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A GLOBAL ENERGY COMPANY FOCUSED ON EXCEPTIONAL VALUE CREATION

FIRST DEEP EXPLORATION WELL YAMALIK-1 DRILLED WITH POSITIVE EVALUATION RESULTS CORPORATE PRESENTATION AUGUST 2017

2

Valeura Corporate Profile Valeura Energy Inc. (“Valeura” or “VLE”) (TSX: VLE) is a Canada-based oil & gas company

producing high netback natural gas in the Thrace Basin of northwest Turkey

Turkey continues to be an attractive international jurisdiction for oil & gas business:

−Flat 12.5% government royalty; 20% corporate tax

−Average natural gas price realization of $7.34/Mcf & operating netback of $22.38/boe in Q2 2017

Pursuing two-pronged growth strategy in Turkey:

−Ramp-up drilling & workovers in existing moderate risk, shallow gas business (<2,500 m depth)

−Pursue potential high impact basin-centered gas play (2,500 – 4,000+ m depth) under JV with Statoil

Growth plan made possible by four transformational transactions, which closed in Q1/Q2 2017:

−Statoil investment of US$36 MM to earn 50% WI in deep rights on VLE’s 100% owned Banarli licences

−Statoil purchase of 50% WI in other deep rights from VLE at West Thrace for US$15 MM

−VLE acquisition of TBNG for US$20.7 MM to increase VLE’s WI to 81.5% & operatorship of the TBNG JV

−$11 MM (gross proceeds) from underwritten private placement of subscription receipts

Transactions have reset the business by boosting the asset base, operational control, investment opportunity and financial capacity

1st deep well funded by Statoil under Banarli Farm-in, Yamalik-1, drilled to 4,196 metres and achieved positive well evaluation results:

– Completion, multi-stage fracing and testing program expected to commence by early Q4 2017

– 3D seismic program (500 km2) under Phase 2 of Banarli Farm-in approximately 36% complete

See ‘Non-IFRS Measures’ and ‘Barrels of Oil Equivalent’ (“boe”) under “Reader Advisories” starting on Slide 24 of the August 2017 Corporate Presentation.

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Thrace Basin Transactions & Land Position

3860

3861

3659 5122

50 km

Bulgaria

Turkey

Greece

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

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

Black Sea

Sea of Marmara

2013 Banarli 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

F17- c2,c3

F18- d1,d2,

d4

F18-c1,c2,c3,c4

F19- d1,d4

TBNG JV licence application F18-d3 (all bids rejected by GDPA)

G19-a1-1

G18- b2-1

G18- b1-1

TBNG JV lease award F19-d3-1

February 2017

2926

VLE licence application F18 -b3,

F19-a4 November 2015

F18-b3 F19-a4

TBNG JV lease award F19-c3-1

February 2017

TBNG acquisition 41.5% WI TBNG JV

1

2

Sale of 50% WI in deep rights to Statoil

– “West Thrace”

3

Statoil Banarli Farm-in

F19-d3-1

F19-c3-1

2016/2017

Basic shares outstanding at August 1, 2017 73,148,321

Common shares purchasable pursuant to outstanding Options

($0.73 weighted average exercise price per share) 6,370,500

Fully diluted shares 79,518,821

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Capital Structure August 1, 2017

Institutions ~ 25%

Retail ~ 70%

Management & Directors 4.9% (11.6% fully diluted)

Q2 2017 Financial & Operating Highlights

RESULTS 3 MONTHS

ENDED JUNE 30, 2017

3 MONTHS ENDED

MARCH 31, 2017

3 MONTHS ENDED

JUNE 30, 2016

Production

Crude oil & NGLs (bbl/d) 9 3 7

Natural gas (Mcf/d) 5,550 4,825 5,560

boe/d 934 807 933

Financial (Canadian $ M, except per boe amounts)

P & NG revenues (net) 3,764 3,088 4,809

Funds flow from (used in) operations 959 (2,883) (2) 2,098

Net income/(loss) (526) (2,001) (642)

Exploration & development capital expenditures 4,011 1,932 3,215

Operating costs ($/boe) 15.70 (1) 8.37 6.23

Average operating netback ($/boe) 22.38 28.62 43.02

Net working capital surplus 8,618 7,545 5,741

Cash 9,903 5,760 4,611

(1) Includes repairs and maintenance to facilities and wells, which are not expected to be recurring, and employee bonuses earned in 2016 totalling approximately $0.4 MM.

(2) Includes one-time transaction related expenses: $0.9 MM legal and advisory expenses; $1.6 MM in realized foreign exchange loss related to the translation of funds repatriated; and $1.1 MM in a preliminary estimate of taxes incurred primarily for the Statoil funding on the sale of the West Thrace lands (future drilling expenditures for 2017 will provide a significant reduction to this temporary current tax obligation).

See ‘Non-IFRS Measures’ and ‘Barrels of Oil Equivalent’ (“boe”) under “Reader Advisories” starting on Slide 24 of the August 2017 Corporate Presentation.

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6

Turkey Pro Forma Reserves Post TBNG Acquisition (Company Gross) (1)(2)(3)

(1) Valeura’s reasonable expectation of how the TBNG Acquisition, had it occurred on or before the effective date of the information set out in Valeura’s Statement of Reserves Data and Other Oil and Gas Information contained in the 2016 AIF, would have affected such information.

(2) D&M's valuations for reserves in Turkey are prepared in US$ and have been converted for purposes of this illustration to Cdn$ assuming a $Cdn/$US exchange rate of 0.74 for the year-end 2016 values.

(3) The forecast prices used in the calculations of the present value of future net revenue for year-end 2016 are based on the D&M December 31, 2016 forecast prices, which are contained in the 2016 AIF for the year ended December 31, 2016.

(4) D&M evaluated reserves as at December 31, 2016 on the Company’s Banarli lands (100% working interest) and on the TBNG JV lands (40% working interest).

