TRANSFORMING THE BUSINESS THROUGH CONSOLIDATION OF THE SHALLOW GAS BUSINESS & DEEP HIGH IMPACT EXPLORATION FUNDED BY STATOIL

Transcription

1 A GLOBAL ENERGY COMPANY FOCUSED ON EXCEPTIONAL VALUE CREATION TRANSFORMING THE BUSINESS THROUGH CONSOLIDATION OF THE SHALLOW GAS BUSINESS & DEEP HIGH IMPACT EXPLORATION FUNDED BY STATOIL CORPORATE PRESENTATION JANUARY 2017

2 Valeura Corporate Profile Valeura Energy Inc. ( Valeura or VLE ) (TSX: VLE) is a Canada-based oil & gas company producing high netback natural gas in the Thrace Basin of northwest Turkey Turkey is a highly attractive international jurisdiction for oil & gas business: Flat 12.5% government royalty; 20% corporate tax Outsized average natural gas price realization of $9.35/Mcf & operating netback of $38.69/boe in Q Financial and operational performance: Q3 2016: 680 boe/d net sales; funds flow from operations $1.1 MM; working capital surplus $3.7 MM; no debt 2P reserves 5.5 MMboe (YE 2015) with NPV 10 before tax value of $117 MM ($2.00/share) Market capitalization $56 MM ($0.95/share) at close on Jan 9, 2017 Pursuing two-pronged growth strategy in Turkey: Consolidating, operating & growing relatively low risk shallow gas business (<2,500 m depth) (VLE % WI) Exploring for higher risk/higher reward deep, basin-centered gas accumulation ( BCGA ) play (2,500 4,000+ m depth) funded by Statoil under 50% WI farm-in (VLE % WI) Growth plan underpinned by four inter-related transformational transactions: Statoil investment of US$36 MM (including US$6 MM upfront payment) to earn 50% WI in deep play on VLE s 100% owned Banarli licences (closed) Statoil purchase of 50% WI in other deep rights from VLE at West Thrace for US$15 MM (Tranche 1 of US$12 MM closed; Tranche 2 expected to close March 2017) VLE acquisition of TBNG for approximately US$18.5 MM (after closing adjustments) to increase VLE s WI to 81.5% and operatorship of the TBNG JV (subject to West Thrace Deep Rights Sale) (expected to close Feb 2017) $11 MM (gross proceeds) from underwritten private placement of subscription receipts (closed Nov 2016); funds expected to be released from escrow concurrent with closing of the TBNG Acquisition Expect pro forma production of 1,100-1,200 boe/d and working capital surplus of $14-15 MM post closing of all transactions 2

3 Recent Transformational Transaction Agreements TURKEY AME-GYP FARM-IN Kahta 17 Well Tekirdag Processing Station 7 3

4 TBNG Acquisition, West Thrace Deep Rights Sale & Equity Raise Definitive agreements executed for three concurrent transactions as announced on October 13/14, 2016: 1. Acquisition of TBNG (the TBNG Acquisition ) for US$22 MM effective March 31, 2016 (estimated US$18.5 MM after closing adjustments) pursuant to a share purchase agreement (the TBNG SPA ) (expected to close Feb 2017) 2. Sale of 50% interest in deep rights in certain TBNG JV lands (the West Thrace lands ) to Statoil for US$15 MM: i. Tranche 1 sale of VLE s currently held 40% interest (the West Thrace Deep Rights Sale ) in deep rights for US$12 MM pursuant to a sale and purchase agreement (the West Thrace SPA ) (closed); and ii. Tranche 2 sale of additional 10% interest (the Subsequent West Thrace Deep Rights Sale ) in the deep rights acquired post TBNG Acquisition for US$3 MM pursuant to a separate sale and purchase agreement (the Subsequent West Thrace SPA ) (expected to close March 2017) 3. $11.0 MM equity raise by way of underwritten private placement of subscription receipts (funds expected to be released from escrow concurrent with closing of the TBNG Acquisition) West Thrace SPA provides for the return of Tranche 1 proceeds of US$12 MM to Statoil in the event the TBNG SPA is terminated or the TBNG Acquisition fails to close Proceeds from Statoil from the West Thrace Deep Rights Sale and the Subsequent Deep Rights Sale (US$15 MM) and back costs under the Banarli farm-in (US$6 MM) effectively fund the TBNG Acquisition in a nondilutive way Equity raise provides additional funds to close the TBNG Acquisition and ramp-up shallow drilling on the TBNG JV lands & Banarli licences Post closing of the above transactions: VLE retains 31.5% WI in deep rights and 81.5% WI in shallow rights on the West Thrace lands and 81.5% on all other TBNG JV lands (the South Thrace lands ); PTI retains current 18.5% WI in all lands & zones in the TBNG JV 4

5 Key Benefits of TBNG Acquisition Transformational transaction for VLE: - Captures operatorship allowing VLE to control the pace & direction of development of TBNG JV lands - Doubles working interest in existing VLE production base and increases production by 59% (1) and 2P reserves by 85% (2) - Attractive acquisition metrics: $15.08 per boe (1P reserves) (2) ; $5.08 per boe (2P reserves) (2) - VLE gains control of upstream and marketing infrastructure; ensures access to market to execute growth program - Capitalizes on VLE s 5-year experience with the assets and proven operational skills - Facilitates Banarli development given current volumes are sold to the TBNG JV and are tied into the TBNG JV facilities and customer base Opportunity to execute a fully funded shallow gas development program on the TBNG JV and Banarli lands: 2017 shallow gas capital program and production outlook to be firmed post closing of the TBNG Acquisition Statoil has agreed not to proceed with deep drilling on TBNG JV lands until it has earned at Banarli (1) Based on annualized Q sales from TBNG s 41.5% working interest in TBNG JV. (2) Based on allocation of D&M s estimates of VLE reserves for the TBNG JV lands at December 31, 2015 in their report prepared for VLE dated March 8,

6 Equity Raise Executed $ 11.0 MM underwritten private placement of subscription receipts concurrent with execution of the TBNG SPA and West Thrace SPA (the Offering ) Each subscription receipt to be exchanged for one common share of VLE upon satisfaction of certain conditions, including that all conditions to the completion of the TBNG Acquisition have been satisfied (but for the payment of the purchase price): MM subscription receipts issued at $0.75 per subscription receipt - Expected net proceeds of $10.2 MM after fees and expenses - Subject to four month hold from date of closing of the Offering - Proceeds of the Offering held in escrow and will be released immediately prior to the closing of the TBNG Acquisition or returned (with interest) to investors if the TBNG Acquisition does not close by a specified date or upon the termination of the TBNG SPA Use of net proceeds shall be to fund completion of the TBNG Acquisition and to fund ramp-up of shallow drilling on the TBNG JV lands and Banarli licences Targeted timelines: - November 3, 2016 Offering closed - February 2017 expected closing of TBNG Acquisition and concurrent release of subscription receipt funds (1) - Early March month hold expires on common shares underlying subscription receipts (1) Subject to a number of conditions including, but not limited to, stock exchange approval. 6

