1. Healthcare

Capital Markets Day
28 January 2015
Lincoln Centre
London
Disclaimer
•
•
•
This presentation contains certain forward-looking statements that are subject to the usual risk factors
and uncertainties associated with the oil and gas exploration and production business
Whilst Petroceltic believes the expectations reflected herein to be reasonable in light of the
information available to them at this time, the actual outcome may be materially different owing to
factors beyond the Group’s control or within the Group’s control where, for example, the Group
decides on a change of plan or strategy
The Group undertakes no obligation to revise any such forward-looking statements to reflect any
changes in the Group’s expectations or any change in circumstances, events or the Group’s plans
and strategy. Accordingly no reliance may be placed on the figures contained in such forward looking
statements
1
Agenda
9.30
Introduction and business review
Brian O’Cathain
Algeria
9.45
10.05
10.30
10.50
11.00
Introduction to Ain Tsila
Project status
Subsurface and Drilling
Security considerations
Algeria summary
Geoff Probert
Geoff Stevenson
Tony Cave
Stuart Harrower
Geoff Probert
11.15 Coffee break
Egypt
11.30
11.50
Production assets
Exploration assets
John Naismith
Ciaran Nolan
Business and operational review
12.15
12.30
12.45
Capital allocation and financing strategy
Business review summary
Questions
1.00
Sandwiches and refreshments
Tom Hickey
Brian O’Cathain
Introduction and Business Review
Brian O’Cathain
Introduction and Key Objectives
•
•
•
•
Review progress made by the business since the merger with Melrose in late 2012
Provide an insight into the Company’s strategy in light of the current low oil price
Review the core asset base in North Africa (Algeria and Egypt) highlighting potential
areas of incremental value creation and future business growth
Introduce the key managers and technical team responsible for delivery
4
Substantial Progress on Key Projects in 2013/14
•
Algeria, significant progress on major Ain Tsila development project
- second farm-out completed
- high quality development team and operating company
- key contracts completed or awarded (GSA, FEED)
- on track for first gas in 2018
•
Egypt, business renewed and political environment improving
- economic stability returning, credit rating upgrades
- portfolio renewed with quality acreage at modest cost
- minimal operational disruption during political transition
•
Scale and diversity of business has mitigated share price volatility in
difficult market
- relatively little near term impact of short term oil price
movements
•
Exploration performance has been disappointing
- reserve replacement targets not achieved
5
Financial Performance 2013/4
•
•
6
Corporate finance initiatives have enhanced financial flexibility
successfully refinanced the Company with 5 year facility
$160 million carry on Sonatrach farm-out covers Algeria to Q1/Q2 2016
$100 million equity issue, partly to bridge Algeria farm-out receipts
EGPC receivable reduced from $125 million at Merger to $53 million at year end
Long term planning for Algeria funding post carry has already commenced
- Refinancing preparations under way
- A number of options under investigation
- Year end debt reduced by $93 million (to $153 million) during 2014
Strategic Considerations - Production and Development
•
The Company’s core value and reserves are dominated by the Algerian Ain Tsila development
and Egyptian producing fields (98% of year end 2013 2P reserves)
• The pace of the Ain Tsila spend is about to increase significantly (c.$600 million net to first gas,
circa 25% covered by Sonatrach carry)
• Bulgaria and Egypt have shown a consistent production decline over last 3 years
• Management focus needs to be firmly on
- Ain Tsila project execution, funding and upside reserves
- Egyptian and Bulgarian production and cost control
Working Interest Production (Mboepd)
40
Egypt
Bulgaria
Algeria
Mboepd
30
20
10
0
2015
7
2016
2017
2018
2019
Strategic Considerations - Exploration and Appraisal
•
•
Limited exploration success since 2012
Remaining high volume prospects are skewed
towards high risk and/or are immature
- Dinarta block (Shireen-1 well), Kurdistan
- Carisio permit (Carpignano Sesia well), Italy
- North Port Fouad and North Thekah
concessions, Egypt
•
Lack of near term drilling opportunities which can
be quickly monetised (near field prospects in
Egypt and Bulgaria)
•
Principal opportunity for low cost organic growth is
South Idku (Nile Delta, Egypt)
•
Elsa discovery (offshore Italy) has significant
potential value but access is challenging
8
Proved plus Probable Reserves and Upside Potential Resources
Combined Total 654 MMboe
Algeria, Egypt and Bulgaria
2P Reserves
144
255
52
Algeria
Indicative Upside
Italy (Elsa)
2C Resources
203
Italy, Egypt and Kurdistan
P50 Risked Resources
Note: 2P Reserves are 2013 year end figures adjusted for Algerian farm-out and 2014 production volumes
9
Strategy Overview
Production, Development and Exploration Assets
•
Focus the organisation on the execution and financing of
the Ain Tsila development project, to achieve a first gas
date in 2018
- actively promote and progress achievable
proposals to enhance project efficiency
•
Invest in Egyptian and Bulgarian production assets to
maximise NPV and support AinTsila funding
- focus the organisation on maintaining production
and reducing costs
•
Minimise short term exploration and new business
expenditures
- completely divest or relinquish all low-graded
exploration assets
- dilute capital exposure to high risk or high cost
exploration and appraisal initiatives
- retain high quality longer term opportunities where
possible at minimal cost
10
Country Plan Implications
Production and Development
Algeria
Focus on project execution, accelerated delivery and securing
financing
Egypt
Focus on maintaining production and cost reduction
Bulgaria
Focus on maintaining production and cost reduction
Exploration and Appraisal
Egypt
Farm-out North Thekah, North Port Faoud and South Idku to
manage risk and financial exposure
Italy
Complete Carpignano Sesia EIA & farm-out to achieve carry in well
Progress Elsa EIA approval and farm-out prior to drilling
Kurdistan
Complete currently drilling Shireen-1 well and review options
Others
Minimise cost exposure wherever possible
11
Strategy Overview
Financial and Corporate
• Optimise the pace of spend on AinTsila commensurate with the plan to
deliver first gas in 2018
• Increase revenues and reduce operating cost in Egypt and Bulgaria
• Restructure the organisation so that it is staffed appropriately for reduced
Exploration and New Business focus
• Capture the associated G&A cost savings
• Progress long term funding strategy for Ain Tsila development
• Remain flexible on corporate opportunities to realise or enhance shareholder
value
12
Algeria
Introduction to Ain Tsila Development
Geoff Probert
Delivering a World Class Project in Algeria
•
Introduction – Geoff Probert, MD North Africa
•
Project Status – Geoff Stevenson, MD Joint Operating Company (“JOC”)
•
Subsurface & Drilling – Tony Cave, Subsurface Manager JOC
•
Security Considerations – Stuart Harrower, Group HSES Manager
•
Summary – Geoff Probert
14
Delivering a World Class Project in Algeria
•
Introduction
–
–
–
–
–
Some basic facts
Achievements in 2014
Snapshot on schedule and costs
Algerian operating environment
The production prize
•
Project Status – Geoff Stevenson, MD JOC
•
Subsurface & Drilling – Tony Cave, Subsurface Manager JOC
•
Security Considerations – Stuart Harrower, Group HSES Manager
•
Summary – Geoff Probert
15
Algeria Basic Facts - Ain Tsila Development
World class development with many regional analogues
1,700 km from port
550 km from regional support base in Hassi Messaoud
16
Algeria Basic Facts - Ain Tsila Development Summary
•
Major gas/ condensate field in Southern Algeria (Illizi Basin) GIIP >10 tcf
•
Will utilise proven processing technology (more than 10 similar plants in Algeria)
•
Development consists of
–
–
–
–
–
–
–
–
–
•
Up to 30 wells prior to first gas, including re-completion of 6 existing wells
Gathering system to carry production to the Central Processing Facility (CPF)
Gas processing plant capacity of 420 MMcfpd wet gas
Condensate and liquefied petroleum gas (LPG) extraction and treatment facilities
3 export pipelines for Gas/ LPG/ Condensate (total length around 400 km)
Onsite standalone power generation
Industrial Base (offices, workshops, warehousing etc)
Living Base/Accommodation + Security Camp
Link road to national highway, field access roads and airstrip
Two significant engineer/ procure/ construct (EPC) lump sum contracts to deliver
In addition, build a Joint Operating Company (“JOC”) to develop and operate the field
17
Algeria Achievements – Active Development
2013
2014
2015
Groupement
established
FEED Tender
Award FEED
Gas Sales
Agreement
Award EPC
Drilling and ongoing facilities
2016
Infrastructure
Liquids marketing
2018
Commissioning
First gas
•
38.25% operated working interest in Production Sharing Contract (PSC)
– partners Sonatrach (43.375%), Enel (18.375%)
– 2nd farm-out of 18.375% to Sonatrach delivered
