainability of initial production rates and decline rates thereafter; uncertainty regarding the ability to address technical drilling challenges and manage water production; uncertainty regarding the state of capital markets and the availability of future financings; the risk of being unable to secure farm-in partners; the risk of being unable to meet drilling deadlines and the requirements under licences and leases (including Banarli licence 5104 and Copkoy licence 5147); uncertainty regarding converting licences under the GDPA’s new licencing regime; uncertainty regarding the amount of operating cash flow and ability to reduce costs and achieve capital efficiencies; the risks of disruption to operations and access to worksites, threats to security and safety of personnel and potential property damage related to political issues, terrorist attacks, insurgencies or civil unrest; the risks of increased costs and delays in timing related to protecting the safety and security of Valeura's personnel and property; the risk of commodity and BOTAS pricing (in Turkish Lira); the risk of fluctuations in foreign exchange rates, particularly the Turkish Lira; the uncertainty associated with negotiating with third parties in countries other than Canada; the risk of partners having different views on work programs and potential disputes among partners; the uncertainty regarding government or other approvals; potential changes in laws and regulations; risks associated with weather delays and natural disasters; and, the risk associated with international activity. The forward-looking statements included in this presentation are expressly qualified in its entirety by this cautionary statement. The forward-looking statements included herein are made as of the date hereof and Valeura assumes no obligation to update or revise any forward-looking statements to reflect new events or circumstances, except as required by law. See Valeura's most recent annual information form ("AIF") for a detailed discussion of the risk factors.

28

Reader Advisories (Cont’d)

Any financial outlook or future oriented financial information in this presentation, as defined by applicable securities legislation, has been approved by management of Valeura. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management’s current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes.

Other Footnotes: INITIAL ON-STREAM PRODUCTION RATES: The initial on-stream production rates disclosed in this presentation are preliminary in nature and may not be indicative of stabilized on-stream production rates. Initial on-stream production rates are not necessarily indicative of long-term performance or ultimate recovery. To date, shallow gas conventional wells and fracked unconventional tight gas wells have exhibited relatively high decline rates at more than 50% and 75%, respectively, in their first year of production. All natural gas rates and volumes are presented net of any load fluids

CONTINGENT RESOURCES: There is no certainty that it will be commercially viable to produce any portion of the contingent resources disclosed in this presentation. Additional information relating to Valeura’s contingent resources, including the related contingencies, can be found in Valeura’s 2012 AIF.

FUTURE NET REVENUE: The net present value of estimated future net revenue disclosed in this presentation should not be construed as the current market value of estimated crude oil, natural gas liquids and natural gas reserves attributable to Valeura's properties. The estimated discounted future net revenue from reserves are based upon price and cost estimates which may vary from actual prices and costs and such variance could be material. Actual future net revenue will also be affected production, supply and demand for crude oil and natural gas, curtailments or increases in consumption by purchasers and changes in governmental regulations or taxation.

DISCLOSURE OF LESS THAN ALL RESERVES: Estimates of reserves for individual properties in this presentation may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

BARRELS OF OIL EQUIVALENT: The term "boe" or barrels of oil equivalent may be misleading, particularly if used in isolation. A boe conversion ratio of 1 boe to 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

RECYCLE RATIO: The recycle ratios disclosed in this presentation were calculated by dividing operating netback by the finding and development costs for the year. Operating netback (or operating cash flow) is calculated as petroleum and natural gas sales less royalties, production expenses and transportation costs.

FINDING AND DEVELOPMENT ("F&D") COSTS: Valeura’s F&D costs, including changes in future development costs ("FDC") but excluding the effects of acquisitions and dispositions, for 2014 were $21.78/boe on a 1P reserve basis and $25.67/boe on a 2P reserves basis. On the same basis, Valeura’s F&D costs for 2013 were $34.26/boe on a 1P reserve basis and $31.64/boe on a 2P reserves basis, and for the last three years were $41.65//boe on a 1P reserve basis and $27.54/boe on a 2P reserves basis. The aggregate of the F&D costs incurred in the most recent financial year and the change during that year in estimated FDC generally will not reflect the total F&D costs related to reserves additions for that year.

DRILLING LOCATIONS: This presentation discloses 75+ potential drilling locations on 40 acre spacing in the Tekirdag area on the TBNG-PTI JV lands based on industry practice and internal review, which can be grouped into three categories: (i) proved locations; (ii) probable locations; and (iii) possible locations. These locations are effectively encompassed in a Tekirdag area development plan that underpins the 2014 D&M Reserves Report, which attributes reserves to 18 proved undeveloped locations, 54 probable undeveloped locations and 24 possible undeveloped locations (96 locations in aggregate) in the Tekirdag area. The drilling locations on which Valeura actually drills wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors.

NON-IFRS MEASURES: This presentation contains the terms "operating netback" (petroleum and natural gas sales less royalties, production expenses and transportation costs) and "funds flow from operations" (net loss for the period adjusted for non‐cash items), which do not have a standardized meaning prescribed by International Financial Reporting Standards ("IFRS") and therefore may not be comparable with the calculation of similar measures by other companies. Management believes these non-IFRS measures are useful supplemental measures to evaluate performance. Additional information relating to these non-IFRS measures, including the reconciliation to "net income", can be found in Valeura’s most recent management’s discussion and analysis.

D&M RESERVES AND RESOURCES DISCLOSURE: The 2011, 2012, 2013 and 2014 year-end reserves disclosure contained in this presentation is derived from the 2011 D&M Reserves Report, the 2012 D&M Reserves Report, the 2013 D&M Reserves Report and the 2014 D&M Reserves Report, respectively. The 2011 and 2012 year-end contingent resources disclosure contained in this presentation is derived from the 2011 D&M Contingent Resources Report and the 2012 D&M Contingent Resources Report, respectively. The foregoing reports were prepared using assumptions and methodology guidelines outlined in the COGE Handbook and in accordance with NI 51-101.