7 Statoil Banarli Farm-in Definitive agreements executed on August 19, 2016 whereby Statoil would need to invest at least US$36 MM (US$6 MM received to date) in three phases to earn 50% interest below 2,500 m in Banarli licences (the Banarli Farm-in ), while Valeura retains 100% interest above 2,500 m, subject to Turkish government approval for licence interest transfers Phase 1 commitment (2017): US$6 MM payment to Valeura for back costs upon approval by GDPA of 50% licence interest transfer (complete) Minimum investment of US$10 MM to drill, frac and test 4,000 m well (target spud Q1 2017) Phase 2 commitment (2017): 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 to acquire 3D seismic (target start Q2/Q3 2017) Phase 3 commitment (2018): 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 a second 4,000 m well Total investment by Statoil of at least US$36 MM required to earn 50% interest (no partial earning) Valeura to operate shallow and deep programs during the Statoil earning phase; Statoil has option to operate deep program post earning 7

8 Thrace Basin Transactions & Land Position (1)(2) Bulgaria 2010 Otto asset purchase (Edirne) (Valeura 35% WI) Black Sea 1 Greece Statoil Banarli Farm-in E17-b4-1 E17-c1-1 E17-c Banarli licence award (Valeura 100% WI) VLE license application F18 -b3, F19-a4 November TBNG acquisition 41.5% WI TBNG JV Sale of 50% WI in deep rights to Statoil West Thrace F17- c2,c3 F18- d1,d2, d4 TBNG-VLE-PTI license application F18-d3 September F18- c1,c2,c3,c4 F18-b3 F19-a4 F19- d1,d4 F18- c4-2 G18- b1-1 F18- c3-1 G18- b2-1 F19- d G19-a1-1 (1) Newly adapted exploration licences and production leases issued to date by the GDPA under the New Petroleum Law (June 2013) are shown on the map with new grid coordinates and naming convention (e.g. Licence F18-c1,c2,c3,c4 encompasses all four quadrants in block F18-C). (2) Banarli licence 5104 converted to two new licences F18-c1, c2, c3, c4 and F19-d1, d4 on June 27, 2015 and extending initial 5-year term to June 27, F19-d4-2 F19- d TBNG-PTI acquisition (Valeura 40% WI onshore; Valeura 15% WI offshore) Turkey F19- c3-1 TBNG-VLE-PTI lease award F19-d3-1 January 2017 TBNG-VLE-PTI lease award F19-c3-1 January km Sea of Marmara 8

9 Capital Structure Post TBNG Acquisition Basic shares outstanding at January 1, ,519,321 Common shares underlying subscription receipts 14,629,000 Basic shares outstanding post TBNG Acquisition 73,148,321 Common shares purchasable pursuant to outstanding Options ($0.72 weighted average exercise price per share) 4,914,500 Fully diluted shares 78,062,821 Institutions ~ 25% Management & Directors 4.9% (10.0% fully diluted) Retail ~ 70% 9

10 Q Financial & Operating Highlights RESULTS 3 MONTHS ENDED SEPT 30, MONTHS ENDED JUNE 30, MONTHS ENDED SEPT 30, 2015 Production Crude oil & NGLs (bbl/d) Natural gas (Mcf/d) 4,020 5,560 4,723 boe/d Financial (Canadian $ M, except per boe amounts) P & NG revenues (net) 3,510 4,809 4,309 Funds flow from operations 1,066 2,098 1,949 Net income/(loss) (1,263) (642) (169) Capital expenditures (net) 3,080 3, Operating costs ($/boe) Average operating netback ($/boe) Net working capital surplus 3,697 5,741 11,335 Cash 2,336 4,611 7,972 See Non-IFRS Measures under Reader Advisories starting on Slide

11 Why Turkey? Thrace Basin (natural gas) TBNG-PTI TBNG-PTI acquisition Acquisition (natural gas & light/medium oil) opportunity Anatolian Basin (medium oil) Prospective Proven petroleum systems Under-explored & under-exploited conventional & unconventional plays Opportunity to deploy modern technology Thrace Basin main gas producing region Anatolia Basin main oil producing region Major IOCs & NOCs returning to Turkey (offshore; onshore unconventional) Positive Business Environment G-20 country, NATO member and democracy with moderate Islamic party in power Coup attempt by elements of military on July 15, 2016 put down by government Attractive royalty (12.5%) & corporate tax (20%) New Petroleum Law passed June 30, 2013 Available infrastructure & oil field equipment No fracing restrictions More than 92% reliant on imports of oil & gas Exposure to world oil prices & premium gas prices linked to long term import contracts (10% reduction in Botas reference price Oct 1, 2016 to $8.48/Mcf) Energy corridor to Europe 11

12 Land Position In Turkey Post Closing of Transactions TRANSACTION LEASES & LICENCES (#) GROSS AREA (acres) VALEURA NET AREA SHALLOW RIGHTS (acres) VALEURA NET AREA DEEP RIGHTS (1) (acres) THRACE BASIN TBNG JV - Onshore (2) (3) , , ,973 Banarli Licences Award (4) (5) 2 133, , ,840 Otto - Edirne 3 49,883 17,459 17,459 SUB TOTAL , , ,272 ANATOLIAN BASIN TBNG JV - Gaziantep 2 152,111 39,549 39,549 TOTAL , , ,821 (1) Post West Thrace Deep Rights Sale and Subsequent West Thrace Deep Rights Sale (aggregate 87,023 net acres of deep rights sold to Statoil) but prior to potential earning by Statoil of 50% in the deep rights on the Banarli licences under the Banarli Farm-in. (2) Reflects approval of two new production leases (G18-b1-1 and G18-b2-1) in December 2015 carved out from exploration licence 3931, expiry of exploration licences 3931 and 3934 and relinquishment of any residual exploration acreage. The area relinquished included 56,012 gross acres onshore (22,405 acres net) and 68,453 gross acres offshore (10,268 acres net). Also reflects January 2017 approval of two new production leases including F19-d3-1 as a carve-out from expired exploration licence 3934 and F19-c3-1 as a carve-out from expired exploration licence (3) Reflects conversion of old exploration licence 5151 to two new licences effective June 27, 2015 and expiry of old exploration licence The TBNG JV requested and the GDPA subsequently posted part of the area encompassed by the relinquished old exploration licence 3858 (30,048 gross acres) for new bids (submitted September 16, 2015). Potential acreage additions from this bid have been excluded from the table. Bids remain under review by the GDPA. (4) Reflects the conversion of old Banarli exploration licence 5104 to two new exploration licences (F18-c1, c2, c3, c4 and F19-d1, d4) effective June 27, The gross and net acreage shown includes 9,981 acres in the northeast corner of licence F19-d1, d4 that could revert to Turkiye Petrolleri Anonim Ortakligi ( TPAO ) if certain work program obligations are performed by TPAO on this land. This small area was once held by TPAO as part of a larger licence that expired prior to the Banarli licence conversion process but was included by the GDPA in the new Banarli licence F19-d1, d4 to enable its adaptation to encompass all of the un-licenced area in the quadrant. (5) Excludes any potential acreage additions from bids submitted by Valeura to the GDPA for two new exploration licences (F18-b3 and F19-a4) contiguous with the Banarli licences. These bids remain under review by the GDPA. 12

