Investor Presentation - premier-oil. · PDF fileForward-looking statements This presentation...
Transcript of Investor Presentation - premier-oil. · PDF fileForward-looking statements This presentation...
Investor Presentation January 2018
Forward-looking statements
This presentation may contain forward-looking statements and information that both represents management's current expectations or beliefs concerning future
events and are subject to known and unknown risks and uncertainties.
A number of factors could cause actual results, performance or events to differ materially from those expressed or implied by these forward-looking statements.
January 2018 | P1
Executive Summary
2017 – a year of strong delivery
Production
2017
Production 75.0 kboepd, in line with guidance
Cost Base
2017
Opex of $16.5/boe; FY capex $305m below revised guidance
Disposals
2017
Wytch Farm completed; Pakistan and ETS pipeline sales announced
Catcher
2017
First oil delivered on 23 December. On schedule and c30% below budget
Tolmount
2017
HoT signed with infrastructure partner; draft FDP submitted to OGA
Sea Lion
2017
Negotiating funding packages; LOI signed with contractors
Exploration
2017
World class oil discovery at Zama-1, Mexico
Net Debt Reduction
2017
Positive cash flow in the year; deleveraging underway
2018 Target
Guidance 80-85 kboepd (Catcher ramp up and 2017 disposals)
2018 Target
FY guidance of opex c$17-18/boe and capex (ex-Abex) of $300m
2018 Target
Complete Pakistan and ETS sales; other processes ongoing
2018 Target
Deliver production ramp up to 60,000 bopd; complete wells
2018 Target
Progress for FID in 2018
2018 Target
Progress financing, fiscal and commercial initiatives
2018 Target
Appraise Zama in H2/early 2019 and define development plans
2018 Target
Generate positive net cash flow and target debt reduction to 3x Net Debt/EBITDA
January 2018 | P3
Production overview
Largest 5 fields account for c. 70% of production
January 2018 | P4
Development portfolio
>800 mmboe of discovered
but undeveloped reserves and
resources
January 2018 | P5
Delivering on our strategy
• Opportunistic acquisitions
• c$16/bbl
• Operated
• FPSO’s
• Partner-funded
• Proven basins
• Under drilled
• 75 kboepd
Value
Stakeholder Returns
Debt Reduction
• Disposals – realising value
Production
Costs
Development Exploration
Portfolio Management
Acquisitions
January 2018 | P6
Future plans
Balance Sheet Management
Value
Stakeholder Returns
Debt Reduction
Production
Operating Costs
Development Exploration
• $17-$18/bbl
• Catcher
• Tolmount
• Sea Lion
• Zama
• Tuna
• High value, near field
• Material upside in Mexico and Brazil
• Continuing growth
• Reserve life >10 yrs
• Free cash flow 2018-2022 reducing debt
• Net debt : EBITDA <3x
Portfolio Management – Acquisitions
• Disposals by majors
• Tax optimisation
Portfolio Management – Disposals
• Non core assets
• Mitigating risk
January 2018 | P7
Producing Portfolio
Chim Sáo, Vietnam (53.125%, operator)
20P 5IPST1
2017 • 14.9 kboepd • High operating efficiency and strong
reservoir performance • $9/boe operating cost • 2 infill wells completed; 6,500 boepd (gross)
production added
0
5
10
15
20
25
30
35
2016 2017 2018 2019 2020
CurrentPrevious
Improved Production Profile kboepd (gross)
59 mmboe reserves
remaining
55 mmboe at sanction
57 mmboe produced
to date
January 2018 | P9
Natuna Sea Block A, Indonesia (28.67%, operator)
2017 • 12.9 kboepd, above budget • Singapore demand above take or pay (49%
of GSA vs 47% contractual share) • High operating efficiency • Opex of c.$8.7/boe • Lama development well (WL-5X) tied into
production; producing 20-25 mmscf/d
Outlook • Singapore demand stable • GSA1 market share increasing • BIGP first gas 2019
0
20
40
60
80
100
0
5
10
15
20
2016 2017 2018 2019 2020
NSBA Production net to PMO (kboepd)
Market Share GSA1 (%)
BIGP
30% IRR
93 Bcf
$340m gross capex
January 2018 | P10
Huntington, Central North Sea (100%, operator)
2017 • 13.0 kboepd, 28% above budget
− High FPSO operating efficiency − Strong reservoir performance − HoT agreed on lease extension
and extended Shell term deal
Outlook • Maximise production
Currently producing ~13 kboepd
January 2018 | P11
Solan, West of Shetlands (100%, operator)
2017 • 5.9 kboepd • Central reservoir on prognosis; Eastern area of field under-performing
Outlook • P1 producing steadily on free flow • P1 workover deferred • Options to improve production being
evaluated; potential infill well 2019
P1
W2
P2
W1
500m
Top Solan Sand Depth Map
January 2018 | P12
Elgin-Franklin, Central North Sea (5.2%)
2017 • 5.4 kboepd • Low opex of c.$8/boe
Outlook • Long field life; production forecast