29


Glossary: Certain other terms used in this presentation but not defined herein or under "RESERVE AND RESOURCE DEFINITIONS" below are defined in NI 51-101 or Valeura’s most recent annual information form and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101 or Valeura’s most recent annual information form, as applicable.

"2011 D&M Contingent Resources Report" means the independent engineering evaluation of oil and gas contingent resources attributable to the Thrace Basin properties of Valeura in Turkey prepared by D&M in its report signed March 9, 2012 and effective December 31, 2011.

"2011 D&M Reserves Report" means the independent engineering evaluation of the oil and natural gas reserves attributable to the properties of Valeura in Turkey prepared by D&M in its report with a preparation date of March 9, 2012 and effective December 31, 2011.

"2012 D&M Contingent Resources Report" means the independent engineering evaluation of oil and gas contingent resources attributable to the Thrace Basin properties of Valeura in Turkey prepared by D&M in its report signed March 13, 2013 and effective December 31, 2012.




"COGE Handbook" means the Canadian Oil and Gas Evaluation Handbook prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

"D&M" means DeGolyer and MacNaughton, independent petroleum engineering consultants of Dallas, Texas.

"NI 51-101" means National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities.

"TBNG-PTI acquisition" means the joint acquisition of non-operated producing natural gas assets and lands in the Thrace Basin of Turkey and other interests in exploration lands in the Anatolian Basin of Turkey from Thrace Basin Natural Gas Turkiye Corporation and Pinnacle Turkey, Inc. by Valeura and an affiliate of TransAtlantic Petroleum Ltd. completed in 2011.

"TBNG-PTI JV" means the joint venture of Valeura (40% WI), Thrace Basin Natural Gas Turkiye Corporation (41.5% WI; operator) and Pinnacle Turkey, Inc. (18.5% WI).

"TBNG-PTI JV lands" means the lands acquired by the TBNG-PTI JV under the TBNG-PTI acquisition.

Reserves and Resources Definitions: "reserves" are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on: (a) analysis of drilling, geological, geophysical, and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions which are generally accepted as being reasonable.

"proved" or "1P" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

"probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable ("2P") reserves.

30


Reserves and Resources Definitions (Cont’d): "probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable ("2P") reserves.

"possible" reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible ("3P") reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves.

"contingent" resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingent resources have an associated chance of development (economic, regulatory, market and facility, corporate commitment or political risks). The estimates herein have not been risked for the chance of development. There is no certainty that the contingent resources will be developed and, if they are developed, there is no certainty as to the timing of such development or that it will be commercially viable to produce any portion of the contingent resources. Contingent resources are further classified in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status.

Best estimate ("2C") is considered to be the best estimate of the quantity of contingent resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those contingent resources that fall within the best estimate have a 50% confidence level that the actual quantities recovered will equal or exceed the estimate.

Low estimate ("1C") is considered to be a conservative estimate of the quantity of contingent resources that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. Those contingent resources at the low end of the estimate range have the highest degree of certainty - a 90% confidence level - that the actual quantities recovered will equal or exceed the estimate.

High estimate ("3C") is considered to be an optimistic estimate of the quantity of contingent resources that will actually be recovered. It is unlikely that the actual remaining quantities of resources recovered will meet or exceed the high estimate. Those contingent resources at the high end of the estimate range have a lower degree of certainty - a 10% confidence level - that the actual quantities recovered will equal or exceed the estimate.

Abbreviations:

Oil and Natural Gas Liquids Natural Gas bbl barrels Mcf thousand cubic feet bbl/d barrels per day Mcf/d thousand cubic feet per day NGLs natural gas liquids MMcf/d million cubic feet per day Bcf billion cubic feet Other boe barrels of oil equivalent m metres

boe/d barrels of oil equivalent per day km kilometres

M thousand km2 square kilometres

MM million 2D two dimensional WI working interest 3D three dimensional IP30 initial 30-day on-stream production rate CAGR Compound annual growth rate

MD measured depth IRR internal rate of return TD total depth NPV10 net present value of estimated future net revenue, discounted at 10% TVD true vertical depth

A GLOBAL ENERGY COMPANY FOCUSED ON EXCEPTIONAL VALUE CREATION

SUPPLEMENTARY INFORMATION

32

Our Heritage

Senior Management

Board of Directors

Past Successes of Management & Board

Market Cap ~$5,920 mm

Sold in 2004 $228 mm

5x ROI (’99-’04) CAGR 43%

Sold 2009 $360 mm

3x ROI (’04-’09) CAGR 22%

Market Cap at Trust Conversion $916 mm

35x ROI (‘94-’03) CAGR 51%


1.4x ROI (’03-’06) CAGR 10%


6x ROI (’05-’07) CAGR 118%


4x ROI (’05-’08) CAGR 89%

Market Cap ~$757 mm


3x ROI (’02-’05) CAGR 34%

33

Organization Structure

34

BOARD OF DIRECTORS

Jim McFarland

PRESIDENT & CEO

Shari Lemon

ASSISTANT

Abby Badwi Jim McFarland Bill Fanagan Ken McKay Claudio Ghersinich Ron Royal Stephanie Stimpson, Corporate Secretary

VP ENGINEERING

MANAGER GEOSCIENCES

VP OPERATIONS

Don Shepherd Lyle Martinson Rob Sadownyk

CFO

Steve Bjornson Barry Wihak

SENIOR GEOLOGISTS

Ron Honch Peter Luxton

4 G&G 0.5 IT 2 Acct

TURKEY BRANCH

Ryan Tomlinson

CONTROLLER CONSULTANTS

MANAGER BUSINESS

DEVELOPMENT

Ken Skea Mehmet Ekinalan Sema Canpolat Zeynep Urkut Mike Kohut - Tech

JV ACCOUNTANT

Debbie Harding

SENIOR ENGINEER

35

Officers

President & CEO: Jim McFarland, P. Eng.

