premier oil inv_pres_nov_2015
TRANSCRIPT
Investor Presentation
November 2015
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.
November2015 | P1
Executive summary
Delivering our short term targets
Above budget and guidance year-to-date driven by 90% operating efficiency
Strong operating cash flow
Production of 57.5 kboepd
Opex per barrel reduction
Net debt stable
Covenant flexibility
Solan and Catcher milestones achieved
Resource additions
Increased cash flows: strong production, lower costs and hedging benefits (which continue for rest of 2015 and 2016)
Further cost savings identified; $16/boe opex expected for FY2015
Net debt of $2.3 billion, despite ongoing investments in Solan and Catcher
Renegotiated terms; covenant headroom >$700m for FY2015
On track for first oil before the year end from Solan and 2017 from Catcher
Discoveries at Zebedee and Isobel Deep; resource additions at Anoa
Refocusing the portfolio
Asset disposals (Norway subsidiary and Aceh in Indonesia); Low cost acreage additions in Brazil and Mexico
November 2015 | P3
Cash generation in a low oil price environment
November 2015 | P4
• Growing production profile
– Intense focus on execution
– Reducing level of spend
2.
• Robust, low cost production generates good cash flow
1.
• Free cash flow will be directed at debt reduction
3.
20 19
17
14 16
0
5
10
15
20
2013 2014 2015budget
2015 1H 2015forecast
Opex ($/boe)
2015F 850 200 2016 570 80 2017 350 35 2018 250 135
Committed capex $m
0
200
400
600
800
1000
1200
2015F 2016 2017 2018
Exploration
P&D Capex
Favourable financing structure
November 2015 | P5
• Liquidity – $1.2bn cash & undrawn facilities (end
October 2015)
– No significant debt maturities until 2019
2.
• Corporate unsecured structure – No reserve base redeterminations
– Average debt cost 2015 ytd: 3.5%
1.
• Increased financial flexibility – Covenants amended
– Strong support from banks & bondholders
3.
Net debt/ EBITDAX Old covenants Amended covenants
0
1
2
3
4
5
20151H
2015FY
20161H
2016FY
20171H
2017FY
307 362
1,238
558
0
200
400
600
800
1000
1200
1400
2015 2016 2017 2018 2019 2020-2024
Drawn debt maturities ($m)
Production
Pakistan (10.3 kboepd) • Well-established gas
producing fields • Generates positive, stable
cash flows • Formal sales process
ongoing
0
5
10
15
20
2014 2015 ytd
2015 ytd – strong production
November 2015 | P7
Indonesia (13.8 kboepd) • Singapore demand above
take or pay • GSA1 share 42.8%; above
contractual share of 39.9% • Pelikan on-stream
0
5
10
15
20
2014 2015 ytd
Vietnam (17.0 kboepd) • High operating efficiency
following summer shutdown
• Better than predicted reservoir performance
0
5
10
15
20
2014 2015 ytd
Group •High operating
efficiency •Higher liquids
production
0
10
20
30
40
50
60
70
2014 2015 ytd
FY guidance
2015 ytd average:
57.5 kboepd
North Sea (16.4 kboepd) • Unrestricted production
from Huntington since April • Steady production from rest
of UK portfolio
05
10152025
2014 2015 ytd
OE 84%
OE 90%
OE 72%
Production (kboepd) Production (kboepd)
Production (kboepd) Production (kboepd)
OE 87%
OE 84%
OE 86%
OE 94%
OE 92%
OE 96%
OE 95%
UK – underlying growth
2015 ytd
• Averaged 16.4 kboepd
• Improved operating efficiency
• Opex $30.2/bbl, down 20% (FY 2014: $37.75/bbl)
– Sale of high cost Scott area
– Active cost management and G&A cuts
• Sanctioned projects will see Premier’s UK production rise to c. 50 kboepd
• $3.3 bn of UK tax losses and allowances
Catcher
Balmoral Area Solan
Wytch Farm