13 Turkey YE 2015 Reserves (Company Gross) (1) CATEGORY PROVED DEVELOPED PRODUCING PROVED DEVELOPED NON- PRODUCING PROVED UNDEVELOPED LIGHT & MEDIUM OIL (Mbbl) NATURAL GAS (Bcf) TOTAL OIL EQUIVALENT (Mboe) NPV 10 BEFORE TAX ($MM) NPV 10 AFTER TAX ($MM) TOTAL PROVED , PROBABLE , TOTAL PROVED PLUS PROBABLE , POSSIBLE , TOTAL PROVED, PROBABLE AND , POSSIBLE (1) Based on a $Cdn/$US exchange rate of 0.72 at December 31, 2015 to convert US$ denominated reserves values in the 2015 D&M Reserves Report. See D&M Reserves Disclosure and Future Net Revenue under Reader Advisories starting on Slide

14 TBNG JV (Valeura 40% WI - Non-Operated) The Proving Ground I-8 Rig Drilling at TDR-9 14

15 TBNG JV Interests in 16 leases & licences in Thrace Basin (0.34 MM gross acres) Well established shallow gas production and marketing business: - ~100 producing wells (gross) (shallow gas & tight gas) in 15 gas fields in onshore lands - Owned compression facilities & distribution lines - Direct sales to 55 commercial & end user customers - Pursuing workovers, recompletions and selective re-entry fracs on existing wells and drilling selectively on new 3D seismic acquired in 2011 and 2013 (650 km 2 ) JV completed extensive proof of concept program to de-risk the tight gas play over the period: - Tight gas resources in deeper sands in the Mezardere, Teslimkoy and Kesan Formations - Applied multi-stage fracture stimulation technology in vertical and horizontal wells Significant natural gas reserves: - 2P reserves 67.3 Bcf (TBNG JV gross); 26.9 Bcf (Valeura gross) at YE 2015 Q gas sales 5.9 MMcf/d (gross) & 2.3 MMcf/d (VLE 40% WI): $9.49/Mcf average natural gas price realization in Q Low activity levels in 2015 and 2016 reflects other priorities of partners: TBNG Acquisition, transfer of operatorship to Valeura and the flow of funds from Statoil and the Offering are expected to enable ramp-up of drilling by early 2017 including drilling of 4 commitment wells to be spudded by late June 2017 under licencing terms See Non-IFRS Measures and D&M Reserves Disclosure under Reader Advisories starting on Slide

16 500 m TBNG JV Shallow Gas & Tight Gas Plays Akcahalil-1 SOUTHWEST Gamma Ray Inecik- 2 Aydede-1 Total Gas YAGCI-8 ND-1 TDR-2 TS-18 DTD-1 KAYI-7 BATI GAZI-1 BATI KARAEVLI-1 TESLIMKOY and KESAN CEYLAN PERFED ZONE 50 km OSMANCIK MEZARDERE DANISMEN NORTHEAST SHALLOW GAS Danismen & Osmancik 5 re-entry fracs since mid-2011 (Osmancik) 63 workovers & 17 new drills in YTD H Osmancik discoveries in Osmanli area indicate new play type potential TIGHT GAS Mezardere, Teslimkoy & Kesan Normally-pressured over much of the TBNG JV lands 50 well re-entry fracs since mid new drills in (14 vertical & 6 horizontal) of which 18 fraced 16

17 Thrace Basin Tight Gas Learning Curve (Q3) THRACE BASIN Program Cumulative capex (1) $89MM (net) Develop NATURAL GAS PRODUCTION boe/d (net) Shallow gas decline Tight gas growth No TBNG JV drilling Grow Cumulative funds flow from operations (2) $74MM (net) 2P RESERVES (3) MMboe (net) 593 TBNG ACQ P Grow 1.7 YE 2011 YE 2012 YE 2013 YE 2014 YE 2015 (1) To end Q Excludes $53.7MM acquisition cost. (2) To end Q See Non-IFRS Measures under Reader Advisories starting on Slide 29. (3) VLE s gross company interest reserves before the effect of the TBNG Acquisition. See D&M Reserves Disclosure under Reader Advisories starting on Slide

18 Tekirdag Area Mezardere/Teslimkoy/Kesan Frac Results & Potential Vertical Well Development (1) Yagci MMcf/d TDR MMcf/d TDR MMcf/d TDR MMcf/d TDR MMcf/d TS MMcf/d KAYI MMcf/d TDR-11H 2.0 MMcf/d TDR MMcf/d TDR MMcf/d KAYI MMcf/d KAYI MMcf/d TDR-5H 2.0 MMcf/d Guney Kayi MMcf/d TDR MMcf/d Yagci-6 ND-3 BTD-4H 0.5 MMcf/d 1.2 MMcf/d 3.3 MMcf/d BTD-5H 2.3 MMcf/d DTD MMcf/d BTD MMcf/d KAYI MMcf/d BTD MMcf/d Kayi Derin MMcf/d BTD-2H 2.3 MMcf/d Baglik MMcf/d BTD MMcf/d DTD MMcf/d BTD MMcf/d DTD-19H 0.6 MMcf/d DTD MMcf/d DTD MMcf/d Mezardere Re-entry Fracs Teslimkoy Producers Upper Kesan Producers Mezardere/Teslimkoy/Kesan Potential Locations 400m X 400 m 40 acres Vertical stacking of Mezardere, Teslimkoy & Kesan sands (>75 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 29. KAYI MMcf/d DTD MMcf/d KAYI MMcf/d 18