to continue until 2037 • 350 mmboe remaining reserves • Ongoing infill drilling, well
intervention programme and exploration upside
January 2018 | P13
Portfolio Potential
September 2017 | P15
Catcher – first oil achieved 23 December
• Arrived in North Sea in October
• Hook up and Commissioning programme executed in c. 2 months
• First Oil from Catcher field achieved 23 December and from Varadero on 12 January
• Phased ramp up of production underway
• Important cornerstone of Premier’s debt reduction
• All 12 wells planned pre-first oil completed confirming good quality oil
• Subsea activities complete including short campaign to support hook-up and commissioning operations post arrival of FPSO
Project capex down 29% on sanction
January 2018 | P15
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
Dai
ly O
il P
ote
nti
al (
stb
/d)
Catcher Varadero Burgman
Catcher Final Commissioning & Production Profile
• Catcher is the initial field on production due to it’s ability to produce oil in a stable fashion for the first stages of the FPSO plant commissioning
• Each field will be brought on in the following manner – Well clean up (initial clean up restricted by rig surface equipment) – Well test through the subsea multi-phase meters – Restricted rate to manage gas rates through commissioning period
• Following gas train commissioning completion and the introduction of Burgman fluids the plant will be run at 60 kbopd
Fuel Gas
Import
Catcher First Oil
Oil Stabili- sation
Fuel Gas
Varadero First Oil
Permeat. Comp
Water Injection
Gas Lift
Gas Export Comm.
Burgman First Oil
Flash Gas
Comp
Primary Gas
Handling
Produced Water
January 2018 | P16
Improved production profile anticipated
Catcher – continuing positive drilling results
• 14 wells completed to date
– 4 on each of Catcher, Varadero and Burgman fields planned pre first oil
– Phase 2 drilling on Catcher underway
• Good test results:
– Net pay encountered by the 8 production wells > 30 % longer than forecast
– Initial production delivery rate per well >40% higher than predicted on average
• Improved production profiles anticipated of c.60 kboepd
• Review of FPSO capacity underway
Varadero
Catcher
Burgman
Plateau production up 20% on sanction
January 2018 | P17
Tolmount – infrastructure partnership
• Partnership with Dana Petroleum and CATS Management Ltd (1)
• Dana and CML will jointly own: – platform – export pipeline
• Tolmount gas will use the facilities – LoF tariff
• Premier’s share of project capex $100m
• Premier retains 50% equity interest in the licence
• Excellent project economics – IRR >50% at gas price of 30p/therm
Estimated Tolmount Capex (Gross) $m
Development Scope Gross Capex (Real, $mm)
% pre 1st gas
Platform 90 100%
SURF (20” pipeline to beach) 100 100%
Host Terminal modifications 150 85%
Drilling (2) 140 64%
PMT 70 92%
Total 550 -
High return project robust down to low
gas prices
PMO 19%
Dana 50%
CML 31%
Capex Split
(1) an Antin Infrastructure Partners portfolio company (2) Based on plan where one well is on-stream pre-1st gas January 2018 | P18
Tolmount – progressing on schedule for FID in 1H 2018
• Initial phase: targeting 540 Bcf resources
• Peak production capacity 300 MMscfd
• FEED contracts awarded; engineering underway
• Evaluation of proposals received for major project scopes (including platform and pipeline) underway
• Draft FDP submitted to OGA
• Timing: – FID 2018 – First gas 2020
Subsurface Depletion Plan • 4 initial development wells in Tolmount • Future phases TE , TFE & Mongour Offshore Facilities • NUI platform with 6 slots / 4 wells • Offshore PWT treatment • Riser / J-tube pre-investment for area development • 20” x 48kn Gas Export pipeline • 3” MeOH (and CI) import pipeline Host Terminal • Dimlington host • New reception & condensate processing • Shared gas processing & compression
Perenco Dimlington SNSPS (Cleeton / Ravenspurn) West Sole (connected to Perenco Easington) Tolmount
Centrica Easington Rough & York
Dimlington Terminal >1 bcf gas processing capacity, 600 mmscfd installed compression capacity plus additional condensate processing
Tolmount
Gassco Langeled Ormen Lange
January 2018 | P19
Tolmount – future phases planned
Tolmount East • Subsea tie-back or small platform • 2019 well planned to confirm resource
Tolmount Far East • Subsea tie-back or small platform to
Tolmount or Tolmount East
Mongour • Subsea tie-back or extended reach
well from Tolmount East
3rd party business potential • A new hub with 20+ year life
Tolmount
Mongour
Tolmount East
Tolmount Far East
Tolmount area
~ 1 Tcf
Indicative production profile
42/28d-12 NE SW
Tolmount Tolmount East
Tolmount Far-East
Gas water contact
January 2018 | P20
ENSCO 8503
