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A GLOBAL ENERGY COMPANY FOCUSED ON EXCEPTIONAL VALUE CREATION

FIRST DEEP WELL YAMALIK-1 TESTING BASIN-CENTERED GAS PLAY CORPORATE PRESENTATION NOVEMBER 2017

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Valeura Corporate Profile – Positioned For Growth Valeura Energy Inc. ("Valeura" or "VLE") (TSX: VLE) is a Canada-based oil & gas company

producing natural gas in the Thrace Basin of northwest Turkey

Turkey is an attractive international jurisdiction for oil & gas:

−Flat 12.5% government royalty & 20% corporate tax

−Strong market for natural gas producers with imports accounting for 99% of supply

Current financial and operational performance:

−1024 boe/d net sales at $6.98/Mcf gas price & $22.66/boe operating netback in Q3 2017

− $5.5 MM working capital surplus (no debt) at September 30, 2017

−8.9 MMboe pro-forma 2P reserves (YE 2016) with $110 MM before tax NPV10 value ($1.50/share) (1)

Pursuing two-pronged strategy to grow reserves and production:

−Build-up shallow gas prospect inventory on new 3D seismic to support additional drilling

−Prove-up deep, potential high impact basin-centered gas play

Growth plan underpinned by four transformational transactions completed in 2017:

−US$36 MM farm-in by Statoil on deep rights at Banarli

−US$15 MM sale to Statoil of other deep rights at West Thrace

−US$20.7 MM acquisition of TBNG by VLE

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

Yamalik-1 well at Banarli (funded by Statoil) drilled to 4,196 metres with positive results:

– Multi-stage fracing & testing program commenced early November 2017; planned 60-day program

– 3D seismic acquisition (500 km2) under Phase 2 of Banarli Farm-in completed; processing underway See ‘Non-IFRS Measures’ and ‘Barrels of Oil Equivalent’ ("boe") under "Reader Advisories" starting on Slide 24 of the November 2017 Corporate Presentation.

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Thrace Basin Lands & Recent Transactions

3860

3861

3659 5122

50 km

Bulgaria

Turkey

Greece

Edirne

TBNG JV South Thrace

Black Sea

Sea of Marmara

Banarli

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

G19-a1-1

G18- b2-1

G18- b1-1

2926 TBNG acquisition

41.5% WI TBNG JV

1

2

Sale of 50% WI in deep rights to Statoil

at West Thrace

3

Statoil Banarli Farm-in

F19-d3-1

F19-c3-1

2016/2017

TBNG JV West Thrace

Basic shares outstanding at November 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 November 1, 2017

Institutions ~ 25%

Retail ~ 70%

Management & Directors 4.9% (11.6% fully diluted)

Q3 2017 Financial & Operating Highlights

RESULTS 3 MONTHS ENDED

SEPT 30, 2017 3 MONTHS ENDED

JUNE 30, 2017

Production

Crude oil & NGLs (bbl/d) 11 9

Natural gas (Mcf/d) 6,077 5,550

boe/d 1,024 934

Financial (Canadian $ M, except per boe amounts)

Funds flow from (used in) operations 1,165 959

Exploration & development capital expenditures 4,992 4,011

Operating costs ($/boe) 13.86 15.70 (1)

Average operating netback ($/boe) 22.66 22.38

Net working capital surplus 5,458 8,618

Cash 2,968 9,903

(1) Includes a backlog of repairs and maintenance to facilities and wells, much of which is not expected to be recurring.

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

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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 November 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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Current Land Position In Turkey (1)

(1) Valeura application for exploration licences F18-b3 & F19-a4 (North Banarli) unsuccessful (awarded to Turkish Petroleum October 2017). TBNG JV application for exploration licence F18-d3 unsuccessful (no bids accepted July 2017); licence re-posted for bidding in December 2017.

(2) Post West Thrace Deep Rights Sale and Subsequent West Thrace Deep Rights Sale (aggregate 87,023 net acres of deep rights sold to Statoil). (3) Based on Statoil earning 50% in the deep rights under the Banarli Farm-in requiring: US$6.0 MM contribution to back costs; drilling, completion and testing of two deep

wells (minimum investment US$10 MM each); and US10 MM for 3D seismic acquisition and processing. If the program is not completed penalties accrue and the deep rights revert to 100% ownership by Valeura.

(4) The gross and net acreage shown at Banarli 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.