19 Mezardere Slope Fan Play Fairway Mezardere Depth Structure Prospective Mezardere play fairway Banarli Tekirdag 10 km Tekirdag area Mezardere exploitation program Slope fan play in Mezardere Formation showing encouraging results Seismic imaging clearly shows channel trends with both structural & stratigraphic trapping potential Koseilyas-1 Tekirdag area Mezardere exploitation program (500 1,500 m depth); area 250 km 2 19 well re-entry fracs completed in 2013 and 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 km 2 2 km Gazi-1 Tekirdag Area Producing Slope Channels See Initial On-Stream Production Rates under Reader Advisories starting on Slide

20 Banarli (Valeura 100% WI - Operated) Provides Material Exploration Upside in Shallow & Deep Formations 3D Seismic Acquisition on Banarli May

21 Banarli Exploration Strategy Banarli licence awarded to Valeura (100% WI) in April 2013 (541 km 2 ; 209 square miles) Converted to two licences under New Petroleum Law, extending initial 5-year term to June 27, 2020: US$9.2 MM commitment: 2,000 m well year 1; 2,000 m well year 2; 3,800 m well year 4; 152 km 2 3D seismic (seismic and two commitment wells already completed in 2015) Potential for five exploration play types: 1. Osmancik/Danismen transverse fault play 2. Osmancik/Danismen stratigraphic traps 3. Mezardere/Teslimkoy slope fan/basin floor fan play with structural & stratigraphic closure 4. Mezardere/Teslimkoy slope fan play with stratigraphic closure only 5. Basin-centered gas play concept Pursuing strategy to exploit conventional gas in the Danismen and Osmancik formations on a 100% basis (<2,500 m) & work with farm-in partner Statoil to assess the deeper BCGA play concept (>2,500 to 4,000+ m) Acquired 152 km 2 of new 3D seismic in Q Spudded first exploration well Bati Gurgen-1 on November 10, 2015 (2,735 m MD): first gas from Osmancik on March 12, 2016 (conventional gas); IP MMcf/d Spudded second exploration well Yayli-1 on December 1, 2015 (2,914 m MD): fracing program carried out in over-pressured Teslimkoy (tight gas), which provided key information for deep farm-in process; Osmancik completion suspended pending assessment of pumping well to handle water production Spudded third well Bati Gurgen-2 on June 19, 2016 (1,857 m TVD): required sidetracking after initial wellbore was low to prognosis and sands appeared wet on logs; Osmancik on-stream September 26, 2016; IP MMcf/d 21

22 TBNG JV Producing Fields & Banarli Conventional Exploration Prospects Banarli F18-c1,c2,c3,c4 Muratli Banarli F19-d1,d4 Yayli-1 Teslimkoy Fraced Osmancik Completion Temporarily Suspended Osmanli EUR: 9.4 Bcf Bati Gurgen-1 Osmancik IP30: 3.4 MMcf/d EUR: 4.9 Bcf Aydinkoy Bati Gurgen-2 Osmancik IP30: 1.1 MMcf/d Gurgen EUR: 6.0 Bcf TBNG JV Lands Kayi EUR:12 Bcf Banarli licences Producing fields (1) Banarli prospects (2) Merged Banarli, Tekirdag & Osmanli 3D seismic (~550km 2 ) similarity imaging Vintage 2D Seismic Potential 3D Seismic (~600 km 2 ) Potential Drilling Locations (2) Karaevli EUR: 1.8 Bcf Tekirdag EUR: 128 Bcf Gazi EUR: 0.7 Bcf Yagci EUR: 7.1 Bcf (1) Estimated Ultimate Recovery ( EUR ) = Cumulative Production to December 31, P Reserves at December 31, (2) These are internally generated prospects and drilling locations. See Drilling Locations under Reader Advisories starting on Slide 29. See D&M Reserves Disclosure and Initial On-Stream Production Rates under Reader Advisories starting on Slide

23 Osmancik/Danismen Prospect Map (< 2,500 m Depth) Mid Danismen PSTM Time Structure Osmancik/Danismen Prospects Discoveries MURATLI Prospects (< 2500 m) (1) AYDINKOY YAYLI-1 TESLIMKOY FRACED OSMANCIK COMPLETION TEMPORARILY SUSPENDED BATI GURGEN-2 OSMANCIK IP MMCF/D Osmanli Field BATI GURGEN-1 OSMANCIK IP MMCF/D GURGEN PRODUCING FIELD (1) These are internally generated prospects and drilling locations. See Drilling Locations under Reader Advisories starting on Slide 29. See Initial On-Stream Production Rates under Reader Advisories starting on Slide

24 Potential Basin-Centered Gas Play Fairway (Play Type 5) Hayrabolu psi/ft Alacaoglu psi/ft Kazanci psi/ft Kandamis psi/ft Banarli F18-c1,c2,c3,c4 Yayli psi/ft 10 km Bati Gurgen psi/ft Ergene psi/ft Banarli F19-d1,d4 Mezardere Depth Structure CI 100m Potential Pressure Seal Area 1,500 km 2 Kayi Derin psi/ft Normal Pressure Baglik psi/ft Transition Zone Pressure Over Pressure The seven deep wells within the potential pressure seal area show pressure gradients ranging from psi/ft below 2,500 m as measured by mud weights during drilling and pressure measurements Compares to normal pressure gradient of ~0.433/ft Kayi Derin-1 & Baglik-1 are normally pressured and not within the potential pressure seal area XPT Wireline Pressure Test DFIT Diagnostic Fracture Injection Test 24

25 Formations & Depositional Environments Within Potential Pressure Seal Area Yayli-1 Ergene-1 Banarli Licenses Boundary Unconformity Top Potential Pressure Seal TD 2,914 m TD 2,967 m Map View Depth 2,500 m Ergene-1 Yayli-1 Osmancik Shorelines Mezardere Slope Channels Teslimkoy Member Basin Floor Fans 25

26 Robust Netbacks & Competitive Costs Drive Attractive Natural Gas Economics in Turkey Operating Netbacks $/boe (1) Netback Opex Royalty Sales Price Current Cost Structure US$MM (gross) TBNG JV BANARLI CONVENTIONAL GAS VERTICAL WELL (1200 m) (2) Drill & Case (1,200 m TVD) 0.7 NA Complete & Tie-in 0.4 NA Total 1.1 NA CONVENTIONAL GAS VERTICAL WELL (2000 m) (3) Drill & Case (2,000 m TVD) Complete & Tie-in (new facilities) Total TIGHT GAS VERTICAL WELL (1400 m) (4) Drill & Case (1,400 m MD) 0.8 NA Multi-stage Frac 1.0 NA 10 Tie-in 0.1 NA Total 1.9 NA to Date (1) See Non-IFRS Measures under Reader Advisories starting on Slide 29. (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. 26