Kyle Huntington
87% operating efficiency
Key projects Equity interest
First oil/gas
Operator Reserves YE14 (gross)
Balmoral Area c. 80% Various Premier 7 mmboe
Catcher 50% 2017 Premier 96 mmboe
Huntington 40% 2013 E.On 16 mmboe
Kyle 40% 2001 CNR 5 mmboe
Solan 100% 2015 Premier 44 mmboe
Wytch Farm 30% 1979 Perenco 47 mmboe
November 2015 | P8
Indonesia – strategically positioned
2015 ytd highlights •Singapore demand
above ToP •42.8% of GSA1 vs
39.9% contractual share •Pelikan on-stream •Block A Aceh sale
completed
Outlook •Steady Singapore gas
demand but increasing market share for GSA1 •Portfolio of growth
opportunities
GSA2
Domestic Gas Swap
GSA1
November 2015 | P9
42.8% share of
GSA1
Growing domestic market
Vietnam – high performing cash generator
November 2015 | P10
2015 ytd highlights • 17 kboepd, reflecting continued
outperformance • Better than predicted reservoir
performance • Significantly reduced opex at
c.$12/boe • 5% premium to Brent for crude
Outlook • No committed capex • Incremental growth opportunities
0
5
10
15
2017 2018 2019 2020 2021 2022 2023
Incremental production
86% operating efficiency
Development
Development – sustained growth
Catcher (50% op.) • 96 mmboe • ~50 kbopd at peak • $1.6bn capex pre-first oil • Reservoir upside
Solan (100% op.) • >40 mmbbls • First oil still Q4 2015 • $1.76bn capex spent to
end Oct 2015
BIGP (28.7% op.) • Backfill our existing
contracts • Q4 2016 investment
decision
Sea Lion Phase 1a (60% op.) • c. 160 mmbbls • ~60 kbopd • $1.8bn capex pre-first oil • 2016 FEED decision
Increasing deliverability
November 2015 | P12
Monetising high value
UK tax pool
Progressing phased,
lower capex solution
Monetising high value
UK tax pool
Solan – first oil Q4 2015
Long term vision
• Reserves upside potential
• Infill drilling opportunities; near field exploration
• Nearby accumulations; potential 3rd party business over Solan hub facility
• Consider farm down of equity post first oil
Cash generative
$26/bbl opex (LOF)
No tax
25,000
20,000
15,000
10,000
5,000
0 2020
Solan oil production rate (stb/d)
November 2015 | P13
Potential ullage?
2015 ytd highlights
• P1/W2 tied in; P2 suspended, W2 underway
• Improved offshore productivity
• Removed partner funding concerns
• Reduced balance sheet exposure (Flowstream)
• Cash spend at as 31 Oct $1.76m
Peak production
25,000 bopd
Solan – facilities update
2015 1H Sep - Oct Nov - Dec
Siem Spearfish 60 men; 180-280 hrs/day
Regalia flotel 135-150 men; 600-800 hrs/day
Superior flotel 200-240 men; 1,000 hrs/day
Habitation 20 men; 100-120 hrs/day
Complete construction works; commissioning of
accommodation
Commissioning of safety, accommodation, & production systems,
power generation & utilities
Tanker Offloading trials
Jul - Aug
Bibby DSV SOST &
P1/W1 tied in
Ocean Valiant P2 suspended; sidetrack Q2 2016
Victory 250 men; 800-1,000 hrs/day
Completion of over-side work & commissioning of
emergency power systems
Bibby DSV Complete commissioning of subsea infrastructure
o
Ocean Valiant W2 spudded
Commissioning of production systems
Commissioning of production systems
First oil
November 2015 | P14
November 2015| P15
Catcher area
Reservoir upside
Near field tie-backs
Exploration upside
No tax
Catcher 5P, 2I
Varadero 4P, 3I
Burgman 5P, 3I
Catcher – subsea
• 2 templates installed (Catcher 1 & Burgman 1)
• PLEM installed • 60 km gas export
pipeline lay completed • Fabrication of remaining
templates completed • Fabrication of towheads