42 years oil & gas experience

Former President & CEO, director and co-founder, Verenex Energy (Libya light oil)

Former Managing Director, Southern Pacific Petroleum (Australian shale oil)

Former President & COO, Husky Oil (heavy oil, upgrading)

23 year career with Imperial Oil (conventional oil & gas, heavy oil, oil sands in-situ & mining, HSE) & other Exxon affiliates in the US, UK & Western Europe (offshore, research)

Director MEG Energy Corp. (oil sands in-situ) and Pengrowth Energy Corporation (Canadian oil & gas); past director Verenex Energy, Vermilion Energy Trust, Aventura Energy, Southern Pacific Petroleum and Central Pacific Minerals

Member Program Committee, World Petroleum Council

Australian Centenary Medal (2003) for outstanding service through business & commerce

MSc Petroleum Engineering (Alberta); BSc Chemical Engineering (Honours) (Queen’s); Executive Development Program (Cornell)

CFO: Steve Bjornson, CA


Former CFO Vermilion Resources, Clear Energy and Sound Energy

24 years of finance, business development, strategic planning and tax experience

Successfully negotiated and executed 15 public and private mergers & acquisitions

Past director Bulldog Oil & Gas, Bulldog Resources and Aventura Energy

BA Commerce (Calgary)

36

Officers (Cont’d)

VP Engineering: Don Shepherd, P. Eng.


Former General Manager, Verenex Energy Area 47 Libya based in Tripoli

13 years with Saudi Aramco as Asset Management Team Leader and Senior Engineering Specialist (Saudi Arabia)

12 years in executive management positions with junior oil & gas companies in Canada (Highfield Oil & Gas, Roxy Petroleum, Morgan Hydrocarbons, Newscope Resources)

10 years with Imperial Oil and Exxon (including Libya posting)

BSc Electrical Engineering (Saskatchewan)

VP Operations: Lyle Martinson, P. Eng.


Former Manager, Drilling & Operations, Verenex Energy Area 47 Libya in Tripoli

Former Manager, Well Engineering & Operations with Chevron Canada Resources (exploration well programs in Northern Canada & East Coast offshore)

28 years of engineering, operations, HSE & HR experience with Chevron (Canada, US, Australia and Indonesia), including 22 years in leadership roles managing organizations and projects of varying size and complexity

BSc Civil Engineering (Saskatchewan)

37

Manager Business Development: Barry Wihak, P. Geol.


Former President & CEO, director and co-founder, Cangea Energy (private, Colombia focus)

5 years with Vermilion Energy Trust as Business Development Advisor on acquisitions in France, Netherlands and Australia

22 years of earlier experience as an independent consultant and employee in exploration & production geological operations and business development roles with junior oil & gas companies in Canada (Golden Horizon Exploration, Truax Resources, Richland Petroleum)

Broad experience A&D, international (new country entry, relationship building, corporate & government liaison), world-wide hydrocarbon basins

BA Geology (Princeton)

Manager Geosciences: Rob Sadownyk, P. Geol.


Former VP Exploration and co-founder, Berland Exploration (tight gas)

Senior Geologist with Vermilion Resources (tight gas, foothills) and Canadian Hunter Exploration (tight gas)

Broad experience as explorationist in clastic, carbonate and foothills play types in the WCSB with specific expertise in exploration & development of tight gas

BSc Geology (Honours) (Alberta); Civil Engineering Diploma (NAIT)

Managers

38

Country Representative (Ankara, Turkey): Mehmet Ekinalan


Former Resident Representative of Thrace Basin Natural Gas Turkiye Corporation

21 years telecommunications experience (Turkey and USA)

Former CEO and Board member of Turkish Telecom

Former CEO of AYCELL (Turkey)

15 years of management and technical roles in Omni Communications (USA), NEC (Turkey), Turkish Telecom (Turkey) and Radiocom (Turkey)

MSc General Administration (World Maritime University, Sweden); BSc Electronics and Telecommunications (Karadeniz Technical University, Turkey)

Managers (Cont’d)

39

Board of Directors

Abby Badwi, P. Geol. Vice-Chairman, Bankers Petroleum Ltd.

Former President & CEO, Bankers Petroleum Ltd.

Geological background

Bill Fanagan, CA (Chair)

Former Chairman, Verenex Energy Inc.

Former President & CEO, Gulf Indonesia Resources Limited

Financial background (Audit Chair)

Claudio Ghersinich, P. Eng. Co-founder & former EVP Business Development, Vermilion Energy Trust

Former Director, Verenex Energy Inc.

Business and engineering background

Jim McFarland, P. Eng.

President & CEO

Engineering background

Ken McKay, P. Geol.

Former Executive Chairman, Bulldog Oil & Gas Inc.

Geological background

Ron Royal, P. Eng.