(5) TBNG's working interest in the TBNG JV lands is 41.5%. TBNG's reserves as of December 31, 2016 as presented were prepared internally (non-independent) by Valeura by making a mathematical adjustment of the Company's TBNG JV lands reserves that represent a 40% working interest to reflect TBNG's 41.5% working interest.

See ‘D&M Reserves Disclosure’ and ‘Future Net Revenue’ under “Reader Advisories” starting on Slide 24 of the August 2017 Corporate Presentation.

PRO FORMA RESERVES AND NET PRESENT

VALUE AT 10% BEFORE TAX

YEAR ENDED DECEMBER 31, 2016

CHANGE

%

VALEURA(4) TBNG(5) PRO FORMA

Reserves Volumes (Mboe)

Proved Reserves 1,567 1,318 2,885 84

Proved plus Probable Reserves 4,704 4,198 8,902 89

Proved plus Probable plus Possible Reserves 7,230 6,315 13,545 87

Reserves Value – NPV10 Before Tax ($MM)

Proved Reserves 21.0 14.2 35.2 68

Proved plus Probable Reserves 61.8 47.9 109.7 78

Proved plus Probable plus Possible Reserves 103.8 80.5 184.3 78

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Land Position In Turkey Post Closing of Transactions GDPA awarded TBNG JV two production leases F19-d3-1 & F19-c3-1 on February 2, 2017

TBNG JV relinquished two non-producing exploration licences at Gaziantep in southeast Turkey N39-a1,a4 & N39-d1,d2 on January 17, 2017

(1) Post West Thrace Deep Rights Sale and Subsequent West Thrace Deep Rights Sale (aggregate 87,023 net acres of deep rights sold to Statoil) but prior to potential earning by Statoil of 50% in the deep rights on the Banarli licences under the Banarli Farm-in.

(2) Reflects approval of two new production leases (G18-b1-1 and G18-b2-1) in December 2015 carved out from exploration licence 3931, expiry of exploration licences 3931 and 3934 and relinquishment of any residual exploration acreage. The area relinquished included 56,012 gross acres onshore (22,405 acres net) and 68,453 gross acres offshore (10,268 acres net). Also reflects February 2017 approval of two new production leases including F19-d3-1 as a carve-out from expired exploration licence 3934 and F19-c3-1 as a carve-out from expired exploration licence 4126.

(3) Reflects conversion of old exploration licence 5151 to two new licences effective June 27, 2015 and expiry of old exploration licence 3858. The TBNG JV requested and the GDPA subsequently posted part of the area encompassed by the relinquished old exploration licence 3858 (30,048 gross acres) (F18-d3) for new bids (submitted September 16, 2015). In July 2017 the GDPA advised that no bids were accepted for this licence. This area may be available for a potential future application.

(4) Reflects the conversion of old Banarli exploration licence 5104 to two new exploration licences (F18-c1, c2, c3, c4 and F19-d1, d4) effective June 27, 2015. The gross and net acreage shown includes 9,981 acres in the northeast corner of licence F19-d1, d4 that could revert to Turkiye Petrolleri Anonim Ortakligi (“TPAO”) if certain work program obligations are performed by TPAO on this land. This small area was once held by TPAO as part of a larger licence that expired prior to the Banarli licence conversion process but was included by the GDPA in the new Banarli licence F19-d1, d4 to enable its adaptation to encompass all of the un-licenced area in the quadrant.

(5) Excludes any potential acreage additions from bids submitted by Valeura to the GDPA for two new exploration licences (F18-b3 and F19-a4) contiguous with the Banarli licences. These bids remain under review by the GDPA.

AREA LEASES & LICENCES

(#)

GROSS AREA (acres)

VALEURA NET AREA SHALLOW RIGHTS

(acres)

VALEURA NET AREA DEEP RIGHTS (1)

(acres)

THRACE BASIN

TBNG JV Licences & Leases (2) (3) 16 344,781 280,996 193,973

Banarli Licences (4) (5) 2 133,840 133,840 133,840

Edirne Leases 3 49,883 17,459 17,459

TOTAL 21 528,504 432,295 345,272

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I-8 Rig Drilling at TDR-9

TBNG JV – Now Under Valeura Operatorship

9

Highly accretive pro forma acquisition metrics:

Transformational transaction for VLE:

- Captures operatorship allowing VLE to control the pace & direction of development of TBNG JV lands

- VLE gains control of upstream and marketing infrastructure; ensures access to market to execute growth program

- Capitalizes on VLE’s 5-year experience with the assets and proven operational skills

- Facilitates Banarli development given current volumes are sold to the TBNG JV and are tied into the TBNG JV facilities and customer base

Opportunity to execute a fully funded shallow gas development program on the TBNG JV and Banarli lands:

- Expect to execute $13 to 14MM shallow gas capital program in 2017 of up to six wells (gross), targeting 2017 exit rate sales of approximately 1,000 to 1,100 boe/d (net)

- Planned drilling program includes up to five wells on TBNG JV lands and one well on Banarli licences

Key Benefits of TBNG Acquisition

Measure Pro Forma Accretion (1)

Absolute Per Share (2)

Cash Flow (3) 78% 43%

Production (4) 54% 23%

2P Reserves (5) 89% 51%

(1) See Valeura’s business acquisition report with respect to the TBNG Acquisition. (2) Based on 58.5 million shares pre-Offering and 73.1 million shares post-Offering. (3) Based on annualized Q4 2016 cash flow. Cash flow herein is defined as revenue less royalties, operating costs and general and administrative ("G&A") expenses,

including an estimated incremental G&A burden of $1.0 million associated with the TBNG Acquisition. (4) Based on annualized Q4 2016 sales from TBNG's 41.5% working interest in the TBNG JV. (5) Based on Valeura's allocation of D&M’s estimate of Valeura’s reserves for the TBNG JV lands at December 31, 2016 in the 2016 D&M Reserves Report.

