A GLOBAL ENERGY COMPANY FOCUSED ON EXCEPTIONAL VALUE CREATION UNLOCKING TURKEY S TIGHT GAS POTENTIAL CORPORATE PRESENTATION MARCH 2015

Transcription

1 A GLOBAL ENERGY COMPANY FOCUSED ON EXCEPTIONAL VALUE CREATION UNLOCKING TURKEY S TIGHT GAS POTENTIAL CORPORATE PRESENTATION MARCH 2015

2 Corporate Profile Valeura Energy Inc. (VLE TSX) is a Canada-based oil and gas company with assets in Turkey Interests in 21 leases & licences in Turkey: 1.0 MM acres (gross); 0.42 MM acres (net) (1) Focused on development of conventional gas & tight gas in the Thrace Basin Applying latest 3D seismic, horizontal drilling & multi-stage frac technologies Pursuing new 3D seismic & drilling strategy on 100% owned Banarli licence in 2015 Q sales in Turkey 1,180 boe/d, up 18% from Q3 2014: 7.0 MMcf/d (net) in Turkey at average natural gas price realization of $10.62/Mcf Average operating netback $46.22/boe (2) Significant discovered resource base in Turkey: 2P reserves 5.8 MMboe (company gross) at YE 2014 (3) 2C contingent resources MMboe (company gross) at YE 2012 (3)(4) Turkey 1P and 2P reserves value $40 MM ($0.68 per share) and $108 MM ($1.86 per share), respectively, at YE 2014 (NPV 10 before tax) (3)(5) $10.0 MM working capital surplus at YE 2014; no debt (1) As at February 28, 2015, reflecting interim conversion status of existing licences to new licences and leases under terms of the new Petroleum Law adopted in May (2) See Slide 28 "Reader Advisories NON-IFRS MEASURES". (3) See Slide 28 "Reader Advisories D&M RESERVES AND RESOURCES DISCLOSURE". (4) See Slide 28 "Reader Advisories CONTINGENT RESOURCES". (5) Based on a $Cdn/$US exchange rate of 0.86 at December 31, 2014 to convert US$ denominated reserves values in the 2014 D&M Reserves Report. 2

3 Capital Structure March 1, 2015 Basic shares outstanding at March 1, ,906,135 Common shares purchasable pursuant to outstanding: Financial warrants ($5.50 exercise price per share) 13,269,217 Options ($0.82 weighted average exercise price per share) 3,174,000 Fully diluted shares 74,349,352 Management & Directors 5.9% (7.4% FD) Institutions ~ 30% Retail ~ 64% 3

4 Q Financial & Operating Highlights (1) Production RESULTS 3 MONTHS ENDED DEC 31, MONTHS ENDED SEPT 30, 2014 YEAR ENDED DEC 31, 2014 Crude oil & NGLs (bbl/d) Natural gas (Mcf/d) 7,022 5,943 6,812 boe/d 1, ,143 Financial (Canadian $ M, except per boe amounts) P & NG revenues (net) 6,921 5,330 24,998 Funds flow from operations (2) 3,654 3,011 13,586 Net income/(loss) 697 (171) 1,090 Capital expenditures (net) 2,822 2,515 10,846 Average operating netback ($/boe) (2) Net working capital surplus 10,044 9,865 10,044 Cash & cash equivalents 5,928 5,974 5,928 (1) The above table includes figures from continuing operations in Turkey only. Prior period figures have been reclassified to remove discontinued operations in Canada. See Valeura s most recent MD&A for further discussion on discontinued operations. (2) See Slide 28 "Reader Advisories NON-IFRS MEASURES". 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 in power Attractive royalty (12.5%) & corporate tax (20%) New Petroleum Law passed May 30, 2013 (removes restrictions on maximum acreage holdings; conversion of some existing licences & award of new leases under new terms progressing) 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 Turkey YE 2014 Reserves (Company Gross) (1) MMboe 14 Possible Probable 12 Proved P 5% and 9% year-over-year increase in 1P and 2P reserves, respectively, in Turkey Primarily natural gas reserves in Thrace Basin on TBNG-PTI JV lands (Valeura 40% WI) and Edirne Licence (Valeura 35% WI) P Growth in reserves driven by: Conventional gas discoveries Additional tight gas drilling YE RESERVES 1P Turkey reserves values (NPV 10 before tax) at YE 2014 (1)(2)(3) 1P $40 MM or $0.68 per share 2P $108 MM or $1.86per share 3P $192 MM or $3.32 per share (1) See Slide 28 "Reader Advisories D&M RESERVES AND RESOURCES DISCLOSURE". (2) See Slide 28 "Reader Advisories FUTURE NET REVENUE". (3) Based on a $Cdn/$US exchange rate of 0.86 at December 31, 2014 to convert US$ denominated reserves values in the 2014 D&M Reserves Report. 6

7 Thrace Basin Transactions (1) Bulgaria E17-b Otto asset purchase (Edirne) (Valeura 35% WI) Black Sea E17-c1-1 E17-c2-1 Turkey Greece 2013 Copkoy licence award (Valeura 100% WI) F18- c F18- c Banarli licence award (Valeura 100% WI) F19- d4-1 F19- d TBNG-PTI acquisition (Valeura 40% WI onshore; Valeura 15% WI offshore) Sea of Marmara 50 km (1) New production leases issued to date by the GDPA upon conversion of all or part of some old exploration licences under the New Petroleum Law are shown in the red outline. 7