27 Turkey Natural Gas Indicative Well Economics (1) PHYSICAL PARAMETERS PER WELL ECONOMICS PER WELL BEFORE TAX (5) PROGRAM RESERVES (2) (Bcf) IP30 (3) (MMcf/d) CAPEX (4) (US$MM) IRR (%) PAYOUT (MONTHS) NPV 10 (US$MM) RECYCLE RATIO (6) Thrace Basin - Gas Shallow Gas Drilling (1,200 m) with Tie-in to Existing Facilities Shallow Gas Drilling (2,000 m) with Tie-in to New Facilities > Tight Gas Vertical Drilling (1,400 m) & Multi- Stage Frac with Tie-in to Existing Facilities (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 1 st 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 internally generated natural gas price deck: TBNG JV US$6.41/Mcf in Q4 2016, US$6.59/Mcf in 2017, US$6.94/Mcf in 2018, US$7.12/Mcf in 2019, US$7.33/Mcf in 2020, escalated 2%/year thereafter; Banarli US$6.28/Mcf in Q4 2016, US$6.45/Mcf in 2017, US$6.79/Mcf in 2018, US$6.97/Mcf in 2019, US$7.18/Mcf in 2020, 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

28 Summary VLE provides exposure to a high netback, natural gas pure play in Turkey: $7-8/Mcf natural gas price realizations effective October 1, 2016; 12.5% government royalty; and $30-35/boe operating netbacks Statoil farm-in on deep formations at Banarli has validated potential of a basincentered gas play in over-pressured tight gas sands below approximately 2,500 m Sale of 50% of VLE s deep rights on the West Thrace lands to Statoil expands the joint venture relationship with Statoil but no unilateral drilling by Statoil before Banarli earning US$18 MM of cash received to date from Statoil provides key source of non-dilutive funding for the TBNG Acquisition without any reduction in VLE reserves (no reserves or resources assigned to deep play at this time) TBNG Acquisition expected to close in February 2017, which will double VLE s interest in the TBNG JV to 81.5% and establish VLE as operator Equity raise of $11.0 MM provides additional financial capacity to fund completion of the TBNG Acquisition and ramp-up shallow gas drilling on the TBNG JV lands and Banarli licences 2017 capital budget and work program to be firmed post closing of the TBNG Acquisition Targeting spud of first Statoil-funded deep well at Banarli in Q

29 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: operational activities and drilling plans on the Banarli licences and TBNG JV lands; the ability to satisfy the conditions for closing the TBNG Acquisition and the Subsequent West Thrace Deep Rights Sale, including securing Turkish government approvals for the transfer of licence interests; the ability to close the TBNG Acquisition and the expected timing; the ability to close the Subsequent West Thrace Deep Rights Sale and the expected timing; the cash consideration for the TBNG Acquisition after final closing adjustments; the ability to fund the TBNG Acquisition with the proceeds from Statoil under the Banarli Farm-in and West Thrace Deep Rights Sale and the Offering; the expected payment of US$3 million on the closing of the Subsequent West Thrace Deep Rights Sale; 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 satisfy the escrow release conditions with respect to the Offering and the expected timing; the capital structure post the TBNG Acquisition; the ability to ramp-up the drilling program in the shallow formations on the TBNG JV lands and Banarli licences; the prospectivity of the shallow formations on the TBNG JV lands and Banarli licences; the ability to fulfill the commitment program of spudding four shallow wells on the West Thrace lands by late June 2017; funding for the 2017 work program; the planned drilling and seismic program in 2017 for the Banarli Farm-in 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 of the areas in which the Corporation is operating and completing transactions, and in particular the aftermath of the July 2016 failed coup attempt in Turkey; continued safety of operations and ability to proceed in a timely manner; the ability to close the TBNG Acquisition and the Subsequent West Thrace Deep Rights Sale and satisfy the escrow release conditions with respect to the Offering; 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; the ability to meet drilling deadlines and other requirements under licences and leases; 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 and associated exploration, development and marketing plans and anticipated costs and sales prices, which are subject to change based on, among other things, the actual results of drilling and related activity, availability of 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 forwardlooking 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: the risks of delay or not obtaining GDPA and Turkish government approvals in a timely manner for the transfer of licence interests in light of the July 2016 failed coup attempt in Turkey and its aftermath, or satisfying other conditions for closing the TBNG Acquisition or the Subsequent West Thrace Deep Rights Sale; failure to satisfy the escrow release conditions with respect to the Offering; 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; uncertainty regarding the availability of drilling rigs and associated equipment on the contemplated timelines for shallow drilling and deep drilling; 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, including potential changes in political leaders or parties or a resurgence of a coup or other political turmoil; 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 29

30 Reader Advisories (Cont d) Forward-Looking Statements (Cont d): disasters; the risk associated with international activity; the uncertainty regarding the ability to fulfill the drilling commitments on the two exploration licences 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; 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. Other Advisories: INITIAL ON-STREAM PRODUCTION RATES: The initial on-stream production rates and short production test rates disclosed in this presentation are preliminary in nature and may not be indicative of stabilized on-stream production rates. Initial on-stream production rates are typically disclosed with reference to the number of days in which production is measured (e.g., IP30 refers to an initial on-stream production rate measured over a 30 day period). Initial on-stream production rates are not necessarily indicative of long-term performance or ultimate recovery. To date, shallow gas conventional wells and fraced unconventional tight gas wells have exhibited relatively high decline rates at more than 50% and 75%, respectively, in their first year of production. All natural gas rates and volumes are presented net of any load fluids ESTIMATED ULTIMATE RECOVERY ( EUR ): An approximation of the quantity of oil or gas that is potentially recoverable or has already been recovered from a reserve or well. EUR is not defined in the COGE Handbook. CUMULATIVE PRODUCTION: the total amount of oil and gas recovered from a reservoir as of a particular time in the life of the field, basin or well, as the case may be. Cumulative production is not defined in the COGE Handbook. FUTURE NET REVENUE: The net present value of estimated future net revenue disclosed in this presentation should not be construed as the current market value of estimated crude oil, natural gas liquids and natural gas reserves attributable to Valeura's properties. The estimated discounted future net revenue from reserves are based upon price and cost estimates which may vary from actual prices and costs and such variance could be material. Actual future net revenue will also be affected production, supply and demand for crude oil and natural gas, curtailments or increases in consumption by purchasers and changes in governmental regulations or taxation. DISCLOSURE OF LESS THAN ALL RESERVES: Estimates of reserves for individual properties in this presentation may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. BARRELS OF OIL EQUIVALENT: The term "boe" or barrels of oil equivalent may be misleading, particularly if used in isolation. A boe conversion ratio of 1 boe to 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. RECYCLE RATIO: The recycle ratios disclosed in this presentation were calculated by dividing operating netback by the finding and development costs for the year. Operating netback (or operating cash flow) is calculated as petroleum and natural gas sales less royalties, production expenses and transportation costs. 30