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TBNG JV Assets & Operations

Interests in 16 leases & licences in Thrace Basin (0.34 MM gross acres)

Well established shallow gas production and marketing business:

- ~85 producing wells (gross) (conventional gas & tight gas) in 15 gas accumulations

- TBNG JV owned gathering system, sales lines and dehydration/compression facilities

- Direct sales to 55 light industry customers

- Conventional shallow gas program in the Danismen and Osmancik Formations has included workovers, recompletions and drilling on new 3D seismic (650 km2)

- Drilled 21 new conventional shallow gas wells since 2012

Extensive “proof of concept” program completed to significantly de-risk the tight gas play:

- Tight gas resources in deeper sands in the Mezardere, Teslimkoy and Kesan Formations

- Completed 50 well re-entry fracs in existing wells

- Drilled 20 new tight gas wells since 2012, including six horizontal wells, and fraced 18 of these

Targeting workover and drilling program to grow shallow gas production, underpinned by relentless focus on safety, improved capital efficiency and reduced unit opex and G&A:

- 27 workovers completed year to date in 2017, essentially offsetting natural declines in the production base

- Expect to drill five exploration wells on TBNG JV lands in 2017 (and one shallow exploration well at Banarli)

- Dogu Atakoy-3 (commitment well) spudded January 24 (TD 1,303 m); on-stream March 8

- Dogu Kilavuzlu-2 spudded May 22 (TD 1,260 m); on-stream June 30

- Sariyer-1 (commitment well) spudded June 7 (TD 2,420 m); cased; completed; evaluating

- Koseilyas-2 spudded July 6 (TD 1,107 m); cased; on-stream August 9

- Karaevli-6 expected to spud late August See ‘Non-IFRS Measures’ and ‘D&M Reserves Disclosure’ under “Reader Advisories” starting on Slide 24 of the August 2017 Corporate Presentation.

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TIGHT GAS

Mezardere, Teslimkoy & Kesan

Normally-pressured over much of the TBNG JV lands

50 well re-entry fracs since mid-2011

20 new drills in 2012-2017 YTD (14 vertical & 6 horizontal) of which 18 fraced

SHALLOW GAS

Danismen & Osmancik

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

83 workovers & 21 new drills in 2012-2017 YTD

H2 2014 Osmancik discoveries in Osmanli area indicate new play type potential

TBNG 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

Dogu Kilavuzlu-2 Dogu Gurgen-1

Koseilyas-2

Bati Yayli-1

Koseilyas-4

Kilavuzlu-3 Dogu Osmanli-2

Guney Karababa-2

Karaevli-6

Sariyer-1

Drill Ready

Yamalik-1

Potential Pressure Seal Area 1,500 km2

@~2,500 m

5 km

Other Prospects

Statoil Deep Test

12

Conventional Shallow Gas Exploration Prospect Inventory

TBNG JV - West Thrace

Banarli

TBNG JV - South Thrace

Potential Tekirdag Tight Gas

Development Area

Karaca 3D Seismic Extension

~500 km2

Gross TBNG JV/Banarli Area 478,621 acres or

748 MIles2

Karanfiltepe-7

Dogu Atakoy-3

Aydinkoy-1

13

TBNG JV Gathering System & Pipeline Infrastructure

5 km

TBNG JV 8”-10” Sales Line

TBNG JV 6” Sales Line

TBNG JV 10”

BOTAS 12” - Zorlu Distributor

BOTAS 2 x 36” - Russian Gas

BOTAS - Interconnector

TBNG JV Central Compression

Facility

TBNG JV Customer Base

TBNG JV - West Thrace

TBNG JV - South Thrace

Banarli Licences

TBNG JV Gathering & Sales Lines BOTAS Pipelines

Potential Tight Gas Development - Tekirdag Field (1)

2011-2015 frac results in Mezardere, Teslimkoy and Kesan formations shown on map

Vertical stacking of Mezardere, Teslimkoy & Kesan sands 75+ locations on 40 acre spacing

Exploit with multi-stage fracs (1) Rates shown are initial peak 24-hour on-stream rates.

See ‘Initial On-Stream Production Rates’ and ‘Drilling Locations’ under “Reader Advisories” starting on Slide 24 of the August 2017 Corporate Presentation. 14

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

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

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

Banarli – Provides Material Exploration Upside in Shallow & Deep Formations

KCA Deutag T-207 Drilling at Yamalik-1 – July 2017 15

16

Banarli Exploration Strategy Banarli licence awarded to Valeura (100% WI) in April 2013 (541 km2; 209 square miles)

Potential for five exploration play types:

1.Osmancik/Danismen transverse fault play

2.Osmancik/Danismen stratigraphic traps

3.Mezardere/Teslimkoy slope fan/basin floor fan play with structural & stratigraphic closure

4.Mezardere/Teslimkoy slope fan play with stratigraphic closure only

5.Basin-centered gas play concept

Pursuing strategy to exploit conventional shallow gas in the Danismen and Osmancik formations on a 100% basis (<2,500 m) & work with farm-in partner Statoil to assess the deeper basin-centered gas play concept (>2,500 to 4,000+ m)

Initial exploration program completed to date:

– Acquired 152 km2 of new 3D seismic in Q2 2015

– Drilled three wells in Q4 2015 and Q2 2016 of which two are producers (Bati Gurgen-1 & 2) and a third is suspended (Yayli-1) awaiting potential recompletion

– Bati Gurgen-1 and Yayli-1 confirmed over-pressure below approximately 2,500 metres

Execute shallow and deep exploration program in 2017:

– Drill 1st deep well Yamalik-1 under Banarli Farm-in: spudded May 13 and rig released July 22 (TD 4,196 m; cased; awaiting completion, multi-stage fracing and testing

– Acquire 500 km2 3D seismic under Banarli Farm-in: commenced June 18

– Drill at least one shallow well (Valeura 100% participating interest): Aydinkoy-1 spudded on July 19 (TD 2,821 m); cased; preparing to complete and test

The seven deep wells within the potential pressure seal area show pressure gradients ranging from 0.60 - 0.79 psi/ft below 2,500 m as measured by mud weights during drilling and pressure measurements

Compares to normal pressure gradient of ~0.433/ft

Potential Basin-Centered Gas Play Fairway (Play Type 5)