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

9 TBNG-PTI JV Interests in 14 leases & licences in Thrace Basin (0.51 MM gross acres onshore) Established shallow gas production and marketing business: - ~65 producing wells (gross) in 15 gas fields in onshore lands - Owned compression facilities & distribution lines - Direct sales to 50+ 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 Exposure to a significant tight gas resource play in the Thrace Basin in deeper sands in the Mezardere, Teslimkoy and Kesan Formations: - Applying multi-stage fracture stimulation technology, and deeper vertical and horizontal drilling Large discovered natural gas resource base: - 2P reserves 84.7 Bcf (TBNG-PTI JV gross); 33.9 Bcf (Valeura gross) at YE 2014 (1) - 2C contingent resources 1,676 Bcf (TBNG-PTI JV gross); 652 Bcf (Valeura gross) at YE 2012 (2) Q gas sales 17.3 MMcf/d (gross) & 6.9 MMcf/d (net): $10.64/Mcf average natural gas price realization in Q (1) See Slide 28 "Reader Advisories D&M RESERVES AND RESOURCES DISCLOSURE". (2) See Slide 28 "Reader Advisories CONTINGENT RESOURCES". 9

10 TBNG-PTI 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 (1) ); 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 (1) ); 2 well re-entry fracs 2015 YTD shallow gas program: Completed 3 workovers (1.3 MMcf/d aggregate initial 7-day rate (1) ) Spudded 1 new drill on Osmanli 3D seismic (producing) Kazanci/ Hayrabolu 5122 Atakoy Osmanli Gurgen Kayi Kilavuzlu/ Karaevli Bekirler 10 km Yagci/ Nusratli Aydede Tekirdag Gazi (1) See Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". 10

11 Osmanli Area Conventional Gas Drilling Guney Osmanli-3 New drills Osmanli Dogu Osmanli-1 Biyikali-2 ST Gurgen-1 Gurgen-2 Gurgen-3 Tavanli Yagci Tekirdag Banarli 5104 Seven (gross) conventional gas wells drilled on merged Osmanli & Tekirdag 3D seismic targeting Osmancik formation (also Mezardere formation in Dogu Osmanli-1) Kayi Merged Osmanli & Tekirdag 3D seismic area 3934 Karaevli Gazi Mezardere Depth Structure 5 km WELL WELL TYPE TD (m) NET PAY (m) POROSITY (%) IP30 RATE (MMcf/d) (gross) (1) STATUS MARCH 10, 2015 Biyikali-2ST Exploration Producing Gurgen-1 Exploration 2, Producing Tavanli-1 Exploration 1, Producing Guney Osmanli-3 Development 1, Producing Dogu Osmanli-1 (2) Exploration 2, Nil Evaluating Gurgen-2 Appraisal 2, Producing Gurgen-3 Appraisal 1, Producing (1) See Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". 11

12 500 m TBNG-PTI JV Shallow Gas & Tight Gas Plays Akcahalil-1 SOUTHWEST Inecik- 2 Aydede-1 YAGCI-8 ND-1 TDR-2 TS-18 DTD-1 KAYI-7 BATI GAZI-1 BATI KARAEVLI-1 OSMANCIK MEZARDERE DANISMEN NORTHEAST SHALLOW GAS Danismen & Osmancik 5 re-entry fracs since mid-2011 (Osmancik) 54 workovers & 17 new drills in YTD Recent Osmancik discoveries in Osmanli area indicate new play type potential TIGHT GAS TESLIMKOY and KESAN Mezardere, Teslimkoy & Kesan 50 well re-entry fracs since mid-2011 Gamma Ray Total Gas CEYLAN PERFED ZONE 50 km 20 new drills in YTD (14 vertical & 6 horizontal) of which 18 fracked 12

13 TBNG-PTI 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) 13

14 Thrace Basin Tight Gas Learning Curve THRACE BASIN Program Cumulative capex (1) $64MM (net) Exploration Horizontal Drills & Fracs Vertical Drills & Fracs 12 VERTICAL TESLIMKOY/KESAN DRILL & FRACS 6 Hz MEZ/TES/KESAN DRILL & FRACS 3 OSMANLI DISCOVERIES DEVELOP Studies 413KM 2 3D SEISMIC CORE WORK: BAGLIK-1, HAYRABOLU KM 2 3D SEISMIC Re-Entry Fracs 31 TESLIMKOY/KESAN 19 MEZARDERE 5 OSMANCIK NATURAL GAS PRODUCTION boe/d (net) Cumulative funds flow from operations (2) $55MM (net) Shallow gas decline Tight gas growth GROW 1170 TBNG ACQ. 2P RESERVES / 2C CONTINGENT RESOURCES (3)(4) MMboe (net) P 2C CONVERT RESOURCES TO RESERVES 1.7 (1) Excludes $53.7MM acquisition cost. (2) See Slide 28 "Reader Advisories NON-IFRS MEASURES". (3) See Slide 28"Reader Advisories D&M RESERVES AND RESOURCES DISCLOSURE". (4) See Slide 28"Reader Advisories CONTINGENT RESOURCES". YE 2011 YE 2012 YE 2013 YE 2014 YE

15 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 frac tight gas wells associated with the Tekirdag development area. (2) 2P refers to Proved + Probable. 15

16 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 tight gas wells associated with the Tekirdag development area. 16

17 Tekirdag Area Horizontal Drilling (1) 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 (1) See Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". 17

18 Tekirdag Area Mezardere/Teslimkoy/Kesan Frac Results & Potential Vertical Well Development (1)(2) 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 KAYI 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 Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". (2) See Slide 28 "Reader Advisories DRILLING LOCATIONS". DTD MMcf/d KAYI MMcf/d 18

19 Potential Mezardere Play Fairway Base Mezardere Depth Structure Alacaogl u Mezarder e Kitchen Prospective Mezardere play fairway Hayrabolu km Tekirdag Tekirdag area Mezardere exploitation program New slope fan play in Mezardere Formation showing encouraging results 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 (1) 30+ recompletion candidates identified 2 Mezardere horizontal wells drilled and fracked in 2014 Basin fairway (500 4,800 m depth); area 3,800 km 2 Plan to also test Mezardere in Hayrabolu-10 well in deeper part of basin (1) See Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". 19

