Analyst and Investor Visit to Greece Wednesday 10 October 2018 - - PowerPoint PPT Presentation

Analyst and Investor Visit to Greece

Wednesday 10 October 2018

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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’s knowledge or control (or within Energean’s 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.

Disclaimer

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Energean Management Team

Senior Management Executive Committee

Mathios Rigas Chief Executive Officer

• Founding Shareholder
• Petroleum engineer with 20 years of investment banking and

private equity experience mainly in the oil & gas sector Panos Benos Chief Financial Officer

• Chartered accountant with more than 15 years oil

& gas experience both in banking & industry

• Joined Energean from Standard Chartered Bank.
• Dr. Stephen Moore

Chief Growth Officer

• 28 years of E&P experience at Shell, Maersk Oil and

Mubadala

• Previously Senior Vice President – Technical at

Mubadala Iman Hill Chief Operating Officer

• 30 years of E&P experience
• Previously held senior roles at Dana Gas, Sasol,

BG Group and Shell Matt Brown HSE

• More than 30 years HSE experience in oil & gas and

chemicals

• Previously worked for Cairn, Repsol, BP and Shell

Vassilis Tsetoglou HSE Manager, Greece & The Adriatic

• 15 years of Experience on HSE Management in potentially high H2S

environments. Fred Riddiford Reservoir Engineering Manager

• Reservoir Engineering with almost 40 years of experience
• Previously VP Reservoir Engineering at Mubadala

David Donaldson Managing Director Prinos Asset

• Petroleum Engineer with over 30 years of industry experience
• Held senior drilling engineer positions at Shell, Eni and

Halliburton Vassilis Zenios Project Execution Manager

• 25 years oil & gas experience, with onshore construction, pipelines and

heavy lift installation.

• Previously worked in Versabar and Saipem in various worldwide locations.

Dennis Anestoudis Exploration Manager

• Geophysicist with more than 20 years of experience.

Costas Ioannidis Kavala Oil Installation Manager

• 35 years of experience as a process engineer ensuring

effective operations, maintenance and security of the facilities

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Kate Sloan

Head of Investor Relations

• 13 years experience in oil & gas
• Senior Equity Analyst for 7 years
• Chartered Accountant (ACA), having trained with Deloitte LLP

Dimitris Gontikas Country Manager - Greece

• Licenced Attorney, with 25 years of senior management experience

in the private and public sectors

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HSE Performance

2018 Total Man-hours (as of 30/09/18): 873,865  Implementation of the Offshore Safety Directive  Participation in the EU Emissions Trading System  Participation in EU Blue Growth Policy through Horizon 2020 program  Compliance with National legislation and European Directives  OSRL membership for the provision oil spill response services  Annual health program: zero occupational diseases  Annual training & competency program for all employees  Certified training courses  Waste management through licensed companies  Regular safety & environmental drills Fatality Lost Time Injuries Rest workday cases Medical cases First Aid cases Near Misses

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Prinos Development Overview

Quarterly production growth Recent progress and work programme

• 40 mmboe of 2P resource across Prinos and Epsilon
• 2018 full year guidance narrowed to 4,000 – 4,250 bopd due to

replacement of Prinos infill drilling with Epsilon Extended Reach

• Production costs reduced to $19 /bbl (1H 2017: $26 / bbl). Full year

guidance $17-19 /bbl

• Epsilon extended reach well spudded July 2018. First production

expected 2H 2018

• Epsilon vertical drilling programme commenced August 2018. First

production late 2019

• 2019 production drivers are performance of Prinos existing wells, infill

wells, recompletions and workovers and Epsilon Extended Reach Well

Prinos Location

27,500 bopd capacity

Platforms Delta Processing Owned Rig

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Prinos Existing Infrastructure

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 1Q 2017 2Q 2017 3Q 2017 4Q 2017 1Q 2018 2Q 2018 3Q to date

kboed 3Q 2018

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Reserves Growth History

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History of Prinos

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Source: Company, NSAI CPR.

