SHIFTING FOCUS TO 100% OWNED & OPERATED BANARLI LICENCES CORPORATE PRESENTATION MARCH 2016

Transcription

1 A GLOBAL ENERGY COMPANY FOCUSED ON EXCEPTIONAL VALUE CREATION SHIFTING FOCUS TO 100% OWNED & OPERATED BANARLI LICENCES CORPORATE PRESENTATION MARCH 2016

2 Corporate Profile Valeura Energy Inc. (VLE TSX) Canada-based oil & gas company with assets in Turkey Interests in 21 leases & licences in Turkey: 0.63 MM acres (gross); 0.31 MM acres (net) (1) Pursuing development of conventional gas & tight gas in the Thrace Basin Utilizing latest 3D seismic, horizontal drilling & multi-stage frac technologies Shifting focus to exploration of 100% owned & operated Banarli licences: Acquired 152 km 2 of 3D seismic in June 2015 Drilled 2 exploration wells in Nov-Dec 2015 with encouraging results: Bati Gurgen-1 tested 3.4 MMcf/d from Osmancik; Yayli-1 frack program underway in Teslimkoy First gas from Banarli (Bati Gurgen-1) expected imminently Q sales in Turkey 809 boe/d: 4.8 MMcf/d (net) at an average natural gas price realization of $9.93/Mcf Turkey 1P and 2P reserves 1.8 MMboe and 5.5 MMboe (company gross), respectively, at YE 2015 Turkey 1P and 2P reserves value $41 MM ($0.71 per share) and $117 MM ($2.02 per share), respectively, at YE 2015 (NPV 10 before tax) (2) $7.3 MM working capital surplus at YE 2015; no debt (1) As at March 1, 2016, reflecting interim conversion status of some existing licences to new licences and leases under terms of the new Petroleum Law. (2) 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 Non-IFRS Measures and D&M Reserves Disclosure under Reader Advisories starting on Slide 25. 2

3 Capital Structure March 1, 2016 Basic shares outstanding at March 1, ,906,135 Common shares purchasable pursuant to outstanding: Options ($0.72 weighted average exercise price per share) 5,177,000 Fully diluted shares 63,083,135 Institutions ~ 25% Management & Directors 5.7% (11.2% fully diluted) Retail ~ 70% 3

4 Q Financial & Operating Highlights Production RESULTS 3 MONTHS ENDED DEC 31, MONTHS ENDED SEPT 30, MONTHS ENDED DEC 31, 2014 Crude oil & NGLs (bbl/d) Natural gas (Mcf/d) 4,805 4,723 7,022 boe/d ,180 Financial (Canadian $ M, except per boe amounts) P & NG revenues (net) 4,425 4,309 6,921 Funds flow from operations 1,600 1,949 3,654 Net income/(loss) 287 (169) 697 Capital expenditures (net) 6, ,822 Operating costs ($/boe) Average operating netback ($/boe) Net working capital surplus 7,253 11,335 10,044 Cash 6,973 7,972 5,928 See Non-IFRS Measures under Reader Advisories starting on Slide 25. 4

5 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 returning to Turkey (offshore; onshore unconventional) Positive Business Environment G-20 country, NATO member and democracy with moderate Islamic party winning new majority in November 1, 2015 election Attractive royalty (12.5%) & corporate tax (20%) New Petroleum Law passed June 30, 2013 Available infrastructure & oil field equipment Heavily reliant on imports of oil & gas Strong product pricing linked to world oil prices & Russian gas prices Energy corridor to Europe from Middle East, Russia and neighbouring countries 5

6 Thrace Basin Transactions (1) Bulgaria E17-b4-1 E17-c1-1 E17-c Otto asset purchase (Edirne) (Valeura 35% WI) Black Sea 2013 Banarli licence award (Valeura 100% WI) Turkey VLE license application F18-b3,F19-d4 November F18-b3 F19-a4 Greece F17- c2,c3 F18- d1,d2, d4 TBNG-VLE-PTI license application F18-d3 September 2015 F18- c1,c2,c3,c4 F19- d1,d4 F18- c4-2 G18- b1-1 F18- c3-1 G18- b2-1 F19- d4-1 G19-a (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-d TBNG-PTI acquisition (Valeura 40% WI onshore; Valeura 15% WI offshore) TBNG-VLE-PTI lease application F19-d3-1 November 2015 TBNG-VLE-PTI lease application F19-c3-1 December km Sea of Marmara 6

