Corporate Presentation January 2019
Disclaimer This presentation may contain forward-looking statements and information that both represents management’s current expectations and beliefs and are subject to the usual risk factors and uncertainties associated with the oil and gas exploration and production business and with any statement about the future. Whilst Energean believes that such expectations and beliefs are reasonable in the light of the information available at this time, the actual outcomes may be materially different from the said statements, owing to factors beyond Energean' knowledge or control (or within Energean' control where, for example, the Company decides on a change in strategy). Energean undertakes no obligation whatsoever to revise any such forward looking statements to reflect any changes (in expectations, beliefs, circumstances, events, the Group’s plans or strategy or otherwise). Accordingly, no reliance may be placed on such forward looking statements or any figures therein. 2 2
Energean at a Glance: a strong, effective operator in the Med FTSE 250 (LN:ENOG) and TASE (TA: גאנא ) listed 4 c. 350 385 Operational Strength Countries, an mmboe 2P Highly skilled approved operator employees $1.8bn $1.4bn $13bn Effective execution ongoing investment in EPCIC contract with revenue secured Israel & Greece TechnipFMC through 13 GSPAs $460m $1.275bn $180m Proven access to capital equity raised in 2018 Project finance secured RBL refinancing in in 2018 2018 3 3
Growth and Performance at the Heart of Energean Historical delivery: 75% 2P + 2C CAGR ‘ 08 – ‘ 18 (mmboe) mmboe $/bbl Karish – Tanin Prinos acquisition acquisition 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Brent Price - $/bbl Prinos Basin 2P Prinos Basin 2C Katakolo 2P Karish and Tanin 2P Karish and Tanin 2C 4 4
Production & cash flow from Greece Recent progress and work programme Quarterly production growth 6000 • 40 mmboe of 2P resource across Prinos and Epsilon. EL-1 has identified reserve upside in the Epsilon Main and Deep reservoirs 5000 • Six sequential quarters of production growth 4000 • 2019 full year guidance 5,000 – 6,000 bopd • 2019 production costs expected to be $14 – 17 /bbl 3000 boepd • First production from Epsilon Extended Reach Well expected in 1Q 2000 2019 with initial rates of > 1,000 bopd • At least 2 wells in the Prinos basin to be drilled in 2019 1000 • $100m investment in Epsilon ongoing and targeting first oil in end of 0 2019. Investment includes installation of satellite platform tieback and three vertical wells Prinos Existing Infrastructure Prinos Location 27,500 bopd capacity Delta processing Platforms Owned rig 5 5
Optimising production: Prinos financial highlights Cash Flows Up Production Costs Down 2019 17.0 expected production costs range • Targeting production of more than 10,000 bopd by 2021 6 6
Developing reserves – optionality at Katakolo Katakolo overview • 2P reserves of 10.5 mmbbls • c.$100 million NPV • $60 million development capex • 2 wells tested • Development plan would likely is to drill the first pilot hole to be converted to an injection well shortly after FID • Environmental and social impact assessment submitted in 4Q18 • Final Investment Decision or farm down to be decided in 2019 7 7
Adding more hydrocarbons - Western Greece and Montenegro Western Greece JV with Repsol Montenegro Key Highlights • Blocks 4218-30 and 4219-26 awarded March 2017 (Energean • Repsol 60% partner and operator; pays 90% of costs to 100%) $49.9 million cap • 1.8 Tcf & 144 mmbbls unrisked prospective resources • Seismic exploration activities have commenced • Low commitment (c.$5 million) first exploration phase • Ioannina holds best estimate gross prospective resources of 103 Bcf and 187 million bbls • 2 block 3D seismic acquisition programme, G&G + training Four year optional second exploration period : – 1 exploration well of not less than 2,800 m ENI operates 4 blocks to the south, work programme commences 2019, which Energean believes includes one well 3D seismic activities to be completed in February 2019 8 8 Source: Company
Developing reserves - a $1.6bn de-risked project in Israel Energean WI: 70% - Karish-Tanin Regulatory FDP approved August 2017 EPCIC Lump sum turnkey EPCIC Contract 4 firm, 6 optional wells Drilling GSPAs 4.2 bcm/yr (16yr av) $12bn revenue Project Financing $1.275 billion $460 mn raise through Premium LSE IPO Equity Taken March 2018 FID 1Q 2021 First Gas 9 9