AREA LEASES & LICENCES

(#)

GROSS AREA (acres)

VALEURA NET AREA SHALLOW RIGHTS

(acres)

VALEURA NET AREA DEEP RIGHTS

(acres)

THRACE BASIN

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

Banarli Licences (4) 2 133,840 133,840 66,920 (3)

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

TOTAL 21 528,504 432,295 278,352

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I-8 Rig Drilling at TDR-9

TBNG JV – Now Under Valeura Operatorship

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Highly accretive pro forma acquisition metrics:

Transformational transaction for VLE:

- Captured operatorship

- Gained control of upstream and marketing infrastructure

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

- Facilitates Banarli shallow and deep development: current shallow volumes are sold to the TBNG JV and are tied into the TBNG JV facilities and customer base; opportunity for Yamalik-1 sales volumes if upcoming completion program in Q4 2017 successful

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

- Plan to execute $12 to 13 MM shallow gas capital program in 2017 including 29 workovers and six drill wells (gross), targeting 2017 exit rate sales of approximately 1,000 to 1,100 boe/d (net)

- Drilling program completed Q3 2017 with five wells on TBNG JV lands and one well on Banarli licences with mixed results (three producers); build-up of drilling portfolio underway

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:

- ~86 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 22 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:

- 29 workovers completed in 2017 YTD

- Drilled five exploration wells on TBNG JV lands in 2017 YTD

- 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 spudded August 14 (TD 1,261 m); plugged & abandoned See ‘Non-IFRS Measures’ and ‘D&M Reserves Disclosure’ under "Reader Advisories" starting on Slide 24 of the November 2017 Corporate Presentation.

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TBNG Gas Gathering System & Pipeline Infrastructure

TBNG owns and controls all gas gathering and sales infrastructure

Existing owned system has capacity to increase production

Proximal tie-in point to existing network of DasGaz, the regional gas distributor

Proximal tie-in points to major gas pipelines

– Import line to Turkey grid (Russian gas)

– Export line to Greece

– Export line to Europe

TANAP to Europe (under construction)

Import line (Russian gas)

Export Line to Europe

Export line to Greece

DasGaz Line

20 km

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TIGHT GAS

Mezardere, Teslimkoy & Kesan

Normally-pressured on TBNG JV lands except parts of West Thrace

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)

85 workovers & 22 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

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Conventional Shallow Exploration Inventory

See ‘Drilling Locations’ under "Reader Advisories" starting on Slide 24 of the November 2017 Corporate Presentation.

Dogu Gurgen-1

Bati Yayli-1

Koseilyas-4

Kilavuzlu-3

Dogu Osmanli-2

Guney Karababa-2

Yamalik-1

5 km

TBNG JV - West Thrace

Banarli

TBNG JV - South Thrace

Potential Tekirdag Tight Gas Development Area

Karanfiltepe-7

Drill Ready Conventional Prospects

Conventional Prospects & Leads

Yamalik-1 - Deep BCGA Test

New 2017 Karaca 3D seismic significantly increases coverages of acreage

Karaca 3D Seismic

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 November 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

KCA Deutag T-207 Drilling at Yamalik-1 15

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

two licences under New Petroleum Law effective June 27, 2015

Potential for five shallow and deep 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 accumulation play concept

Pursuing strategy to exploit conventional shallow gas on a 100% basis (<2,500 m) & explore deeper basin-centered gas play potential under farm-in with Statoil (>2,500 to 4,000+ m)

Initial exploration program completed 2015-2016:

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

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

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

Executing 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; completion and testing expected to commence during November 2017

– Acquire 500 km2 3D seismic under Banarli Farm-in: commenced June 18; recording completed September 20; processing underway for late Q1 2018 completion (fast-track processing will provide earlier preliminary data)

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

D&M completing resource assessment for basin-centered gas play on Valeura lands in Q4 2017

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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

2017 work program:

– Yamalik-1 drilled within budget of US$12.85 MM (drilling, logging, coring (including analysis), casing and rig mobilization/demobilization) and achieved positive log evaluation results: TD 4,196 m; cored 134 m

– Yamalik-1 completion to include 8-stage frac and four zonal flow tests under US$10.3 MM AFE (Statoil funds up to 110% of AFE); commenced early November; with success, potential tie-in for long term test with gas sales

– 500 km2 Karaca 3D seismic recording completed and processing underway under US$10 MM budget: targeting fast-track processing results in December and final results Q1 2018

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Basin-Centered Gas Accumulation Play ("BCGA") Valeura identified potential for a BCGA in Thrace Basin based on drilling results and

regional geological modelling – 2011-2013

Valeura captured rights to majority of Thrace Basin BCGA fairway - 2013-2016

Statoil willing to fund work program to prove the model & earn 50% WI by: US$MM (1)

– Purchase 50% WI in West Thrace lands 15 (Actual)