7 Land Position In Turkey At March 1, 2016 THRACE BASIN TRANSACTION LEASES & LICENCES (1) (#) GROSS AREA (acres) VALEURA NET AREA (acres) TBNG JV - Onshore (2) (3) , ,468 Banarli Licence 5104 Award (4) (5) 2 133, ,840 Otto - Edirne 3 49,883 17,459 SUB TOTAL , ,767 ANATOLIAN BASIN TBNG JV - Gaziantep 2 152,111 39,549 TOTAL , ,316 (1) Reflects the conversion as at December 31, 2015 of some old exploration licences to new exploration licences and production leases under the New Petroleum Law. (2) Reflects recent 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). TBNG-PTI JV applications have been submitted to the GDPA for: (i) one new production lease as a carve-out from expired exploration licence 3934 (F19-d3-1) (15,765 acres gross, 6,306 acres net); and (ii) one new production lease as a carve-out from expired exploration licence 4126 (F19-c3-1) (35,346 acres gross, 14,138 acres net). Potential acreage additions from these applications have been excluded from the table. GDPA decisions remain outstanding on the two production lease applications. (3) Reflects conversion of old exploration licence 5151 to two new licences effective June 27, 2015 and expiry of old exploration licence The TBNG-PTI 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. 7

8 Turkey YE 2015 Reserves (Company Gross) 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 25. 8

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

10 TBNG JV Interests in 1 leases & licences in Thrace Basin (0.29 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 12.0 MMcf/d (gross) & 4.8 MMcf/d (net): $9.93/Mcf average natural gas price realization in Q See Non-IFRS Measures and D&M Reserves Disclosure under Reader Advisories starting on Slide

11 500 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 YTD (14 vertical & 6 horizontal) of which 18 fracked 11

12 Thrace Basin Tight Gas Learning Curve THRACE BASIN Program Exploration 3 OSMANLI DISCOVERIES 2 Banarli Discoveries Cumulative capex (1) $80MM (net) Horizontal Drills & Fracs Vertical Drills & Fracs 12 VERTICAL TESLIMKOY/KESAN DRILL & FRACS Studies 413KM 2 3D SEISMIC CORE WORK: BAGLIK-1, HAYRABOLU-10 6 Hz MEZ/TES/KESAN DRILL & FRACS 232KM 2 3D SEISMIC 152 KM2 3D Seismic Develop Re-Entry Fracs 31 TESLIMKOY/KESAN 19 MEZARDERE 5 OSMANCIK NATURAL GAS PRODUCTION boe/d (net) Shallow gas decline Tight gas growth Grow Banarli Mitigate TBNG-PTI JV Cumulative funds flow from operations (2) $69MM (net) 2P RESERVES (3) MMboe (net) 593 TBNG ACQ P Grow discovered resource base 1.7 Convert resources to reserves (1) Excludes $53.7MM acquisition cost. (2) See Non-IFRS Measures under Reader Advisories starting on Slide 25. (3) See D&M Reserves Disclosure under Reader Advisories starting on Slide 25. YE 2011 YE 2012 YE 2013 YE 2014 YE

13 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 25. KAYI MMcf/d DTD MMcf/d KAYI MMcf/d 13

14 Mezardere Slope Fan Play Fairway Mezardere Depth Structure Prospective Mezardere play fairway Banarli 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 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 fracked in 2014 Basin fairway (500 4,800 m depth); area 3,800 km 2 See Initial On-Stream Production Rates under Reader Advisories starting on Slide 25. Tekirdag 10 km 2 km Koseilyas-1 Tekirdag area Mezardere exploitation program Gazi-1 Tekirdag Area Producing Slope Channels 14