– $20m cash (received)
– $140m development carry (being drawn down)
– two contingent payments of $10m each (future potential)
•
Development Plan approved by Algerian Authorities
– $1.5 billion pre-production capex (gross) – spend concentrated in 2016/17/18
– 355 MMcfpd production plateau (14 years)
– Gross reserves 2.1 Tcf gas and 175 MMbbls condensate and LPG
– First gas in Q4 2018
18
Algeria Achievements – 2014 Highlights and Lowlights
Major progress in important areas
+ Second farm-out agreement (to Sonatrach) ratified by Government 18 June
+ Secondment Agreement - signed with Sonatrach 26 June
+ Gas Sales Agreement - signed with Sonatrach 8 September
+ FEED contract - signed with CB&I 9 September
+ Sonatrach paid Petroceltic $35 million on 16 September - initial farm-out payment
+ Accelerated EPC award schedule agreed to compensate for FEED award delay
+ Drilling main rig tendered and unit identified - drilling commences end 2015
+ Joint Operating Company relocated to Hassi Messaoud operations base
Start-Up challenges – substantially overcome
- Challenging joint operating environment in Algiers
- Slow initial progress in contracting and procurement activities - FEED delay
- First gas rescheduled to Q4 2018
19
Algeria Achievements – Gas Sales Agreement (GSA)
Contract Materiality
•
•
•
Dry gas accounts for 55% of all project revenues (the rest from liquids)
Petroceltic’s total share of revenues from the dry gas under the GSA is
- ~ $2 billion over contract life (at $80/bbl oil price) and
- ~ $120 million per year during plateau production
GSA duration is tied to that of Contractor’s participation in PSC
Gas Sales Heads of Terms (“HoT”) signed with Sonatrach August 2012
• Sets out key commercial principles and terms
• No material deviation from HoT permitted in final GSA
Execution of GSA September 2014, approved by Algerian authorities December 2014
• All operational procedures and terms fixed in GSA
• Incorporates gas price formula, take or pay, gas specifications, measurement and delivery
20
Algeria Snapshot - Project Schedule
AIN TSILA Field Development - Phase 1
.
December 2014 - rev. 2
December 2014
2014
2015
2016
2017
2018
#
Activity description
.
.
1
Early civil works for well engineering
2
Logistic camp ready for use
2
3
Main rig mobilization completed
3
4
Well engineering Long Lead Items - Delivery to site
5
24 new wells + 6 recompletions
6
WAZ 3D Seismic Acquisition Award
7
WAZ 3D Seismic Acquisition and Processing
8
WAZ 3D Seismic data interpretation
9
FEED Tender, Evaluate and Award
10
FEED Award
11
FEED Execution
12
EPC(s) Pre-qualify, Tender, Evaluate and Award
13
EPC 1: CPF+BI, BdV, GATH. & EXP SYSs Award
14
EPC 1 Engineering, Procure & Construct
15
EPC 1 Commissioning
16
EPC 2: ROADS & AIRSTRIP Award
17
EPC 2: Engineering, Procure & Construct
18
Ramp up and performance testing
19
FIRST GAS - Full Production
.
.
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
#
.
1
~23.5 MONTHS
4
5
27 MONTHS
6
7
~15 MONTHS
8
12 MONTHS
9
10
11
46 weeks
Tender, Evaluate & Award
Pre-qualify
12
13
CPF+BI, BdV+SC, Gather/Export
14
32 months
15
6 months
16
Roads & airstrip
18 months
17
18
First Gas
19
.
Q4
2014
21
Q1
Q2
Q3
2015
Q4
Q1
Q2
Q3
2016
Q4
Q1
Q2
Q3
2017
Q4
Q1
Q2
Q3
2018
Q4
Algeria Snapshot – Petroceltic Cumulative Cashflow (MM USD)
600
500
400
300
200
100
Carried
-
2014
2015
2016
Major Commitments
Late 2015
2017
Max Exposure
Mid 2018
@USD80/bbl)
22
2018
2019
2020
Cash “Payback”
within 4 years
2021
Algeria Operating Environment - Characteristics
• Political Context: post-independence political forces remain in place, however,
–
This is not the location for the next ‘Arab Spring’
–
Population suffered greatly during 1990s civil war, and still remember it
–
Spectre of terrorism visible
–
Sufficient economic benefits from hydrocarbon industry to soften aspirations
–
Safety valve of emigration to Europe and remittances from expatriate Algerians
important
–
Alignment on hydrocarbon strategy among competing power bases
• Hydrocarbon Business
–
Rational, not nationalistic
–
Mediterranean, not Arab
–
Recognition that IOCs provide expertise in E&P and capital essential to Algeria
–
Legitimacy important – reliable product supplier
–
Important to comply with contractual requirements to maintain your rights
–
Challenging negotiation space, but rights are ultimately respected
23
Algerian Operating Environment – Decision Making Framework
•
Sonatrach - not Petroceltic - hold the licence to exploit discovered hydrocarbons
•
Petroceltic are the “Contractor” to Sonatrach to (partly) fund and deliver an
agreed development plan to exploit the discovered hydrocarbons
•
Reward for project delivery is an entitlement to a share of future production from
Ain Tsila (based only on CAPEX invested; OPEX not cost recoverable)
•
Development plans agreed first by Contractor with Sonatrach, then by
Sonatrach with Algerian competent authority – ALNAFT
– Open ended process depending on simplicity and familiarity of concept
– No discretion to expend funds prior to formal approval
•
24
On approval, JOC formed between Contractor and Sonatrach to conduct all
petroleum operations, in accordance with the approved development plan
Algerian Operating Environment – Decision Making Framework
•
JOC prepares all work plans and budgets and is governed by a management
council which takes unanimous decisions
•
Sonatrach mandate equipment specification and control procurement
•
Key constraint is that Petroceltic is not the sole operator of Isarene: operations
effected jointly and unanimously with Sonatrach and in accordance with the law
•
However:
– Petroceltic personnel are very experienced at operating in the Algerian
environment
– We are able to work and deliver effectively within the system constraints
– We have a track record of successful Algerian projects
25
Algerian Operating Environment – Development Planning
Considerations
•
Development plan must
– Be compliant with Algerian regulatory requirements
– Be delivered jointly with Sonatrach and compliant with local laws on tendering
– Recognise Algerian location remoteness and logistical challenges
– Yield products to pipeline specification
• Maximise liquid recovery from gas
• Pipeline gas/ liquids are not processed further prior to export
• Sonatrach strongly protect market reputation for product quality
– Meet Sonatrach strategic considerations
• 355 MMscf/d daily average off-take, low annual production/ reserves
ratio, long plateau, high reliability, 25 year facility design life, low opex
– Deliver the contracted production at low risk to Sonatrach
26
Algerian Operating Environment
Overall Joint Venture Structure and Locations
Management Council
CONTRACTOR
SONATRACH
ISARÈNE
JOC
Petroceltic (op)
JOA
Enel
HR
HSE
Finance
Contracts
and
Procurement
Technical
Project
Services
Hassi Messaoud
Project
FEED/EPC
27
Hassi
Messaoud
IT
Co-Administrators
Subsurface
Drilling
Significant Algeria Operating Experience
Name
Role
Geoff Probert
Petroceltic
MD North Africa
Toyoki
Nishibayashi
Petroceltic Algeria
Country Manager
JOC
Geoff Stevenson Managing Director
JOC
Bertrand Demont Project Director
Didier Lafont
Ian McKie
Andreas
Pelekanou
JOC CFO
JOC Facilities Project
Manager
JOC
Engineering Manager
JOC
David Donaldson Drilling Manager
JOC
Tony Cave
Subsurface Manager
28
Algeria
Experience
BHP ROD/Ohanet,
Petroceltic
Itochu, BHP,
Petroceltic
BHP ROD/Ohanet
BHP Ohanet, Hess
Sodexho
BHP Ohanet, Hess
BHP Ohanet, Hess
BHP ROD/Ohanet
BHP ROD/ Ohanet
Ohanet Facilities, Algeria
150 Km from Ain Tsila
The Prize – Base and Upside Production Profile
800
Enhanced Plateau >700 mmscfd wet gas
Wet Gas Rate (MMcfpd)
700
600
Upside Production Profile
Plateau rate 710mmscfd
500
Nominal plant capacity 420 mmscfd
400
300
Initial Production Profile
Plateau rate 355mmscfd
200
4.8 Tcf
(38% RF)
100
2.1 Tcf
(21% RF)
0
0
1
2
3
4
5
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Years From Production Start
Potential for material uplift in long term field recovery based on field performance
29
Ain Tsila Gas Project – focus on delivery in 2015
• Deliver deep FEED by summer, and award EPC before year end
• Contract main rig and mobilise to site
• Procure first batch of drilling and well equipment
• Effectively manage remote logistical and organisational challenges
• Elevate security risk management, ready for site location
• Maintain alignment on project execution strategy between partners
• Capture lower development costs in low oil price environment
30
Ain Tsila Development
Project Status
Geoff Stevenson
Ain Tsila development project status
• The development project is well under way
• We have a strong, experienced team who are motivated to succeed
• We are aligned with our Partners and Algerian stakeholders
• Our Joint Operating Company (“the Groupement”) functions well
• 2015 is a critical year for the project development
–
Front End Engineering and Design (FEED) studies are underway and due to
complete August 2015
–
Development drilling due to commence before year end
–
Main Engineer Procure Construct (EPC) contract tendering imminent with
award EPC before year end
32
What is the Ain Tsila gas development project?
