Investor Presentation. May 2014

Transcription

1 Investor Presentation May 2014

2 DISCLAIMER These materials are being supplied to you by Genel Energy plc (the Company ) solely for your information and for use at this presentation. All numbers and charts included in this presentation are from Company data unless specified otherwise. These materials may not be reproduced in any form, redistributed or passed on, directly or indirectly, to any other person or published, in whole or in part, by any medium or for any purpose. Failure to comply with this restriction may constitute a violation of applicable securities laws. The presentation and these materials have not been independently verified and no representation or warranty, express or implied, is made or given by or on behalf of the Company as to, and no reliance should be placed on, the accuracy, completeness or fairness of the information, including projections, estimates, targets, or opinions contained in the presentation and these materials and no responsibility or liability is assumed by any such persons for any such information or opinions or for any errors, omissions or misstatements contained herein. The presentation and these materials do not constitute or form part of any offer or invitation to sell or issue, or any solicitation of any offer to purchase or subscribe for, or any offer to underwrite or otherwise acquire any securities, nor shall any part of these materials or the fact of their distribution or communication form the basis of, or be relied on in connection with, any contract, commitment or investment decision whatsoever in relation thereto. The information included in the presentation and these materials is subject to updating, completion, revision and amendment, and such information may change materially. No person is under any obligation to update or keep current the information contained in the presentation and these materials, and any opinions expressed in relation thereto are subject to change without notice. The presentation and materials do not constitute an offer of securities for sale in the United States or in any other jurisdiction. Any Securities referred to herein have not been and will not be registered under the US Securities Act of 1933, as amended, (the "Securities Act") or the securities law of any state of the United States, and may not be offered or sold in the United States absent registration or an exemption from the registration requirements of the Securities Act and applicable states securities laws. The distribution or transmission, directly or indirectly, of these materials in the United States or other jurisdictions may also be restricted by law, and persons into whose possession these materials come should inform themselves about, and observe, any such restrictions. This presentation includes forward-looking statements that reflect the Company's intentions, beliefs or current expectations. Forward-looking statements involve all matters that are not historical fact. The Company has tried to identify those forward-looking statements by using the words "may", "will", "would", "should", "expect", "intend", "estimate", "anticipate", "project", "believe", "seek", "plan, "predict", "continue" and similar expressions or their negatives. Such statements are made on the basis of assumptions and expectations that the Company currently believes are reasonable, but could prove to be wrong. Such forward-looking statements are subject to risks, uncertainties and assumptions and other factors that could cause the Company's actual results of operations, financial condition, liquidity, performance, prospects or opportunities, as well as those of the markets it serves or intends to serve, to differ materially from those expressed in, or suggested by, these forward-looking statements. Important factors that could cause those differences include, but are not limited to: changing business or other market conditions, general economic conditions, and the Company's ability to respond to trends in its industry. Additional factors could cause actual results, performance or achievements to differ materially. The Company and each of its directors, officers, employees and advisors expressly disclaim any obligation or undertaking to release any update of or revisions to any forward-looking statements in the presentation or these materials, and any change in the Company's expectations or any change in events, conditions or circumstances on which these forward-looking statements are based, except as required by applicable law or regulation. No information included in this presentation is intended to be a profit forecast or a financial projection or prediction. Post performance of the Company cannot be relied on as a guide to future performance. By attending the presentation or by accepting any copy of the materials presented, you agree to be bound by the foregoing limitations and conditions. 2

3 UNIQUE PORTFOLIO POSITIONED FOR GROWTH The leading portfolio of assets in the Kurdistan Region of Iraq Four world class assets Taq Taq, Tawke, Miran and Bina Bawi. Largest KRI producer with current net production capacity of 80kbopd, growth to 145kboepd targeted by end-2014 Largest holder of 2P reserves in the KRI - 453mmboe, 1.1bn boe of contingent resources (both end-2013) KRI pipeline infrastructure now complete and tied into the ITP, commissioning substantially complete Two major gas development projects in Miran and Bina Bawi to supply increasing Turkish gas supply deficit. Significant Africa Exploration Portfolio Interests in 10 licences across Angola, Morocco, Malta, Somaliland, Ethiopia and Côte d'ivoire provide material upside potential Well on very material Dilolo prospect on Block 39 offshore Angola due to spud mid-2014 Noble Paul Romano to drill Hagar Qim prospect (Malta) in May, followed by Sidi Moussa prospect (Morocco) Strong Management Team and Operating Capability Experienced executive management team across London and Ankara led by Tony Hayward Unrivalled relationships with Turkish Government and Kurdistan Regional Government Turkish brand differentiates company in Middle East and African jurisdictions Strong balance sheet to support growth engine Cash reserves of c.$0.6bn, no debt at end March $500m senior unsecured bond issue priced at 7.5% in May production guidance of 60-70kboepd (midpoint represents c.50% growth on 2013) 2014 revenue guidance of $ m, capex guidance of $ m. 3