Former President & GM, Esso Chad

Engineering background

40

Turkey YE 2014 Reserves (Company Gross) (1)

CATEGORY LIGHT & MEDIUM

OIL (Mbbl)

NATURAL GAS

(Bcf)

TOTAL OIL EQUIVALENT

(Mboe)

NPV10 BEFORE TAX (2)

(US$MM)

NPV10 AFTER TAX (2)

(US$MM)

PROVED 79 10.0 1,738 34.0 31.4

PROBABLE 48 24.1 4,066 58.6 46.8

TOTAL PROVED PLUS PROBABLE

127 34.1 5,804 92.5 78.2

POSSIBLE 91 26.8 4,564 72.8 59.0

TOTAL PROVED, PROBABLE AND POSSIBLE

218 60.9 10,368 165.4 137.1

(1) See Slide 28 "Reader Advisories – D&M RESERVES AND RESOURCE DISCLOSURE". (2) See Slide 28 "Reader Advisories – FUTURE NET REVENUE".

Turkey YE 2012 Contingent Resources (Company Gross) (1)(2) 302% year-over-year increase in 2C

contingent resources in Turkey (YE 2012 compared to YE 2011)

Natural gas in six discovered gas fields on TBNG JV lands only (Valeura 40% WI)

− Area of structures ˂ 3% of gross acreage

Growth in contingent resources driven by:

− new 3D seismic control over all of the fields

− new petrophysical analysis correlated to new core analysis results

− additional well control

Primarily tight gas in the Teslimkoy and Kesan formations in the Tekirdag area, and Mezardere Formation in the Hayrabolu area

Not updated since YE 2012 and any decision to update dependent on results from further drilling on TBNG-PTI JV lands and Banarli

MMboe

(1) See Slide 28 "Reader Advisories – D&M RESERVES AND RESOURCE DISCLOSURE". (2) See Slide 28 "Reader Advisories – CONTINGENT RESOURCES".

41

3C – Contingent Resources 2C – Contingent Resources 1C – Contingent Resources

42

Land Position In Turkey At March 1, 2015

TRANSACTION

LEASES & LICENCES (1)

(#)

GROSS AREA (acres)

VALEURA NET AREA

(acres)

THRACE BASIN

TBNG-PTI JV - Onshore (2) 14 507,853 203,141

TBNG-PTI JV - Offshore - 116,508 17,476

Banarli Licence 5104 Award (3) 1 118,598 118,598

Copkoy Licence 5147 Award (4) 1 20,668 20,668

Otto - Edirne 3 49,883 17,459

SUB TOTAL 19 813,510 377,343

ANATOLIAN BASIN

TBNG-PTI JV - Gaziantep 2 152,111 39,549

TOTAL 21 956,621 416,892

(1) Reflects the conversion as at March 1, 2015 of some old exploration licences to new exploration licences and production leases under terms of the New Petroleum Law adopted in May 2013.

(2) Applications to the GDPA remain outstanding for conversion of several exploration licences to terms under the New Petroleum Law. There is no certainty that such conversions can be achieved and timing remains uncertain.

(3) Valeura has applied to the GDPA to convert the Banarli licence to the new licencing regime in Turkey, which could be approved by mid-2015, thereby extending the initial term of the licence to five years and deferring the first year drilling commitment to late 2015. There is no certainty that such a conversion can be achieved and timing remains uncertain. Valeura’s current plan is to carry out 3D seismic and drill up to three exploration wells in 2015 at Banarli (including at least one licence retention well).

(4) Valeura has applied to the GDPA to convert the Copkoy licence to the new licencing regime in Turkey and it may also be impacted by the licence conversion process associated with the offsetting lands in the TBNG-PTI JV lands. Therefore, the timing of any drilling commitment will likely be deferred to later in 2015. There is no certainty that such a conversion can be achieved and timing remains uncertain.

43

TBNG-PTI JV 2011 Frac Results

WELL FRAC DATE

(d/m/y) NET PAY (1)

(m) POROSITY (1)

(%)

PEAK 24-HOUR ON-STREAM

RATE (MMcf/d) (2)

INITIAL 7-DAY AVERAGE

ON-STREAM RATE (MMcf/d) (2)

IP30 RATE (MMcf/d) (2)

CUMULATIVE PRODUCTION TO

FEB 28, 2015 (MMcf)

Yazir-2; 1st stage 18/07/2011 2 10

0.1 (3) 0.1 (3) - 3 (3)

Yazir-2; 2nd stage 1/08/2011 15 10

Kayi-15 30/09/2011 29 12 0.6 0.5 0.5 105

BTD-2 3/10/2011 8 13 4.3 3.3 2.6 1,316

Aydede-2 22/11/2011 4 16 2.2 1.4 0.8 148

DTD-7 28/11/2011 11 12 0.2 0.1 0.1 43

Kayi-14 7/12/2011 13 13 5.0 3.7 3.2 333

Dogu Yagci-1 12/12/2011 7 13 2.0 1.5 1.3 142

Aydede-1 14/12/2011 8 13 0.9 0.7 0.4 153

(1) Net pay and porosity based on preliminary cutoffs: ≥ 9% porosity; ≤ 60% water saturation; ≤ 35% clay content. (2) See Slide 28 "Reader Advisories – INITIAL ON-STREAM PRODUCTION RATES". (3) Yazir-2 first and second stage frac production is commingled.