Downside protected through gas sales contracts Volume 4.6 bcm/yr (+0.7 bcm/yr Or Contingent Contract) Min: 7 years -- Weighted Average: 16 years -- Max: 20 years Tenor Weighted Avg 75% Take-or-Pay Weighted Avg $4.1 / mmbtu Current Price Weighted Avg > $4 / mmbtu Floor Price Largest private industrial companies and IPPs in Israel 10 10
Karish Development Plan 11 11
Development risk mitigated through Technip EPCIC turnkey contract ENERGEAN POWER 12 12
On track to deliver First Gas in 1Q 2021 Q2 2019 Q3/Q4 2019 Q2 2020 March 2018 • Installation of • FID • Pipeline beach • Sales-gas crossing at Dor pipeline production installation Dor manifold and to Karish other sub-surf structures First gas: Q1 2018 2019 2020 2021 Q3 – Q4 2019 26 Nov 2018 Q1 2019 Q4 2019 2020 Q4 2020 • • FPSO First • Drilling Karish • • • Drill 3 FPSO hull Integration of Completed steel cut topsides in North development towed from FPSO towed Sembcorp ’ s wells with China to to Israel Shipyard in Stena DrillMAX Singapore Singapore FPSO Key Milestones Well Key Milestones Subsea / SURF and Onshore Key Milestones Source: Company. 13 13
2019 – Drilling Four Wells In Israel • 1 st Step: Karish North - March 2019 1.3 Tcf gas & 16.4 mmbls liquids 69% chance of success Single well development in success case • Next Steps: Karish Main – 2019 3 development drilling wells Upside potential for Karish Main*: 46 bcm (1.6 Tcf) GIIP potential A B D1 D4 *Note: Management estimates, not independently audited numbers 14 14
Adding more hydrocarbons - committed well at Karish North Strong DHI conforming to structure Karish North Karish North • Spud: March 2019. Estimated drill time 45 days • 1.3 Tcf + 16.4 million bbls gross recoverable prospective resources (Energean 70%) Karish Main • High Geological Chance of Success – 69% volume weighted average1 • Exploration well budget $25 million • Exploration well to be suspended as potential Y producer. Karish North • Single well development in the success case Karish East • 5 km tie back to the FPSO, estimated cost (including completion) $100 million Karish • Commercialisation: Sell more gas or delay Tanin Main development X 1. Previously quoted figure of >80% relates to the C sands only. C sands still have an individual chance of success > 80% 15 15
Significant near-field prospective resources Targeting multiples of upside through infrastructure-led exploration 1. NSAI August 2018 16 16
Adding more hydrocarbons – additional tie-backs Zeus 17 17
Adding more hydrocarbons: our infrastructure opportunity Additional FPSO capacity 9 8 7 3.4 BCM/yr Spare Capacity Net Cash Flow Margin > 50% 6 0.4 BCM/y 5 BCM/y Contingent upon future gas from 4 Karish North 3 4.2 BCM/yr Gas Sales Contracted Net Cash Flow Margin c.25% 2 1 0 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Gas Sales in Place IPM Spare Capacity in FPSO 18 18
Adding more hydrocarbons – commercialisation options Meeting Growing Israeli Gas Demand Export Options 35 30 25 20 bcma 15 10 5 0 Energean Contracted Energean Available Capacity Rest of Market per Adiri Additional demand per BDO • A market that has grown by an average 15% CAGR for the last 10 years • Commercialization of potential discoveries in the five new exploration blocks • IEC required to reduce coal generation post 2017 • Potential for exposure to higher pricing • August 2016 decision to close the 1,440 MW Orot Rabin coal-fired plant by • Existing and potential export routes: June 2022 and replace it with gas-fired generation – Cyprus: proposal for a c200km pipeline from Karish • Incentivise light industrial customers to switch from oil to gas • – Incentivise CNG stations and electric vehicles Jordan: INGL close to complete export pipeline • Government funded deployment of a new natural gas distribution system – Egypt: EMG and Arab Gas pipeline (via Jordan connection) • 5 IEC power plants to be privatised in coming years without associated gas – Longer term – East Med pipeline connecting to the European gas network supply contracts via Greece and Italy Source: Adiri Committee Interim Report (Director General of the Ministry) 19 19
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