– Pay back costs in Banarli Licences 6 (Actual)

– Drill and Test Yamalik-1 23 (Actual drilling cost & testing budget)

– Infill existing 3D seismic with Karaca 3D seismic 10 (Minimum expenditure)

– Drill and test additional deep exploration well in 2018 15 (Estimate)

What is a BCGA? (2)

Pervasive", basin-wide gas accumulations trapped in low permeable rock

"Potentially, one of the more economically important unconventional gas systems in the world" (2)

Up to 15% of total US gas production - 4 Tcf/year (3)

BCGA

Total US$69 MM (Actual & estimate)

(1) Estimated total investment based on Statoil completing all three phases of the Banarli Farm-in (compared to the minimum required investment of US$36 MM). (2) Diagram is a model of a BCGA per USGS. Categories of oil and natural gas occurrence as used in the National Assessment of Oil and Gas Project (Schenk and Pollastro, 2002).

(3) American Association of Petroleum Geologists and EIA Communication.

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BCGA Potential Fairway extends over ~ 1600 km2

Hayrabolu-10 Banarli West Thrace

10km 0

Pressure Seal Area @ ~2,500 m

BCGA play fairway defined by onset of overpressures and hydrocarbon generation window

8 deep wells on fringe of Thrace Basin all encounter: – High overpressures below ~ 2500m

– Increased mud gas and interpreted gas saturation in reservoir

– high temperatures

Yayli-1

Yamalik-1

Kazanci-5

Alacaoglu-1

Kandamis-1

Ergene-1

Bati Gurgen-1

Cross Section

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Ergene-1 Tekirdag Fields Yamalik-1 Yayli-1 Guney Osmanli-1 Misinili-1

Osmancik

Hydrostatic Gas Fields

10 km

2500m

3000m

4000m

5000m

S N

Basin Cross-section

Normal Pressure

Transition Pressure

Teslimkoy

Kesan

Over Pressure

Overpressured Zone of Interest

Mezardere

Strong Natural Gas Prices & Competitive Costs Drive Attractive Economics in Turkey

(1) See ‘Non-IFRS Measures’ under "Reader Advisories" starting on Slide 24 of the November 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 (1,200 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 (2,000 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 (1,400 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)

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33.43 28.62

22.38 22.66

8.47

8.37 15.70 13.86

6.07

5.50 6.20

5.62

0.00

10.00

20.00

30.00

40.00

50.00

60.00

Q4 2016 Q1 2017 Q2 2017 Q3 2017

$/b

oe

Operating Netbacks - $/boe (1)

Netback Opex Royalty

47.97

42.49 44.28

42.14

Sales Price

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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. 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) IP30 sales gas rates as shown for the various well types are based on estimates developed internally utilizing existing property-specific well performance data. Decline rates of

up to 65% are expected 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 November 2017 Corporate Presentation.

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Summary

VLE provides exposure to a natural gas pure play in Turkey, with attractive natural gas prices and a competitive fiscal and royalty regime

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 provides 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 funded the TBNG Acquisition and the ramp-up of shallow gas workovers and drilling in 2017

1st deep well under Banarli Farm-in, Yamalik-1, achieved positive drilling results; testing program commenced early November 2017; Phase 2 Karaca 3D seismic recording completed, with processing underway

2017 shallow gas drilling program paused at six wells to update and high-grade the 2018 prospect inventory incorporating new Karaca 3D seismic results

Currently targeting final 2017 shallow gas capex program of $12 to 13 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 work program, operational plans, expected capital expenditures and target exit volumes; 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 estimated total investment of Statoil under the Banarli Farm-in; 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 design, elements and final cost of the Yamalik-1 Testing Program and the expected timeline; the potential to tie-in and conduct a long term production test and achieve natural sales from the Yamalik-1 well; the final cost and timeline to complete the processing of the Karaca 3D seismic and early fast-track processing step to facilitate planning; the preparation of the D&M Resource Assessment and the timing thereof; 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; and the availability of operating cash flow and the ability to finance development from existing cash and operating cash flow. 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.

25

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, 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.

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

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.






"Banarli Farm-in" means the farm-in agreement for the exploration of the deeper formations below approximately 2,500 metres on Valeura’s Banarli licences in accordance with the farm-in agreement between Valeura’s wholly-owned affiliate, Corporate Resources B.V., and Statoil.

"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.

"Statoil" means Statoil Banarli Turkey B.V.

"Subsequent West Thrace Deep Rights Sale" means the sale of a 10% participating interest (held by Valeura’s wholly-owned affiliate, TBNG) in the deep formations below approximately 2,500 metres depth on certain TBNG JV lands, including two exploration licenses and the three production leases, to Statoil for cash consideration of US$3 million which closed on June 22, 2017.