Ain Tsila is by industry standards a large scale project:
• It will process 420 MMcfpd wet gas, recovering condensate and liquefied petroleum
gas (LPG) and delivering sales quality gas
• It will require up to 30 wells at first gas, with further development drilling over the
life of the field
• The project will require a major gas gathering system across the field, plus a 3pipeline product export system totaling 380 km in length
• The field is located in a remote, harsh environment with no support infrastructure
within 550 km radius. Therefore it will include significant infrastructure development
including power generation, water supply, access roads, industrial base, living
quarters, security encampment and airport
• The gas processing is based upon proven technology, providing >95% plant uptime
and >95% liquid extraction from wet gas at low operating costs
• There are more than 10 similar plants in operation in Algeria, with others under
construction
33
How does that translate into numbers?
• 15 million construction manhours, employing at peak over 3000 workers
• Over 200 pieces of major equipment, 25% of which are over 50 tonnes
–
Heaviest piece is around 400 tonnes
–
Largest piece 48 metres x 4 metres
• Over 50,000 tonnes of pipeline materials; in total we will transport over 100,000
tonnes of materials to the field
• More than 400 km of casing and production tubing utilized during drilling
• Over 700 km of gas gathering and export pipelines
• We will generate 55 MW of electricity daily – equivalent of 4,000 homes
• At 3 litres per day per person, will recycle 3 million plastic bottles a year…
34
Similar plant to Ain Tsila proposed design
35
Large projects – some simple rules for success
• The (PSC) Contract drives the project requirements
• History shows that “fast track” projects are invariably neither fast nor on track
• Fail to spend money up front and you will pay for it in multiples
• Large projects are like life - you get what you pay for - in projects it is usually
manifested in poor plant and reservoir performance leading to poor returns
• Avoid attempting to offload risk at your peril – the consequences always come
back to the operator
Properly managed and executed projects are creators of capital….
36
What are the key challenges
• Project execution and maintaining cost and schedule
• Location and natural constraints
• Logistics and Customs
• Security of personnel
• Working within restrictive tendering and procurement procedures
• Labour shortages / resource conflict with other projects
• Effective drilling, stimulation and completion program
37
Geographical Area of Activity
1,700 km from port
550 km from regional support base in Hassi Messaoud
38
Design and Execution Constraints - Location and Infrastructure
• Distance from ports - 1,700 km involving crossing the Atlas mountains at 2,200 m
–
Requires detailed planning as many bridges and roads are inadequate
–
Logistics support and customs clearance specialists key function for success
• Lack of local infrastructure - Hassi Messaoud has nearest support infrastructure
and is 550 km away
–
Plant design uptime of 95% requires high degree of on-line sparing uncommon
elsewhere. Reliability modeling determines the needs
–
Less critical off-line spares located in local warehouse to support maintenance
• Climate - summer temperature exceeds 48 degrees C
–
beyond ratings for most gas processing equipment. Performance degradation
is a key factor in design
• Labour - Algeria has limited pool of skilled workers
• Security - personnel security requirements impact on direct and indirect execution
39
Ain Tsila Export Routings
Mederba
Station
TFT
Base/Airstrip
Repsol
Base/Airstrip
Condensate
pipeline
Gas and LPG
pipelines
Ain Tsila
Central
Processing
Facilty
40
To In Amenas
(175 km)
Environment
• Ain Tsila is located in the Sahara desert, an ecologically fragile environment
•
41
–
Operator has a duty to maintain it in its pristine condition
–
As such we are obliged to perform Environmental Impact Assessments for all
our activities
–
The project team includes two full time environmental specialists to ensure we
comply with our responsibilities and obligations
A major issue is managing waste
–
Consumable waste will be compacted and disposed elsewhere
–
Packaging of equipment and materials is also a key contributor to waste, this
will predominantly be incinerated locally
–
Drilling generates significate waste that will be cleaned/recycled or remediated
Project execution - maintaining cost and schedule
• We have assembled an experienced team of engineers with in excess of 300 years
of relevant Algerian experience of drilling, subsurface and EPC execution
• Engineers from Sonatrach to complement Petroceltic team to guide passage through
local authorities and regulatory requirements
• The concept of deep FEED has been adopted to remove ambiguity for the EPC
contractor to:
–
Minimise time for EPC contractor to complete detailed engineering & construction
–
Avoid in-built cost and schedule contingencies due to uncertainty
–
Minimise scope for variation order claims
–
Develop a detailed control estimate and execution schedule
–
Allow early procurement of long lead items to de-risk the schedule
• We have a robust wells program to ensure start up on full capacity and maintenance
of early production plateau
• Sonatrach not constrained by local content rules, if it is identified as a schedule
requirement
42
Project Status - Deep FEED
• Lump sum contract awarded in October 2014 to Chicago Bridge & Iron BV (CB&I)
after restricted tender
• Completion scheduled for August 2015. Execution in Den Haag, London and New
Delhi
–
Phase 1 completed on schedule
–
Contractor up-manning to execute Phase 2
–
Contract includes provisions to support EPC tender and evaluation
–
Also includes the provision to support long lead item procurement, if deemed
necessary to underwrite schedule
Key elements of deep FEED
• Define all critical elements of facilities design (including selection of any critical and/or long lead
equipment)
• Develop design hazard and operability study (HAZOP)
• Develop control cost estimate to American Association Cost Engineers Level 2
• Develop approved suppliers list to ensure all equipment and materials procured by EPC
contractors are of the necessary quality to maximise the reliability and availability of the facilities
and support the operations and maintenance philosophy
43
Simplified Facilities Block Flow Scheme
30 MW Export
Gas
Compression
Wellheads
and manifolds
Gas Dehydration
and Mercury
Removal
Gathering
Pipelines
Expander
Plant and NGL
Separation
Sales Gas to
Tie-In
LPG Storage
20 MW Front
End
Compression
Slugcatcher
83 km Export
Pipeline
3 x 500m3
Spheres
Utilities
Power
Hot Oil System
55 MW Power
Plant with Waste
Heat Recovery
Instrument Air
Condensate
Storage 4 x
2000m3 Storage
Tanks
86 km Export
Pipeline
LPG to Tie-In
Nitrogen
Raw Water Wells
165 km Export
Pipeline
Potable Water
Firewater
Flares & Drains
44
Condensate
to Tie-In
Project Status – Main EPC Contract
• Scope covers gas processing facility, power generation, export pipelines, gas
gathering system, and industrial and accommodation bases
• Prequalification is about to begin to shortlist potential contractors
• This will be followed by a two stage, technical and commercial tender process
held in parallel with the FEED
• There are several contractors with the experience and skills to execute this work
package, including:
–
Petrofac - Sharjah
–
JGC - Japan
–
Samsung - Korea
–
Technicas Unidas - Spain
• EPC contract execution scheduled for late 2015
• Current oil prices should lead to very competitive tendering as other projects are
curtailed
• We will also be requesting EPC contractors to consider all steps to shorten the
project duration
45
Alternate development options which have been considered
Could we purchase a ‘standard’ gas plant and ship to Algeria?