well-advanced • First steel cut on mid-
water arches • Fabrication of bundles
underway • Fabrication of risers and
jumpers to commence in 2016
November 2015 | P16
Catcher - execution phase progressing
November 2015 | P17
Formal concept select
FPSO HUC
DECC approval
2013 2016 2015 2014 2017
Exploration
FPSO and SURF fabrication
commenced
SURF installation
Development drilling
FPSO • Turret and mooring system
progressing
• Hull fabrication on-going in Japan and Korea
• Topsides fabrication underway in ProFab, Dynamac and Asia Offshore yards
Drilling • Ensco 100 rig on hire since July
• Batch drilling of first 4 wells completed
• CTI1 water injection well complete; good reservoir results
• CCI2 water injection well being completed
• Operations on schedule and within budget
96mmboe
$1.6bn (gross budget to first oil)
Peak production c.50 kbopd First
oil
CTI1
Buoy and moorings
installation
De-risking the Sea Lion development
November 2015 | P18
• Phase 1a reservoir is fully appraised, subsurface plan is robust
• FPSO and SURF is well understood, conceptual design is now mature
• Key project execution contractors selected ahead of FEED
• Financing plans progressing well
• Upside in the area has increased and become better defined
• Stakeholder discussions continuing
Phase 1a facilities
Subsea drill centre
FPSO Shuttle tanker
8 well production
manifold
5 well water injection
manifold
Flowline to gas well
Nov 2014 capex
Pre-sanction capex $0.1bn
Surf & installation $0.7bn
Project management $0.4bn
Pre-first oil drillex $0.6bn
$1.8bn
Potential for cost
reductions
November 2015 | P19
3Km
Phase 1a (160 mmbbls)
Phase 1b
Phase 2
Exploration
Exploration – re-shaping the portfolio
Balance of wells targeting Mature verses Emerging plays
2012 2015
North Sea and SE Asia
Falklands, Brazil and Mexico 11 0
Growth in emerging basins
with material opportunities
Rationalisation in
mature areas
• Focusing on under-explored, emerging plays in proven hydrocarbon provinces
– Entry into Brazil and follow-on farm in to Block 661, Ceará Basin
– Successful entry into Mexico with award of Blocks 2 & 7
• Minimising up-front capex commitments
• Current industry conditions favour low cost acreage acquisition
• Exiting acreage in traditional, more mature areas (save for near-field exploration)
– Significant disposal proceeds and reduced well commitments
– Improved materiality of discoveries
• Net unrisked prospective resource of >1 bn boe
100% Emerging
100% Mature
2015 well campaign
2012 well campaign
17 51
November 2015 | P21
2015 North Falklands Basin campaign
2015 ytd highlights
• Zebedee oil & gas discovery (36% op interest) – adds c. 50 mmbbls to Phase 2
• Isobel Deep oil discovery (36% op interest) – de-risks the Isobel/Elaine fan complex (un-
risked Pmean resource of 400 mmbbls) – opens up potential Phase 3 development
Two discoveries
from two wells
2015 /2016 look ahead
• Isobel Deep (36% op interest), well to spud Q4 2015 – Partners agreed to performing more drilling at
Isobel Deep, ahead of Jayne East
• Chatham (40% op interest), well to spud Q1 2016 – would add resource to Phase 1b
Chatham Pmean
47 mmbbls
50 mmbls
Zebedee
Southern exploration
leads
Phase 2 prospects
PL032 prospects
Jayne East Pmean
39 mmbbls
Isobel / Elaine
Pmean
400 mmbbls
November 2015 | P22
Beyond 2016
• Additional exploration/appraisal prospects identified for drilling in 2017/2018
Falklands: Isobel Deep Re-Drill
