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A GLOBAL ENERGY COMPANY FOCUSED ON EXCEPTIONAL VALUE CREATION

FIRST DEEP WELL YAMALIK-1 DISCOVERS GAS AND CONDENSATE IN BASIN-CENTERED GAS PLAY

Corporate Presentation December 2017

2

Valeura Energy: Positioned for Material Growth

Positive cash flow underpins two-pronged growth strategy

1. Delineate high impact basin-centered gas-condensate play discovered by Yamalik-1 well

− Valeura operates and controls majority of the 1,600 km2 play fairway

− Exploration work program funded by Statoil under 2017 deep rights farm-in and sales agreements

− Extensive stimulation and testing program of Yamalik-1 commenced in Q4 2017

− Planning ongoing for follow-up 2018 delineation drilling

2. Build on solid foundation of existing production from conventional, shallow gas

− Valeura increased ownership of TBNG to 81.5% and assumed operatorship

− 8.9 MMboe of 2P reserves (YE2016) and >20 year reserves life indicative of potential growth

− Acquired 500 km2 3D seismic in 2017 to support new portfolio growth and potential new 2018 drill program

Valeura (TSX: VLE) Canada-based company producing gas in NW Turkey

Internationally-experienced management team with proven delivery of value to shareholders

Turkey is very attractive for gas production

− Excellent fiscal terms - 12.5% royalty and 20% tax

− High gas prices $6.98/Mcf & high operating netbacks $22.66/boe in Q3 2017

See ‘Non-IFRS Measures’, ‘Barrels of Oil Equivalent’ , and ‘D&M Reserves Disclosure ‘ under "Reader Advisories" starting on Slide 23

Production Test #1 – Yamalik-1 well

3

Valeura Snapshot Capital Structure

Market Cap.

Working Capital (1)

2P Reserves

Production(1)

Gas Price(1)

Operating Netback(1)

Land Position (Net)

Infrastructure

73.1 MM shares o/s (79.5 MM fully diluted)

$138 MM @ share price of $1.89 (11/29/17)

$5.5 MM and no debt

8.9 MMboe (2) (up 89% from YE2016)

Reserves Life > 20 years

1,024 boepd (up 29% from Q4 2016)

$6.98/Mcf

$22.66/boe

432,297 acres (shallow rights)

278,354 acres (deep rights)

Valeura owns and operates all gas gathering and sales contracts

through 81.5% ownership of TBNG JV (1) Data from Q3 2017 financials. (2) Pro forma YE2016 post TBNG Acquisition. See slide 29.

4

Natural Gas Growth in Turkey

Turkey experiencing some of strongest GDP growth in Europe and G20

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

Essentially unlimited gas supply market for domestic gas producers as currently importing >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

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

Area of VLE Operations

Source: Forbes, Feb 2016 “Turkey's Rising Natural Gas Demand Needs U.S. LNG”

5

Dominant Operated Position in NW Turkey

(1)

5 year initial term for Exploration Licenses

Maximum of 11 years

Ability to produce hydrocarbons while in exploration phase

Up to 20 year initial term for Production Leases

Can convert 100% of exploration area if a proven area (e.g. unconventional play)

One renewal term possible for up to additional 20 year term

(1) Under the Statoil Banarli Farm-in, to earn their 50% working interest, Statoil must fully fund i) the drilling and testing of the Yamalik-1 well, ii) the acquisition of the Karaca 3D seismic, and iii) the drilling and testing of one more deep exploration well. If this work is not fully completed, there are financial penalties and Valeura reverts to 100% ownership of deep rights.

6

Infrastructure to Immediately Monetize Gas

Owned facilities allow immediate tie-in and sales of new production

TBNG owns and controls all gas gathering and sales infrastructure

Existing owned system has capacity to increase production and gas sales

All exploration wells, appraisal wells, and pilot project can be tied in and sold immediately

5 km

TBNG 8"-10" Sales Line

TBNG 6" Sales Line

GAZDAS 12”Distributor

BOTAS 2x36" Russian Gas

BOTAS export to Greece

TBNG Central Compression Facility

TANAP 48“ Spur to Europe (Planned)

Proximal pipeline infrastructure capable of several Bcf/day

Local Tekirdag tie-in to regional gas distributor, GAZDAS

Proximal tie-in points to major gas pipelines Domestic line to Istanbul and extensive Turkish gas grid Export line to Greece New TANAP export line to Europe