20 Banarli Licence (Valeura 100% WI - Operated) Banarli I-8 Rig Drilling Seismic at Acquisition TDR-9 June

21 Potential Basin-Centered Gas Play Fairway Base Mezardere Depth Structure Temrez Alacaogl u Mezarder e Kitchen Mezardere Potential kitchen area Hayrabolu-10 Kazanci Banarli Tekirdag Gurgen-1 10 km Banarli licence awarded to Valeura (100% WI) in April 2013 (480 km 2 ; 185 square miles; 185 sections) Potential basin-centered, over-pressured, pervasive gas play in deepest part of basin where Mezardere shale may be in active hydrocarbon generating "kitchen" below 2,500 m Recent Osmancik drilling success at Osmanli has led to new Banarli strategy to pursue shallow horizon (2,500 m) on a 100% basis and fund up to 150 km 2 of 3D seismic & up to 3 exploration wells in leads identified on 92 km of new 2D seismic (June 2013) merged with >200 km of vintage 2D Application submitted to GDPA to convert Banarli licence to new licencing regime, which could be approved by mid-2015, thereby extending initial term to 5 years & deferring drilling to late 2015 Seeking partner to fund deep exploration; Moyes & Co. assisting farm-out process 21

22 Recent Osmancik & Mezardere Results & Potential Extension of Play Types into Banarli Potential Pressure Seal Hayrabolu-10 Banarli Planned 3D: 150 km 2 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) Dogu Osmanli-1 Cased (Mez) Tavanli-1 IP30: 1.4 MMcf/d (Osm) IP30 rates (1) 2014/15 new drills Guney Osmanli-3 IP30: 0.7 MMcf/d (Osm) Biyakili-2ST IP30: 0.8 MMcf/d (Osm) Kayi-7 IP30: 2.6 MMcf/d (Mez) Kayi-14 IP30: 4.1 MMcf/d (Mez) IP30: 3.2 MMcf/d (Tes) Banarli exploration leads on 2D seismic TDR-11H IP30: 1.3 MMcf/d (Mez) TDR-5H1 IP30: 1.3 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 Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". 22

23 Robust Netbacks & Competitive Costs Drive Attractive Natural Gas Economics in Turkey Operating Netbacks $/boe (1) Royalty Opex Netback Sales Price Cost Structure US$MM (gross) CURRENT CONVENTIONAL GAS VERTICAL WELL (2) FUTURE POTENTIAL Drill & Case Tie-in (new facilities) Total TIGHT GAS RE-ENTRY FRAC (3) Single-stage Frac TIGHT GAS VERTICAL WELL (4) Drill & Case Multi-stage Frac & Tie-in Total TIGHT GAS HORIZONTAL WELLS (5) Drill & Case Multi-stage Frac & Tie-in Total H 2011 Avg (1) See Slide 28"Reader Advisories NON-IFRS MEASURES". (2) Vertical well: 2,000 m TD; tie-in to new facilities (e.g. Banarli) (3) Typical re-entry fracs in Mezardere Formation. (4) Vertical wells: 1,400 m TD; four-stage frac; tie-in to existing facilities. (5) Horizontal wells: 1,000 m TVD (Mezardere); 800 m lateral length; 10- stage frac; tie-in to existing facilities. 23

24 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$MM) IRR (%) PAYOUT (MONTHS) NPV 10 (6) (US$MM) RECYCLE RATIO (7) 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. Type curves utilized for illustrative economics include: vertical well - D&M 2P curve; horizontal well - Valeura HZ Type #2 (per Slides 15 &16). (4) Targeted cost (per Slide 23) to drill, complete and equip a vertical well to the following TD: shallow conventional gas 500 m or 2,000 m; tight gas 1,400 m completed with a 4- stage frac. Targeted 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) See Slide 28 "Reader Advisories FUTURE NET REVENUE". (7) See Slide 28 "Reader Advisories RECYCLE RATIO". First year operating netback based on: 12.5% government royalty + 1% gross overriding royalty on TBNG-PTI 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. 24

25 Turkey Net Capital Budget Outlook 2015 (1) 2015 work program and budget targeting to: Achieve 2015 sales from the TBNG-PTI JV lands of 1,200 1,250 boe/d (5 to 10% growth on 2014) Drill balanced program of up to 10 new conventional gas & tight gas wells on the TBNG-PTI JV lands Acquire 150 km 2 of 3D seismic & drill at least one conventional gas exploration well at Banarli (licence retention well); seek partner to pursue deep, basin-centered gas play BUSINESS SEGMENT GROSS WELLS (#) DRILLING AND COMPLETIONS NON DRILLING TOTAL (2) NET WELLS (#) WI AMOUNT ($MM) WI AMOUNT ($MM) WI AMOUNT ($MM) TBNG-PTI JV THRACE BASIN Vertical Conventional Gas Wells Vertical Tight Gas Wells Workovers & 6 Re-entry Fracs Other TOTAL TBNG-PTI JV THRACE BASIN BANARLI Banarli (3) OTHER Edirne GRAND TOTAL TURKEY (1) Outlook as at March 10, These work programs include firm and contingent items. See Slide 27 "Reader Advisories FORWARD-LOOKING STATEMENTS". (2) Represents a best estimate of the ultimate firm program within a possible range up to $18 to $20 MM (net). (3) Licence retention well has been delayed to 2015 given that the licence conversion process remains underway with the GDPA, which is expected to be concluded by mid The planned 2015 program of one exploration well in Banarli is a licence retention well. 25