• Given location, infrastructure needs, requirement for high availability/ efficiency and
contracted product specification, Ain Tsila is far more complex than a typical gas
plant
• Modular facilities are designed around standard equipment in multiples of smaller
units, delivering lower unit availability and often lower specifications: as such they
sacrifice efficiency for delivery expediency
• Unfortunately, this approach is not effective for Ain Tsila or the Algerian environment:
–
–
–
–
–
–
Significant re-engineering required to deliver product to specification
Unable to meet Algerian design codes and standards
Requires local contractors to assemble, hook up and commission
High level of modularisation required to transport a plant to site (mountains, roads/ bridges,
distance)
Standard plants not designed for availability requirements in Algeria (insufficient installed
sparing), with higher operating costs and no local maintenance infrastructure
Overlooks the many other parts of project like infrastructure and export pipelines
• In summary, ‘standard’ gas plants are ineffective solutions in the Algerian context
46
Other Infrastructure
(not in main EPC contract scope)
• As shown on the maps Ain Tsila is remote, has no nearby support infrastructure
and transportation facilities. Therefore we need to build it
• This involves
–
Over 150 km of roads
–
2,000 metre airstrip to support
crew changes
–
Permanent accommodation and
office space for 250
–
Telecoms networks including field
wide cellular system
–
Security facilities & accommodation
for military detachment for ~50
–
Facilities for ongoing well
engineering activities
Typical local accommodation base - 150
47
Project Status - Drilling
• The main rig contractor selected and Partner approval process advanced
–
Contract signature in February 2015
–
Rig mobilization in Q3 2015
• A light rig for workover and completions under tender for a Q4 2015 mobilization
• Well tubulars have been tendered and Partner approval process advanced
–
Award in Q1 for Q3 2015 delivery
• Wellhead and Xmas tree tenders under technical evaluation
–
Award in Q2 for Q4 2015 delivery
• Some 45 other drilling support contracts in process to meet drilling requirements
48
Strong alignment on earliest possible production from Ain Tsila
Opportunities
•
In seeking ideas of how to get to earliest reliable production consistent with stakeholder
requirements, we must consider which activities lie on the critical path
•
As is common with most developments of this kind, the critical path for the Ain Tsila
development runs through the facilities work scope portion of the activities, namely:
FEED
EPC contract tender/award
EPC execution
Production
•
3 recent contract awards for similar plants in Algeria have been awarded on 36 month EPC
execution cycles
•
As the pipelines and turbo generators are essential for plant commissioning, these items
may be recommended for early procurement by FEED contractor
•
Modularisation is a cost/ schedule reduction opportunity that is being fully evaluated
during FEED, and will be a key criterion in awarding the gas plant EPC
49
Algeria Snapshot - Project Schedule
AIN TSILA Field Development - Phase 1
.
December 2014 - rev. 2
December 2014
2014
2015
2016
2017
2018
#
Activity description
.
.
1
Early civil works for well engineering
2
Logistic camp ready for use
2
3
Main rig mobilization completed
3
4
Well engineering Long Lead Items - Delivery to site
5
24 new wells + 6 recompletions
6
WAZ 3D Seismic Acquisition Award
7
WAZ 3D Seismic Acquisition and Processing
8
WAZ 3D Seismic data interpretation
9
FEED Tender, Evaluate and Award
10
FEED Award
11
FEED Execution
12
EPC(s) Pre-qualify, Tender, Evaluate and Award
13
EPC 1: CPF+BI, BdV, GATH. & EXP SYSs Award
14
EPC 1 Engineering, Procure & Construct
15
EPC 1 Commissioning
16
EPC 2: ROADS & AIRSTRIP Award
17
EPC 2: Engineering, Procure & Construct
18
Ramp up and performance testing
19
FIRST GAS - Full Production
.
.
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
#
.
1
~23.5 MONTHS
4
5
27 MONTHS
6
7
~15 MONTHS
8
12 MONTHS
9
10
11
46 weeks
Tender, Evaluate & Award
Pre-qualify
12
13
CPF+BI, BdV+SC, Gather/Export
14
32 months
15
6 months
16
Roads & airstrip
18 months
17
18
First Gas
19
.
Q4
2014
50
Q1
Q2
Q3
2015
Q4
Q1
Q2
Q3
2016
Q4
Q1
Q2
Q3
2017
Q4
Q1
Q2
Q3
2018
Q4
Similar plant to Ain Tsila proposed design
51
Ain Tsila Subsurface and Drilling
Tony Cave
Ain Tsila – Gas and Reservoir Rocks
Top Ordovician Depth Structure Map
(m below ground level)
AT-8
AT-1
AT-5z
AT-9
AT-2
AT-4
• Large field area (80km by 35km) and
GIIP > 10 Tcf
• Tight gas field but key bonus character
in Algerian Ordovician fields
–
High matrix permeability zone (up to 1
Darcy) in NW of field related to post
glacial deposition and burial history
–
Natural fracturing along fault/fracture
corridors
• Local specific analogues
AT-3
AT-7
AT-6
1918.0
1918.3
Good primary porosity (12.5%, 775 mD)
53
Ain Tsila – Multi Tcf Ordovician Development Analogues
• Tiguentourine (BP, Statoil)
– 3 trains
– 1000 MMscf/d wet gas plateau
– ~30 wells
• Tin Fouye-Tabenkort (Total, Repsol)
– 2 trains
– 700 MMscf/d wet gas plateau
– ~40 wells
• Ohanet (BHP Billiton)
– 2 trains
– 350 MMscf/d wet gas plateau
– ~12 wells
– total plateau 700 MMscf/d from
Ordovician and Devonian
• Project personnel have worked
on and are familiar with these
projects
54
Isarene Permit Area Exploration History
13 wells drilled on permit since 2005
34 MMscf/d
AT-1
AT-8
39 MMscf/d
AT-5 &5z
AT-9
68 MMscf/d
2006
exploration
drilling
AT-2
AT-4
Isarene 3D
2008 3D
seismic
acquisition
AT-3
AT-7
AT-6
2009-10
exploration
& appraisal
drilling
2010-11
appraisal
drilling
50 km
55
55
Project Status – Preparing for Drilling
•
24 new wells and 6 re-completions prior to First Gas
•
Drilling rig and long lead time equipment contracts awards imminent
•
Rig operations to commence in 2015. Key preparation activities include: roads,
airstrip, camps, civil works, communications and procurement
•
Simple early wells (vertical, open hole and fracced)
•
Well location selection based on reservoir depth, gross pay, fracture intensity
and matrix permeability (i.e. targeting high permeability layer)
•
Later wells may be used to appraise peripheral reservoir regions and test
completion designs
56
56
Subsurface – Well Target Selection Strategy
• Objectives of the early wells are to provide:
–
productive wells for hook-up to the
gathering system and plant
–
additional data to optimise the efficient
location, drilling and completion of later
wells in the development campaign
• Status
–
12 target locations technically approved
and work ongoing to select a further 12
–
Early target selection is needed to
provided locations in a timely manner
for efficient well site construction
A joint process with our partners
57
Subsurface – Selection of First 12 New Well Targets
Locations ranked on key geological and reservoir engineering criteria
58
–
Structural Elevation and Gross Pay Thickness
• Top Ordovician Depth Structure /Field Gas water contact 1570m below
sea level
–
Vertical and lateral stand-off to water to minimise water production
–
Matrix Permeability
• Extent of high permeability layer from well data
–
Ordovician/Silurian palaeotopography
–