Prinos and Katakolo Production Profile

bopd Production Estimates December 2007

• Acquisition of Kavala Oil

for $1.5 mn (plus acquired indebtedness) – Prinos license relatively close to expiry March 2013

• 25 years

extension of Prinos licenses 2008 - 2013

• Corporate

restructuring and drilling of appraisal wells May - July 2013

• Investment of

Third Point

• Start of new

drilling campaigns

Life of Field Prinos Production Profile

Prinos before Energean ownership

• Discovered in 1974 by Wintershall and

brought on stream in 1981 by NAPC

• Kavala Oil takes over the asset following

departure of NAPC in 1999 bopd 10,000 20,000 30,000 1981 1991 2001 2011 2021 2031 Prinos Prinos North Epsilon 3,000 6,000 9,000 12,000 15,000 2000 2003 2006 2009 2012 2015 2018 2021 2024

Prinos Prinos North Epsilon Katakolo

> 10,000 bopd by 2021

Prinos before Energean ownership

• Discovered in 1974 by Wintershall and

brought on stream in 1981 by NAPC

• Kavala Oil takes over the asset following

departure of NAPC in 1999

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Basic Terms for Prinos Asset

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• Special income tax at a rate of 20% plus a regional tax at a rate of 5% (exclusively)
• The imposition of the income tax exhausts the income tax obligations of each Co- Lessee as well as its shareholders/partners/members, with respect to the

profits resulting from its contractual operations

• Exemptions are also granted on stamp duties and other indirect taxes applied on Loans and credit agreements, plus cash calls paid by each Co-Lessee to the

Operator, provided that the purpose of funds granted is exclusively the financing of petroleum operations

• Tax losses can be utilized to offset taxable profits up to the termination of the companies duration

Fiscal Terms

Total Royalties Average Daily Production 0% Up to 2,500 bbls 3% From 2,501 to 5,000 bbls 6% From 5,001 to 10,000 bbls 10% > 10,001 bbls Field Development License Expiration Date Extensions Available Prinos Dec-24 2 at 5 years each Epsilon Jun-29 2 at 5 years each Prinos North Dec-24 2 at 5 years each South Kavala Nov-17 Nov-18

License expiration dates and possible extensions

Historical Prinos infrastructure and wells (pre-existing to the 1999 lease agreement):

• According to the Prinos lease agreement, abandonment and decommissioning liabilities of pre-existing offshore and onshore infrastructure are the

responsibility of the Greek state.

• Following the signature date of the Prinos lease agreement in 1999, and the delivery to Energean of the existing wells and infrastructure, Energean

is liable only for decommissioning any additional wells and any infrastructure it adds in the area.

• Energean is under no obligation to return any pre-existing infrastructure to its original (1999) condition.

Post Signature(1999):

• Energean is responsible for 50% of the liabilities for decommissioning any additional wells and any infrastructure it adds in the area and the Greek

State is responsible for the remaining 50%.

Abandonment Liabilities

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Commercial Agreements

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BP Offtake Agreement

• The agreement was signed in April 2013 and remains in full force, as amended, until November 2025 or delivery of 25 mmbbls of oil to BP
• c.5.0 mmbbls have been delivered to date
• Cargo sizes are scheduled for amounts not to exceed 350,000 bbls
• The US$ FOB price per bbl is based on average monthly Urals price(1), minus a price discount ($6.4/bbl), plus the API escalator(2)

Notes: Notes (1) Calculated as avg. monthly dated Brent plus the Urals differential to Brent for that period, for the month of lifting or the month prior to the month of lifting at BP’s option. (2) API escalator of Average dated Brent for month M/150*(API-29.5) where API is up to a maximum of 33.

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EPCIC and Financing Terms

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12 31 21 22 23

• Contractor: GSP Offshore
• Scope:

Production Facilities (Lamda Platform) and three production wells

• Lump Sum: $88.25mn (61% Construction, 39% Drilling)
• Warranty: 2 years post Practical Completion
• LD: Liquidated damages based on day-rate for delays beyond scheduled completion of up to 15% of contract

price

• Amount: $180mn (from $75mn of the previous facility)
• Usage: Refinance existing debt, Epsilon development, other Prinos fields and other corporate purposes
• Tenor: 7 years
• Interest: IFI Facility (L+4.9%), Romanian Facility (L+3%)
• Lenders:

Key EPCIC Terms Key Financing Terms

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Financial Highlights

11 26.8 26.3 8.0 16.7 16.0 16.9 20 40 60 80 H1 2017 H1 2018

Revenue (US$mn) Adjusted EBITDAX (US$mn) Operating Cashflow (US$mn)

6.1 7.1 3.1 2.6 1.0 1.1 0.8 1.1 1.1 1.3 12.1 13.2 10 20 H1 2017 H1 2018

Total Other Machinery Repairs and Maintenance Consumptions Electricity and Fuel

Cost of Production Breakdown (US$mn) Revenue, EBITDAx and OCF (US$mn)