15 Banarli (Valeura 100% WI - Operated) Opportunity to Leverage Four+ Years of Learnings 3D Seismic Acquisition on Banarli May

16 Banarli Exploration Strategy Banarli licence awarded to Valeura (100% WI) in April 2013 (480 km 2 ; 185 square miles) Converted to two licences under New Petroleum Law, which extends 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 Potential for five exploration play types: 1. Osmancik transverse fault play with 3-way closure against a fault 2. Osmancik transverse fault play with 2 bounding faults 3. Mezardere/Teslimkoy slope fan play with structural-stratigraphic closure 4. Mezardere/Teslimkoy slope fan play with stratigraphic closure only 5. Basin-centered gas play concept Late 2014 Osmancik discovery at Gurgen-1 on TBNG JV lands led to new Banarli strategy to pursue shallow exploration of Osmancik and Mezardere/Teslimkoy formations on a 100% basis (<3,000 m MD) & farm-out deeper basin-centered gas play (>4,000 m MD) 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 expected imminently Spudded second exploration well Yayli-1 on December 1, 2015 (2,914 m MD): undergoing completion and fracking operations Bati Gurgen-1 and Yayli-1 wells testing play types 1, 2 and 3 16

17 TBNG JV Producing Fields & Banarli Conventional Exploration Prospects Banarli F18-c1,c2,c3,c4 Muratli Banarli F19-d1,d4 Osmanli EUR: 9.4 Bcf Yayli-1 Teslimkoy Fracking Underway Aydinkoy Bati Gurgen-1 Osmancik 24-hr production test 3.4 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 25. See D&M Reserves Disclosure and Initial On-Stream Production Rates under Reader Advisories starting on Slide

18 Osmancik Prospect Map (Play Types 1 and 2) Osmancik B PSTM Time Structure P10 Prospect Areas (1) MURATLI PROSPECT AYDINKOY PROSPECT YAYLI-1 TESLIMKOY FRACKING UNDERWAY BATI GURGEN-1 OSMANCIK 24-HR PRODUCTION TEST 3.4 MMCF/D Recently Drilled Wells Potential Drilling Locations (2) MAIN OSMANLI GAS FIELD GURGEN PRODUCING FIELD (1) Internal estimate. (2) These are internally generated prospects and drilling locations. See Drilling Locations under Reader Advisories starting on Slide 25. See Initial On-Stream Production Rates under Reader Advisories starting on Slide

19 Mezardere Prospect Map (Play Type 3) Tekirdag D PSTM Time Structure P10 Prospect Areas (1) MURATLI PROSPECT AYDINKOY PROSPECT MAIN OSMANL I GAS FIELD YAYLI-1 TESLIMKOY FRACKING UNDERWAY BATI GURGEN-1 OSMANCIK 24-HR PRODUCTION TEST 3.4 MMCF/D GURGEN PRODUCING FIELD Recently Drilled Wells Potential Drilling Locations (2) (1) Internal estimate. (2) These are internally generated prospects and drilling locations. See Drilling Locations under Reader Advisories starting on Slide 25. See Initial On-Stream Production Rates under Reader Advisories starting on Slide

20 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 20

21 Formations & Depositional Environments Within Potential Pressure Seal Area Yayli-1 Ergene-1 Banarli License 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 21

22 Robust Netbacks & Competitive Costs Drive Attractive Natural Gas Economics in Turkey Current Cost Structure US$MM (gross) Operating Netbacks $/boe (1) Royalty Opex Netback Sales Price CONVENTIONAL GAS VERTICAL WELL (2) TBNG JV BANARLI Drill & Case (2,000 m TVD) Tie-in (new facilities) Total TIGHT GAS RE-ENTRY FRAC (3) Single-stage Frac 0.5 NA TIGHT GAS VERTICAL WELL (4) Drill & Case (1,400-3,000 m TVD) Multi-stage Frac Tie-in (new facilities) Total TIGHT GAS HORIZONTAL WELLS (5) Drill & Case (1,000 m TVD) 1.1 NA Multi-stage Frac & Tie-in 1.3 NA Total 2.4 NA (1) See Non-IFRS Measures under Reader Advisories starting on Slide 25. (2) Vertical well: 2,000 m MD; tie-in to new facilities. (3) Typical re-entry fracs in Mezardere Formation. (4) Vertical wells: 1,400-3,000 m MD; four-stage frac; tie-in to new facilities. (5) Horizontal wells: 1,000 m TVD (Mezardere); 800 m lateral length; 10- stage frac; tie-in to existing facilities. 22