26 Summary Owning Valeura provides exposure to a natural gas-focused, pure play in Turkey, which benefits from: $10.62/Mcf natural gas prices, 12.5% government royalty & $46.22/boe operating netbacks (Q4 2014) Large land position of 1.0 MM acres (gross); 0.42 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 Pursuing new 3D seismic & first drilling on Banarli licence (100% WI operated) in 2015, which provides conventional and tight gas upside potential Q sales in Turkey 1,180 boe/d, up 18% from Q Turkey 2P reserves value $108 million ($1.86 per share) at YE 2014 (NPV 10 before tax) (1)(2) New Osmancik discoveries and Mezardere slope fan play on TBNG-PTI JV lands (Valeura 40% WI - non-operated) has significantly expanded opportunity portfolio Planning 2015 capital budget of up to $18-20 MM (net) in Turkey, contingent on level of cash flow, up significantly from $10.8 MM in 2014 $10.0 MM working capital surplus at YE 2014; no debt (1) See Slide 28"Reader Advisories D&M RESERVES AND RESOURCE DISCLOSURE". (2) See Slide 28 "Reader Advisories FUTURE NET REVENUE". 26

27 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: Valeura s 2015 work program and budget, operational plans (seismic, drilling, fracking and workovers) and capital expenditures on the TBNG JV lands and the Banarli licence 5104; expected production growth on the TBNG JV lands in 2015; the planned seismic and drilling program on the Banarli licence in 2015 and the associated timelines; the ability to negotiate a transportation and marketing arrangement with the TBNG JV to tie-in at least one well at Banarli, assuming drilling success; the potential to frac the Guney Osmanli-1 well to achieve commercial gas production; the availability of operating cash flow and the ability to finance development; tieing-in new wells and getting these on-stream; the timing, estimated costs and ability to fund each of the foregoing; the plans to attract a joint venture partner to drill the deep, potential basincentered gas play on the Banarli licence; the plans to attract a farm-in partner on the deeper horizons in certain of the TBNG-PTI JV lands; and, the ability to convert the Banarli Licence under the new licencing regime in Turkey. 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 forwardlooking 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 forward-looking 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 recompletion activity; the prospectivity of the Osmanli area on the TBNG JV lands and follow-on drilling locations; the prospectivity of the Banarli licence; future production rates, capital efficiencies 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 licence 5104 and Copkoy licence 5147; the ability to attract partners and negotiate farm-in arrangements, in particular for deep exploration on the Banarli licence 5104; 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 2015 work program and budget are based upon the current work programs proposed by 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: 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 ability to address technical drilling challenges and manage water production; uncertainty regarding the state of capital markets and the availability of future financings; 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 (including Banarli licence 5104 and Copkoy licence 5147); uncertainty regarding converting licences under the GDPA s new licencing regime; 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; 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 commodity and BOTAS pricing (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. 27

28 Reader Advisories (Cont d) Any financial outlook or future oriented financial information in this presentation, as defined by applicable securities legislation, has been approved by management of Valeura. 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 Footnotes: INITIAL ON-STREAM PRODUCTION RATES: The initial on-stream production rates disclosed in this presentation are preliminary in nature and may not be indicative of stabilized onstream production rates. 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 CONTINGENT RESOURCES: There is no certainty that it will be commercially viable to produce any portion of the contingent resources disclosed in this presentation. Additional information relating to Valeura s contingent resources, including the related contingencies, can be found in Valeura s 2012 AIF. 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. FINDING AND DEVELOPMENT ("F&D") COSTS: Valeura s F&D costs, including changes in future development costs ("FDC") but excluding the effects of acquisitions and dispositions, for 2014 were $21.78/boe on a 1P reserve basis and $25.67/boe on a 2P reserves basis. On the same basis, Valeura s F&D costs for 2013 were $34.26/boe on a 1P reserve basis and $31.64/boe on a 2P reserves basis, and for the last three years were $41.65//boe on a 1P reserve basis and $27.54/boe on a 2P reserves basis. The aggregate of the F&D costs incurred in the most recent financial year and the change during that year in estimated FDC generally will not reflect the total F&D costs related to reserves additions for that year. DRILLING LOCATIONS: This presentation discloses 75+ potential drilling locations on 40 acre spacing in the Tekirdag area on the TBNG-PTI 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 2014 D&M Reserves Report, which attributes reserves to 18 proved undeveloped locations, 54 probable undeveloped locations and 24 possible undeveloped locations (96 locations in aggregate) in the Tekirdag area. 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 AND RESOURCES DISCLOSURE: The 2011, 2012, 2013 and 2014 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 and the 2014 D&M Reserves Report, respectively. The 2011 and 2012 year-end contingent resources disclosure contained in this presentation is derived from the 2011 D&M Contingent Resources Report and the 2012 D&M Contingent Resources Report, respectively. The foregoing reports were prepared using assumptions and methodology guidelines outlined in the COGE Handbook and in accordance with NI

29 Reader Advisories (Cont d) Glossary: Certain other terms used in this presentation but not defined herein or under "RESERVE AND RESOURCE 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 Contingent Resources Report" means the independent engineering evaluation of oil and gas contingent resources attributable to the Thrace Basin properties of Valeura in Turkey prepared by D&M in its report signed March 9, 2012 and effective December 31, "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 Contingent Resources Report" means the independent engineering evaluation of oil and gas contingent resources attributable to the Thrace Basin properties of Valeura in Turkey prepared by D&M in its report signed March 13, 2013 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, "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-PTI 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-PTI JV lands" means the lands acquired by the TBNG-PTI JV under the TBNG-PTI acquisition. Reserves and Resources 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. 29