Burial history and preservation of primary permeability (early charge)
–
Natural Fracturing
• Proximity to major fault systems
–
Well interference/drainage radius/well spacing
–
Locations should be consistent with the estimated final development
according to the current knowledge of the reservoir
Subsurface – First Batch of 12 Target Locations Agreed
With faults
• In expected higher matrix
permeability area between AT-8,
AT-1 & AT-9
• Largely on “pop-up” structures for
higher elevation and possible
natural fracturing
• Approximate 2.5km well spacing
• Accessible from initial drilling
camp
Current
3D
59
Subsurface – Forward Plans
• Key focus on preparing for operations
–
Regulatory approvals
–
Data acquisition plans
–
Frac optimisation
–
Well testing plans
• Select further well locations
• 3D Seismic planning for 2016
60
An integrated approach for a future producing asset
• Subsurface development is not
just about the drilling
• Close co-operation with the
“Deep FEED” team
• Efficient construction planning
–
Matching models to the real
world
• Process plant design
–
Modelling production
profiles and product
streams through field life
• Production operations
–
Future well performance
–
Surveillance plans
Key personnel in subsurface, drilling and facilities
engineering have worked together on previous
successful Algerian projects
61
Network modelling
snapshot
Drilling – An optimised delivery plan to meet the objectives and
addresses the challenges and uncertainties
• Objective: to deliver at least 420 MMscf/d at “First Gas”
–
–
–
–
24 new vertical producers
6 recompletions
All producers hydraulically fracced
10 new water wells (+2 workovers/reinstatements)
• Challenges
–
–
–
Well performance optimisation
Hydraulic fracture performance
Minimising well programme duration and cost
• Considerations
5K Well Head
~7m
20” Conductor
Aquifer
16” Open Hole
13⅜” Surface Casing
~ 300 m
Visean C
12 ¼” Open Hole
–
–
–
–
–
–
62
Reservoir performance
Hydraulic fracture performance
Well performance (initial rate + sustainability)
Completion selection
Limited well data
External factors (availability, market, security)
F2 layer
Devonian
9 ⅝” Intermediate Casing
~ 1300 m
Devonian
F6 layer
Devonian
8 ½” Open Hole
7” Production Casing
~ 1900 m
6” Open Hole
Ordovician
TD
~ 1950 m
Upper Completion: 2 ⅞” – 4 ½”
Lower Completion: Bare Foot
Drilling – an innovative approach
• Objective: Optimise drilling performance across initial 30 well programme
–
What does that mean?
• Shorten well delivery timelines
• Reduce drilling and completion costs
• Generate early data to optimise later wells
• Batch process utilising Main Rig + Service Rig + Rigless Frac
• Uses service (750 hp) rig for top hole section and completion
• Uses main (1500 hp) rig only to drill main sections
• Rigless hydraulic fracturing before completion is selected and installed
63
Opportunities for long term value creation
•
Productivity / recovery upsides
– Hydraulic frac optimisation/well spacing
– Distribution of good reservoir facies (higher permeability)
•
Sonatrach approach to development planning
– Under-appraised structure going into development
– First year of production key to demonstrating potential to increase recovery
factor (currently 21% of GIIP)
•
Maturing upside case (“3P”) reserves potential
– 2nd train to increase recovery within licence period
– Plot space for 2nd processing train provided
•
Silurian shale reserves above reservoir
– additional gas potential feeding existing reservoir
– Potential further upside through direct development
64
Opportunities for longer term value creation
800
Wet Gas Rate (MMcfpd)
700
600
500
400
300
Initial Production Profile
Plateau rate 355mmscfd
200
100
2.2 Tcf
Base
(21% RF)
0
0
1
2
3
4
5
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Years From Production Start
Conservative 2P Reserves based on Available Data
Initial Focus on Delivering First Gas rather than Unlocking Upside Potential
65
Indicative upside production profile
800
Enhanced Plateau >700 mmscfd wet gas
Wet Gas Rate (MMcfpd)
700
600
Upside Production Profile
Plateau rate 710mmscfd
500
Nominal plant capacity 420 mmscfd
400
300
Initial Production Profile
Plateau rate 355mmscfd
200
4.8 Tcf
100
(38% RF)
0
0
1
2
3
4
5
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Years From Production Start
Potential for material uplift in long term field recovery based on field performance
66
In summary
• Getting on with the business of development
–
Deliver the base – bank the plateau production
• An experienced and integrated team
–
Experienced in working with this reservoir
–
Experienced in working in the country
–
Experienced in working with and building trust with our national partner
• Able to use that experience and trust to further optimise the development plan
and introduce further innovation and therefore access the upside
67
Security Considerations
Country and Project Level Planning
Stuart Harrower
Petroceltic Security Philosophy
• Overall security philosophy to be adopted for all Petroceltic’s major developments
•
provides guidance on security measures (physical, procedural and organisational)
that should be incorporated during the design, construction and operational phases
• Defines the constituent parts required to deliver an effective overall security programme
•
Policy, Strategy and Tactics
•
Threat Assessments
•
Security Plans
•
Security Organisation
•
Physical Security Measures
•
Evacuation Plans
• Phased approach, defining when specific security arrangements will be in place and
linked to the timing of each physical field/project location becoming operational
• Where execution of security plans / measures is by others (seismic, drilling and EPC
contractors) appropriate bridging arrangements must be established
69
Country Situation
• Crime and social unrest pose main risk to personnel
•
Recent protests relating to shale gas
• Terrorist threat continues to pose risk to personnel and assets
•
Al-Qaeda in the Islamic Maghreb (AQIM)
•
Unity Movement for Jihad in West Africa (MUJWA)
•
Islamic State affiliations and influence
• Considerable and conspicuous Algerian security forces
– Enforced access control in oil producing areas
– Increased strength on eastern and southern borders
In Amenas considerations
• Ain Tsila much further from Libyan border,
much less accessible
• Learnings from In Amenas being
incorporated, first hand experience in team
• Petroceltic Security Leadership role
• Building and maintaining industry and incountry networks
• Relationship with Algerian security forces
70
FEED Activities
1 – Asset Characterisation
0 – Pre-SVA
6
Information request
Agree risk parameters
Mobilisation, Site survey
Information review
Asset register
Criticality Analysis
Identify existing countermeasures
Estimate severity of risks
0
1
6 – Design & Implementation
Develop risk treatment options into
security designs
5 – Countermeasures Analysis
Recommend enhancements using
deter, detect, delay, respond principles
5
4 – Risk Assessment
Assess risk
Determine likelihood of adversary success
Plot assets on LAS–Severity Matrix and
determine which assets are exposed
beyond risk appetite
2
4
3
2 – Threat Assessment
Identify adversaries
Characterise adversaries
Threat ranking
Evaluate asset attractiveness