23 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 (500 m) with Tie-in to Existing Facilities Shallow Gas Drilling (2,000 m) with Tie-in and New Facilities (2,000 m) > > Tight Gas Well Re-Entry Frac Tight Gas Vertical Drilling & Multi-Stage Frac with Tie-in and New Facilities Tight Gas Horizontal Drilling & 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) Assume 40 acre drainage area for vertical gas wells and 80 acre drainage area for horizontal wells. (3) Valeura s type curves for new drills reflect IP30 sales rates as shown for the various well types and up to a 75% decline rate in the 1 st year. (4) Cost to drill, complete and equip a vertical well to the following MD: shallow conventional gas 500 m or 2,000 m; tight gas 1,400 m completed with a 4-stage frac. Cost to drill, complete and equip a horizontal well to a TVD of 1,000 m and an 800 m horizontal lateral completed with a 10-stage frac. (5) Utilizing the following natural gas price deck: US$9.10/Mcf in 2015 and 2016, escalated 2%/year thereafter per 2014 D&M Reserves Report. (6) First year operating netback based on: 12.5% government royalty + 1% gross overriding royalty on TBNG JV lands; operating costs: shallow gas and re-entry frac US$0.90/Mcf + US$2,500/well month; tight gas - US$1.00/Mcf + US$3,500/ well month. F&D cost includes front end capital only. See Future Net Revenue and Recycle Ratio under Reader Advisories starting on Slide

24 Summary Valeura provides exposure to a natural gas-focused, pure play in Turkey: $9-10/Mcf natural gas prices, 12.5% government royalty & >$40/boe operating netbacks Large land position of 0.63 MM acres (gross); 0.31 MM acres (net) Applying latest 3D seismic, horizontal drilling and multi-stage frac technologies to develop under-exploited conventional gas and tight gas plays in the Thrace Basin New Osmancik discoveries in 2014 & 2015 and delineation of Mezardere slope fan play on TBNG JV lands (Valeura 40% WI) have expanded opportunity portfolio on both TBNG JV lands and Banarli licences Shifted focus in 2015 and 2016 to 100% owned & operated Banarli licences, which provide conventional and over-pressured tight gas upside potential Seeking partner(s) to exploit deeper basin-centered gas potential on the Banarli licences and certain TBNG JV lands (Valeura 40% WI) Q sales in Turkey 809 boe/d $7.3 MM working capital surplus at YE 2015; no debt Turkey 2P reserves value $117 million ($2.02 per share) at YE 2015 (NPV 10 before tax) See D&M Reserves Disclosure and Future Net Revenue under Reader Advisories starting on Slide