44


WELL

FRAC DATE (d/m/y)

NET PAY (1)

(m) POROSITY (1)

(%)

PEAK 24-HOUR ON-STREAM RATE

(MMcf/d) (2)





FEB 28, 2015 (MMcf)

DTD-11 7/01/2012 3 13 1.1 0.8 0.6 117

Karya Derin-1 (3) 4/02/2012 11 14 0.2 0.07 0.04 7

TDR-5 (2-stage) 11/02/2012 13 13 3.0 2.1 1.5 331

Senova-1 (4) 15/02/2012 13 19 0.2 0.03 0.03 2

Kuzey Kayi-2 19/02/2012 10 12 0.7 0.6 0.3 49

DTD-10 09/03/2012 5 11 0.2 0.2 0.1 28

Kayi-12 19/03/2012 7 14 0.3 0.2 0.2 65

BTD-1 (5) 21/03/2012 4 12 - NA NA NA

TDR-4 24/03/2012 6 18 1.6 1.2 1.0 251

DTD-4 28/03/2012 8 12 0.3 0.2 0.1 9

(1) Net pay and porosity based on preliminary cutoffs: ≥ 9% porosity; ≤ 60% water saturation; ≤ 35% clay content. (2) See Slide 28 "Reader Advisories – INITIAL ON-STREAM PRODUCTION RATES". (3) Fracked into a water zone; well is not tied into the gathering system. (4) Frac test to extend licence term; well is not tied into the gathering system. Small volumes represent compressed natural gas sales. (5) No gas flow after frac; well is not tied into the gathering system.

45

TBNG-PTI JV 2012 Frac Results (Cont’d)

WELL FRAC DATE

(d/m/y) NET PAY (1)

(m) POROSITY (1)

(%)


(MMcf/d) (2)





FEB 28, 2015 (MMcf)

Sulemaniye-2 (3) 9/05/2012 1 10 0.3 NA NA NA

Dogu Karya-1 (4) 22/05/2012 1 10 0.1 0.04 0.01 1

TDR-8 (Kesan) 29/05/2012 2 10 0 0 0 0

Kayi-7 13/06/2012 7 16 0.4 0.4 0.3 70

Guney Kayi-1 (5) 20/06/2012 15 12 0.6 0.4 0.4 67

DTD-1 11/07/2012 15 14 0.6 0.6 0.5 168

TDR-8 (Teslimkoy) 16/07/2012 4 13 0.3 0.2 0.1 5

Koseilyas-1 19/07/2012 9 12 0.9 0.7 0.4 100

BTD-3 (L. Kesan) (6) 02/08/2012 NA NA 1.3 0.8 0.3 15

TDR-2 (7) 18/08/2012 7 10 0.6 0.5 0.4 62

Kayi Derin-1 (6) 18/12/2012 NA NA 0.1 0.03 0.04 2

TDR-7 (2-stage) (8) 30/12/2012 3 11 0.01 - - 0.3

(1) Net pay and porosity based on preliminary cutoffs: ≥ 9% porosity; ≤ 60% water saturation; ≤ 35% clay content. (2) See Slide 28 "Reader Advisories – INITIAL ON-STREAM PRODUCTION RATES". (3) Exploratory well spudded in December 2011; two-stage frac; deep target fracked into a water zone ; well is not tied into the gathering system. (4) Exploratory well; deep target fracked into a water zone. (5) Three-stage frac. (6) "Slick water" frac into a naturally fractured interval in Kesan at a depth of 2,475 m in BTD-3 (this interval is now abandoned and well completed in Teslimkoy) & 3,700 m

in Kayi Derin-1. Effective net pay & porosity are undetermined . (7) "Slick water" frac. (8) Suspended.

46


WELL FRAC DATE

(d/m/y) NET PAY (1)

(m) POROSITY (1)

(%)


(MMcf/d) (2)





FEB 28, 2015 (MMcf)

Baglik-1 (L. Kesan) (3) 8/01/2013 NA NA NA NA NA NA

Kazanci-5 (1st stage) (4) 29/01/2013 4 15 NA NA NA NA

BTD-5 (4-stage) (5)

(Kesan) 15/02/2013 28 10 0.5 0.2 0.2 11

DTD-19 (5-stage) 01/03/2013 32 11 0.7 0.6 0.5 138

Baglik-1 (4-stage) (U. Kesan/Teslimkoy) 26/03/2013 35 11 2.9 1.2 1.7 434

ND-3 (2-stage) (Mezardere) 26/04/2013 19 11 1.2 1.1 1.1 101

BTD-3 (1st stage) (6)

(U. Kesan) 10/05/2013 9 10 0.1 - - 0.2

TS-18 (Mezardere) 30/05/2013 29 14 1.0 0.9 0.9 117

BTD-5 ( 2-stage) (Teslimkoy) 10/06/2013 28 12 0.9 0.7 0.8 156

BTD-3 (2nd stage)

(Teslimkoy) 02/07/2013 18 12 1.8 1.3 1.2 222

Karanfiltepe-1 (L. Osmancik) 05/07/2013 18 16 0.07 0.04 - 2

(1) Net pay and porosity based on preliminary cutoffs: ≥ 9% porosity; ≤ 60% water saturation; ≤ 35% clay content. (2) See Slide 28 "Reader Advisories – INITIAL ON-STREAM PRODUCTION RATES". (3) Abandoned interval and moved up hole to complete the Kesan / Teslimkoy. (4) Abandoned interval, appears wet. (5) Abandoned interval and moved up hole to complete the Teslimkoy. (6) Set frac plug over interval in order to move up hole and complete the Teslimkoy.