Target ranking
3 – Vulnerability Analysis
Evaluate assets’ vulnerability to
threats and adversaries
API/NPRA adapted by Control Risks for CB&I
71
Security Measures
• Principle is deter / detect / delay / respond
•
Sum of delay factors should exceed response time
•
Layers of protection
• Security requirements developed with expert advice and integrated into FEED studies
• Physical security measures:
•
•
•
•
•
•
72
Berm, wall, fences, razor wire, intruder detection
Advanced vehicle checkpoint, 100m from entrance
Rising kerb barriers, gate barriers, anti-ram barriers
Physical speed restrictors, bends, barriers on approach route
Suitable lighting, CCTV monitoring, guard towers, access control
Secure “panic” rooms
Security Measures
•
Procedural security measures:
•
•
•
•
•
Organisational security measures:
•
•
•
•
73
Access control
Journey management
Security Operational Requirements
Emergency response and evacuation plans
Personnel screening
Security awareness training
Intelligence gathering and monitoring through relations with Algerian authorities and local forces
Industry networks and cooperation
Summary
• Security plans established
• Appropriate controls established in-country for current activities
• Close cooperation with partners, industry and authorities
• Security integrated into the design process
• Phased ramp up as project progresses to EPC stage
• Continual monitoring
• Close relationships
74
Algeria Summary
Geoff Probert
Summary of Algerian Fiscal Terms for Isarene PSC
General
• The blocks awarded to Petroceltic in the 5th Algerian Licensing Round of 2004
• Standard Algerian PSC under the 2001 licencing model with a bid “k” factor
Participation (Investors)
Petroceltic (contractor)
38.25% Operator
Enel (contractor)
18.375%
Sonatrach
43.375%
Term
•
Ain Tsila development plan approved by Algerian Authorities December 2012, allowing for
30 year development stage to commence
Key PSC Provisions
•
Investors recover 6 times their expenditure on favourable terms (effective ~55% tax rate)
•
The Investors’ share of hydrocarbons declines rapidly when they have recovered in
excess of 8 times their expenditure
•
Petroceltic entitled to farm-out up to 49% of its equity in blocks during exploration and
appraisal stage to another party (complete)
•
Gas transportation costs once it leaves the block are Sonatrach’s responsibility; pipeline
cost recoverable
76
The Production Prize – Base and Upside Production Profile
800
Enhanced Plateau >700 mmscfd wet gas
Wet Gas Rate (MMcfpd)
700
600
Upside Production Profile
Plateau rate 710mmscfd
500
Nominal plant capacity 420 mmscfd
400
300
Initial Production Profile
Plateau rate 355mmscfd
200
4.8 Tcf
(38% RF)
100
2.1 Tcf
(21% RF)
0
0
1
2
3
4
5
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Years From Production Start
Potential for material uplift in long term field recovery based on field performance
77
Ain Tsila Gas Project in 2015
• Focused on project delivery
• On track for EPC award this year, along with main rig mobilisation
• Challenging project, but well managed by experienced, professional regional
experts
• We understand how to do business in Algeria, and manage risks effectively
• Set up to capture and cost benefits from softening in supply market
• There is space for significant upside reserves and production capture (and with
early recognition a 2nd processing train)
78
Current Access Road to Isarene Area…
Ain Tsila Gas Project in 2015
79
Egypt Production and Development
John Naismith
Egypt Country Overview
•
Petroceltic Egypt
– Long term presence in country since 1998 (and operatorship since 2006)
– Well established Joint Operating Company (Mansoura Petroleum Company)
– Strong national staff base, including senior management
•
Production and development assets
– Onshore Nile Delta gas/condensate and oil fields
– Key assets commenced production between 2006 and 2010
– Focus on production optimisation and operating cost control
•
Egyptian asset portfolio rejuvenated over last two years with new exploration licences
– Onshore Nile Delta (South Idku)
– Offshore deepwater (North Thekah and North Port Fouad)
– Onshore Gulf of Suez (El Qa’a Plain)
81
Egyptian Production and Developments
Onshore Nile Delta
• Petroceltic operated assets (100% WI)
- 13 development leases, 12 fields
currently on production
- 3 material assets with long term
production (West Dikirnis, West Khilala
and South Damas)
W Khilala
S Idku
• International liquids prices ($92/bbl) and
domestic gas prices ($2.76/Mcf)
E Dikirnis
20
Egypt Operating Cost Trend
Field staff
Operating costs
5.00
4.00
15
3.00
10
2.00
5
1.00
-
0.00
2012 2013 2014 2015 2016 2017 2018
82
Qantara
Opex ($/boe)
25
Opex ($ million)
• Average combined 2014 production rate
- 96 MMcfpd and 2,900 blpd
W Dikirnis
S Mansoura
El Tamad
Al Rawdah
Damas
S Damas
• Low cost operating environment
($2.57/boe in 2014)
• Competitive Production Sharing Contract
terms
- 35% cost oil and 20% profit share
W & E NEAbu Zahra
Abu Khadra
S Khilala
S Zarqa
Petroceltic’s Nile Delta Concessions - Operating Environment
• Agriculture based economy with high population
density
• Good local infrastructure availability (roads,
pipelines and power)
• Corporate Social Responsibility programs well
established
-
Educational, community centre and minor
infrastructure support
-
Small business enterprise scheme (micro
financing)
• Minimal operational disruption during recent
political changes
83
3 Key Fields account for almost 75% of reserves
West Khilala
Field
Remaining 2P
Reserves*
%
West Dikirnis
16.2
34
West Khilala
13.4
28
South Damas
5.7
12
Others
12.2
26
Total
47.5
100
West Dikirnis
*2013 year end reserves adjusted for 2014 production
84
West Dikirnis Oil and Gas Field
• Oil rim/gas cap reservoir with remaining reserves of 16.2 MMboe (7.8 MMbbl and 49 Bcf)
− Highly volatile oil
− Variable permeability
− Strong and non-uniform aquifer
− Localised faulting (some act as baffles, others as conduits)
• Technically advanced development with horizontal wells, gas re-injection and LPG plant
•
Gas re-injection has stabilised production and LPG Plant is recovering significant liquids
•
Current production 1,950 blpd from 5 wells with all produced gas re-injected
• Recovery will be optimised by
•
–
Having suitable well stock
–
Maximising gas cycling rates
N
WD11H
WD4 WD-1 gas
injector
S
WD7HW
70 ft oil
rim
The development plan includes:
–
2 new wells
–
3 well conversions to injection
85
0
0.5
1 km
West Khilala Gas Field
•
Miocene channel sand reservoir with high to
moderate permeability and a moderate aquifer
•
Dry gas with remaining reserves 77 Bcf
– 5 gas producers
WKh-5
WKh-10
WKh-3st
WKh-2
WKh-8
– compression added 2013
– current production 20 MMcfpd
WKh-6
WKh-1
WKh-9
•
•
Water and associated sand production is major
influence on field offtake strategy
Well rates actively managed to reduce the risk of
– premature water breakthrough
– downhole sand fill
– sand issues in surface flowlines
•
Production optimisation initiatives to redesign
surface flowlines and introduce desanders
86
WKh-4st
West Khilala Future Development
Planned 2015 wells
•
WK-10: infill well in good quality
area of reservoir (currently drilling
ahead)
-
•
Reserves 9.9 Bcf, production 6
MMscf/d
WK-6st: near field undeveloped