31 Reader Advisories (Cont d) Other Advisories (Cont d): 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 2015 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 prospects and potential drilling locations on the Banarli licences 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. 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 and 2015 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 and the 2015 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 Glossary: Certain other terms used in this presentation but not defined herein or under "RESERVES DEFINITIONS" below are defined in NI or the AIF and, unless the context otherwise requires, shall have the same meanings herein as in NI 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, "2012 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 13, 2013 and effective December 31, "2013 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 11, 2014 and effective December 31, "2014 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 10, 2015 and effective December 31, "2015 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 8, 2016 and effective December 31, "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 " means National Instrument , Standards of Disclosure for Oil and Gas Activities. "TBNG-PTI acquisition" means the joint acquisition of non-operated producing natural gas assets and lands in the Thrace Basin of Turkey and other interests in exploration lands in the Anatolian Basin of Turkey from Thrace Basin Natural Gas Turkiye Corporation and Pinnacle Turkey, Inc. by Valeura and an affiliate of TransAtlantic Petroleum Ltd. completed in "TBNG JV" means the joint venture of Valeura (40% WI), Thrace Basin Natural Gas Turkiye Corporation (41.5% WI; operator) and Pinnacle Turkey, Inc. (18.5% WI). "TBNG JV lands" means the lands acquired by the TBNG JV under the TBNG-PTI acquisition. 31

32 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 sum of the estimated proved plus probable plus possible 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 km 2 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 NPV 10 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) 32

33 A GLOBAL ENERGY COMPANY FOCUSED ON EXCEPTIONAL VALUE CREATION SUPPLEMENTARY INFORMATION

34 Our Heritage Senior Management Board of Directors 34

35 Past Successes of Management & Board Sold 2009 $360 mm 3x ROI ( 04-09) CAGR 22% Market Cap ~$6,738 mm 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% Sold in 2004 $228 mm 5x ROI ( 99-04) CAGR 43% Sold in 2014 $1,800 mm 2x ROI ( 11-14) CAGR 24% 35

36 Organization Structure BOARD OF DIRECTORS Bill Fanagan Jim McFarland Claudio Ghersinich Ron Royal Tim Marchant Stephanie Stimpson, Corporate Secretary PRESIDENT & CEO Jim McFarland CFO Steve Bjornson VP ENGINEERING VP OPERATIONS VP EXPLORATION Don Shepherd Lyle Martinson Rob Sadownyk VP BUSINESS DEVELOPMENT Barry Wihak CONTROLLER Ryan Tomlinson JV ACCOUNTANT Debbie Harding TURKEY BRANCH Mehmet Ekinalan Sema Canpolat Zeynep Urkut Ozan Arin GEOSCIENCE TECHNICIAN CONSULTANTS Mike Kohut 3 G&G 3 D&C 1 Acct 0.5 IT 36

37 Officers President & CEO: Jim McFarland, P. Eng. 44 years oil & gas experience Former President & CEO, director and co-founder, Verenex Energy (Libya light oil) Former Managing Director, Southern Pacific Petroleum (Australian shale oil) Former President & COO, Husky Oil (heavy oil, upgrading) 23 year career with Imperial Oil (conventional oil & gas, heavy oil, oil sands in-situ & mining, HSE) & other Exxon affiliates in the US, UK & Western Europe (offshore, research) - VP roles (Environment; Oil Sands; Exxon Production Research) Director MEG Energy Corp. (oil sands in-situ) and Pengrowth Energy Corporation (Canadian oil & gas); past director Verenex Energy, Vermilion Energy Trust, Aventura Energy, Southern Pacific Petroleum and Central Pacific Minerals Member Program Committee, World Petroleum Council Australian Centenary Medal (2003) for outstanding service through business & commerce MSc Petroleum Engineering (Alberta); BSc Chemical Engineering (Honours) (Queen s); Executive Development Program (Cornell) CFO: Steve Bjornson, CA 30 years oil & gas experience 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) 37

38 Officers (Cont d) VP Engineering: Don Shepherd, P. Eng. 43 years oil & gas experience Former General Manager, Verenex Energy Area 47 Libya based in Tripoli 13 years with Saudi Aramco as Asset Management Team Leader and Senior Engineering Specialist (Saudi Arabia) 12 years in executive management positions with junior oil & gas companies in Canada (Highfield Oil & Gas, Roxy Petroleum, Morgan Hydrocarbons, Newscope Resources) 10 years with Imperial Oil and Exxon (including Libya posting) BSc Electrical Engineering (Saskatchewan) VP Operations: Lyle Martinson, P. Eng. 39 years oil & gas experience 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) 38

39 Other Vice Presidents VP Business Development: Barry Wihak, P. Geol. 33 years oil & gas experience 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) VP Exploration: Rob Sadownyk, P. Geol. 28 years oil & gas experience 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) 39

40 Managers Country Representative (Ankara, Turkey): Mehmet Ekinalan 9 years oil & gas experience 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) 40

41 Board of Directors Bill Fanagan, CA (Chair) Claudio Ghersinich, P. Eng. Tim Marchant, Ph. D Jim McFarland, P. Eng. Ron Royal, P. Eng. Former Chairman, Verenex Energy Inc. Former President & CEO, Gulf Indonesia Resources Limited Financial background (Audit Chair) Co-founder & former EVP Business Development, Vermilion Energy Trust Former Director, Verenex Energy Inc. Business and engineering background Adjunct Professor, Strategy & Energy Geopolitics, Haskayne School of Business, University of Calgary Former VP Exploration & Production, BP Middle East Geological background (Ph. D) President & CEO Engineering background Former President & GM, Esso Chad Engineering background 41