4 STRATEGY Maintain the highest level of corporate governance Create value with the drill bit Manage our KRI business on a broadly cash flow neutral basis Maximise shareholder returns by monetising at all points in the exploration, development and production cycle and return excess cash to shareholders Build a material Exploration and Production company 4

5 PRODUCTION AND SALES Net Genel Production (kbopd) Net Genel Revenues ($m) c.145 kboepd Year-End Capacity $500 $600m (1) c.80 kbopd Capacity 70 kboepd kboepd E E (1) 2014 guidance assuming revenue recognition methodology on an accruals basis. 5

6 $m CASHFLOW AND CAPEX 800 KRI Cash Flow Neutrality since Merger Completion 600 Including: nd CPF and 4 additional production wells at Taq Taq 200 Taq Taq Deep exploration well 0 KRI Operating Cash Flow KRI Capex $564m $ m 2 nd CPF, additional production wells and 300kbopd export pipeline from field to Tawke partners Fishkabur export facility MW-5 appraisal well + EWT $229m 3D seismic at Chia Surkh and Ber Bahr Africa drilling campaign $60m $67m $46m $86m 2 wells offshore Angola 3 exploration wells in Morocco (Cap Juby, Sidi and Mir Left) E Malta Area 4 well KRI Development KRI Exploration & Appraisal Africa Exploration 6

7 CAPITAL STRATEGY Balance sheet will evolve to be consistent with Genel's future business needs and will reflect: Confidence in oil export revenue Capex needs of current portfolio Portfolio management Access to debt markets New business opportunities Commodity price environment Rigorous capital allocation process minimising non-productive capital ahead of export clarity and portfolio rationalisation c.$600 million cash balances at end Q1 14 $500 million senior unsecured bonds, due 2019, priced at 7.5% in May 2014 Significant strength and flexibility in current capital structure with potential opportunities to return excess capital to investors going forward 7

8 2014 CATALYSTS & KEY EVENTS A TRANSFORMATIONAL YEAR Politics pipeline exports to ramp up Agreement with Baghdad or independently via Turkey Ramp up of production at both Taq Taq and Tawke with international price realisations KRI Oil processing capacity to grow Processing capacity at Taq Taq to increase from 120,000 bopd to 200,000 bopd Processing capacity at Tawke to double from 100,000 bopd to 200,000 bopd KRI Gas derisking of a major gas resource Early domestic gas monetisation with first production at Dohuk Miran Gas Supply Offtake Agreement with KRG and FID for full field development Exploration further high-impact drilling Taq Taq Deep well testing results expected Q well in Malta (Area 4 licence) 2 wells offshore Angola (Dilolo on Block 39 followed by Block 38 well) 2 further exploration wells in Morocco (Sidi Moussa and Mir Left licences) 8

9 REGIONAL PIPELINE INFRASTRUCTURE New KRI export pipeline Iraq Turkey pipeline Iraq section Iraq Turkey pipeline Turkish section 40 Pipeline Tawke field 46 Pipeline Khurmala Dome Taq Taq field 40 Pipeline 46 Pipeline PIPELINE SYSTEM FULLY OPERATIONAL BY H

10 GENEL ENERGY KRI LICENSES Tawke 708 mmbbls 23 mmbbls 355 mmbbls 1,2 Processing Capacity 100 kbopd 200 kbopd 2 2P CR PR End-13 End-14 Ber Bahr Dohuk mmboe mmbbls 2P CR 50 mmbbls CR Bina Bawi 849 mmbbls CR Taq Taq 579 mmbbls 248 mmboe Processing Capacity 120 kbopd 200 kbopd 2P PR End-13 End-14 Miran mmboe mmboe CR PR 2P = 2P Reserves CR = Contingent Resources PR = Prospective Resources 1 Includes Tawke Deep and Peshkabir 2 Operator estimate Chia Surkh 250 mmboe 112 mmboe CR PR 10