shallow gas discovery
-
Reserves 4.4 Bcf, production 6
MMscf/d
WKh-5
WKh-10
WKh-3st
WKh-2
Replace with
WKh-8
cleaner
map
WKh-6
WKh-1
WKh-9
Potential 2016 infill wells
•
WK-1 sidetrack
•
WK-2 sidetrack
•
WK-11 new well
87
WKh-4st
South Damas Gas Field
South Damas is clean, high net-to-gross, Sidi Salim formation
Field has outperformed with ultimate reserves estimate increasing from 30 to 57 Bcf
South Damas-2 drilled 2013 and completed with gravel pack for extended life
Have maintained a combined rate of 20 MMscf/d from both wells
Added compression at end 2014 to maintain the high offtake rate
25
DEPTH
STRUCTURE
FeedGasMMscfd
Completion SDAMAS001:QAWASIM
South Damas Production History
Completion SDAMAS002:QAWASIM
20
Gas Rate (MMscf/d)
•
•
•
•
•
15
10
5
0
JAN FEBM AR APR M AY JUN JUL AUG SEP OCT NOV DEC JAN FEBM AR APR M AY JUN JUL AUG SEP OCTNOV DEC
2013
2014
Date
88
Field Development
2015 Capital Budget Summary
•
Infill Drilling Activity
– Four wells (2 West Khilala, 2 West Dikirnis)
– Incremental 2P reserves of 0.9 MMbbl and 14.3 Bcf
– Production contribution of 1,900 boepd (2015)
•
Opex Reduction and Production Enhancement
– South Batra Plant retirement (30% of facilities footprint)
– West Dikirnis injection gas redistribution
– Tamad flowline and compression reconfiguration
•
Safety Upgrades
– West Khilala compression upgrade
– Flowline replacement program
•
Total capex $39m including Joint Operating Company G&A costs
89
Production Optimisation Opportunities
West Dikirnis Gas Cap Blowdown Philosophy
•
Maximising liquids recovery means cycling gas through the reservoir until most liquids have
been recovered (liquids attract international prices)
•
Implies delaying the recovery of the gas cap gas until later in the field life (gas attracts the
domestic price of ~$2.76/Mcf)
•
Optimising field value requires sufficient production and injection wells and maximising the
volume of gas being cycled through the reservoir
•
Economic trade-off between continuing to produce liquids at relatively low rates or selling gas
cap gas earlier at higher rates
•
Production strategy is oil price dependent (at low oil prices the optimum blowdown timing
accelerates)
•
Studies underway to evaluate optimum blowdown timing under current price expectations
90
Production Optimisation Opportunities
•
Fields are mostly channel sand reservoirs with relatively weak sands and active aquifers
•
Wells generally have high flow potential and the 12 fields have been developed with few wells
(23 current producers in total)
•
Wells suffer from water and sand production issues and as a result:
− Most are rate controlled with chokes to manage the risks of well loss and facilities damage
− Gravel packs are installed in new completions
− Surface flowlines are being reconfigured
•
Data is gathered to support the optimisation studies (sand production and well testing, flow line
pigging, ultrasonic surveys)
•
Main areas under evaluation include individual well choke settings, perforation policy and well
clean-out practices
•
Offtake decisions balance short term rate enhancement against risk of well failures
91
Egypt - Exploration
Ciaran Nolan
Egypt Exploration
Introduction
W.Khilala
W.Dikirnis
S.Damas
93
• Recent portfolio renewal
– Undertaken when competition was low
– Guided by expected gas price trends
• Four new licenses acquired in 2013/14
– N Thekah and N Port Fouad (gas)
High impact, material potential
– South Idku (oil +gas)
Near field, early monetisation
– El Qa’a Plain (oil)
Under explored oil sub-basin
• Low to moderate work programme
commitments
• 3D seismic in 2015/2016 first drilling in
2016/2017
• Farm-out campaign underway to manage
near term capital requirements
Egypt is becoming a net gas importer…..
LNG production and consumption
•
Domestic gas price is set at around
$2.75/mcf
•
Over 30% of gas production achieves
enhanced prices to permit development
(up to $5.80/mcf)
•
Price incentives largely limited to deep
water and marginal offshore
developments
•
Significant gas price increases in 2014
for industrial consumers (circa $5/mcf to
$8/mcf)
•
Egypt has started the process of
removing local subsidies to have a
phased re-alignment of domestic prices
with international gas market
•
Agreements with Sonatrach and
Gazprom to supply over 40 LNG
shipments at market rates (currently
$12/mcf to $13/mcf)
94
New Licences
Concession terms and commitments
El Qa’a Plain (PCI 37.5%, Dana 37.5%, Beach 25%)
• PSC signed January 2014
• Minimum 1st period commitment of 450km2 of 3D seismic & 1 well
South Idku (PCI 75% and operator, Edison 25%)
• PSC signed 12 Feb 2014
• Minimum 1st period commitment of seismic & 2 wells ($18m gross)
North Thekah (PCI 50%, Edison 50% and operator)
• PSC signed 12 Feb 2014
• Minimum 1st period commitment of 1,500km2 3D seismic ($20m gross)
North Port Fouad (PCI 50%, Edison 50% and operator)
• PSC ratified Dec. 2014
• Minimum 1st period commitment of 1,000km2 3D seismic ($15m gross)
95
Egypt Nile Delta Onshore – Greater El Mansoura
3D seismic was key to identifying amplitude supported prospects
3D Mansoura
3D SE Mansoura
•
•
•
•
•
•
96
Petroceltic 100%
3D key to defining structurally conformable DHIs
52 exploration wells – 37% success rate
Discovered 140 Mmboe (82% gas / 18% liquids)
PCI finding rate = 2.7mmboe/well
Finding cost of c. $1.2/barrel
Egypt Nile Delta Onshore – South Idku
Replicating the success story in Greater El Mansoura
• Petroceltic 75%(op), Edison 25%
• 3D tendering underway, drilling in 2016/2017
• Low cost, attribute driven exploration via 3D seismic –
looking to replicate the success in greater El Mansoura
• Prospective resources of 400-1900 Bcf
97
South Idku - Messinian Play
• Numerous Messinian ‘Abu Madi’
amplitude anomalies identified on
sparse 2D seismic
SE
Bright amplitude
Messinian anomaly
NW
Pliocene Shales
Lead 3
• Amplitude supported play with
potential for significant risk
reduction post 3D acquisition
Sidi Salim
Messinian
Leads
Abu Kir
1.5 Tcf + 40
MMbbls
NE
SW
Bright amplitude
Messinian anomaly
Pliocene Shales
Lead 3
Focus area for
first phase of
exploration
Sidi Salim
Lead 3
98
Egypt Offshore Nile Delta - North Thekah & North Port Fouad
High Impact Blocks on trend with Leviathan and Tamar
Edison 50% (op), Petroceltic 75%
Levantine Basin
• 3D tendering underway (blue outlines)
• High-impact blocks in the Levantine Basin on trend
with Israeli/Cypriot Discoveries
• Deepwater Egyptian part of the Levantine underexplored
• Multi-Tcf potential identified on existing leads (2D)
• >40 TCF discovered in Israel and Cyprus
• High quality sands that have some of the
highest individual well rates in the world
(Tamar – 250 - 300 mmscf/d)
• Communication across fault blocks common gas gradient
• Smaller number of wells required to develop
Aphrodite
Leviathan
Karish
Tamar
Dalit
Oligo-Miocene sands
sourced from the Nile Delta
99
Eastern Mediterranean Bid Rounds – Signature Bonuses
Cyprus 2012 and EGAS 2013 and 2014
ENI Shorouk
$5mm signature bonus
ENI & KOGAS
TOTAL
ENI North Leil
$34m
signature
bonus
N.Port Fouad - PCI
$5.1m signature
bonus
$210mm
signature bonus
Noble Aphrodite
5Tcf
BP North El Max
Noble, Tamar
$10m signature
bonus
10Tcf
Noble, Leviathan
ENI & BP
Karawan
BP North Tennin
22Tcf
$20m signature
bonus.