47


WELL FRAC DATE

(d/m/y) NET PAY (1)

(m) POROSITY (1)

(%)


(MMcf/d) (2)





FEB 28, 2015 (MMcf)

Karanfiltepe-6 (L. Osmancik) 12/07/2013 21 15 3.4 2.0 2.3 546

Yagci-5 (Mezardere) 19/07/2013 29 10 0.6 0.2 0.08 6

DTD-19H (7-stage) (3)

(Upper Kesan) 26/07/2013 NA NA 0.6 0.5 0.4 82

BTD-1

(Teslimkoy) 30/07/2013 9 11 0.2 0.2 0.1 5

TDR-14 (U. Kesan) 05/08/2013 5 13 0.8 0.6 0.4 76

DTD-11 (Mezardere) 14/08/2013 28 17 1.5 1.2 0.8 36

DTD-7 (2-stage) (Mezardere) 17/08/2013 13 14 0.4 0.3 0.1 10

TDR-8 (Mezardere) 26/08/2013 14 15 0.8 0.6 0.3 11

DTD-6 (Mezardere) 03/09/2013 24 14 2.1 1.8 1.5 139

Karaevli-4 (Mezardere) 08/09/2013 32 11 NA NA NA NA

BTD-4H (10-stage) (4)

(Teslimkoy) 19/09/2013 NA NA 3.4 3.0 3.0 638

(1) Net pay and porosity based on preliminary cutoffs: ≥ 9% porosity; ≤ 60% water saturation; ≤ 35% clay content. (2) See Slide 28 "Reader Advisories – INITIAL ON-STREAM PRODUCTION RATES". (3) Partially cleaned out well (five frac balls, ball seats and sand) with service rig and coiled tubing unit. Well is tied into gathering system but likely only five intervals are

contributing to flow. (4) Unsuccessful in cleaning out frac balls and seats with coiled tubing unit. Therefore unlikely that all 10 fracked intervals are contributing to flow.

48


WELL FRAC DATE

(d/m/y) NET PAY (1)

(m) POROSITY (1)

(%)


(MMcf/d) (2)





FEB 28, 2015 (MMcf)

Yagci-6 (Mezardere) 07/10/2013 9 11 0.5 0.2 0.2 8

Kayi-14 (Mezardere) 23/10/2013 21 14 5.4 4.7 4.1 390

Kayi-12 (Mezardere) 28/10/2013 35 12 1.6 1.2 1.1 85

Kayi-6 (Mezardere) 31/10/2013 19 15 0.9 0.8 0.9 69

DTD-4 (Mezardere) 07/11/2013 71 11 1.3 1.0 0.8 55

Karanfiltepe-5 (2-stage) (Osmancik) 14/11/2013 37 9 NA NA NA NA

DTD-13 (Mezardere) 21/11/2013 14 16 NA NA NA NA

Kayi-7 (2-stage) (Mezardere) 30/11/2013 32 17 3.4 3.2 2.6 499

Guney Kayi-1 (Mezardere) 04/12/2013 7 16 1.8 1.3 0.6 32

BTD-5H (3-stage) (Teslimkoy) 20/12/2013 NA NA 2.3 2.0 2.0 519

Kayi Derin -1 (Mezardere) 26/12/2013 14 17 0.7 0.6 0.4 50

(1) Net pay and porosity based on preliminary cutoffs: ≥ 9% porosity; ≤ 60% water saturation; ≤ 35% clay content. (2) See Slide 28 "Reader Advisories – INITIAL ON-STREAM PRODUCTION RATES".

49


WELL FRAC DATE

(d/m/y) NET PAY (1)

(m) POROSITY (1)

(%)


(MMcf/d) (2)





FEB 28, 2015 (MMcf)

Kayi-16 (2-stage) (Mezardere/Teslimkoy) 22/01/2014 20 17 0.2 0.2 0.1 26

TDR-9 (2-stage) (Mezardere) 03/02/2014 44 15 0.6 0.5 0.3 31

BTD-2H (8-stage) (Mezardere) 04/03/2014 NA NA 2.3 1.5 1.5 308

TDR-11H (10-stage) (Mezardere) 25/03/2014 NA NA 1.9 1.6 1.3 107

Kazanci-5 (Osmancik) 17/04/2014 12 20 0.2 0.1 0.1 26

TB-13 (Osmancik) 24/04/2014 6 10 0.1 0.1 0.1 15

BTD-1 (Mezardere) 06/05/2014 35 16 1.2 1.1 0.9 106

Kayi-16 (Mezardere) 04/06/2014 8 16 0.7 0.5 0.3 25

DTD-7 (Teslimkoy) 15/08/2014 20 16 0.9 0.7 0.8 90

DTD-11 (Teslimkoy) 17/08/2014 21 15 0.4 0.3 0.3 33

TDR-5H (8-stage) (Teslimkoy) 22/08/2014 NA NA 2.0 1.8 1.3 153

(1) Net pay and porosity based on preliminary cutoffs: ≥ 9% porosity; ≤ 60% water saturation; ≤ 35% clay content. (2) See Slide 28 "Reader Advisories – INITIAL ON-STREAM PRODUCTION RATES".

50

TBNG-PTI JV New Drill Spuds In 2012 - 2015 YTD

TIME GROSS WELLS

SPUDDED PRODUCING

EVALUATING/

COMPLETING

CASED &

STANDING

PLUGGED &

ABANDONED DRILLING

UNCONVENTIONAL

2012 - 2013 SUB-TOTAL 17 15 2 - - -

2014 SUB-TOTAL 3 3 - - - -

2015 YTD SUB-TOTAL - - - - - -

CONVENTIONAL

2012 - 2013 SUB-TOTAL 10 6 2 - 2 -

2014 SUB-TOTAL 6 5 1 - - -

2015 YTD SUB-TOTAL 1 1 - - - -

TOTAL 2012 - 2015 YTD 37 30 5 - 2 -

Guney Kayi-1

Baglik-1

Dogu Karya-1, Sig-1

BTD-2H, 3, 4H, 5, 5H

TSK-1, 2

Guney Karababa-1

Dogu Gazi-2

Kayi Derin-1

10 km

Kayi-16 Guney Atakoy-2 Koseilyas-1

Deveseki-1

Atakoy-8

Karanfiltepe-5, 6

DTD-19, 19H

TDR-5H, 9, 11H, 14

Kuzey Atakoy-1

Tekirdag

Development

Area

Hayrabolu

Deep

Exploration

Area

Hayrabolu-10 Kazanci-5

Gurgen-1,2,3

Biyikali-2ST Tavanli-1

Guney Osmanli-3 Dogu Osmanli-1

Osmanli

New

Discovery

Area

51

TBNG-PTI JV New Drill Spuds In 2012

WELL LICENCE SPUD

(d/m/y) RIG RELEASE

(d/m/y) WELL TYPE

TD (m)