11 TAQ TAQ RAMPING UP TO 200,000 BOPD CAPACITY 2013 Key Developments 77,000 bopd gross production in 2013 Strong domestic demand and pricing (c.$71/bbl) Trucked exports averaged c.20,000 bopd ($75-80/bbl) YE 2013 processing capacity of 120,000 bopd YE 2013 well production capacity >150,000 bopd Export pipeline complete; capacity >150,000 bopd 2014 Activity Export pipeline tie-in at Taq Taq (Jan 2014) Development drilling: 4 further wells One appraisal well and one vertical development well First deviated and horizontal wells on the field New TLS: 150,000bopd completed Q Completion of CPF II construction around year-end 2014 to increase processing capacity to over 200,000 bopd Taq Taq Deep testing results expected Q Taq Taq processing facilities (Jan 2014) 11

12 TAWKE CONTINUING SUCCESFUL DEVELOPMENT DRILLING PROGRAM 2013 Key Developments 39,000 bopd gross production in 2013 with domestic prices of c.$60/bbl YE 2013 processing capacity of 100,000 bopd YE 2013 well production capacity of c.155,000 bopd Horizontal production wells (TW-20 and TW-23) flowed at rates of 25,000 bopd and 32,500 bopd 2014 Activity Development drilling: 7 production wells TW-21 and TW-22 horizontals flowed at a combined rate of 37,000 bopd Three additional horizontal wells in the primary Cretaceous reservoir Two vertical wells (T-26 and T-27) in Tertiary reservoir Well capacity expected to increase to 270,000 bopd by year-end 2014 Peshkabir-1A well to spud in Q2 to test c.200mmbbls prospective resources Processing capacity expected to increase to 200,000 bopd by year-end 2014 Tawke processing facilities (DNO) Construction of a second tie-in pipeline to Fishkabur to increase total pipeline export capacity to >400,000 bopd 12

13 KRI GAS MARKET Export markets: GSA signed between Turkey and KRG in November 2013 GSA for 4 bcma of gas exports starting 2017 rising to 10 bcma by 2020 Option of increasing to 20 bcma Miran and Bina Bawi to deliver gas to underpin the GSA Gas Sales Offtake Agreements with KRG for Miran and Bina Bawi expected to be signed in 2014 Domestic market: significant value creation opportunity through domestic sales First gas from Dohuk PSC to be delivered Q mmscfd near term demand within the KRI Rapidly growing domestic economy driving gas demand (e.g. power, cement, steel, fertiliser) 9% GDP growth in 2013, per capita GDP increased sevenfold between

14 DOHUK GAS PROJECT GSA for domestic gas supply signed with KRG in September 2013 Initial deliveries of mmscfd commencing Q and ramping up to mmscfd Development first phase near completion Summail-3 well completed March 2014 Summail-2 spudded April train CPF total capacity up to 140 mmscfd: c.$100m 14

15 MIRAN Resources (RPS mean contingent) 10.5tcf gas in place 3.5tcf recoverable sales gas with 35mmbbls condensate 60mmbbls oil Image TBC Phased Gas Development Studies KRG exercises back-in right for 25% in Miran PSC (23 Feb 2014) Gas Sales Offtake Agreement H FID H Partner / financing solution H PMC contract award H First gas 2017 Capex: facilities c.$500m/bcma, c.30 development wells for both phases at c.$35m per well Opex: c.$4.0/boe Oil Development Oil EWT ongoing, production sold locally at c.$51/bbl FDP submitted (Feb 2014) and horizontal oil well to be drilled to maximise production potential MW-5 appraisal & development gas well drilling ahead (Feb 2014) 15

16 BINA BAWI Resources (RPS mean contingent) 8.1tcf gas in place 4.9tcf recoverable sales gas Gas Development Studies 6 bcma export development Gas Sales Offtake Agreement H FID 2015, first gas 2018 Capex: facilities c.$500m/bcma, c.30 development wells for both phases at c.$35m per well Opex: c.$4.0/boe Early Oil Encouraging results from BB-3 workover in January ,700 bopd 45 API crude Development feasibility study underway 16