17

Mezardere Depth

Structure CI 100 m

Potential Pressure Seal Area 1,500 km2

@ ~2,500 m

10 km

Ergene-1 0.68 psi/ft

Kayi Derin-1 0.43 psi/ft

Hayrabolu-10 0.75 psi/ft

Kazanci-5 0.77 psi/ft

Baglik-1 0.43 psi/ft

Alacaoglu-1 0.73 psi/ft

Kandamis-1 0.77 psi/ft

Kayi Derin-1 & Baglik-1 are normally pressured and not within the potential pressure seal area

Yamalik-1 0.79 psi/ft Yayli-1

0.69 psi/ft

Banarli F18-c1,c2,c3,c4 Banarli

F19-d1,d4

Normal Pressure

Transition Zone Pressure

Over Pressure

XPT – Wireline Pressure Test DFIT – Diagnostic Fracture Injection Test

Bati Gurgen-1 0.69 psi/ft

18

Statoil Banarli Farm-in Banarli Farm-in transaction closed on Jan 6, 2017; Statoil to invest at least US$36 MM in three phases to

earn 50% interest below 2,500 m in Banarli licences; Valeura retains 100% interest in the shallow formations above 2,500 m

Phase 1 commitment (2017):

− US$6 MM payment to Valeura for back costs (funds received January 6, 2017)

− Required minimum investment of US$10 MM to drill, frac and test 4,000 m well


− Statoil has the option to exit after Phase 1 by paying a penalty of US$10 MM (US$26 MM minimum investment at that point)

− If Statoil elects to proceed to Phase 2, minimum investment of US$10 MM required for 3D seismic acquisition and processing


− Statoil has the option to exit after Phase 2 by paying a penalty of US$5 MM (US$31 MM minimum investment at that point)

− If Statoil elects to proceed to Phase 3, minimum investment of US$10 MM to drill, frac and test 2nd 4,000 m well

Valeura will operate deep programs (and shallow) during the Statoil earning phase; Statoil has option to operate deep program post earning

Planned farm-in program in 2017:

– Agreed final AFE cost of US$12.85 MM for Yamalik-1 well drilling, logging, coring (including analysis), casing and rig mobilization/demobilization (Statoil to fund up to 110% of AFE)

– Yamalik-1 drilled within budget and achieved positive results: TD 4,196 m; cored 134 m; log evaluation results exceeded criteria to proceed with completion and testing

– Design of completion, multi-stage frac and testing program being developed under a separate AFE; expect to commence completion by early Q4 2017

– 3D seismic acquisition underway targeting 500 km2 at a cost of US$10 MM and completion by early Q4 2017

(1) These are internally generated prospects and drilling locations.

19 See ‘Drilling Locations’ and ‘Initial On-Stream Production Rates’ under “Reader Advisories” starting on Slide 24 of the August 2017 Corporate Presentation.

Banarli Osmancik/Danismen Prospects (< 2,500 m Depth)

Banarli Osmancik/Danismen

Prospects (<2,500 m)

Discoveries

Drill Ready

Other Prospects (1)

Aydinkoy-1

Gurgen Field Bati Gurgen-1

Osmancik IP30 3.4 MMcf/d

Yayli-1 Teslimkoy Fraced

Osmancik Temporarily Suspended

Mid Danismen PSTM Time Structure

Osmanli Field

Bati Gurgen-2 Osmancik

IP30 1.1 MMcf/d

Yamalik-1

Bati Yayli-1

Banarli Farm-in

1st Deep Well

20

Unconformity

Yayli-1 Ergene-1

Teslimkoy Member Basin Floor Fans

Mezardere Slope Channels

Osmancik Shorelines

Banarli Licenses Boundary

Ergene-1

Yayli-1

Top Potential Pressure Seal

TD 2,914 m

TD 2,967 m

Map View Depth Slice @ 2,500 m

Formations & Depositional Environments Within Potential Pressure Seal Area

TD 4,196 m

Yamalik-1

45.01 46.4840.41

25.26

6.81 6.36

7.63

12.32

8.10 8.26

7.18

5.88

0

10

20

30

40

50

60

70

80

2014 2015 2016 H1 2017

Netback Opex Royalty

Sales Price

59.92 61.10

55.52

43.46

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

(1) See ‘Non-IFRS Measures’ under “Reader Advisories” starting on Slide 24 of the August 2017 Corporate Presentation.

(2) Vertical wells: 1,200 m MD; tie-in to existing facilities (3) Vertical wells: 2,000 m MD; tie-in to new facilities. (4) Vertical wells: 1,400 m MD; four-stage frac; tie-in to existing facilities.

TBNG JV BANARLI

CONVENTIONAL GAS VERTICAL WELL (1200 m) (2)

Drill & Case (1,200 m TVD) 0.6 NA

Complete & Tie-in 0.4 NA

Total 1.0 NA

CONVENTIONAL GAS VERTICAL WELL (2000 m) (3)

Drill & Case (2,000 m TVD) 1.2 1.2

Complete & Tie-in (new facilities) 1.0 1.0

Total 2.2 2.2

TIGHT GAS VERTICAL WELL (1400 m) (4)

Drill & Case (1,400 m MD) 0.8 NA

Multi-stage Frac 1.0 NA

Tie-in 0.1 NA

Total 1.9 NA

Current Cost Structure – US$MM (gross)

21

Operating Netbacks – $/boe (1)

22

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

(US$MM)

RECYCLE RATIO (6)

Thrace Basin - Gas

Shallow Gas Drilling (1,200 m) with Tie-in to Existing Facilities

0.5 0.8 1.0 80 21 0.5 1.8

Shallow Gas Drilling (2,000 m) with Tie-in to New Facilities

1.2 2.3 2.2 >100 10 2.1 2.1

Tight Gas Vertical Drilling (1,400 m) & Multi-Stage Frac with Tie-in to Existing Facilities