Baglik-1 3931 10/03/2012 06/05/2012 Unconventional 3,594 Producing

Dogu Karya-1 3934 04/04/2012 23/04/2012 Unconventional 2,022 Evaluating

TSK-1 3931 05/04/2012 10/04/2012 Conventional 657 Producing

Guney Atakoy-2 3734 18/04/2012 03/05/2012 Conventional 1,759 Producing

Dogu Karya Sig-1 3934 01/05/2012 05/05/2012 Conventional 400 Plugged & Abandoned

Guney Kayi-1 3931 03/05/2012 13/05/2012 Unconventional 1,496 Producing

Kuzey Atakoy-2 3734 12/05/2012 30/05/2012 Conventional 1,820 Producing

BTD-3 3931 12/05/2012 03/06/2012 Unconventional 2,512 Producing

Kayi Derin-1 3931 21/05/2012 17/07/2012 Unconventional 3,754 Producing

Koseilyas-1 3934 05/06/2012 15/06/2012 Unconventional 1,506 Producing

Dogu Gazi-2 3934 10/06/2012 27/06/2012 Conventional 1,800 Plugged & Abandoned

Guney Karababa-1 3734 18/06/2012 28/06/2012 Conventional 1,100 Evaluating

Deveseki-1 3931 20/06/2012 25/06/2012 Conventional 693 Producing

TSK-2 3931 29/06/2012 09/07/2012 Unconventional 1,400 Producing

Kazanci-5 2926 05/09/2012 02/12/2012 Unconventional 3,253 Producing

Atakoy-8 3659 07/09/2012 20/09/2012 Conventional 1,429 Producing

Karanfiltepe-6 3659 14/10/2012 27/10/2012 Conventional 1,400 Producing

BTD-5 3931 02/11/2012 26/11/2012 Unconventional 1,915 Producing

TDR-9 3931 15/12/2012 21/01/2013 Unconventional 2,750 Producing

DTD-19 3931 23/12/2012 19/01/2013 Unconventional 1,939 Producing

52

TBNG-PTI JV New Drill Spuds 2013 - 2015 YTD WELL LICENCE

SPUD (d/m/y)

RIG RELEASE (d/m/y)

WELL TYPE TD (m)


TDR-14 3931 29/01/2013 22/02/2013 Unconventional 1,749 Producing

Hayrabolu-10 2926 08/02/2013 10/04/2013 Unconventional 4,054 Evaluating

DTD-19H 3931 03/06/2013 07/07/2013 Unconventional -

Horizontal 1,626 MD 1,096 TVD

Producing

BTD-4H 3931 27/07/2013 01/09/2013 Unconventional -

Horizontal 1,774 MD 1,004 TVD

Producing

Karanfiltepe-5 3659 07/09/2013 21/09/2013 Conventional 1,875 Evaluating

BTD-5H 3931 19/11/2013 03/12/2013 Unconventional -

Horizontal 1,519 MD 975 TVD

Producing

Kayi-16 3931 28/12/2013 05/01/2014 Unconventional 1,150 Producing

BTD-2H 3931 03/02/2014 15/02/2014 Unconventional –


Producing

TDR-11H 3931 20/02/2014 03/03/2014 Unconventional –


Producing

TDR-5H 3931 28/07/2014 08/08/2014 Unconventional –


Producing

Biyikali – 2ST 3931 15/08/2014 20/08/2014 Conventional 900 Producing

Gurgen-1 3931 25/08/2014 08/09/2014 Conventional 2,100 Producing

Tavanli-1 3931 12/09/2014 23/09/2014 Conventional 1,300 Producing

Guney Osmanli-3 3931 29/09/2014 09/10/2014 Conventional 1,080 Producing

Dogu Osmanli-1 3931 13/10/2014 26/10/2014 Conventional 2,100 Evaluating



DTD-19H Horizontal – Upper Kesan Reservoir

Upper Kesan reservoir horizon (Baglik-1 producing zone)

Spud June 3, 2013 (34 drill days)

1,096 m TVD; 1,626 m MD

425 m horizontal leg

Total 209 m of sand

7-stage frac Packers Plus assembly

8,613 bbls X-linked gel; 4% KCL water energized with 23-36% N2

1,071,000 lbs sand

Milled out 5 frac ports

IP30 rate 0.4 MMcf/d (1)

53

LP @ 1201.15 m MD

@ 1107.28 m TVD

@ -987 m SSTVD

Mud g

as

show

G

R

TD @ 1626 m MD

@1096 m TVD

@ -976 m SSTVD

Lateral section length : 425 m


BTD-4H Horizontal - Teslimkoy Reservoir

54

Teslimkoy BTD-2 producing zone

Spud July 27, 2013 (36 drill days)

1,004 m TVD; 1,774 m MD


Total 308 m of sand


5,815 bbls X-linked gel; 4% KCL water energized with 40-48% N2

682,000 lbs sand

No frac ports drilled out

IP30 rate 3.0 MMcf/d on 34/64" choke (1)

Lateral section length : 655 m

Landing point: 1,119 m


BTD-5H Horizontal - Teslimkoy Reservoir

55

Teslimkoy BTD-2 producing zone

Spud Nov 19, 2013 (15 drill days)