17 KRI GAS SIGNIFICANT PROGRESS & MOMENTUM 2013 March KRG/Turkey agree Heads of Terms for bilateral Energy Agreement August Genel issued Declaration of Commerciality on the Miran discovery KRG approves Declaration of Commerciality on the Miran discovery September Gas Sales Agreement for Summail signed with KRG November KRG/Turkey sign legally binding Gas Sales Agreement February 2014 KRG exercises back-in right for 25% in Miran

18 EXPLORATION STRATEGY High Impact Exploration 4-5 wells targeted per annum Focus on material prospects: >250mmbbls with PoS >20% Further high-impact activity in 2014: Taq Taq Deep well testing, Hagar Qim (Malta Area 4), Dilolo (Angola Block 39), Nour (Sidi Moussa), Angola Block 38, Mir Left Exploration Expansion Deepen in existing hubs Establish new hubs in focus areas: Middle East and Africa Leverage Turkish roots 18

19 Probability of Success EXPLORATION INVENTORY (PoS) 50% 45% Lower risk KRI portfolio drill-out potential, proven basin, prospect specific risk Kurdistan Offshore Africa Onshore Africa 40% 35% 30% Higher risk, high-impact Africa exploration both basin and prospect specific risk 25% 20% 15% 10% 5% Miran Deep 0% Notes: - Bubble size proportional to net risked prospective resource. - Represents both current prospects and leads (does not equate to block-wide prospectivity). - Somaliland and Ethiopia lead sizes based on Yemen analogues assuming minimum 50mmbbls commerciality threshold. - Angola Block 38 & 39 prospective resource estimates have not been disclosed by operator Gross mean unrisked resources (mmboe) 19

20 TRIASSIC JURASSIC D E PTH (MSL) CRETACEOUS KRI EXPLORATION TAQ TAQ DEEP Top Jurassic Depth Map Seismic Line S W TT-22 N E Results to date Drilling operations completed in March 2014 at a depth of 4,600m Gas encountered in Jurassic (Naokelekan, Sargelu and Butmah) and Triassic (Kurrachine) Key prospect / drilling info Testing programme on Triassic and Jurassic currently in progress Results due Q

21 AFRICA EXPLORATION HIGH IMPACT WELLS TARGETED IN 2014 NORTH ATLANTIC OCEAN Mir Left Sidi Moussa Juby Maritime MOROCCO Area 4 Morocco 3 licences, 13,890km 2 combined Juby Maritime (37.5% W.I.) 550mmboe Sidi Moussa (60% W.I.) 700mmboe Mir Left (75% W.I.) 750mmboe Malta 1 licence, 5,715km 2 Area 4 (75% W.I.) 700 mmboe CÔTE D IVOIRE ATLANTIC OCEAN San Pedro ATLANTIC OCEAN Block 38 Luanda ANGOLA Odewayne Block Block CI-508 Adigala Block Block SL-10B/13 Block 39 Côte d Ivoire 1 licence, 1,060km 2 combined CI-508 (24% W.I.) 300mmboe Angola 2 licences, 14,000km 2 combined Block 38 (7.5% W.I.) Block 39 (7.5% W.I.) Note: resource numbers shown on this page refer to gross mean prospective unrisked resources. Ethiopia 1 licence, 20,400km 2 Adigala (40% W.I.) 500mmboe Somaliland 2 licences, 47,000km 2 SL-10B/13 (75% W.I.), 1bnboe Odewayne (50% W.I.), 1bnboe 21

22 ANGOLA PRE-SALT PLAY AND GENEL ENERGY LICENCES Whales Park (Pre-Salt) (Post-Salt) Discoveries South Atlantic plate reconstruction Kwanza Basin analogue of prolific Brazilian pre-salt plays All elements of a working hydrocarbon system proven in Kwanza Basin White Rose/Genel JV holds 15% WI in Blocks 38 & 39 $150m firm commitment includes entry and drilling cost for first wells on Block 38 & 39 Stena Carron drillship contracted to drill very material Dilolo prospect from mid-year