26.2 19.2 12.0 13.2 20 40 $/boe

Production Costs ($/boe) Production Costs ($MM) Production (boepd) 2.534

H1 2017 H1 2018

3.801

20 40

US$mn

Efficient and Cost Conscious Operator

10.8 11.6 12.6 5.7 6.0 5.8

1.7 2.2 1.7 1.4 2.0 2.5

2.1 2.4 2.7 21.7 24.3 25.3 10 20 30 2015 2016 2017 28.4 39.7 57.8

• 1.2

16.2 20.7

• 2.8

29.1

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10 30 50 2015 2016 2017 15.2 41.0 19.1 24.7 22.0 24.3 25.3 20 40 60 80

$/boe

US$mn

2015 2017 2016 80 40 20 60

1,459 2,803 3,490 569.134 417.566 Barrels sold (bbls)

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Prinos Basin Regional Review

• Prinos Basin is formed as a result of big scale extension,

rotation and basement exhumation tectonics, on the North Aegean during Miocene-Pleistocene.

• Steep normal NE-SW and NW-SE faults form the deep and

narrow NE-SW trending Prinos Basin (30km long and 15km wide), that rapidly filled with >5km of sediments.

• Well understood stratigraphic column divided in: the Pre-

Evaporitic (Miocene), the Evaporitic (Messinian) and the Post- Evaporitic Sequences (Plio-Pleistocene).

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Production Offshore: Delta Complex and the Energean Force

Production Figures 3Q18:

• Oil Production:

4080 bopd

• Water Production:

10500 bwpd

• Water Injected:

17500 bwpd

• Gas Injected:

11000 Nm3/hr Derrick & Drill floor

ALPHA BETA ENERGEAN FORCE Flare DELTA

Produced Water Treatment

How it Works

• Prinos Does not have a supporting Aquifer
• It is a closed structure
• As oil is produced the Reservoir pressure

declines

• Sea Water is injected to maintain Reservoir

pressure

• Gas is injected into the oil flow to lift the well

Sea Water Injection

Energean Valiant Energean Wave

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• 1. Crude Stabilization
• 2. Crude Storage
• 3. Sour Gas Treatment
• 4. NGL Recovery
• 5. Sulphur Plant
• 6. Gas Recycle For Gas Lifting
• 7. Gas Import / Export
• 8. Power Plant
• 9. Sour Water Treatment

10.Steam Generation & Distribution

Located on the edge of a nature reserve, Energean’s neighbors are fish farms, agriculture wild life & the sea

Sigma is self sufficient:

• Maintenance & Inspection
• Testing & Compliance
• Diving & Surveying
• Training & Competency
• Well Maintenance & Operations
• Laboratory & Fluids Analysis

Production Onshore: Sigma Plant

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Own Drilling Rig - Energean Force

Source: Daily Drilling Report ( DDR)

Rig Availability

75.00 80.00 85.00 90.00 95.00 100.00 Rig Availability % Productive time %

• Purchased from KCA Deutag in 2014
• Refurbished in Piraeus Greece in 2015
• Drilling in Prinos 2015 to Present
• 9 wells & 3 workovers
• Multiple Interventions
• Accommodation for 110 POB
• Normal POB while Drilling 68
• Rig & PSV Dayrate: $59k/day
• Departments
• Drilling
• Maintenance
• Barge
• Catering

15 Month January February March April May June July August September Operating Hours Per Month 744 672 744 720 744 720 744 744 720 Operating Hours - As per program 672 648 733 631 720 697 559 703 675 Non rig related NPT (Hours) 48 12 10 86 23 22 185 40 40 Rig Equipment Related NPT (Hours) 24 12 2 4 2 2

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6 GPA / Incident / Planned Maint/WOW

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126 180 241

• Rig Availability %

96.77% 98.21% 99.73% 99.51% 99.80% 99.72% 100.00% 99.80% 99.17% Productive time % 90.36% 96.39% 98.45% 87.64% 96.74% 96.74% 75.13% 94.42% 93.68%

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Prinos North

• Energean 100% working Interest,
• 3.3 mmbbls 2P Reserves (NSAI CPR 2017),
• New Well PNA-H4 drilled 2018.
• Expected production ~1500 bopd in 2H18 from PNA-H4,
• Current cumulative production 4.4 and STOIIP 24.3 mmbbls
• Recovery Factor to date 18%
• Expected Recovery Factor 30% (Prinos Recovery Factor 40%)
• Options forward:
• a further well in the SE region.
• appraise East Saddle
• increase Recovery Factor
• accelerate production

Eastern Saddle 16

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Epsilon – Key Highlights

 Energean 100% working interest  18.4 mmbbls 2P reserves  Expected production > 5,000 bopd in 2020  Three vertical wells tied to Lamda platform &