42 Mezardere Slope Fan Model DTD-6 Mezardere consists of a north-easterly prograding slope fan complex, deposited within delta front and pro-delta setting Potential reservoirs include: Porous channel and basin floor sands Interlaminated sands and shales from channel abandonment, overbank, distal apron facies Organic shale source intervals 3931 Basin Floor Fans Kayi-14 Kayi-6 Meandering Slope Channel Kayi Karaevli Gazi Single Stage Re-entry Frac Frac: 97,000 lbs, 431 bbls XL gel/ 46-53% N2 IP30 rate 1.5 MMcf/d DTD-6 DTD-11 DTD-7 5 km See Initial On-Stream Production Rates under Reader Advisories starting on Slide

43 Recent Osmancik & Mezardere Results & Potential Extension of Play Types into Banarli Potential Pressure Seal Hayrabolu-10 Banarli D: 152 km 2 Yayli-1 Teslimkoy fraced Osmancik completion temporarily suspended Bati Gurgen-1 Osmancik IP MMcf/d Bati Gurgen-2 Osmancik IP MMcf/d Gurgen-1 IP30: 3.3 MMcf/d (Osm) Gurgen-2 IP30: 3.3 MMcf/d (Osm) Gurgen-3 IP30: 1.1 MMcf/d (Osm) Dogu Osmanli-1 Cased (Mez) Tavanli-1 IP30: 1.4 MMcf/d (Osm) I IP30 rates (1) 2014/2015 new drills Banarli exploration drilling 2015/2016 Guney Osmanli-3 IP30: 0.7 MMcf/d (Osm) Biyakili-2ST IP30: 0.8 MMcf/d (Osm) TDR-11H IP30: 1.3 MMcf/d (Mez) TDR-5H1 IP30: 1.3 MMcf/d (Tes) Kayi-7 IP30: 2.6 MMcf/d (Mez) Kayi-14 IP30: 4.1 MMcf/d (Mez) IP30: 3.2 MMcf/d (Tes) BTD-2H IP30: 1.5 MMcf/d (Mez) (1) Rates shown are IP30 rates for fraced Mezardere ("Mez") or Teslimkoy ("Tes") formation completions and un-fraced Osmancik ("Osm") formation completions. See Initial On-Stream Production Rates under Reader Advisories starting on Slide

44 Formations Present At Top Of Potential Pressure Seal (2,500 m Depth) Potential Pressure Seal Mezardere Slope Channels Osmancik Shorelines Lower Danismen Coastal Plain Teslimkoy Basin Floor Fans Yayli-1 Bati Gurgen-1 Bati Gurgen-2 44

45 Time Horizon Slice - Similarity Seismic Image Yayli-1 5 km Bati Gurgen-1 Bati Gurgen-2 45

46 Basin Floor Fan - Spectral Decomposition Seismic Image 5 km Upper Teslimkoy Basin Floor Fan Complex Yayli-1 Bati Gurgen-1 Bati Gurgen-2 Mezardere Slope Channel Osmancik Shorelines 46

47 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 km 2 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) Kazanci/ Hayrabolu 2926 Atakoy F18-c1, c2, c3, c4 F19-d1, d4 Bekirler F17-c2, c3 10 km F18-d1, d2, d4 F18-d3 Osmanli F18-c4-2 F18-c3-1 F19-d4-1 Yagci/ Nusratli G18-b G18-b2 Gurgen Kayi Aydede G19-a1-1 F19- d F19-d3-1 Tekirdag Gazi Kilavuzlu/ Karaevli F19-c3-1 See Initial On-Stream Production Rates under Reader Advisories starting on Slide

48 TBNG JV Tight Gas Proof-Of-Concept Program Phases 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 Q re-entry fracs: 8 in H1 2011; 16 in 2012; 25 in 2013; 6 in 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 new unconventional wells fraced in new unconventional wells fraced in Multi-stage fracs in vertical wells 22 multi-stage fracs completed since mid 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) 48

49 RAW GAS RATE - MMscf/d CUMMLATIVE PRODUCTION (RAW) - Bcf Teslimkoy/Kesan Multi Frac Type Curve (Vertical Wells) (1) 2P Type Curve - Multi Frac Vertical Wells Vertical Well, 2P Bcf, Rate vs. Time Vertical Well, 2P Bcf, Cum. Production vs. Time TIME - months (1) Refers to internally generated "type curve" forecast used to project well production rates and 2P reserves/well for vertical multi-stage fraced tight gas wells associated with the Tekirdag development area. See Reader Advisories starting on Slide

50 RAW GAS RATE - MMscf/d CUMMLATIVE PRODUCTION (RAW) - Bcf Shallow Gas (2,000m) Type Curve (Vertical Wells) (1) 2P Type Curve - 2,000m MD Vertical Wells Vertical Well, 2P Bcf, Rate vs. Time 1500 Vertical Well, 2P Bcf, Cum. Production vs. Time TIME - months 0.0 (1) Refers to internally generated "type curve" forecast used to project well production rates and 2P reserves/well for vertical 2,000m MD Osmancik wells on Banarli lands. See Reader Advisories starting on Slide

51 RAW GAS RATE - Mscf/d CUMMLATIVE PRODUCTION (RAW) - Bcf Shallow Gas (1,200m) Type Curve (Vertical Wells) (1) 2P Type Curve - 1,200m MD Vertical Wells Vertical Well, 2P Bcf, Rate vs. Time Vertical Well, 2P Bcf, Cum. Production vs. Time TIME - months (1) Refers to internally generated "type curve" forecast used to project well production rates and 2P reserves/well for vertical 1,200m MD shallow wells on TBNG JV lands. See Reader Advisories starting on Slide

52 Tekirdag Area Horizontal Drilling 5 th HZ well TDR-11H Mezardere 678 m lateral 10-stage frac IP30 rate 1.3 MMcf/d 2 nd HZ well BTD-4H Teslimkoy 655 m lateral 10-stage frac IP30 rate 3.0 MMcf/d TDR-14 BTD-5 1 st HZ well DTD-19H U. Kesan 425 m lateral 7-stage frac IP30 rate 0.4 MMcf/d DTD-6 Baglik-1 DTD m 400 m 6 th HZ well TDR-5H Teslimkoy 569 m lateral 8-stage frac IP30 rate 1.3 MMcf/d 3 rd HZ well BTD-5H Teslimkoy 403 m lateral 3-stage frac IP30 rate 2.0 MMcf/d BTD-3 4 th HZ well BTD-2H Mezardere 476 m lateral 8-stage frac IP30 rate 1.5 MMcf/d See Initial On-Stream Production Rates under Reader Advisories starting on Slide