Flat Spot
• Major hydrocarbon discovery in shallow water, offshore Mexico
• Initial gross oil in place estimates are 1.2 – 1.8 Bnbbls (unrisked P90-P10 resources of 400-800 mmboe), exceeding pre-drill estimates
• Contiguous gross oil bearing interval of over 335m, with over 200m of net oil bearing reservoir
• Light oil : 28-30° API
Full stack reprocessed seismic data in depth
E W Zama-1 Well
Good conformance of seismic amplitude with structural contours
Zama-1 oil discovery - volume estimates
Gross oil bearing interval to scale
January 2018 | P21
Potential to leverage Mexican fabrication capability
Zama – illustrative development scenario
Location of Zama discovery
Indicative development metrics
Resources 400-800 mmboe1
Daily peak production 100-150 kbopd
Capex +/- $1.8 billion
Appraisal 2018-19
First oil 2022-23
Block 7 prospect map
Zama
(1) Including the extension onto the neighbouring block
Amoca
Zama
Hokchi
January 2018 | P22
Project status • FEED substantially completed • Breakeven reduced to c$45/bbl
− Capex to first oil reduced to $1.5bn − Field opex reduced to $15/bbl − Indicative FPSO cost of $10/bbl (LoF)
• LOIs signed with contractors
Outlook • Positive commercial and fiscal
engagement with FIG • Positive engagement with contractor
market and senior debt providers • Licence extension to May 2020
Sea Lion, Falkland Islands (60%, operator)
0
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40
60
80
100
120
140
160
0 5 10 15 20
An
nu
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vera
ge
oil
ra
te (m
bo
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)
Years from first production
Phase 2Phase 1
January 2018 | P23
Tuna, Indonesia (65%, operator)
Highlights • Discovered in 2014 by the Singa
Laut-1 and Kuda Laut-1 wells >90 mmboe • Evaluation of potential development
scenarios ongoing • Government agreement signed with
Vietnam and Indonesian governments re: connection to existing infrastructure in Vietnam
• Granted 3 year extension to exploration period of licence
January 2018 | P24
Ceara Basin, Brazil – exploration
• Largest acreage holder in the Ceara basin
• 4,000 km2 of fast-track seismic data across all 3 blocks received in 2016
• Final depth migrated broadband seismic data received in April 2017
• Well locations to be selected during 2017
• Licence extensions received for all 3 blocks
• Drilling operations planned for 2019
CE-M-661 CE-M-665
CE-M-717
Excellent imaging on new broadband seismic of Upper Cretaceous turbidite channel sands
Maraca K40
Ganza K40
Pecem K40
Berimbau Up-dip pinch out and fault offset
Berimbau
Pecem K50 discovery
1-CES-158 1-CES-112 SW NE
CE-M-717
Data Proprietary to PGS Investigacoa Petrolifera Limitada 8km
January 2018 | P25
Financials
Net debt and hedging
Drawn Debt Total Facilities(incl cash)
Cash & Undrawn
$4.0 bn Facilities confirmed 1
$3.4 bn
0
1,000
2,000
3,000
4,000
2017 2018 2019 2020 2021 2022
Previous
Revised
Maturities extended 1
1 FX as at when facilities entered into
Net debt
• Net debt of $2.7bn
• Positive cash flow in 2017 including disposals; debt reduction accelerating as Catcher production ramps up
• Average cost of debt c7% going forward
• Targeting Net Debt/EBITDAX <3x by end 2018
Comprehensive refinancing completed
Other key amended terms • Covenant profile re-set with headroom • Enhanced economics (~1.5%) to lenders • A warrant package to lenders • Convertible bond re-priced • Corporate governance controls
January 2018 | P27
Liquids and UK gas hedging as at 31 December
• 40% of 2018 oil production hedged:
• 10% with options, floor price $55/bbl
• 30% swaps and fixed term sales, average price $57/bbl
• 24% of 2018 UK gas production hedged at 47p/therm
Capex
2014-2017
• Reduced from over $1.0bn pa. to $305m in 2017
• Reduced forward commitments
2018-2020
• Maintain at current run rate depending on new projects
• Disciplined approach to capital allocation
Operating Costs
2014-2017
• Down from c$20/boe to c$16/boe
• Over $300m of absolute cost savings delivered since 1/1/2015
2018-2020
• Stable operating cost base at current levels $17-18/boe
Net debt
2014-2017
• Increased due to investment and weakness in oil price
• Reducing by end 2017
2018-2020
• Leverage ratio below 3.0x and falling
• Priority remains reduction in absolute levels of net debt
Portfolio management
2014-2017
• Over $350m realised from disposals
• Significant value created through E.ON acquisition
2018-2020
• Further disposals to accelerate deleveraging
Financial outlook
January 2018 | P28
Premier Oil Plc 23 Lower Belgrave Street London SW1W 0NR Tel: +44 (0)20 7730 1111 Fax: +44 (0)20 7730 4696 Email: [email protected]
www.premier-oil.com
January 2018