• ne Extended Reach Well tied to Prinos Delta

 First Oil accelerated through decision to drill extended reach well: expected onstream December 2018  First Oil from three vertical wells expected in 4Q 2019  Funded by Prinos Cash Flows & RBL Facility (L+3%)

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Epsilon Development - Details

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 Epsilon field

• Discovered 2001
• Appraised 2010 via ERD well drilled from Prinos
• Similar reservoir setting to Prinos

 Development Concept and Design

• Satellite tie back to Prinos complex: utilise spare capacity
• Minimum manned facility with 15 well slots: controlled remotely

from Prinos Delta

• Gas lift, water injection, power and chemicals supplied from Delta
• Pipeline/Umbilical construction installation and commissioning
• Platform designed for drilling and well maintenance using

Energean Tendor Assist Drilling Rig, Workover Rig or Jack up rig.  Project Execution

• First production accelerated to December 2018 via decision to drill

ERW from Prinos A platform

• TURNKEY Contractor GSP for Construction of all facilities and

drilling of 3 initial vertical wells by Jack up Rig

• Pre drilling of 3 vertical wells : 2H 2018 / 1H 2019
• Construction and Installation of facilities completed (platform,

pipelines umbilicals): Q3 2019

• 3 vertical well completions by Jack up Rig once the platform is

installed 2H 2019

• Commissioning and Production Start FIRST OIL: 4Q
• 5 further wells proposed to fully recover 18.4 mmbbls of 2P

reserves  Project Development Cost: c.$155m

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Project installation sequence

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• 2. GSP Jupiter drilling rig pre-

drills 3 wells

• 3. Topsides and jacket

fabricated at GSP shipyard

• 4. Platform piles and base

frame installed

• 5. Jacket installed on top of

piles

• 6. Deck installed on jacket and

final commissioning 80% complete by YE’18 40% complete by YE’18 On Track First oil from vertical wells 2H19

• 1. Energean Force drilling

EWR to accelerate production First Oil – December ‘18

1 2 3 4 5 6

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Lamda Platform Fabrication Site – Constanza Yard

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GSP BASE FABRICATION FACILITY (PREVIOUS SIMILAR PROJECT) , AGINA, CONSTANZA ROMANIA 500 NM TRANSPORT FROM CONSTANZA TO PRINOS FIELD

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Exploration (Finding The Next Epsilon)

Prinos & South Kavala Blocks:

• Booked (NSAI CPR 2017):
• Contingent Resources:
• 22,9mmbbls
• (Athos, Delta, Kazaviti

Discoveries etc.)

• Prospective Oil Resources:
• 8,9mmbbls
• (Alpha, Prinos SE B&C)
• Internal Estimates of Known
• Discoveries/Prospects/Leads:
• 50mmbbls
• Ongoing Studies (add to above

resources):

• Basin Prospectivity Analysis
• Exploration Portfolio Update &

Ranking

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Maximising Recovery (IOR/EOR Potential)

• Prinos Field:
• P50 STOOIP = 289 mln bbls
• Production to date = 112 mln bbls, Recovery Factor(Rf) =

39%

• Water injected to maintain pressures and optimise sweep
• IOR potential:
• Contingent Resources assume Rf can be increased to ~50%

through further development of the Prinos Field

• Static and dynamic model upgrades commenced
• EOR potential:
• Prinos screens well to various techniques
• Miscible flood (Acid Gas), Low saline water flood,

Surfactants

• CO2 flood study complete – availability
• Sampling and analysis programme in parallel with infill drilling
• Target Field Rf ~55%
• Advantages:
• Proximity to shore – low CAPEX for new pipelines
• Availability of CO2 and H2S from produced gas – reuse in an

EOR scheme significantly reduces Opex

• Availability of low saline water
• Miscible (Acid Gas) WAG – potentially ideal option.
• Forward Plan:
• Work Programme being scoped with the NTU, Athens
• Additional Resources ~15 mmbbls
• Target Pilot Test 2020/21

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Calfrac Exploration Licenses

Calfrac Licenses (Ownership - Hellenic Petroleum 25%, Calfrac 75%)

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Underground Gas Storage Project

Kappa Platform Sigma site To be connected with a 32 km pipeline

• South Kavala is an almost depleted, offshore gas

field producing since 1981 (89 % RF; 52 m water depth; GIIP 0.96*109 m3 )

• Turbiditic sandstone; Øavg 22%; kavg 100 mD
• Evaporite top seal
• No aquifer
• Dry sweet gas (0.14 mol% CO2)
• Pini 182 bar (current Pres 27bar), Tres 95 °C
• Located next to the Greek gas transportation

network.