30 Reader Advisories (Cont d) Reserves and Resources Definitions (Cont d): "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. "contingent" resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingent resources have an associated chance of development (economic, regulatory, market and facility, corporate commitment or political risks). The estimates herein have not been risked for the chance of development. There is no certainty that the contingent resources will be developed and, if they are developed, there is no certainty as to the timing of such development or that it will be commercially viable to produce any portion of the contingent resources. Contingent resources are further classified in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. Best estimate ("2C") is considered to be the best estimate of the quantity of contingent resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those contingent resources that fall within the best estimate have a 50% confidence level that the actual quantities recovered will equal or exceed the estimate. Low estimate ("1C") is considered to be a conservative estimate of the quantity of contingent resources that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. Those contingent resources at the low end of the estimate range have the highest degree of certainty - a 90% confidence level - that the actual quantities recovered will equal or exceed the estimate. High estimate ("3C") is considered to be an optimistic estimate of the quantity of contingent resources that will actually be recovered. It is unlikely that the actual remaining quantities of resources recovered will meet or exceed the high estimate. Those contingent resources at the high end of the estimate range have a lower degree of certainty - a 10% confidence level - that the actual quantities recovered will equal or exceed the estimate. 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 WI working interest 3D three dimensional 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 true vertical depth 30

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

32 Our Heritage Senior Management Board of Directors 32

33 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% Sold in 2006 $306 mm 1.4x ROI ( 03-06) CAGR 10% Sold in 2004 $228 mm 5x ROI ( 99-04) CAGR 43% Market Cap ~$757 mm Sold in 2008 $202 mm 4x ROI ( 05-08) CAGR 89% Sold in 2005 $122 mm 3x ROI ( 02-05) CAGR 34% Sold in 2007 $898 mm 6x ROI ( 05-07) CAGR 118% Market Cap ~$5,920 mm 33

34 Organization Structure BOARD OF DIRECTORS Abby Badwi Jim McFarland Bill Fanagan Ken McKay Claudio Ghersinich Ron Royal Stephanie Stimpson, Corporate Secretary PRESIDENT & CEO Jim McFarland ASSISTANT Shari Lemon CFO Steve Bjornson VP ENGINEERING VP OPERATIONS MANAGER GEOSCIENCES Don Shepherd Lyle Martinson Rob Sadownyk MANAGER BUSINESS DEVELOPMENT Barry Wihak CONTROLLER Ryan Tomlinson JV ACCOUNTANT SENIOR ENGINEER Ken Skea TURKEY BRANCH Mehmet Ekinalan Sema Canpolat Zeynep Urkut SENIOR GEOLOGISTS Ron Honch Peter Luxton Mike Kohut - Tech CONSULTANTS 4 G&G 0.5 IT 2 Acct Debbie Harding 34

35 Officers President & CEO: Jim McFarland, P. Eng. 42 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) 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) 35

36 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. 37 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) 36

37 Managers Manager Business Development: Barry Wihak, P. Geol. 31 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) Manager Geosciences: Rob Sadownyk, P. Geol. 26 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) 37

38 Managers (Cont d) Country Representative (Ankara, Turkey): Mehmet Ekinalan 7 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) 38

39 Board of Directors Abby Badwi, P. Geol. Bill Fanagan, CA (Chair) Claudio Ghersinich, P. Eng. Jim McFarland, P. Eng. Ken McKay, P. Geol. Ron Royal, P. Eng. Vice-Chairman, Bankers Petroleum Ltd. 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 President & CEO Engineering background Former Executive Chairman, Bulldog Oil & Gas Inc. Geological background Former President & GM, Esso Chad Engineering background 39

40 Turkey YE 2014 Reserves (Company Gross) (1) CATEGORY LIGHT & MEDIUM OIL (Mbbl) NATURAL GAS (Bcf) TOTAL OIL EQUIVALENT (Mboe) NPV 10 BEFORE TAX (2) (US$MM) NPV 10 AFTER TAX (2) (US$MM) PROVED , PROBABLE , TOTAL PROVED PLUS PROBABLE , POSSIBLE , TOTAL PROVED, PROBABLE AND , POSSIBLE (1) See Slide 28 "Reader Advisories D&M RESERVES AND RESOURCE DISCLOSURE". (2) See Slide 28 "Reader Advisories FUTURE NET REVENUE". 40

41 Turkey YE 2012 Contingent Resources (Company Gross) MMboe 3C Contingent Resources 2C Contingent Resources 1C Contingent Resources (1)(2) 302% year-over-year increase in 2C contingent resources in Turkey (YE 2012 compared to YE 2011) Natural gas in six discovered gas fields on TBNG JV lands only (Valeura 40% WI) Area of structures 3% of gross acreage Growth in contingent resources driven by: new 3D seismic control over all of the fields new petrophysical analysis correlated to new core analysis results additional well control Primarily tight gas in the Teslimkoy and Kesan formations in the Tekirdag area, and Mezardere Formation in the Hayrabolu area (1) See Slide 28 "Reader Advisories D&M RESERVES AND RESOURCE DISCLOSURE". (2) See Slide 28 "Reader Advisories CONTINGENT RESOURCES". Not updated since YE 2012 and any decision to update dependent on results from further drilling on TBNG-PTI JV lands and Banarli 41

42 Land Position In Turkey At March 1, 2015 THRACE BASIN TRANSACTION LEASES & LICENCES (1) (#) GROSS AREA (acres) VALEURA NET AREA (acres) TBNG-PTI JV - Onshore (2) , ,141 TBNG-PTI JV - Offshore - 116,508 17,476 Banarli Licence 5104 Award (3) 1 118, ,598 Copkoy Licence 5147 Award (4) 1 20,668 20,668 Otto - Edirne 3 49,883 17,459 SUB TOTAL , ,343 ANATOLIAN BASIN TBNG-PTI JV - Gaziantep 2 152,111 39,549 TOTAL , ,892 (1) Reflects the conversion as at March 1, 2015 of some old exploration licences to new exploration licences and production leases under terms of the New Petroleum Law adopted in May (2) Applications to the GDPA remain outstanding for conversion of several exploration licences to terms under the New Petroleum Law. There is no certainty that such conversions can be achieved and timing remains uncertain. (3) Valeura has applied to the GDPA to convert the Banarli licence to the new licencing regime in Turkey, which could be approved by mid-2015, thereby extending the initial term of the licence to five years and deferring the first year drilling commitment to late There is no certainty that such a conversion can be achieved and timing remains uncertain. Valeura s current plan is to carry out 3D seismic and drill up to three exploration wells in 2015 at Banarli (including at least one licence retention well). (4) Valeura has applied to the GDPA to convert the Copkoy licence to the new licencing regime in Turkey and it may also be impacted by the licence conversion process associated with the offsetting lands in the TBNG-PTI JV lands. Therefore, the timing of any drilling commitment will likely be deferred to later in There is no certainty that such a conversion can be achieved and timing remains uncertain. 42