23 KWANZA BASIN PRE-SALT PLAYS Key Reservoir Intervals: Platform Carbonates Microbial Build-ups Skeletal Limestone SW NE

24 Recoverable Reserves (bn bbl) FIELD SIZE COMPARISON Santos & Campos Basins: Large Pre-Salt Field Sizes Lula, Santos Basin, Brazil bn bbls rec. reserves Angola Blocks 38 & 39 Kwanza Basin Source: ANP Modified after White Rose

25 MOROCCO JUBY MARITIME (CAP JUBY) Key play info Upper Jurassic carbonate shelf & reef play (proven) Middle Jurassic oolitic shoal play Cap Juby: 110m water depth Top Upper Jurassic reservoir: 2,110m TVDSS at JM-1 OWC, oil and gas shows down to 2,330m TVDSS Forward activity - evaluate Upper Jurassic discovery Attractive fiscal terms mean even small volumes could be commercial 25

26 MOROCCO SIDI MOUSSA (NOUR PROSPECT) NOUR-1 Upper Jurassic Mid Jurassic Top Salt Key play info Upper Jurassic carbonate reef play; analogue to Cap Juby discovery Middle Jurassic oolitic shoals play Nour-1: 980m water depth Top Upper Jurassic reservoir: 1,936m TVDSS Top Mid Jurassic reservoir: 2,110m TVDSS 26

27 MOROCCO MIR LEFT Salt Flank Leads BTU L.CRET UPPER JUR MID JUR SALT New 3D Seismic (PSTM, 2013) Upper Jurassic 1 Salt 2 Sub-Salt Structure Key play info Salt flank trap Upper & Middle Jurassic carbonate platform with reefs 2 Leads identified and maturing 1,000 km 2 3D seismic acquired in 1H2013 Continued targeting of Jurassic Carbonate fairway Continued evaluation of the sub-salt play

28 MALTA GEOLOGICAL CONTEXT Cretaceous Libyan Sirte Basin rift extension into Maltese waters Hagar Qim will test a Tertiary carbonate build up The Lower Eocene & Upper Cretaceous carbonate plays host billion barrel fields on the North African Margin 28

29 MALTA AREA 4 (HAGAR QIM PROSPECT) SW Hagar Qim 1 NE Lower Eocene Tertiary Cretaceous Cretaceous upside Cretaceous leads will be matured in 2014 with new PSDM Prospective resources in Cretaceous: 450mmboe Hagar Qim-1: 460m water depth Top reservoir (Lower Eocene) crest: ~2,200m TVDSS 4 way dip closed structure with stratigraphic upside 3 build up prospects identified at the Lower Eocene Level 29

30 Africa Kurdistan EXPLORATION ACTIVITY PROGRAMME Assets W.I. Country Block Gross Unrisked Prospective Resources (mmboe) Block Net Unrisked Prospective Resources (mmboe) H H H H Gross Unrisked Resource Prospect (mmboe) Net Unrisked Resource Prospect (mmboe) PoS Taq Taq Deep 44% KRI % Peshkabir-1A 25% KRI % Tawke Deep 25% KRI % Miran Deep 75% KRI % Area 4 (Tertiary) Dilolo (Block 39) 75% Malta % 7.5% Angola See footnote Sidi Moussa 60% Morocco % Mir Left 75% Morocco % Block % Angola See footnote Block % Cote d Ivoire % Juby Maritime (Upside) Area 4 (Cretaceous) 37.5% Morocco % 75% Malta % Adigala 40% Ethiopia * % Prospective resource estimates for Block 38 and Block 39 have not been disclosed by the operator, although Genel s press release on the deal described Block 38 and 39 as holding multi-billion barrel prospectivity and Dilolo was described as a very material prospect *Notional prospect size 30