0.7 1.1 1.9 56 25 0.9 1.7

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) Reserves per successful well assuming 40 acre drainage area. (3) Internally generated type curves (raw gas) for new drills reflect IP30 sales rates as shown for the various well types and up to a 65% decline rate in the 1st year. (4) Cost to drill, complete and equip a vertical well to the following MD: shallow conventional gas 1,200 m or 2,000 m; tight gas 1,400 m completed with a 4-stage frac. (5) Utilizing the following natural gas price deck: TBNG JV US$5.70/Mcf in 2017, US$6.33/Mcf in 2018, US$6.57/Mcf in 2019, US$6.83/Mcf in 2020, US$7.11/Mcf in 2021,

US$7.43/Mcf in 2022, US$7.77/Mcf in 2023, US$8.24/Mcf in 2024, US$8.73/Mcf in 2025, escalated 2%/year thereafter; Banarli US$5.55/Mcf in 2017, US$6.20/Mcf in 2018, US$6.43/Mcf in 2019, US$6.69/Mcf in 2020, US$6.96/Mcf in 2021, US$7.28/Mcf in 2022, US$7.61/Mcf in 2023, US$8.07/Mcf in 2024, US$8.55/Mcf in 2025, escalated 2%/year thereafter.

(6) Recycle ratio = operating netback (fist year) ÷ finding and development (“F&D”) cost. First year operating netback based on: 12.5% government royalty + 1% gross overriding royalty on TBNG JV lands; 12.5% government royalty on Banarli lands; operating costs: 2,000m shallow gas – US$1.00/Mcf + US$3,500/well month; 1,200 m shallow gas and tight gas - US$0.45/Mcf + US$3,000/ well month. F&D cost includes front end capital only and excluding past land and seismic costs. See ‘Future Net Revenue’ and ‘Recycle Ratio’ under “Reader Advisories” starting on Slide 24 of the August 2017 Corporate Presentation.

23

Summary

VLE provides exposure to high operating netback, natural gas pure play in Turkey

Statoil Farm-in on deep formations at Banarli has validated potential for a high impact basin-centered gas play on VLE lands in the Thrace Basin

VLE retained interest in deep rights of 50% at Banarli and 31.5% at West Thrace provide significant optionality if basin-centered gas play successful

TBNG Acquisition doubled VLE’s interest to 81.5% in base business shallow gas play on the TBNG JV lands and established VLE as operator

US$21 MM of cash received from Statoil and gross proceeds of $11 MM from subscription receipts financing have funded TBNG Acquisition and enabled a ramp-up of shallow gas workovers and drilling

1st deep well under Banarli Farm-in, Yamalik-1, achieved positive drilling results, exceeding criteria to proceed with completion and testing expected to commence by early Q4 2017; Phase 2 3D seismic also well advanced

Pausing 2017 shallow gas drilling program at six wells to retain financial flexibility in the event the pace of the deep program with Statoil is accelerated in 2018, based on positive deep drilling results at Yamalik-1

Currently targeting 2017 shallow gas capex program of $13 to 14 MM (net) and an exit sales rate of approximately 1,000 to 1,100 boe/d (net)

24

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: the Corporation’s 2017 and 2018 work program, operational plans (drilling and target depths) on the TBNG JV lands and Banarli licences, expected capital expenditures, target exit volumes and expected timelines; the expected timeline and cost of the Yamalik-1 completion and testing program; the estimated scope and cost of the 3D seismic program under the Banarli Farm-in; the key benefits of the TBNG Acquisition, the West Thrace Deep Rights Sale and the Subsequent West Thrace Deep Rights Sale; the TBNG Acquisition metrics; the ability to ramp-up the drilling program in the shallow formations on the TBNG JV lands and Banarli licences and the associated prospectivity; the ability to fulfill the 2017 drilling commitment program on the West Thrace lands; and, the extent of over-pressure below approximately 2,500 metres across the Banarli licences and West Thrace lands and the potential for a basin-centered gas play. 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" are deemed forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves can be profitably produced in the future.

Forward-looking statements are based on management's current expectations and assumptions regarding, among other things: political stability in Turkey; continued safety of operations and ability to proceed in a timely manner; continued operations of and approvals forthcoming from the GDPA in a manner consistent with past conduct; future seismic and drilling activity on the expected timelines; the prospectivity of the TBNG JV lands and Banarli licences, including the deep potential; the ability to meet drilling deadlines and other requirements under licences and leases; the potential reversion of 9,981 acres in Banarli licence F19-d1, d4 to TPAO; the continued favourable pricing and operating netbacks in Turkey; future production rates and associated operating netbacks and cash flow; future economic conditions; future currency 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 work programs and budgets are in part based upon expected agreement among joint venture partners, which are subject to change based on, among other things, the actual results of drilling and related activity, availability of fracing 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: failure to realize the key benefits of the TBNG Acquisition, the West Thrace Deep Rights Sale and the Subsequent West Thrace Deep Rights Sale; the risks of currency fluctuations; changes in gas prices and netbacks in Turkey; 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 in Turkey; political stability in Turkey in light of the July 2016 failed coup attempt and its aftermath and the results of the April 2017 constitutional referendum; the risks of increased costs and delays in timing related to protecting the safety and security of Valeura's personnel and property; the uncertainty regarding government and other approvals; potential changes in laws and regulations; risks associated with weather delays and natural disasters; the risk associated with international activity; the uncertainty regarding the ability to fulfill the 2017 drilling commitments on the West Thrace lands and other drilling deadlines and requirements under other licences and leases; 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, and the ability to mitigate these declines; uncertainty regarding the state of capital markets; uncertainty regarding the amount of operating cash flow; the uncertainty associated with negotiating with third parties; counterparty risk; and the risk of partners having different views on work programs and potential disputes among partners. 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.

Any financial outlook or future oriented financial information in this presentation, as defined by applicable securities legislation, has been approved by management of Valeura, including, but not limited to, the expected acquisition and accretion metrics for the TBNG Acquisition. 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.