7

Transformative Deals closed in Q1 2017

Purchased TBNG shares to capture 41.5% of TBNG JV for US$20.7 MM - ownership in TBNG JV now 81.5%

Valeura assumed operatorship of TBNG JV production and development

Pro forma YE2016 increase in VLE production 54% (1)

Pro forma YE2016 increase in VLE 2P reserves 89% (1)

On sold 50% of TBNG West Thrace “Deep Rights” to Statoil for US$15 MM

Net cost of TBNG purchase US$5.7 MM

Effective purchase price per 2P Reserve US$1.36/boe

Effective purchase price per flowing boe/d US$13,300

Farmed in Statoil to fund exploration of basin-centered gas play – Earns 50% of Banarli Deep Rights for US$6 MM cash and work program carry of US$30 MM (minimum)

Yamalik-1 drilled and tested in 2017 – US$23 million

Karaca 3D seismic acquired in 2017 – US$10 million (minimum)

Deep Well #2 – to be drilled and tested in 2018 (minimum US$10 MM)

(1) See slide 15.

Basin Centered Gas Play – Material Upside Following Yamalik-1 Gas-Condensate Discovery

KCA Deutag T-207 Drilling at Yamalik-1 – July 2017 8

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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 farmed in to fund testing of 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 play? (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

10

BCGA Potential Fairway Extends Over ~ 1,600 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 over-pressures interpreted below ~ 2,500 m

– 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

Thrace Basin Cross-section

Normal Pressure

Transition Pressure

Teslimkoy

Kesan

Over Pressure

Overpressured Zone of Interest

Mezardere

12

Thrace Basin Demonstrates Key Attributes of BCGA

Play area generally 100’s km2 in depocenter of basin

Thrace Basin mapped as ~1,600 km2

Reservoirs typically significantly over-pressured and high temperature

Wells on basin fringe 0.68-0.77 psi/ft - Yamalik-1 0.8-0.84 psi/ft

High geothermal gradient of 35O C / Kilometer

Lack down-dip water contacts in wells

Yamalik-1 reservoirs gas-saturated from ~ 2,900 m to TD of 4,196 m with no water zones interpreted

Yamalik-1 flowed gas without any formation water interpreted

Normally pressured gas and water encountered around edge of basin edge

Thrace basin fringed by gas fields producing from normally pressured reservoirs in the same formations

Requires significant thickness of reservoir - permeability is generally < 0.1 mD

Yamalik-1 encountered almost 500 m of net sand (44% N/G) in Teslimkoy and Kesan reservoirs

Shallower Mezardere and Osmancik reservoirs not yet tested in basin center

Production Test #1 – Yamalik-1 well

13

I-8 Rig Drilling at TDR-9

TBNG JV – Now Under Valeura Operatorship

14

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 six exploration wells on TBNG JV lands:

• Three wells on production (Dogu Atakoy-3, Dogu Kilavuzlu-2 & Koseilyas-2)

• Two wells cased & under evaluation (Sariyer-1 & Aydinkoy-1)

• One well plugged & abandoned (Karaevli-6)

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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 in 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

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.

Production Growth & Cost Focus Post TBNG Acquisition

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• High gas prices

• $6.98 Q3 2017 realization

• Government Royalty of 12.5%

• Management focused on continued cost reduction

• Q2 2017 period of high operating costs due to TBNG Acquisition

• Production & gas sales increases QoQ

• High workover activity has offset natural production declines

• Q4 2017 plan for re-entry fracs in two wells

$44.97

$42.49 $44.28

$42.14

Sales Price

See ‘Non-IFRS Measures’ and ‘Barrels of Oil Equivalent’ , under "Reader Advisories" starting on Slide 23.

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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

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

18

Production Growth Strategies

See ‘Drilling Locations’ under "Reader Advisories" starting on Slide 23.

Dogu Gurgen-1

Bati Yayli-1

Koseilyas-4

Kilavuzlu-3

Dogu Osmanli-2

Guney Karababa-2

Yamalik-1

5 km

TBNG JV - West Thrace

TBNG JV - South Thrace

Karanfiltepe-7

Drill Ready Conventional Prospects

Conventional Prospects & Leads

Yamalik-1 - Deep BCGA Test

2) Portfolio of small but low cost in-field

or near-field prospects

• Focused low-cost drilling program

• Improved chance of success

1) Potential Tekirdag Tight Gas

Development Area

• Convert 2P to production

3) Mature portfolio on new

Karaca 500km2 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

(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 23.