31 2014 AN EXCITING YEAR AHEAD Q1 Q2 Q3 Q4 Politics & Infrastructure KRI Oil Commissioning of KRI- Turkey export pipeline infrastructure Tawke-21 and 22 (horizontal wells) results Tawke-24 and 26 (horizontal wells) spud Taq Taq first deviated well spuds Taq Taq appraisal well spuds Tawke-25 (horizontal well) spuds Peshkabir-1A well spuds Ramp-up of export volumes via KRI-Turkey pipeline infrastructure Taq Taq first horizontal well spuds Taq Taq vertical well spuds Tawke-27 and 28 (horizontal wells) spud Tawke Tertiary 1 and 2 wells spud Tawke-29 appraisal well spuds Taq Taq CPF II completion (around year-end) Tawke production capacity upgrade (100->200kbopd by year-end) Peshkabir-2 well spuds KRI Gas Summail-2 well spuds First Summail gas Miran GSOA (H2 2014) Miran West-5 appraisal well results (by mid-year) MW-5 gas EWT commences Summail-4 (or 5) appraisal well spuds Exploration Cap Juby (Morocco) exploration well results Adigala seismic acquisition commences Hagar Qim (Malta) exploration well spud Taq Taq Deep exploration well testing results Dilolo (Angola) exploration well spud Hagar Qim (Malta) exploration well results Sidi Moussa (Morocco) exploration well spuds Dilolo (Angola) well results Sidi Moussa (Morocco) exploration well results Mir Left (Morocco) exploration well spuds Block 38 (Angola) exploration well spuds 31

32 SUMMARY & 2014 OUTLOOK Oil Significant production growth of > 50% in 2014 Gas Genel s first gas sales at Dohuk Q Derisking of major gas resource (Miran and Bina Bawi GSA & FID) Exploration High impact exploration wells including the very material Dilolo prospect offshore Angola Financial strength Fully funded 32

33 GENEL ENERGY RESERVES AND RESOURCES (END-2013) Gross Resource Net Resource 2P 3P Contingent Unrisked Prospective Working Interest 2P 3P Contingent Unrisked Prospective PoS Risked Prospective mmboe mmboe mmboe mmboe % mmboe mmboe mmboe mmboe % mmboe Producing assets Taq Taq % Tawke % Total 1,287 1, Development assets Miran % % 60 Bina Bawi % Total - - 1, E&A Portfolio Taq Taq Deep % % 44 Tawke Deep % % 14 Miran Deep % % 100 Dohuk % Peshkabir % % 22 Chia Surkh % Barda Sur & Qalami % % 13 Ber Bahr % Total , Total KRI 1,339 1,869 1,917 1, , Juby Maritime - Cap Juby % % 31 Juby Maritime - Exploration % % 23 Sidi Moussa % % 84 Mir Left % % 113 Malta Area 4 - Tertiary % % 38 Malta Area 4 - Cretaceous % % 51 Cote d' Ivoire - Block % % 11 Somaliland - Block 13/10B ,000 75% % 113 Somaliland - Odewayne ,000 50% % 75 Ethiopia - Adigala % % 30 Total Africa , , Total E&A , , Total 1,339 1,869 1,917 7, ,088 4, Note: Does not reflect DNO International s (Tawke operator) Annual Statement of Reserves 2013, which reported gross remaining 2P oil reserves for the Tawke field at end-2013 of 714mmbbls. 33

34 Appendix 34

35 EXECUTIVE MANAGEMENT TEAM ACROSS LONDON AND ANKARA Tony Hayward Chief Executive Officer Group CEO of BP from 2007 to 2010 Previous roles at BP include Group Treasurer and Chief Executive for Upstream Activities Senior independent director of Glencore John Hurst Head of Exploration Founder of Barrus Petroleum Previously held senior positions with BP and Total Previously a director of AIM listed Indago Petroleum Mehmet Sepil President Founded Genel Energy in 2002 Previously served as founder, president and chairman of Zafer and EPIK Construction Dawn Summers Head of Operations & Development Over 20 years experience at BP most recently as VP for Capability for Operations, HSE and Engineering Starting in April 2013 Julian Metherell Chief Financial Officer Former partner at Goldman Sachs & CEO of their UK investment banking business Significant experience in the international energy sector Stephen Mitchell General Counsel Joined Genel in November 2011 Previously VP Legal with BHP Billiton plc (6 years), Group General Counsel at Reuters Group plc (7 years), Partner Freehills (6 years) Murat Özgül President, Turkey & KRI Joined Genel as CCO in 2008 CEO of INTA SpaceTurk from 2006 to 2011 Led the merger of Genel Energy International with Vallares Plc in 2011 Martha Desmond Head of HR Over 20 years experience in international HR Previous companies include BG Group and Thames Water Charles Proctor President, Africa and Head of Commercial 23 years at BP Previous roles include President BP Middle East, BP Group Chief of Staff, Chief Financial Officer BP Azerbaijan, Commercial Manager BP Angola Joined Genel as an Advisor in 2011 Served in Undersecretariat of Treasury and Foreign Trade department of Turkish Govt between Partner at AB Consultancy Macit Merey Deputy Chief Financial Officer Joined Genel in 2005 and worked as CFO of Genel since 2009 Seconded to Taq Taq Operating Company from 2006 to 2009 as Finance & Accounting Manager 35 Pars Kutay Head of Government & Public Affairs 35