25 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 anticipated timing of first gas from the Bati Gurgen-1 well; the ultimate extent of the Teslimkoy fracking program in the Yayli-1 well, the timing of the availability of a large coiled tubing unit and resumption of fracking operations, and the results thereof; planned tie-in of the Yayli-1 well and the timing thereof; the future completion of the Danismen formation in the Bati Gurgen-1 well and Osmancik formation in the Yayli-1 well; the planned drilling program on the Banarli licences and TBNG-PTI JV lands and the timing thereof; the extent of over-pressure below approximately 2,500 metres across the Banarli licences and certain TBNG-PTI JV lands and the potential for a basincentered gas play; the availability of operating cash flow and the ability to finance development from existing cash and operating cash flow; tieing-in new wells and getting these onstream; the timing, estimated costs and ability to fund each of the foregoing; and the plans to attract a farm-in partner(s) to drill the deep, potential basin-centered gas play on the Banarli licences and certain of the TBNG-PTI JV lands. Forward-looking statements typically contain words such as "anticipate", "estimate", "expect", "target", "potential", "could", "should", "would" or similar words suggesting future outcomes. Valeura cautions readers and prospective investors in the Corporation s securities to not place undue reliance on forward-looking statements, as by their nature, they are based on current expectations regarding future events that involve a number of assumptions, inherent risks and uncertainties, which could cause actual results to differ materially from those anticipated by the Corporation. Statements related to "reserves" or "contingent resources" are deemed forwardlooking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources can be profitably produced in the future. Forward-looking statements are based on management's current expectations and assumptions regarding, among other things: continued political stability of the areas in which the Corporation is operating and completing transactions; continued operations of and approvals forthcoming from GDPA in a manner consistent with past conduct; future seismic, drilling, fracking and workover activity on the expected timelines; the prospectivity of the Banarli licences; future production rates and associated cash flow; future cost reductions; future capital and other expenditures (including the amount and nature thereof); the ability to meet drilling deadlines and other requirements under licences and leases, including spudding deadlines under the Banarli licences; the potential reversion of 9,981 acres in Banarli licence F19-d1, d4 to TPAO; the ability to attract partners and negotiate farm-in arrangements, in particular for deep exploration on certain TBNG JV lands and on the Banarli licences; future sources of funding; future economic conditions; future currency and exchange rates; and the Corporation's continued ability to obtain and retain qualified staff and equipment in a timely and cost efficient manner. In addition, the Corporation s 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 fracking and other specialized oilfield equipment and service providers, and unexpected delays and changes in market conditions. Although Valeura management believes the expectations and assumptions reflected in such forward-looking statements are reasonable, they may prove to be incorrect. Forward looking statements involve significant known and unknown risks and uncertainties. Exploration, appraisal, and development of oil and natural gas reserves are speculative activities and involve a significant degree of risk. A number of factors could cause actual results to differ materially from those anticipated by the Corporation including, but not limited to: operational risks associated with the over-pressure encountered in the Bati Gurgen-1 and Yayli-1 wells; uncertainty associated with future flow testing results on the Yayli-1 well; risks associated with the oil and gas industry (e.g. operational risks in exploration, inherent uncertainties in interpreting geological data, and changes in plans with respect to exploration or capital expenditures, the uncertainty of estimates and projections in relation to costs and expenses, and health, safety, and environmental risks); uncertainty regarding the sustainability of initial production rates and decline rates thereafter; uncertainty regarding the availability of drilling rigs and equipment and the ability to address technical drilling challenges; uncertainty regarding the state of capital markets and availability of funding to drill prospects and for other expenditures; the risk of being unable to secure farm-in partners; the risk of being unable to meet drilling deadlines and the requirements under licences and leases; uncertainty regarding the amount of operating cash flow and ability to reduce costs and achieve capital efficiencies; the risks of disruption to operations and access to worksites, threats to security and safety of personnel and potential property damage related to political issues, terrorist attacks, insurgencies or civil unrest in Turkey; the risks of increased costs and delays in timing related to protecting the safety and security of Valeura's personnel and property; the risk of fluctuations in commodity pricing and BOTAS reference prices (in Turkish Lira); the risk of fluctuations in foreign exchange rates particularly the Turkish Lira; the uncertainty associated with negotiating with third parties in countries other than Canada; the risk of partners having different views on work programs and potential disputes among partners; the uncertainty regarding government or other approvals; potential changes in laws and regulations; risks associated with weather delays and natural disasters; and, the risk associated with international activity. The forward-looking statements included in this presentation are expressly qualified in its entirety by this cautionary statement. The forward-looking statements included herein are made as of the date hereof and Valeura assumes no obligation to update or revise any forward-looking statements to reflect new events or circumstances, except as required by law. See Valeura's most recent annual information form ("AIF") for a detailed discussion of the risk factors. 25