25

Reader Advisories (Cont’d)

Other Advisories: INITIAL ON-STREAM PRODUCTION RATES: The initial on-stream production rates and short production test 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 typically disclosed with reference to the number of days in which production is measured (e.g., IP30 refers to an initial on-stream production rate measured over a 30 day period). Initial on-stream production rates are not necessarily indicative of long-term performance or ultimate recovery. To date, shallow gas conventional wells and fraced 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

ESTIMATED ULTIMATE RECOVERY (“EUR”): An approximation of the quantity of oil or gas that is potentially recoverable or has already been recovered from a reserve or well. EUR is not defined in the COGE Handbook.

CUMULATIVE PRODUCTION: the total amount of oil and gas recovered from a reservoir as of a particular time in the life of the field, basin or well, as the case may be. Cumulative production is not defined in the COGE Handbook.

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.

DRILLING LOCATIONS: This presentation discloses 75+ potential drilling locations on 40 acre spacing in the Tekirdag area on the TBNG 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 2016 D&M Reserves Report, which attributes reserves to 16 proved undeveloped locations, 46 probable undeveloped locations and 19 possible undeveloped locations (81 locations in aggregate) in the Tekirdag area. The shallow gas prospects and potential drilling locations on the Banarli licences and TBNG JV lands are based on internal estimates and review. 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. The Yamalik-1 drilling location for a deep exploration test was selected by Statoil for the first well under the Banarli Farm-in.

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 DISCLOSURE: The 2011, 2012, 2013, 2014, 2015 and 2016 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, the 2014 D&M Reserves Report, the 2015 D&M Reserves Report and 2016 D&M Reserves Report, respectively. The foregoing reports were prepared using assumptions and methodology guidelines outlined in the COGE Handbook and in accordance with NI 51-101. The 2016 D&M Reserves Report does not give effect to the TBNG Acquisition.

26

Reader Advisories (Cont’d)

Glossary: Certain other terms used in this presentation but not defined herein or under "RESERVES DEFINITIONS" below are defined in NI 51-101 or the AIF and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101 or the AIF, as applicable.

"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.






"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” means Thrace Basin Natural Gas (Turkiye) Corporation.

"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 TBNG and Pinnacle Turkey, Inc. (“PTI”) by Valeura and an affiliate of TransAtlantic Petroleum Ltd. completed in 2011.

"TBNG JV" means the joint venture of Valeura (40% WI), TBNG (41.5% WI; operator) and PTI (18.5% WI).

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

27

Reader Advisories (Cont’d) Reserves 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.

"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 3P reserves.

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 (seismic) WI working interest 3D three dimensional (seismic) 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 ft

true vertical depth feet

P10 psi PSTM

10% probability of occurrence based on Monte Carlo analysis pounds per square inch pressure pre-stack time migration (seismic)

A GLOBAL ENERGY COMPANY FOCUSED ON EXCEPTIONAL VALUE CREATION

SUPPLEMENTARY INFORMATION

29

Our Heritage

Senior Management

Board of Directors

Past Successes of Management & Board

Market Cap ~$4,827 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%

Sold in 2006 $306 mm

1.4x ROI (’03-’06) CAGR 10%

30

Sold in 2014 $1,800 mm

2x ROI (’11-’14) CAGR 24%

31

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 & NOCs returning to Turkey (offshore; onshore unconventional)

Positive Business Environment

G-20 country and NATO member

Coup attempt by elements of military on July 15, 2016 put down by government

April 16, 2017 constitutional referendum approved

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

New Petroleum Law passed June 30, 2013

Available infrastructure & oil field equipment

No fracing restrictions

More than 92% reliant on imports of oil & gas

Exposure to world oil prices & premium gas prices linked to cost of imports

Energy corridor to Europe

Thrace Basin (natural gas)

TBNG-PTI Acquisition opportunity

2011 Initial TBNG acquisition (natural gas & light/medium oil)

Anatolian Basin (medium oil)

Organization Chart

32

BOARD OF DIRECTORS

Jim McFarland

PRESIDENT & CEO

Bill Fanagan Jim McFarland Claudio Ghersinich Ron Royal Tim Marchant Stephanie Stimpson, Corporate Secretary

VP ENGINEERING

VP EXPLORATION

VP OPERATIONS

Don Shepherd Lyle Martinson Rob Sadownyk Barry Wihak

GEOSCIENCE TECHNICIAN

Mike Kohut 3 G&G 2 D&C 1 Eng 0.5 IT 1 Procure 1 HSE 1 Acc

TURKEY BRANCH (ANKARA)

Heather Campbell

CONTROLLER CONSULTANTS ©

COO

Sean Guest

VP BUSINESS

DEVELOPMENT

14 Financial, Regulatory &

Admin Employees

JV ACCOUNTANT

Debbie Harding

TBNG (TEKIRDAG)

56 Operational Employees

Mehmet Ekinalan (Country Rep)

Steve Bjornson

CFO

Namik Ertem (Operations Mgr)

33

Senior Management

President & CEO: Jim McFarland, P. Eng.

44 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) - VP roles (Environment; Oil Sands; Exxon Production 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)

34

Senior Management (Cont’d) COO: Sean Guest, Ph.D.


Former Chief Executive Officer: Bukit Energy Inc. (private) (Indonesia); and Pexco Energy (private) (Australia, Indonesia, Malaysia, Ethiopia)

5 years in leadership roles with Woodside Energy: General Manager, Australia Exploration & New Business; and Exploration Manager, Libya

12 year career with Shell in exploration and research functions (Australia, Malaysia and the Netherlands)

Ph.D. Geology (Queen’s); B.Sc. Applied Science (Honours) (Queen’s)

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)

35

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

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

BSc Electrical Engineering (Saskatchewan)

VP Exploration: 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)

Senior Management (Cont’d)

36

VP 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)

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)

Senior Management (Cont’d)

37

Board of Directors

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, Vermilion Energy Inc., & Verenex Energy Inc. Business and engineering background

Tim Marchant, Ph. D

Adjunct Professor, Strategy & Energy Geopolitics, Haskayne School of Business, University of Calgary Former VP Exploration & Production, BP Middle East Geological background (Ph. D)