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

"TBNG Acquisition" means the acquisition by Valeura’s wholly-owned affiliate, Valeura Energy Netherlands B.V., of 100% of the shares of TBNG as held by TransAtlantic Worldwide, Ltd. for cash consideration of US$20.9 million (which includes US$3.1 million held in escrow pending a final reconciliation of the closing statement of adjustments) which closed on February 24, 2017.

"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.

"West Thrace Deep Rights Sale" means the sale of a 40% participating interest (held by Valeura’s wholly-owned affiliate, Corporate Resources B.V. (“CRBV”)) in the deep formations below approximately 2,500 metres depth on certain TBNG JV lands, including two exploration licenses and the three production leases, to Statoil for cash consideration of US$12 million which closed on January 6, 2017.

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 ~$5,755 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%

Organization Chart

31

BOARD OF DIRECTORS

Jim McFarland

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 ©

President & COO

Sean Guest

VP BUSINESS

DEVELOPMENT

13 Financial, Regulatory &

Admin Employees

JV ACCOUNTANT

Debbie Harding

TBNG (TEKIRDAG)

49 Operational Employees

Mehmet Ekinalan (Country Rep)

Steve Bjornson

CFO

Namik Ertem (Operations Mgr)

32

Senior Management

CEO: Jim McFarland, P. Eng.

45 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)

President & 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 & research functions (Australia, Malaysia, the Netherlands)

Ph.D. Geological Sciences (Queen’s); BSc Geological Engineering (Honours) (Queen’s)

33

Senior Management (Cont’d) 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)

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)

34

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)

35

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)

36

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

37

Turkey YE 2016 Reserves Pre-TBNG Acquisition (Company Gross) (1)(2)

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.

(2) Approximately 78% of the drilling locations assigned proved undeveloped reserves and 89% of the drilling locations assigned probable undeveloped reserves are in tight gas reservoirs located below the conventional shallow gas reservoirs in the Tekirdag field, which is located immediately adjacent to the growing city of Tekirdag. Valeura expects that the process to achieve routine drilling location approvals from the Ministry of Energy and Natural Resources, the Ministry of Agriculture and the local landowners could take longer than experienced in the past and may require pad drilling operations, all of which could extend the current contemplated timelines of four years and seven years for development of the proved undeveloped reserves and the probable undeveloped reserves, respectively.

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

38

Natural Gas Growth in Turkey

Turkey experiencing some of strongest growth in Europe and G20

Gas demand growth projected 8% per year – 50% of electricity generated from gas

Unlimited gas supply market, currently imports >99% of gas consumption

Proximal pipeline infrastructure and energy corridor to Europe

Proven and under-exploited petroleum systems

Globally Competitive fiscal terms– 12.5% royalty and 20% corporate tax

Premium gas prices – ~C$7.00/Mcf (Q3 2017)

Mature O&G operating environment with availability of services, contractors and staff

Area of VLE Operations

Natural Gas Pricing in Turkey

39

BOTAS Gas Sales Price is set by the government and denominated in TL

Price changes have occurred at times of large differentials between EU and BOTAS

BOTAS import contracts are confidential, but indicates that import cost is likely priced similar to EU

Result is that BOTAS price has recently behaved like a dampened EU gas price

Botas Price Increase

Botas Price Decrease

40

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 2x36" - Russian Gas

BOTAS - Interconnector to

export line to Greece

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

TANAP 48" - To Europe

41

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 5 new drills (3 producing; 1 completing/evaluating; 1 plugged & abandoned) – Completed 29 workovers (7.0 MMcf/d gross aggregate initial 7-day rate)

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

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

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

42

43

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 5 3 1 - 1 -

TOTAL 2012 – 2017 YTD 42 33 5 - 4 -

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 Karaevli-6 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

44

TBNG JV New Drill Spuds In 2012

WELL LICENCE SPUD

(d/m/y) RIG RELEASE

(d/m/y) WELL TYPE

TD (m)

STATUS NOVEMBER 1, 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

45

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



46

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

Karaevli-6 F19-D 14/08/2017 21/08/2017 Conventional 1,261 Plugged & Abandoned

Thrace Basin Seismic

47

2015 Banarli 3D (152 km2)

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 2015

Karaca 3D survey (504 km2) under Banarli Farm-in completed Sept 2017; processing underway

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

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

2017 Karaca 3D (504 km2)

48

Turkey Natural Gas 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

− Teslimkoy – gas

− Kesan – gas

− Sogucak – oil

− Hamitabat - gas

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