BP, Salamat
4.4Tcf &
22mmbls
100
N.Thekah - PCI
$7.1m signature
bonus
Dana Gas, N. Arish
$20m signature
bonus
Nile Delta / Levantine Basin – Play Types
Regional SW – NE Cross Section*
Pliocene
Delta slope channels
e.g. Sequoia
Miocene
structural traps
e.g. S.Idku
Cretaceous
Deep HPHT
Oligocene
Deep HPHT
e.g. Notus & Salamat
Levantine sub-salt
Miocene and Oligocene
e.g. N.Thekah & N.Port Fouad
* After Aal et al., 2006
101
North Thekah Prospectivity
• Material structures identified on sparse 2D
NE
• 3D seismic and Pre-Stack Depth Migration is
required to improve trap definition & identify DHIs
SW
Prospect 1 (130km²)
10-15 Tcf
Messinian evaporites
Top Reservoir
Prospect 1 is a
draped over a
deep high
SW
102
Deep Structure
at Mesozoic
Level
NE
Levantine Basin – impact of 3D seismic on prospect risking
•
•
•
•
•
* After Skiple et al., 2012
103
Most Levantine Discoveries have a DHIs
DHI response vary depending on sand quality and
seismic data type and quality
Modelling of Tamar field carried out by PGS
Shown above is the synthetic model response
compared to an actual 2D response
High quality 3D surveys in the Levantine can
significantly reduce prospect risks
• High quality sands that have some of the
highest individual well rates in the world;
250 - 300 mmscf/d)
• 10 producers required to recover 10.6 TCF
• EUR/producer of 176 mmboe
Slide courtesy of Noble Energy
104
Egypt Gulf of Suez - El Qa’a Plain
Underexplored oil prone onshore acreage
•
•
•
•
•
•
105
Dana 37.5% operator, Petroceltic
37.5%, Beach 25%
Underexplored 1824 km2 onshore
block (with 2D seismic/2 wells drilled
in target sub basin)
Lower Cretaceous (Nubian) oil play in
with a proven regional hydrocarbon
system
Two main oil prospects - combined
unrisked mean prospective resources
of around 140 mmbo
Four year first licence period - work
commitment 450 km2 3D seismic and
one well
Seismic planned for 2015, one well in
2016
Egypt Exploration
Summary
• Low cost, high quality portfolio
renewal in 2014/15
• Quality regional partnerships
• Looking to replicate the Mansoura
success story at South Idku
• Low cost entry into high impact
Levantine Basin Licences
W.Khilala
W.Dikirnis
S.Damas
106
• Improving business environment
– more flexibility on gas pricing
– reduction in receivables
• Farm-out campaign underway to
manage capital commitments
• 3D seismic acquisition in 2015/2016
first drilling in 2016/2017
Financial Strategy
Tom Hickey
Financial and Corporate
• Manage Egypt and Bulgarian production and restructure organisation to deliver
reserves at progressively lower costs as fields mature
• Manage exposure to exploration costs via farmout, avoid material new commitments
• Keep sufficient liquidity in the business to manage fluctuations in activity, debt service
and resource price volatility
• Maximise value of activities covered by Sonatrach Carry in 2015 -16, including EPC
award and initiation of development drilling
• Commence Ain Tsila-driven refinancing process in 2015 as markets stabilise, as a
clear part of a longer term plan
108
Capital allocation evolution - 2015 Budget
•
•
Capital allocation directed towards core
areas, development and operated
interests
− over 80% in Egypt/Algeria
− 80% development
− Over 85% operated
Algeria costs all carried - further $40
million to recover in 2016
Development
Exploration
Total
2014***
$million
$million
$million
$million
Algeria
80*
-
80*
10*
Bulgaria
20
-
20
7
Egypt
39
23
62
38
5
5
3
Italy/Greece
•
•
Farm-out initiatives may further reduce
or delay exploration expenditure
Running costs management
− 40% corporate headcount
reduction programme
− 15% operating costs reduction
in Egypt and Bulgaria
Kurdistan**
-
7
7
33
Romania
-
-
-
10
139(59)*
35
174(94)*
101
Total
*Algeria costs covered by farmout carry arrangements; the 2015
numbers in brackets and the 2014 number represents costs
attributable to Petroceltic post carry
** Budget prior to testing
*** Subject to audit
109
Production portfolio – Pricing terms and oil linkage
Egypt – limited exposure due to reserve profile and
EGPC arrears position
– Gas pricing fixed at $2.76/mcf for all current
production. Liquids at open market prices
– Cashflows not directly revenue related due to
recovery of EGPC arrears
– Improving Egyptian credit environment and
payment performance in 2013-14
•
Bulgaria – based on Gazprom oil price linked import
price, but with 9 month lag – Woodmac 2015 Estimate
of $7/mcf
•
Ain Tsila – Oil price linked Gas Sales contract
– Open market liquids pricing
– c.40% of value in liquids
EGYPT 5 yr CDS spread 2012-14
EGPC receivable
US$’m
•
110
180
160
140
120
100
80
60
40
20
0
Financing the Long Term Production Profile
Current RBL structure
• Utilises existing producing and nondeveloped assets in Egypt/Bulgaria
50
•
Complementary to Algeria farm-out
structuring and process
40
•
However terms out in 2018 so limited
effectiveness 2016 onwards
30
Longer term planning
• Balance of value between Algeria and
existing production is progressively
weighting more towards Algeria
•
•
Financing plan for funding of
development obligations post
Sonatrach Carry
Objective to effect a partial or first
stage of refinancing during 2015
Corporate
Facilities
20
Farmout
10
RBL/Dev
Funding
0
Gas
Liquids
Longer term strategy to match funding to stable post 2018 production profile
111
Isarene PSC – Positive Gearing Characteristics, Swift Payback
•
Cashflow positive from first production - 14
year Plateau means very strong cashflow
generation through 2030
•
PSC structure guarantees rapid recovery of
Capital Investment
– High Operating Cashflow/mcf even at
lower oil prices
– Average Opcost $0.30/mcf at plateau
•
Gas Sales arrangements provide certainty on
pricing and revenue
– High take or pay %
– Consistent cashflow visibility
•
Progressive approach to funding project before
2016 spend
Carried
Major Commitments
Late 2015
112
Max Exposure
Mid 2018
Cash “Payback”
within 4 years
Algeria – Investment roadmap and gearing potential
Activity
2014/15
2015
Project
Milestones
FEED outputs
update
schedule and
costs
Main contracts
placed – EPC,
Drilling, Civils
Production
drilling and
facilities
construction
First
production
Gas and
Liquids
Marketing
Full GSA
signed
Execution of
Development
Monitoring of
completion of
CPs on GSA
CPs completed
& GSA enters
into full force
Financing
Status
Farmout
Concluded
and effective
Funding
Milestones
established
Drawdown on
funds
progressive
financing
strategy
Revenue flows
Free cash
used to pay
down debt
Loan to
Value%
30-35%
2016-2018
35-40%
Key Decisions
113
40-50%
2018+
50-60%
Financing Activities 2013/4
•
Corporate finance initiatives have enhanced financial flexibility
− successfully refinanced the Company with 5 year facility to 2018
− $160 million carry on Sonatrach farm-out covers Algeria to Q1/Q2 2016
− $100 million equity issue, partly to bridge Algeria farm-out receipts
•
However, not all objectives have been achieved
− Reserve replacement performance disappointing, thereby limiting longer term Reserves
Based Lending potential
− Recent Commodity price decline impacts on potential debt availability
•
114
Long term planning for Algeria funding post carry has already commenced
− Corporate Bond/High Yield
− Combination RBL/Bond solution
− Asset specific project finance
− Corporate reorganisation to facilitate the future debt funding of Algeria
Business Review Summary
Brian O’Cathain
Summary
•
•
•
•
•
•
Portfolio value concentrated in Algeria and Egypt
Key to adding value in Algeria is in de-risking execution and finance availability
Management focus on delivery in these areas
Experienced teams and work plans in place to deliver
Exploration and new business de-emphasised, but long term value preserved
G&A and capex adjustments to fit new strategy
116
Brent Crude Forward Prices
$/bbl
115
110
105
Forward @ 1 July 2014
100
95
Forward @ 1 December 2014
90
85
80
Current Forward (23 January 2015)
75
70
65
60
55
50
45
Current Forward
____________________
Source: Bloomberg as at 23 January 2015.
117
Forward as at 1-Dec-2014
Forward as at 1-Jul-2014
Conclusions
•
•
•
•
•
Petroceltic’s portfolio in Egypt mainly fixed gas price – not impacted by oil price
movements
Bulgarian gas price indirectly linked to oil with nine month lag
Algeria exposed to oil price movements, but first full year of production in 2019
Company well placed to manage through the oil price cycle down-turn
Exploration budgets reduced, transformational potential preserved in Egypt (and Italy)
•
•
•
•
De-risking in Algeria through project execution and financing progressing
Project on track to deliver first gas in 2018
Project costing may benefit from near term demand weakness in service sector
Significant upside in Ain Tsila still to play for
118