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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

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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, 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 23

Near-Term Potential Value Catalysts

December 2017

December 2017

Late January 2018

Q1 2018

July 2018

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Continued stimulation and testing of Yamalik-1

Conventional Production: fracing of two existing wells to access bypassed pay

D&M Report on the Prospective Resource and Contingent Reserves associated with BCGA

Tie in of Yamalik-1 (assuming economic production from testing operations)

Decision with partner Statoil on the number of wells in 2018 delineation program for the BCGA Play

Spud of first BCGA delineation well – Valeura fully carried under Banarli Farm-in

22

Valeura: Compelling Investment Opportunity

Deep Basin-Centred Gas Play

2017 Farm-in of Statoil provided US$21 MM cash and work program carry of a minimum of US$36 MM to test the BCGA play in the Thrace Basin

Yamalik-1, the first deep well discovered gas-condensate and validated the BCGA concept

Stimulation and testing of Yamalik-1 is ongoing, and D&M are preparing a resource report on the potential size of the BCGA in the Thrace Basin

Statoil are required to fund the drilling and testing of an additional deep delineation well

VLE operates and controls the majority of the interpeted play area and retained interest in deep rights of 50% at Banarli and 31.5% at West Thrace

Conventional Gas Production

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

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

VLE has grown gas production in 2017 and is rebuilding the portfolio based on new 3D seismic and learnings from recent drilling – work underpins potential 2018 drilling campaign

23

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; reserves life; 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; production growth strategies, cost reduction plans; the preparation of the Resourcce Report by D&M and the timing thereof, 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.

24

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. A pressure transiant analysis or well test interpretation has not been carried out in respect of the well test on the Yamalik-1 well.

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.

25

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.

26

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

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 23.

28

29

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 23.

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

Organization Chart

30

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)

31

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

Past Successes of Management & Board

Market Cap ~$5,425 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%

32

Sold in 2014 $1,800 MM

2x ROI (’11-’14) CAGR 24%

Natural Gas Pricing in Turkey

33

BOTAS Price Increase

BOTAS Price Decrease

(1) Boru Hatlari ile Petrol Tasima Anonim Sirketi ("BOTAS") owns and operates the national crude oil and natural gas pipeline grids in Turkey and purchases the majority of Turkey's natural gas imports. BOTAS regularly posts prices and its Level-2 wholesale tariff is shown herein as BOTAS Gas Price. See Valeura’s 2016 AIF for further discussion.

BOTAS (1) 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 indications are that import cost is likely priced similar to EU gas price

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

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Extensive 3D Seismic Coverage

Alacaoglu 3D

Vakiflar 3D

Kepirtepe 3D

Corlu 3D

Osmanli-Tekirdag Merged 3D 404 km2

Hayrabolu 3D 204 km2

Karaca 3D 504 km2

Banarli 3D 152 km2

BCGA Boundary

3D Coverage: > 1,900 km2

2D Coverage: > 6,000 km

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

35

36

TBNG JV New Drill Spuds In 2012 – 2017

TIME GROSS WELLS

SPUDDED PRODUCING

EVALUATING/

COMPLETING

PLUGGED &

ABANDONED

UNCONVENTIONAL

2012 - 2013 17 15 - 2

2014 3 3 - -

CONVENTIONAL

2012 - 2013 10 6 - 4

2014 6 5 - 1

2015 1 1 - -

2017 YTD 6 3 2 1

TOTAL 2012 – 2017 YTD 43 33 2 8

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

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

Mezardere Slope Fan Play Fairway

37

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

See ‘Initial On-Stream Production Rates’ under “Reader Advisories” starting on Slide 23.

10 km

Tekirdag

Banarli

Prospective Mezardere

play fairway

Mezardere Depth Structure

Tekirdag area Mezardere

exploitation program

Tekirdag Area Channels

Koseilyas-2 2017 Discovery

Producing Koseilyas-4 2018 Well Koseilyas-1

Producing Karaevli-6

P&A

Koseilyas-1 Producing

Gazi-1 Producing 1 km

Tekirdag Area Channels

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

38

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