43 TBNG-PTI JV 2011 Frac Results WELL FRAC DATE (d/m/y) NET PAY (1) (m) POROSITY (1) (%) PEAK 24-HOUR ON-STREAM RATE (MMcf/d) (2) INITIAL 7-DAY AVERAGE ON-STREAM RATE (MMcf/d) (2) IP30 RATE (MMcf/d) (2) CUMULATIVE PRODUCTION TO FEB 28, 2015 (MMcf) Yazir-2; 1 st stage 18/07/ Yazir-2; 2 nd stage 1/08/ (3) 0.1 (3) - 3 (3) Kayi-15 30/09/ BTD-2 3/10/ ,316 Aydede-2 22/11/ DTD-7 28/11/ Kayi-14 7/12/ Dogu Yagci-1 12/12/ Aydede-1 14/12/ (1) Net pay and porosity based on preliminary cutoffs: 9% porosity; 60% water saturation; 35% clay content. (2) See Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". (3) Yazir-2 first and second stage frac production is commingled. 43

44 TBNG-PTI JV 2012 Frac Results WELL FRAC DATE (d/m/y) NET PAY (1) (m) POROSITY (1) (%) PEAK 24-HOUR ON-STREAM RATE (MMcf/d) (2) INITIAL 7-DAY AVERAGE ON-STREAM RATE (MMcf/d) (2) IP30 RATE (MMcf/d) (2) CUMULATIVE PRODUCTION TO FEB 28, 2015 (MMcf) DTD-11 7/01/ Karya Derin-1 (3) 4/02/ TDR-5 (2-stage) 11/02/ Senova-1 (4) 15/02/ Kuzey Kayi-2 19/02/ DTD-10 09/03/ Kayi-12 19/03/ BTD-1 (5) 21/03/ NA NA NA TDR-4 24/03/ DTD-4 28/03/ (1) Net pay and porosity based on preliminary cutoffs: 9% porosity; 60% water saturation; 35% clay content. (2) See Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". (3) Fracked into a water zone; well is not tied into the gathering system. (4) Frac test to extend licence term; well is not tied into the gathering system. Small volumes represent compressed natural gas sales. (5) No gas flow after frac; well is not tied into the gathering system. 44

45 TBNG-PTI JV 2012 Frac Results (Cont d) WELL FRAC DATE (d/m/y) NET PAY (1) (m) POROSITY (1) (%) PEAK 24-HOUR ON-STREAM RATE (MMcf/d) (2) INITIAL 7-DAY AVERAGE ON-STREAM RATE (MMcf/d) (2) IP30 RATE (MMcf/d) (2) CUMULATIVE PRODUCTION TO FEB 28, 2015 (MMcf) Sulemaniye-2 (3) 9/05/ NA NA NA Dogu Karya-1 (4) 22/05/ TDR-8 (Kesan) 29/05/ Kayi-7 13/06/ Guney Kayi-1 (5) 20/06/ DTD-1 11/07/ TDR-8 (Teslimkoy) 16/07/ Koseilyas-1 19/07/ BTD-3 (L. Kesan) (6) 02/08/2012 NA NA TDR-2 (7) 18/08/ Kayi Derin-1 (6) 18/12/2012 NA NA TDR-7 (2-stage) (8) 30/12/ (1) Net pay and porosity based on preliminary cutoffs: 9% porosity; 60% water saturation; 35% clay content. (2) See Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". (3) Exploratory well spudded in December 2011; two-stage frac; deep target fracked into a water zone ; well is not tied into the gathering system. (4) Exploratory well; deep target fracked into a water zone. (5) Three-stage frac. (6) "Slick water" frac into a naturally fractured interval in Kesan at a depth of 2,475 m in BTD-3 (this interval is now abandoned and well completed in Teslimkoy) & 3,700 m in Kayi Derin-1. Effective net pay & porosity are undetermined. (7) "Slick water" frac. (8) Suspended. 45

46 TBNG-PTI JV 2013 Frac Results WELL FRAC DATE (d/m/y) NET PAY (1) (m) POROSITY (1) (%) PEAK 24-HOUR ON-STREAM RATE (MMcf/d) (2) INITIAL 7-DAY AVERAGE ON-STREAM RATE (MMcf/d) (2) IP30 RATE (MMcf/d) (2) CUMULATIVE PRODUCTION TO FEB 28, 2015 (MMcf) Baglik-1 (L. Kesan) (3) 8/01/2013 NA NA NA NA NA NA Kazanci-5 (1 st stage) (4) 29/01/ NA NA NA NA BTD-5 (4-stage) (5) (Kesan) 15/02/ DTD-19 (5-stage) 01/03/ Baglik-1 (4-stage) (U. Kesan/Teslimkoy) 26/03/ ND-3 (2-stage) (Mezardere) 26/04/ BTD-3 (1 st stage) (6) (U. Kesan) 10/05/ TS-18 (Mezardere) 30/05/ BTD-5 ( 2-stage) (Teslimkoy) 10/06/ BTD-3 (2 nd stage) (Teslimkoy) 02/07/ Karanfiltepe-1 (L. Osmancik) 05/07/ (1) Net pay and porosity based on preliminary cutoffs: 9% porosity; 60% water saturation; 35% clay content. (2) See Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". (3) Abandoned interval and moved up hole to complete the Kesan / Teslimkoy. (4) Abandoned interval, appears wet. (5) Abandoned interval and moved up hole to complete the Teslimkoy. (6) Set frac plug over interval in order to move up hole and complete the Teslimkoy. 46