53 TBNG JV New Drill Spuds In (Q3) Hayrabolu Deep Exploration Area Hayrabolu Kazanci-5 Kuzey Atakoy-1 Guney Atakoy-2 Guney Karababa-1 F17-c2, c3 10 km 5122 Atakoy-8 F18-d1, d2, d Osmanli New Discovery Area Karanfiltepe-5, 6 Tekirdag Development Area Biyikali-2ST Tavanli-1 Guney Osmanli-3 Dogu Osmanli-1 Deveseki-1 F18-c1, c2, c3, c4 F19-d1, d4 F18-c4-2 F18-c3-1 F19-d4-1 G18-b1 Gurgen-1,2,3 TDR-5H, 9, 11H, TSK-1, 2 BTD-2H, G18-b2 3, 4H, 5, 5H Guney Kayi G19-a1-1 Baglik-1 F19-d4-2 Kayi Derin-1 F19-d3-1 DTD-19, 19H Koseilyas-1 Dogu Gazi-2 Dogu Karya-1, Sig-1 Kayi-16 F19-c3-1 TIME GROSS WELLS SPUDDED PRODUCING EVALUATING/ COMPLETING CASED & STANDING PLUGGED & ABANDONED UNCONVENTIONAL CONVENTIONAL TOTAL DRILLING 53

54 TBNG JV New Drill Spuds In 2012 WELL LICENCE SPUD (d/m/y) RIG RELEASE (d/m/y) WELL TYPE TD (m) STATUS JANUARY 1, 2016 Baglik /03/ /05/2012 Unconventional 3,594 Producing Dogu Karya /04/ /04/2012 Unconventional 2,022 Evaluating TSK /04/ /04/2012 Conventional 657 Producing Guney Atakoy /04/ /05/2012 Conventional 1,759 Producing Dogu Karya Sig /05/ /05/2012 Conventional 400 Plugged & Abandoned Guney Kayi /05/ /05/2012 Unconventional 1,496 Producing Kuzey Atakoy /05/ /05/2012 Conventional 1,820 Producing BTD /05/ /06/2012 Unconventional 2,512 Producing Kayi Derin /05/ /07/2012 Unconventional 3,754 Producing Koseilyas /06/ /06/2012 Unconventional 1,506 Producing Dogu Gazi /06/ /06/2012 Conventional 1,800 Plugged & Abandoned Guney Karababa /06/ /06/2012 Conventional 1,100 Evaluating Deveseki /06/ /06/2012 Conventional 693 Producing TSK /06/ /07/2012 Unconventional 1,400 Producing Kazanci /09/ /12/2012 Unconventional 3,253 Producing Atakoy /09/ /09/2012 Conventional 1,429 Producing Karanfiltepe /10/ /10/2012 Conventional 1,400 Producing BTD /11/ /11/2012 Unconventional 1,915 Producing TDR /12/ /01/2013 Unconventional 2,750 Producing DTD /12/ /01/2013 Unconventional 1,939 Producing 54

55 TBNG JV New Drill Spuds YTD WELL LICENCE SPUD (d/m/y) RIG RELEASE (d/m/y) WELL TYPE TD (m) STATUS JANUARY 1, 2016 TDR /01/ /02/2013 Unconventional 1,749 Producing Hayrabolu /02/ /04/2013 Unconventional 4,054 Evaluating DTD-19H /06/ /07/2013 Unconventional - Horizontal 1,626 MD 1,096 TVD Producing BTD-4H /07/ /09/2013 Unconventional - Horizontal 1,774 MD 1,004 TVD Producing Karanfiltepe /09/ /09/2013 Conventional 1,875 Plugged & Abandoned BTD-5H /11/ /12/2013 Unconventional - Horizontal 1,519 MD 975 TVD Producing Kayi /12/ /01/2014 Unconventional 1,150 Producing BTD-2H /02/ /02/2014 Unconventional Horizontal 1,240 MD 640 TVD Producing TDR-11H /02/ /03/2014 Unconventional Horizontal 1,291 MD 518 TVD Producing TDR-5H /07/ /08/2014 Unconventional Horizontal 1,698 MD 991 TVD Producing Biyikali 2ST /08/ /08/2014 Conventional 900 Producing Gurgen /08/ /09/2014 Conventional 2,100 Producing Tavanli /09/ /09/2014 Conventional 1,300 Producing Guney Osmanli /09/ /10/2014 Conventional 1,080 Producing Dogu Osmanli /10/ /10/2014 Conventional 2,100 Evaluating Gurgen /11/ /12/2014 Conventional 2,003 Producing Gurgen /01/ /01/2015 Conventional 1,803 Producing 55

56 Thrace Basin Seismic F18-c1, c2, c3, c4 F19-d1, d4 F17-c2, c3 F18-d1, d2, d4 F19-d4-1 F19- F19-d3-1 d4-2 F18-c4-2 F18-c3-1 F18- d G18-b G19-a1-1 G18-b F19-c km 2015 Banarli 3D (152 km 2 ) 2013 Osmanli 3D (232 km 2 ) 2011 Tekirdag/Hayrabolu 3D (413 km 2 ) 2013 Banarli 2D (92.5 km) 2012 acquired 2D (186 km) 2012 acquired 2D (175 km) 2012 reprocessed 3D (231 km 2 ) 2012 reprocessed 2D (704 km) Legacy seismic (3,514 km onshore) (1,586 km offshore) Drilling on 2D seismic only prior to & D seismic (645 km 2 ) guiding TBNG- PTI JV drilling since early 2012 Valeura funded D seismic on Banarli Licence & D seismic on Copkoy Licence (licence expired) Tiway Oil funded 2012 offshore 2D seismic Valeura Banarli 152 km 2 3D seismic acquisition completed June 10,

57 Turkey Natural Gas Infrastructure 57

58 Turkey Oil Infrastructure 58

59 Thrace Basin Turkey Stratigraphic Column Tertiary basin 9,000 m of tertiary age sediments Depositional environment Deltaic sands Turbidite sands Reef development on Paleozoic highs Key reservoirs Danismen - gas Osmancik gas Mezardere - gas Ceylan gas Sogucak oil Hamitabat - gas 59

60 SE Turkey Stratigraphic Column Source: IHS Energy Group 2010 (modified by Valeura) Reservoirs Sinan/Garzan reefs (Tertiary/Upper Cretaceous) Karabogaz & Mardin (Mid Cretaceous) Bedinan (Ordovician) Source Rocks Karabogaz (Cretaceous) Dadas (Silurian) Seals Germav (Upper Cretaceous) Dadas (Silurian) Play Types Structural - Reverse and normal faults - Anticlines Stratigraphic - Reefs Resource - Fractured shales 60