26 Reader Advisories (Cont d) Other Advisories: Any financial outlook or future oriented financial information in this presentation, as defined by applicable securities legislation, has been approved by management of Valeura. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management s current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes. INITIAL ON-STREAM PRODUCTION RATES: The initial on-stream production rates and 24-hour 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 fracked unconventional tight gas wells have exhibited relatively high decline rates at more than 50% and 75%, respectively, in their first year of production. All natural gas rates and volumes are presented net of any load fluids ESTIMATED ULTIMATE RECOVERY: The term estimated ultimate recovery ( EUR ) is an approximation of the quantity of oil or gas that is potentially recoverable or has already been recovered from a reserve or well. The terms Cumulative Production and EUR are 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 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

27 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 or Valeura s most recent annual information form and, unless the context otherwise requires, shall have the same meanings herein as in NI or Valeura s most recent annual information form, 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. 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. 27

28 Reader Advisories (Cont d) 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) 28

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

30 Our Heritage Senior Management Board of Directors 30

31 Past Successes of Management & Board Sold 2009 $360 mm 3x ROI ( 04-09) CAGR 22% Market Cap at Trust Conversion $916 mm 35x ROI ( 94-03) CAGR 51% Market Cap ~$300 mm Sold in 2007 $898 mm 6x ROI ( 05-07) CAGR 118% Sold in 2006 $306 mm 1.4x ROI ( 03-06) CAGR 10% Market Cap ~$4,653 mm Sold in 2004 $228 mm 5x ROI ( 99-04) CAGR 43% 31

32 Organization Structure BOARD OF DIRECTORS Abby Badwi Tim Marchant Bill Fanagan Jim McFarland Claudio Ghersinich Ron Royal Stephanie Stimpson, Corporate Secretary PRESIDENT & CEO Jim McFarland ASSISTANT Shari Lemon 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 SENIOR ENGINEER Ken Skea TURKEY BRANCH Mehmet Ekinalan Sema Canpolat Zeynep Urkut Ozan Arin SENIOR GEOLOGISTS Ron Honch Peter Luxton Mike Kohut - Tech CONSULTANTS 3 G&G 2 D&C 1 Acct 0.5 IT Debbie Harding 32

33 Officers President & CEO: Jim McFarland, P. Eng. 43 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 28 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) 33

34 Officers (Cont d) VP Engineering: Don Shepherd, P. Eng. 41 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. 38 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) 34

35 Other Vice Presidents VP Business Development: Barry Wihak, P. Geol. 32 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. 27 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) 35

36 Manager Country Representative (Ankara, Turkey): Mehmet Ekinalan 8 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) 36

37 Board of Directors Abby Badwi, P. Geol. Bill Fanagan, CA (Chair) Claudio Ghersinich, P. Eng. Tim Marchant, Ph. D Jim McFarland, P. Eng. Ron Royal, P. Eng. Vice-Chairman, Bankers Petroleum Ltd. Executive Chairman, Americas Petrogas Inc. Former President & CEO, Bankers Petroleum Ltd. Geological background 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 37

38 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

39 Recent Osmancik & Mezardere Results & Potential Extension of Play Types into Banarli Potential Pressure Seal Hayrabolu-10 Banarli Dogu Osmanli-1 Cased (Mez) D: 152 km 2 Yayli-1 Teslimkoy fracking underway Bati Gurgen-1 Osmancik 24-hr production test 3.4 MMcf/d Gurgen-1 IP30: 3.3 MMcf/d (Osm) Gurgen-2 IP30: 3.3 MMcf/d (Osm) Gurgen-3 IP(30): 1.1 MMcf/d (Osm) Tavanli-1 IP30: 1.4 MMcf/d (Osm) I P30 rates (1) 2014/15 new drills Banarli exploration drilling Q 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 fracked Mezardere ("Mez") or Teslimkoy ("Tes") formation completions and un-fracked Osmancik ("Osm") formation completions. See Initial On-Stream Production Rates under Reader Advisories starting on Slide

40 Formations Present At Top Of Potential Pressure Seal (2,500 m Depth) Potential Pressure Seal Mezardere Slope Channels Osmancik Shorelines Lower Danismen Coastal Plain Yayli-1 Bati Gurgen-1 Teslimkoy Basin Floor Fans 40