47 TBNG-PTI JV 2013 Frac Results (Cont d) WELL FRAC DATE (d/m/y) NET PAY (1) (m) POROSITY (1) (%) PEAK 24-HOUR ON-STREAM RATE (MMcf/d) (2) INITIAL 7-DAY AVERAGE ON-STREAM RATE (MMcf/d) (2) IP30 RATE (MMcf/d) (2) CUMULATIVE PRODUCTION TO FEB 28, 2015 (MMcf) Karanfiltepe-6 (L. Osmancik) 12/07/ Yagci-5 (Mezardere) 19/07/ DTD-19H (7-stage) (3) (Upper Kesan) 26/07/2013 NA NA BTD-1 (Teslimkoy) 30/07/ TDR-14 (U. Kesan) 05/08/ DTD-11 (Mezardere) 14/08/ DTD-7 (2-stage) (Mezardere) 17/08/ TDR-8 (Mezardere) 26/08/ DTD-6 (Mezardere) 03/09/ Karaevli-4 (Mezardere) 08/09/ NA NA NA NA BTD-4H (10-stage) (4) (Teslimkoy) 19/09/2013 NA NA (1) Net pay and porosity based on preliminary cutoffs: 9% porosity; 60% water saturation; 35% clay content. (2) See Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". (3) Partially cleaned out well (five frac balls, ball seats and sand) with service rig and coiled tubing unit. Well is tied into gathering system but likely only five intervals are contributing to flow. (4) Unsuccessful in cleaning out frac balls and seats with coiled tubing unit. Therefore unlikely that all 10 fracked intervals are contributing to flow. 47

48 TBNG-PTI JV 2013 Frac Results (Cont d) WELL FRAC DATE (d/m/y) NET PAY (1) (m) POROSITY (1) (%) PEAK 24-HOUR ON-STREAM RATE (MMcf/d) (2) INITIAL 7-DAY AVERAGE ON-STREAM RATE (MMcf/d) (2) IP30 RATE (MMcf/d) (2) CUMULATIVE PRODUCTION TO FEB 28, 2015 (MMcf) Yagci-6 (Mezardere) 07/10/ Kayi-14 (Mezardere) 23/10/ Kayi-12 (Mezardere) 28/10/ Kayi-6 (Mezardere) 31/10/ DTD-4 (Mezardere) 07/11/ Karanfiltepe-5 (2-stage) (Osmancik) 14/11/ NA NA NA NA DTD-13 (Mezardere) 21/11/ NA NA NA NA Kayi-7 (2-stage) (Mezardere) 30/11/ Guney Kayi-1 (Mezardere) 04/12/ BTD-5H (3-stage) (Teslimkoy) 20/12/2013 NA NA Kayi Derin -1 (Mezardere) 26/12/ (1) Net pay and porosity based on preliminary cutoffs: 9% porosity; 60% water saturation; 35% clay content. (2) See Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". 48

49 TBNG-PTI JV 2014 Frac Results WELL FRAC DATE (d/m/y) NET PAY (1) (m) POROSITY (1) (%) PEAK 24-HOUR ON-STREAM RATE (MMcf/d) (2) INITIAL 7-DAY AVERAGE ON-STREAM RATE (MMcf/d) (2) IP30 RATE (MMcf/d) (2) CUMULATIVE PRODUCTION TO FEB 28, 2015 (MMcf) Kayi-16 (2-stage) (Mezardere/Teslimkoy) 22/01/ TDR-9 (2-stage) (Mezardere) 03/02/ BTD-2H (8-stage) (Mezardere) 04/03/2014 NA NA TDR-11H (10-stage) (Mezardere) 25/03/2014 NA NA Kazanci-5 (Osmancik) 17/04/ TB-13 (Osmancik) 24/04/ BTD-1 (Mezardere) 06/05/ Kayi-16 (Mezardere) 04/06/ DTD-7 (Teslimkoy) 15/08/ DTD-11 (Teslimkoy) 17/08/ TDR-5H (8-stage) (Teslimkoy) 22/08/2014 NA NA (1) Net pay and porosity based on preliminary cutoffs: 9% porosity; 60% water saturation; 35% clay content. (2) See Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". 49

50 TBNG-PTI JV New Drill Spuds In YTD Hayrabolu-10 Kazanci-5 Kayi Derin-1 Dogu Karya-1, Sig-1 Hayrabolu Deep Exploration Area Kuzey Atakoy-1 Guney Karababa-1 Atakoy-8 Karanfiltepe-5, 6 Guney Atakoy-2 Guney Kayi-1 Biyikali-2ST Tavanli-1 Guney Osmanli-3 Dogu Osmanli-1 Gurgen- 1,2,3 Kayi-16 Koseilyas-1 Osmanli New Discovery Area 10 km Tekirdag Development Area Deveseki-1 TDR-5H, 9, 11H, 14 TSK-1, 2 BTD-2H, 3, 4H, 5, 5H DTD-19, 19H Baglik-1 Dogu Gazi-2 TIME UNCONVENTIONAL GROSS WELLS SPUDDED PRODUCING EVALUATING/ COMPLETING CASED & STANDING PLUGGED & ABANDONED SUB-TOTAL SUB-TOTAL YTD SUB-TOTAL CONVENTIONAL SUB-TOTAL SUB-TOTAL YTD SUB-TOTAL TOTAL YTD DRILLING 50