974 m TVD; 1,519 m MD


Total 89 m of sand

4-stage frac Packers Plus assembly (3 fracs completed)

583 bbls X-linked gel; 2% KCL water energized with 42-59% N2

114,430 lbs sand

No frac ports drilled out

IP30 rate 2.0 MMcf/d on 30/64" choke (1)

Lateral section length : 403 m Landing point: 1,116 m


BTD-2H Horizontal - Mezardere Reservoir

56

Mezardere DTD-6 producing zone

Spud February 3, 2014 (13 drill days)

635 m TVD; 1,246 m MD

Lateral section: 476 m

Total sand encountered: 242 m


3,420 bbls X-linked gel; 2% KCL water energized with 26-55 % N2

469,000 lbs sand

Fracked on March 4, 2014

IP30 rate 1.5 MMcf/d on 28/64" to 42/64" choke (1)

Lateral section: 476m

BTD-2 DTD-6


TDR-11H Horizontal - Mezardere Reservoir

57

Mezardere TS-18 producing zone

Spud February 20, 2014 (11 drill days)

518 m TVD; 1,291 m MD




4,754 bbls X-linked gel; 2% KCL water energized with 40-52 % N2

677,500 lbs sand

Fracked on March 25, 2014


Subsequently drilled out frac ports but no change in rate



58

Teslimkoy C producing zone

Spud July 28, 2014 (12 drill days)

991 m TVD; 1,698 m MD



Total silt encountered: 103 m


4,890 bbls X-linked gel; 2% KCl water (including sand-off clean out) energized with 34-50% N2

285,700 lbs sand

Fracked on August 22, 2014

2 stages sanded-off


Lateral section: 569m

TDR-5 TDR-5H

Landing Point: 1,129m TD: 1,698m

TDR-5H1 Horizontal - Teslimkoy Reservoir


59

Mezardere Slope Fan Model

Single Stage Re-entry Frac

Frac: 97,000 lbs, 431 bbls XL gel/ 46-53% N2

IP30 rate 1.5 MMcf/d (1)

DTD-6

DTD-6

DTD-7

DTD-11

Kayi-14

Kayi-6

Kayi-12

5 km

Meandering Slope Channel

Basin Floor Fans

3931

3934

Gazi

Karaevli

Mezardere consists of a north-easterly pro-grading slope fan complex, deposited within delta front and pro-delta setting

Potential reservoirs include:

− Porous channel and basin floor sands

− Interlaminated sands and shales from channel abandonment, overbank, distal apron facies

− Organic shale source intervals


Thrace Basin Seismic

60

2011 Tekirdag/Hayrabolu 3D (413 km2)

Drilling on 2D seismic only prior to 2012

2011 & 2013 3D seismic (645 km2) guiding TBNG JV drilling since early 2012

Valeura funded 2013 2D seismic on Banarli Licence & 2012 2D seismic on Copkoy Licence 3999 (licence expired in January 2013; Valeura applied for new licence)

Tiway Oil funded 2012 offshore 2D seismic

2012 reprocessed 3D (231 km2) 2012 reprocessed 2D (704 km)

2012 acquired 2D (175 km)

2012 acquired 2D (186 km)

2013 Banarli 2D (92.5 km)

Legacy seismic (3,514 km onshore) (1,586 km offshore)

2013 Osmanli 3D (232 km2)

61

Gaziantep Licences– Alibey-1 Horizontal

152,111 gross acres (Valeura 26% WI) in Anatolian Basin

Operated by TransAtlantic

Alibey-1 Hz drilled in July 2012 as 414 m horizontal side-track in original Alibey-1 vertical well, which flowed heavy oil from the Mardin Group

Sidetrack intersected 80 m of horizontal fractured pay

Logged and cased to TD (2,354 m) (TVD 1,868 m)

Completed 56 m gross interval at toe of well indicating initial oil productivity of 150 bbl/d (2)

Perforated additional pay but tested small amounts of oil (10-15 bbl/d) at a high water-cut; under evaluation

Two new licences issued to replace old Licence 4607 (3)

Alibey-1 HZ (evaluating)

10 km

Mardin Time Structure - 2D Seismic (1)

(1) Seismic map from TransAtlantic August 2012 corporate presentation. (2) January 2, 2013 TransAtlantic press release (Alibey-1 productivity based on swabbing operations). See

Slide 28 "Reader Advisories – INITIAL PRODUCTION ON-STREAM RATES". (3) Issued under New Petroleum Law in Q4 2014 (Licence N39-d1 & d2; Licence N39-a1 & a2)

N39-a1

N39-a4

N39-d1 N39-d2

Old Licence 4607

New Licences

62

Turkey Natural Gas Infrastructure

63

Turkey Oil Infrastructure

Thrace Basin Turkey – Stratigraphic Column

Tertiary basin

9,000 m of tertiary age sediments

Depositional environment

− Deltaic sands

− Turbidite sands

− Reef development on Paleozoic highs

Key reservoirs

− Danismen - gas

− Osmancik – gas

− Mezardere - gas

− Ceylan – gas

− Sogucak – oil

− Hamitabat - gas

64

65

SE Turkey – Stratigraphic Column

Reservoirs

Sinan/Garzan reefs (Tertiary/Upper Cretaceous)

Karabogaz & Mardin (Mid Cretaceous)

Bedinan (Ordovician)

Source Rocks

Karabogaz (Cretaceous)

Dadas (Silurian)

Seals

Germav (Upper Cretaceous)

Dadas (Silurian)

Play Types

Structural - Reverse and normal faults - Anticlines

Stratigraphic - Reefs

Resource - Fractured shales

Source: IHS Energy Group 2010 (modified by Valeura)

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