41 Time Horizon Slice - Similarity Seismic Image Yayli-1 5 km Bati Gurgen-1 41

42 Basin Floor Fan - Spectral Decomposition Seismic Image 5 km Upper Teslimkoy Basin Floor Fan Complex Yayli-1 Bati Gurgen-1 Mezardere Slope Channel Osmancik Shorelines 42

43 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 Atakoy Gurgen Osmanli Kayi Kilavuzlu/ Karaevli Bekirler 10 km Yagci/ Nusratli Aydede Tekirdag Gazi See Initial On-Stream Production Rates under Reader Advisories starting on Slide

44 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 fracked in new unconventional wells fracked in new unconventional wells fracked 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 (evaluating possible fracking) 44

45 PRODUCTION RATE - Mcf/d CUMMULATIVE RECOVERY - % OF EUR Teslimkoy/Kesan Multi Frac Type Curves (Vertical Wells) (1)(2) Type Curve - Vertical Wells D&M Vertical Well, 2P Bcf, Rate vs. Time 1000 D&M Vertical Well, 2P Bcf, Cum. Recovery vs. Time MONTHS (1) Refers to "type curve" forecasts developed by D&M to project well production rates and 2P reserves/well as at December 31, 2014 in their reserves report dated March 10, 2015 for vertical multi-stage fracked tight gas wells associated with the Tekirdag development area. (2) 2P refers to Proved + Probable. See Reader Advisories starting on Slide

46 PRODUCTION RATE - Mcf/d CUMMULATIVE RECOVERY - % OF EUR Mezardere Multi Frac Type Curve (Horizontal Wells) (1)(2) Type Curve Comparisons - Horizontal Wells VLE HZ Type #2, Reserves Bcf, Rate vs. Time D&M Teslimkoy Hz, 2P Bcf, Rate vs. Time VLE HZ Type #2, Reserves Bcf, Cum. Recovery vs. Time D&M Teslimkoy Hz, 2P Bcf, Cum. Recovery vs. Time MONTHS (1) The Valeura HZ Type #2 type curve forecast is based on average performance of Teslimkoy horizontal wells BTD-4H and BTD-5H that have been on production for 17 months and 14 months as of March 1, 2015, respectively. (2) The D&M Teslimkoy Hz type curve forecast was developed by D&M to project well production rates and 2P reserves/well as at December 31, 2014 in their reserves report dated March 10, 2015 for Teslimkoy horizontal multi-stage fracked tight gas wells associated with the Tekirdag development area. See Reader Advisories starting on Slide

47 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

48 TBNG JV New Drill Spuds In Hayrabolu Deep Exploration Area Hayrabolu-10 Kuzey Atakoy-1 Guney Atakoy-2 Guney Karababa-1 10 km Atakoy-8 Osmanli New Discovery Area Karanfiltepe-5, 6 Tekirdag Development Area Kazanci-5 Biyikali-2ST Tavanli-1 Guney Osmanli-3 Dogu Osmanli-1 Deveseki-1 Gurgen-1,2,3 TDR-5H, 9, 11H, 14 TSK-1, 2 BTD-2H, 3, 4H, 5, 5H Guney Kayi-1 Kayi Derin-1 DTD-19, 19H Koseilyas-1 Dogu Gazi-2 Dogu Karya-1, Sig-1 Kayi-16 Baglik-1 TIME UNCONVENTIONAL GROSS WELLS SPUDDED PRODUCING EVALUATING/ COMPLETING CASED & STANDING PLUGGED & ABANDONED CONVENTIONAL TOTAL DRILLING 48

49 TBNG JV New Drill Spuds In 2012 WELL LICENCE SPUD (d/m/y) RIG RELEASE (d/m/y) WELL TYPE TD (m) STATUS MARCH 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 49

50 TBNG JV New Drill Spuds WELL LICENCE SPUD (d/m/y) RIG RELEASE (d/m/y) WELL TYPE TD (m) STATUS MARCH 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 Evaluating 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 50

51 Thrace Basin Seismic 10 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,

52 Turkey Natural Gas Infrastructure 52

53 Turkey Oil Infrastructure 53

54 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 54

55 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 55