51 TBNG-PTI JV New Drill Spuds In 2012 WELL LICENCE SPUD (d/m/y) RIG RELEASE (d/m/y) WELL TYPE TD (m) STATUS MARCH 10, 2015 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 51

52 TBNG-PTI JV New Drill Spuds YTD WELL LICENCE SPUD (d/m/y) RIG RELEASE (d/m/y) WELL TYPE TD (m) STATUS MARCH 10, 2015 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 52

53 DTD-19H Horizontal Upper Kesan Reservoir Upper Kesan reservoir horizon (Baglik-1 producing zone) Spud June 3, 2013 (34 drill days) 1626 m m -976 m SSTVD 1,096 m TVD; 1,626 m MD GR 425 m horizontal leg Total 209 m of sand 7-stage frac Packers Plus assembly Mud gas show Lateral section length : 425 m m m -987 m SSTVD 8,613 bbls X-linked gel; 4% KCL water energized with 23-36% N2 1,071,000 lbs sand Milled out 5 frac ports IP30 rate 0.4 MMcf/d (1) (1) See Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". 53

54 BTD-4H Horizontal - Teslimkoy Reservoir Teslimkoy BTD-2 producing zone Spud July 27, 2013 (36 drill days) 1,004 m TVD; 1,774 m MD 655 m horizontal leg Total 308 m of sand 10-stage frac Packers Plus assembly 5,815 bbls X-linked gel; 4% KCL water energized with 40-48% N2 682,000 lbs sand No frac ports drilled out IP30 rate 3.0 MMcf/d on 34/64" choke (1) Lateral section length : 655 m Landing point: 1,119 m (1) See Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". 54

55 BTD-5H Horizontal - Teslimkoy Reservoir Teslimkoy BTD-2 producing zone Spud Nov 19, 2013 (15 drill days) 974 m TVD; 1,519 m MD 403 m horizontal leg Total 89 m of sand 4-stage frac Packers Plus assembly (3 fracs completed) 583 bbls X-linked gel; 2% KCL water energized with 42-59% N2 114,430 lbs sand No frac ports drilled out IP30 rate 2.0 MMcf/d on 30/64" choke (1) Lateral section length : 403 m Landing point: 1,116 m (1) See Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". 55

56 BTD-2H Horizontal - Mezardere Reservoir Mezardere DTD-6 producing zone Spud February 3, 2014 (13 drill days) 635 m TVD; 1,246 m MD Lateral section: 476 m Total sand encountered: 242 m 8-stage frac Packers Plus assembly 3,420 bbls X-linked gel; 2% KCL water energized with % N2 469,000 lbs sand Fracked on March 4, 2014 IP30 rate 1.5 MMcf/d on 28/64" to 42/64" choke (1) BTD-2 Lateral section: 476m DTD-6 (1) See Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". 56

57 TDR-11H Horizontal - Mezardere Reservoir Mezardere TS-18 producing zone Spud February 20, 2014 (11 drill days) 518 m TVD; 1,291 m MD Lateral section: 678 m Total sand encountered: 394 m 10-stage frac Packers Plus assembly 4,754 bbls X-linked gel; 2% KCL water energized with % N2 677,500 lbs sand Fracked on March 25, 2014 IP30 rate 1.3 MMcf/d on 32/64" to 60/64" choke (1) Subsequently drilled out frac ports but no change in rate Lateral section: 678 m (1) See Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". 57

58 TDR-5H1 Horizontal - Teslimkoy Reservoir Teslimkoy C producing zone Spud July 28, 2014 (12 drill days) 991 m TVD; 1,698 m MD Lateral section: 569 m Total sand encountered: 35 m Total silt encountered: 103 m 8-stage frac Packers Plus assembly 4,890 bbls X-linked gel; 2% KCl water (including sand-off clean out) energized with 34-50% N2 285,700 lbs sand Fracked on August 22, stages sanded-off IP30 rate 1.3 MMcf/d on 32/64" to 64/64" choke (1) TDR-5 TDR-5H Landing Point: 1,129m Lateral section: 569m TD: 1,698m (1) See Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". 58

59 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 (1) DTD-6 DTD-11 DTD-7 5 km (1) See Slide 28 "Reader Advisories INITIAL ON-STREAM PRODUCTION RATES". 59

60 Thrace Basin Seismic 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 JV drilling since early 2012 Valeura funded D seismic on Banarli Licence & D seismic on Copkoy Licence 3999 (licence expired in January 2013; Valeura applied for new licence) Tiway Oil funded 2012 offshore 2D seismic 60

61 Gaziantep Licences Alibey-1 Horizontal 152,111 gross acres (Valeura 26% 10 km Alibey-1 HZ (evaluating) N39-a1 N39-a4 N39-d1 N39-d2 Mardin Time Structure - 2D Seismic (1) New Licences Old Licence 4607 (1) Seismic map from TransAtlantic August 2012 corporate presentation. (2) January 2, 2013 TransAtlantic press release (Alibey-1 productivity based on swabbing operations). See Slide 28 "Reader Advisories INITIAL PRODUCTION ON-STREAM RATES". (3) Issued under New Petroleum Law in Q (Licence N39-d1 & d2; Licence N39-a1 & a2) WI) in Anatolian Basin Operated by TransAtlantic Alibey-1 Hz drilled in July 2012 as 414 m horizontal side-track in original Alibey-1 vertical well, which flowed heavy oil from the Mardin Group Sidetrack intersected 80 m of horizontal fractured pay Logged and cased to TD (2,354 m) (TVD 1,868 m) Completed 56 m gross interval at toe of well indicating initial oil productivity of 150 bbl/d (2) Perforated additional pay but tested small amounts of oil (10-15 bbl/d) at a high water-cut; under evaluation Two new licences issued to replace old Licence 4607 (3) 61

62 Turkey Natural Gas Infrastructure 62

63 Turkey Oil Infrastructure 63

64 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 64

65 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 65