Jim McFarland, P. Eng. President & CEO Engineering background

Ron Royal, P. Eng. Former President & GM, Esso Chad Engineering background

38

Turkey YE 2016 Reserves (Company Gross) (1)

CATEGORY

LIGHT & MEDIUM OIL

(Mbbl)

NATURAL GAS

(Bcf)

TOTAL OIL EQUIVALENT

(Mboe)

NPV10 BEFORE TAX

($MM)

NPV10 AFTER TAX

($MM)

PROVED DEVELOPED PRODUCING

6 2.8 470 9.3 9.3

PROVED DEVELOPED NON-PRODUCING

- 2.4 405 6.9 6.2

PROVED UNDEVELOPED

- 4.2 692 4.7 3.1

TOTAL PROVED 6 9.4 1,567 21.0 18.6

PROBABLE 3 18.8 3,137 40.8 33.0

TOTAL PROVED PLUS PROBABLE

9 28.2 4,704 61.8 51.6

POSSIBLE 5 15.1 2,526 42.0 34.2

TOTAL PROVED, PROBABLE AND POSSIBLE

14 43.3 7,230 103.8 85.8

(1) Based on a $Cdn/$US exchange rate of 0.74 at December 31, 2016 to convert US$ denominated reserves values in the 2016 D&M Reserves Report. The 2016 D&M Reserves Report does not give effect to the TBNG Acquisition.

See ‘D&M Reserves Disclosure’ and ‘Future Net Revenue’ under “Reader Advisories” starting on Slide 24 of the August 2017 Corporate Presentation.

39

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

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

See ‘Initial On-Stream Production Rates’ under “Reader Advisories” starting on Slide 24 of the August 2017 Corporate Presentation.

Mezardere Slope Fan Play Fairway

40

Slope fan play in Mezardere Formation showing encouraging results

Seismic imaging clearly shows channel trends with both structural & stratigraphic trapping potential

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

− 2 Mezardere horizontal wells drilled and fraced in 2014

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


10 km

Tekirdag

Banarli

Prospective Mezardere

play fairway

Mezardere Depth Structure

Tekirdag area Mezardere

exploitation program

Tekirdag

Area

Producing

Slope

Channels

Koseilyas-1

Gazi-1

2 km

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

41

(1) Rates shown are IP30 rates for fraced Mezardere ("Mez") or Teslimkoy ("Tes") formation completions and un-fraced Osmancik ("Osm") formation completions.


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)

TBNG JV 2014/2015 drills

Banarli exploration

drills 2015/2016

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)

Dogu Osmanli-1 Cased (Mez)

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

Banarli

Potential Pressure

Seal

2015 3D:

152 km2

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

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




IP30 3.4 MMcf/d

Yayli-1 Teslimkoy fraced

Osmancik completion temporarily suspended


IP30 1.1 MMcf/d

42

(1) Estimated Ultimate Recovery (“EUR”) = Cumulative Production to December 31, 2015 + 2P Reserves at December 31, 2015. (2) These are internally generated prospects and drilling locations. See ‘Drilling Locations’, ‘D&M Reserves Disclosure’ and ‘Initial On-Stream Production Rates’ under “ Reader Advisories” starting on Slide 24 of the August 2017 Corporate

Presentation.

Osmanli EUR: 9.4 Bcf

Tekirdag EUR: 128 Bcf

Yagci EUR: 7.1 Bcf

Gazi EUR: 0.7 Bcf

Karaevli EUR: 1.8 Bcf

Gurgen EUR: 6.0 Bcf

Kayi EUR:12 Bcf

Aydinkoy

Yayli-1 Teslimkoy Fraced

Osmancik Completion Temporarily Suspended

Banarli F18-c1,c2,c3,c4

Banarli F19-d1,d4

TBNG JV Lands

Banarli licences Producing fields (1)

Banarli prospects (2)

Merged Banarli, Tekirdag & Osmanli 3D seismic (~550km2) similarity imaging

Vintage 2D Seismic Potential 3D Seismic (~600 km2) Potential Drilling Locations (2)

Muratli


IP30: 3.4 MMcf/d EUR: 4.9 Bcf

TBNG JV Producing Fields & Banarli Conventional Exploration Prospects


IP30: 1.1 MMcf/d

43

Formations Present At Top Of Potential Pressure Seal (2,500 m Depth)

Bati Gurgen-1 Yayli-1

Teslimkoy Basin Floor Fans

Mezardere Slope

Channels

Osmancik Shorelines

Lower Danismen

Coastal Plain

Potential Pressure Seal

Bati Gurgen-2

Time Horizon Slice - Similarity Seismic Image

44

Bati Gurgen-1

Yayli-1

5 km

Bati Gurgen-2

Basin Floor Fan - Spectral Decomposition Seismic Image

45

Bati Gurgen-1

Yayli-1

Upper Teslimkoy

Basin Floor Fan

Complex

Mezardere Slope

Channel

5 km

Osmancik

Shorelines

Bati Gurgen-2

46

TBNG 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); 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); 2 well re-entry fracs

2015 shallow gas program:

− Completed 9 workovers (4.0 MMcf/d aggregate initial 7-day rate) − Spudded 1 new drill on Osmanli 3D seismic (producing)

2016 shallow gas program: – Completed 1 workover (1.0 MMcf/d initial 7-day rate)

2017 YTD shallow gas program: – Spudded 4 new drills (3 producing; 1 completing/evaluating) – Completed 27 workovers (6.1 MMcf/d gross aggregate initial 7-day rate), essentially offsetting natural declines

10 km

F17-c2, c3 F18-d1, d2, d4

F18-c1, c2, c3, c4

F19-d4-2 F18-c4-2 F18-c3-1 F19-d4-1

F19-d1, d4

G18-b1 G18-b2 G19-a1-1

F19-d3-1 F19-c3-1

3860 3861

5122

2926

3659

Atakoy

Osmanli

Kazanci/ Hayrabolu

Gurgen

Kayi

Yagci/ Nusratli

Aydede Tekirdag

Gazi

Bekirler

Kilavuzlu/ Karaevli

F18-d3


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 fraced 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 (future fracing candidate)

TBNG JV Tight Gas Proof-Of-Concept Program Phases

47

Teslimkoy/Kesan Multi Frac Type Curve (Vertical Wells) (1)

48

(1) Refers to internally generated "type curve" forecast used to project well production rates and 2P reserves/well for vertical multi-stage fraced tight gas wells associated with the Tekirdag development area.