• Well integrity good

 Ideal candidate for UGS Field Key Facts

• Currently, Hellenic Republic Asset

Development Fund (HRADF) is tendering for an external consultant to provide financial advisory services in relation to underground facilities in South Kavala.

• Energean Oil & Gas, as the sole owner of

permits and licenses in the area, has already completed the update the technical and economic model (gas market), in order to continue operate the field in the future. Current Status

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Developing Reserves – Optionality At Katakolo

• 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 to be submitted in 4Q18

• Final Investment Decision or farm down to

be decided in 2019

Katakolo overview

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Adding More Hydrocarbons - Western Greece And Montenegro

• Repsol 60% partner and operator; pays 90% of costs to

$49.9 million cap

• Seismic exploration activities have commenced

Western Greece JV with Repsol Montenegro Key Highlights

• Blocks 4218-30 and 4219-26 awarded March 2017
• (Energean 100%)
• 1.8 Tcf & 144 mmbbls unrisked prospective resources
• Low commitment (c.$5 million) first exploration phase
• 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

Source: Company

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Prinos: Oil & Gas, Tourism And Environment Coexist

Transfer 37 years experience of working safely in environmentally sensitive locations in NE Greece to every area we

• perate

Safety of Offshore Oil & Gas Operations Directive

Gulf of Kavala: Over 10 Blue Flags Every Year for the Last 10 Years Energean’s HSE Mission Thasos: Traditional tourist destination in the Aegean

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Energean and TEI Kavala

99 people are currently working in the company

• 26 from Oil & Gas Technology
• 73 from other TEI departments
• Under graduate programme started in 1981
• Post-graduate program started in 2012
• Company’s contribution
• Teaching & Lectures
• Internships
• Scholarships

Oil & Gas Technology

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Strong Relationships With The Local Communities

Support the 4th Olympia Marathon & the Association of Paraplegics in the Ileia Prefecture, Western Greece Donate difibillators to municipalities of the Ioannina Prefecture, Western Greece Support Petrochem Day, organized by students

• f the Chemical Engineering School of the

National Technical University of Athens Energean Kavala BC Kavala, Donation for the replacement of tires for the only crane vehicle of the Fire Service department of Eastern Macedonia OUR VISION: The company’s objective is to generate sustainable growth. We are therefore committed to conducting

• ur

business responsibly, which means safeguarding the health and safety of our employees, caring for our environment, supporting the local communities in which we operate, meeting their expectations and needs and contributing to the sustainable development

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those communities. Honour World Environment Day by cleaning with Energean’s divers the seabed of the main port of Kavala 29

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Conclusions  Investment in the field is attractive because of:

i.

High operational leverage (UOC goes down as production grows)

ii.

Very good fiscal term

iii.

Energean’s operating capabilities

 Future growth potential is significant; of the three reservoirs (A, B &C) only the A reservoir

has been exploited

 The asset is operationally self sufficient; drilling and workover plans can be executed with full

control

 We understand the Prinos Basin fields and we will deliver an increase in production to

>10,000 bopd by 2021

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Thank You for your attention!

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Appendix

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FLOW ASSURANCE

Asphaltene Precipitation is the major flow assurance challenge in Prinos

Continuous injection Asphaltene Inhibitor

Treatment There are 3 methods to treat Asphaltene related flow assurance

• Inhibition
• Treatment
• Prevention

Asphaltene A complex tar like substance within the produced fluid.

• Pressure & temperature changes
• Precipitation
• Deposition
• Other factors

The Ashpaltene problem & how we addressed it

Key Factors

• Bubble point
• Asphaltene precipitation envelope

(ADE)

• Precipitated of asphaltene increases

as pressure decreases from the upper onset pressure to the saturation pressure of the oil.

• Asphaltene onset pressure (AOP)

Xylene treatments pumped into well

The Asphaltene Challenge

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Asphaltene Management Strategy

 FBHP maintained above the Asphaltene Onset Pressure (AOP) and bubble point: – AOP measurements/ Phase Behaviour P&T per reservoir – Pressures and temperatures closely monitored. – Stabilize the decline in the reservoir pressures via water injection.  Surveillance Data: – Surface samples periodically acquired for ADT testing. – Wells completion with deep chemical injection lines. Continuous injection of asphaltene inhibitor keeping the tubing’s free of restrictions. – Optimization of Asphaltene inhibitor dosages through frequent ADT testing. – Daily monitoring of well test data (THP, THT flow rates,

GL rate) to understand promptly sudden changes related to blockages. – Daily measurement

• f

salinities and water cut incremental  Perform flowing gradient surveys (P&T): – Estimate accurate FBHP’s – Tune the VLP correlation

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