36 GENEL ENERGY NON-EXECUTIVE DIRECTORS Rodney Chase Chairman Former positions include Chairman of Petrofac, Deputy Chairman of Tesco, Deputy Chairman of TNK-BP, Senior Independent Director at Diageo 38 years at BP covering all major businesses, including 11 years on the Board Mark Parris U.S. Ambassador to Turkey from 1997 to 2000 and Special Assistant to the President for Near East/South Asian affairs Senior Non-Resident Fellow at Brookings Institute Jim Leng Former Chairman of Corus Group and former Deputy Chairman of Tata Steel Senior Advisor and Non-Executive Director at HSBC Bank plc Mehmet Ögütçü Chairman of the Global Resources Corp. Senior Counsellor to BG Group Previous positions at the OECD and IEA Former Turkish diplomat in Ankara, Beijing, Brussels and Paris Sir Graham Hearne Chairman of the Catlin Group and Braemar Shipping Services Chairman of Enterprise Oil between and CEO from Murat Yazici Board member of various multinational companies operating in Turkey Founding Chairman of Petroleum Platform Association Founding & Managing Partner of Yazici Law Firm George Rose Non-Executive director at Experian plc Non-Executive Chairman of the Audit Committee of National Grid Former Group Finance Director at BAE Systems for 13 years Chakib Sbiti Special advisor to the Chairman and CEO of Schlumberger since years service at Schlumberger including VP of Oilfield Services and President for Asia & Middle East Nathaniel Rothschild Non-Executive Director of Barrick Gold Corp Member of the Belfer Center s International Council at the JFK at Harvard University Nazli Karamehmet Williams Board member of Turkcell, a leading Turkish communications company Executive board member at Digiturk 36 36