See “Reader Advisories” starting on Slide 24 of the August 2017 Corporate Presentation.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0

200

400

600

800

1000

1200

1400

1600

0 12 24 36 48 60 72 84 96 108 120 132 144 156

CUM

MLA

TIV

E P

ROD

UCT

ION

(RAW

) -Bc

f

RAW

GA

S RA

TE -

MM

scf/

d

TIME - months

2P Type Curve - Multi Frac Vertical Wells

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

Vertical Well, 2P - 0.8 Bcf, Cum. Production vs. Time

Shallow Gas (2,000m) Type Curve (Vertical Wells) (1)

49

(1) Refers to internally generated "type curve" forecast used to project well production rates and 2P reserves/well for vertical 2,000m MD Osmancik wells on Banarli lands.


0.0

0.5

1.0

1.5

0

500

1000

1500

2000

2500

3000

0 12 24 36 48

CUM

MLA

TIV

E P

ROD

UCT

ION

(RAW

) -Bc

f

RAW

GA

S RA

TE -

MM

scf/

d

TIME - months

2P Type Curve - 2,000m MD Vertical Wells



Shallow Gas (1,200m) Type Curve (Vertical Wells) (1)

50

(1) Refers to internally generated "type curve" forecast used to project well production rates and 2P reserves/well for vertical 1,200m MD shallow wells on TBNG JV lands.


0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

0

100

200

300

400

500

600

700

800

900

1000

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

CUM

MLA

TIV

E P

ROD

UCT

ION

(RAW

) -Bc

f

RAW

GA

S RA

TE -

Msc

f/d

TIME - months

2P Type Curve - 1,200m MD Vertical Wells



Tekirdag Area Horizontal Drilling

51


BTD-3

1st HZ well DTD-19H U. Kesan

425 m lateral 7-stage frac


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



52

TBNG JV New Drill Spuds In 2012 – 2017 YTD

TIME GROSS WELLS

SPUDDED PRODUCING

EVALUATING/

COMPLETING

CASED &

STANDING

PLUGGED &

ABANDONED DRILLING

UNCONVENTIONAL

2012 - 2013 17 15 1 - 1 -

2014 3 3 - - - -

CONVENTIONAL

2012 - 2013 10 6 2 - 2 -

2014 6 5 1 - - -

2015 1 1 - - - -

2017 YTD 4 3 1 - - -

TOTAL 2012 – 2017 YTD 41 33 5 - 3 -

F17-c2, c3 F18-d1, d2, d4

F18-c1, c2, c3, c4

F19-d4-2

F18-c4-2 F18-c3-1 F19-d4-1

F19-d1, d4

G18-b1 G18-b2 G19-a1-1

F19-d3-1 F19-c3-1

3860 3861

5122

2926

3659

Guney Kayi-1

Baglik-1

Dogu Karya-1, Sig-1

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

Guney Karababa-1

Dogu Gazi-2

Kayi Derin-1

10 km

Guney Atakoy-2

Koseilyas-1, 2

Deveseki-1

Atakoy-8

DTD-19, 19H

TDR-5H, 9, 11H, 14

Kuzey Atakoy-1

Tekirdag

Development

Area

Hayrabolu

Deep

Exploration

Area

Hayrabolu-10 Kazanci-5

Biyikali-2ST Tavanli-1

Guney Osmanli-3 Dogu Osmanli-1 Osmanli

New

Discovery

Area

Karanfiltepe-5, 6

Gurgen-1,2,3

Kayi-16

TSK-1, 2

Dogu Atakoy-3

Dogu Kilavuzlu-2

Sariyer-1

53

TBNG JV New Drill Spuds In 2012

WELL LICENCE SPUD

(d/m/y) RIG RELEASE

(d/m/y) WELL TYPE

TD (m)

STATUS AUGUST 10, 2017

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

54

TBNG JV New Drill Spuds 2013 – 2016 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 Plugged & Abandoned

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



55

TBNG JV New Drill Spuds 2017 YTD WELL LICENCE

SPUD (d/m/y)

RIG RELEASE (d/m/y)

WELL TYPE TD (m)


Dogu Atakoy-3 F18-D 24/01/2017 03/02/2017 Conventional 1,303 Producing

Dogu Kilavuzlu-2 F19-D 22/05/2017 31/05/2017 Conventional 1,260 Producing

Sariyer-1 F18-D 07/06/2017 28/06/2017 Conventional 2,420 Evaluating

Koseliyas-2 F19-D 06/07/2017 13/07/2017 Conventional 1,107 Producing

Thrace Basin Seismic

56

2011 Tekirdag/Hayrabolu 3D (413 km2)

Drilling on 2D seismic only prior to 2012

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

Valeura funded 2013 2D seismic on Banarli Licence & 2012 2D seismic on Copkoy Licence (licence expired)

Tiway Oil funded 2012 offshore 2D seismic

Valeura Banarli 152 km2 3D seismic acquisition completed June 10, 2015

Karaca 3D survey (500 km2) under Banarli Farm-in targeting early Q4 2017 completion

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)

10 km

2015 Banarli 3D (152 km2)

F17-c2, c3 F18-d1, d2, d4

F18-c1, c2, c3, c4

F19-d4-2 F18-c4-2 F18-c3-1 F19-d4-1

F19-d1, d4

G18-b1 G18-b2

G19-a1-1

F19-d3-1 F19-c3-1

3860

3861

5122

2926

3659

F18-d3 3860

57

Turkey Natural Gas Infrastructure

58

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

59

60

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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