37 KURDISTAN REGION OF IRAQ PSC TERMS Taq Taq Tawke Miran Dohuk Ber Bahr Chia Surkh Bina Bawi Genel Paying Interest 55% 25% 75% 1 40% 60% 75% 55% Genel Working Interest 44% 25% 75% 1 40% 40% 60% 44% KRG carried interest 20% 20% 25% (not carried) 1 20% 20% 20% 20% State royalty 10% 10% 10% 10% 10% 10% 10% Cost recovery limit - Oil Crude oil and assoc. natural gas: 40% Crude oil and assoc. natural gas: 45% Crude oil and assoc. natural gas: 40% Crude oil and assoc. natural gas: 43% Crude oil and assoc. natural gas: 40% Crude oil and assoc. natural gas: 40% Crude oil and assoc. natural gas: 40% Cost recovery limit - Gas Non-assoc. gas: 55% Non-assoc. gas: 55% Non-assoc. gas: 50% Non-assoc. gas: 55% Non-assoc. gas: 53% Non-assoc. gas: 53% Non-assoc. gas: 55% Contractor share of Profit Oil (R Factor = cumulative revenues / cumulative costs) Oil: Per R-Factor R < 1.0: 30% 1 < R < 2.5: 30% - ( )*(R-1)/(2.5-1) R > 2.5: 15.6% Gas: Per R-Factor R < 1.0: 38% 1 < R < 3.0: 38 - (38-20)*(R-1)/(3.0-1) R > 3.0: 20% Oil: Per R-Factor R < 1.0: 38% 1 < R < 2.4: 38% - (38-16)*(R-1)/(2.4-1) R > 2.4: 16% Gas: Per R-Factor R < 1.0: 40% 1 < R < 3.0: 40 - (40-22)*(R-1)/(3.0-1) R > 3.0: 22% Oil: Per R-Factor R < 1.0: 30% 1 < R < 2.0: 30 - (30-15)*(R-1)/(2.0-1) R > 2.0: 15% Gas: Per R-Factor R < 1.0: 35% 1 < R < 2.75: 35 - (35-18)*(R-1)/(2.75-1) R > 2.75: 18% Oil: Based on R- Factor R < 1.0: 32% 1 < R < 2: 32 - (32-16)*(R-1)/(2-1) R > 2: 16% Gas: Per R-Factor R < 1.0: 40% 1 < R < 3.0: 40- (40-22)*(R-1)/(3-1) R > 3.0: 22% Oil: Per R-Factor R < 1.0: 32% 1 < R < 2.0: 32 - (32-16)*(R-1)/(2-1) R > 3: 16% Gas: Per R-Factor R < 1.0: 35% 1 < R < : 35- (35-20)*(R-1)/(2.75-1) R > 2.75: 20% Oil: Per R-Factor R < 1.0: 30% 1 < R < 2: 30 - (30-15)*(R-1)/(2.0-1) R > 2: 15% Gas: Per R-Factor R < 1.0: 35% 1 < R < : 35- (35-20)*(R-1)/(2.75-1) R > 2.75: 20% Oil: Per R-Factor R < 1.0: 30% 1 < R < 2: 30 - ((30-15)*(R-1)) R > 2: 15% Gas: Per R-Factor R < 1.0: 40% 1 < R < 2: 40 - ((40-20)*(R-1)) R > 2: 20% Capacity Building Payment 30% of Genel s profit oil 30% of Genel s profit oil 7.5% of Genel s profit oil 30% of Genel s profit oil 30% of Genel s profit oil 40% of Genel s profit oil 30% of Genel s profit oil Contract expiry February 26, 2033 July 18, 2031 (2037 for Peshkabir) October 2, 2039 October 15, 2037 March 31, 2041 June 11, 2041 March 29, 2038 Other Addax 2.5% royalty 2 Includes Peshkabir exploration area Source: Production Sharing Agreements, McDaniel & Associates June Post KRG back-in KRG 25% interest on Miran is not carried by the contractors. 2 As per Addax farm-in agreement Addax shall pay Genel 2.5% of the realised market price net of royalty paid under the PSC of Addax s Assigned Interest share of crude oil to which it is entitled. Royalty is first applied to offset outstanding carried interest from Genel to Addax of $61.8m, and then is payable to Genel in cash. 37

38 KURDISTAN PSC PRODUCTION SHARING Contractor Interest (80%) Government Interest (20%) Production 100bbls Production & Revenue Gross Production 100 bbls Cost Oil 40-55% of Net Production is available for Contractors to recover development and operating costs. Unrecovered costs may be carried forward and recovered in future periods. Royalty 10bbls Cost Oil (up to 40% of net production) 7bbls* (0-36bbls) Net Production 90bbls Contractor Working Interest Production Contractor Entitlement Production Profit Oil (Net Production minus Cost Oil) 83bbls 80 bbls 15 bbls Contractor Revenue $1,500 Profit Oil Remaining production after deduction of royalty and cost oil is called Profit Oil. Profit Oil is split between Government and Contractor using a formula based on R-factor. Contractor Profit Oil post Capacity Building Payment (70%) 8bbls Formula based on R-factor : (Cumulative revenues Cumulative costs) Contractor share of Profit Oil (15%*) 12bbls Government Capacity Building Payment (30%) 4bbls Government share of Profit Oil 71bbls * Average over the life of the field. 38

39 COST OIL 40-55% of Net Production (Gross Production minus Royalty) is available for Contractors to recover costs Unrecovered costs may be carried forward and recovered in future periods Equipment and facilities become the property of the Government once the Contractor recovers the cost What costs are recoverable? Exploration and appraisal costs Development costs Operating costs Gas marketing costs Decommissioning costs 39

40 PROFIT OIL Contractor s share of Profit Oil is determined by an R-factor formula Re-set every 6 months R factor = Cumulative Revenues Cumulative Costs R-factor < 1 30% 1< R-factor < 2.5 Between 15-30% R-factor > % Early in the field life cumulative costs are high, cumulative revenues are low, R-factor < 1, higher share of Profit Oil Later in the field life cumulative costs are high, cumulative revenues are higher, R-factor > 2.5, lower share of Profit Oil 40

41 CONTACTS AND WEBSITE Phil Corbett Head of Investor Relations Website 41