Full stack amplitude at F3G horizon • Further drilling at Isobel / Elaine complex to confirm significant resource potential of southern F3 fan system (unrisked Pmean 400 mmbbls)
• Chatham exploration well follows, also appraises the expected gas cap in the west of the Sea Lion field
•
North Falkland Graben
Isobel / Elaine Re-drill Isobel Deep
Jayne East
Zebedee
Jayne East
Isobel Deep
Isobel / Elaine
November 2015 | P23
10Km
Brazil Ceará Basin – expanding acreage footprint
Pecem discovery • Flowed light oil
to surface when tested in 2014
• De-risks key play elements
Outline of new 3D survey being acquired 2H15
Cretaceous sand channel systems
Brazil Focus Basin
• Strong analogies with West African Tano basin discoveries
• Proven light oil petroleum system
• Multiple play types
• Attracted supermajors to make significant operational commitments
Opportunity
• Position in 3 Licences provides dominant position in basin
• 3 wells drilling late 2017/18
• Premier coordinating rig-share
• 3D seismic survey 50% complete
Mean gross unrisked resource
> 2 bn bbls
November 2015 | P24
Mexico – low cost entry
Strong partnership
Proven but under-explored
hydrocarbon basin
Low cost entry
November 2015 | P25
Block 2 • Primary target – 100 mmbbls • 3 follow on prospects of c. 80-100 mmbbls each
Block 7 • Primary target – 130 mmbbls • 4 follow on prospects of
c. 40-150 mmbbls each
Block 2
Salt stock
Closure
Miocene Depth Structure Map – Poblano Prospect
Low cost entry to high quality acreage • Awarded 10% in Blocks 2 & 7,
shallow water Sureste Basin • Option to increase interest to
25% prior to drilling • Numerous leads in established
and emerging plays • Fully carried to first well on each
block
2015/2016 exploration drilling schedule
November 2015 | P26
All well timings are subject to revision for operational reasons
Finance
Strong cash flows in 2015 1H
6 months to 30 June
2015
6 months to 30 June
2014
Working Interest production (kboepd) 60.4 64.9
Entitlement production (kboepd) 55.7 59.7
Realised oil price (US$/bbl) - post hedge 83.7 107.9
Realised gas price (US$/mcf) - post hedge 7.2 9.1
$m $m
Cash flow from operations 570 609
Taxation (57) (110)
Operating cash flow 513 499
Capital expenditure (518) (506)
Disposals 83 -
Finance and other charges, net (49) (49)
Dividends - (44)
Share buy back - (33)
Net cash in (out) flow 29 (236)
Capital expenditure ($m) Comprises $49m from the Block A Aceh sale and ~$34m positive adjustment from Scott area disposal Liquids hedging
1H 2015 2H 2015 2016
Barrels hedged
2.7 m 2.85 m 3.65 m
Average price ($/bbl)
$103 $92 $68
2015 1H FY 2015 E
Exploration $115 $240
Development $403 $900
Total $518 $1,140
November2015 | P28
0
500
1000
1500
2014 2015F 2016 2017 2018
Committed capex ($m)
Exploration
P&D Capex
Significantly reduced costs
November 2015 | P29
30% reduction in opex
• Sale of Scott area
• Renegotiation of contracts
• Operating efficiencies
• Lower insurance & fuel costs
• Reduced headcount
• Contractor rate cuts
0
100
200
300
400
500
FY 2014 (actual) 2015 initialbudget (Oct 14)
2015 finalbudget (Feb 15)
2015 forecast(Aug 15)
Opex ($m)
0
50
100
150
200
250
300
350
FY 2014(actual)
2015 initialbudget(Oct 14)
2015 finalbudget(Feb 15)
2015forecast(Aug 15)
Gross G&A ($m)
2015 1H: $14/bbl opex
Significantly reduced
capex commitments
from 2016
Forecast
Actual
Forecast
Actual
6 months to 30 June 2015
$m
6 months to 30 June 2014
$m
Sales and other operating revenues 577 885
Cost of sales (684) (646)
Gross profit/(loss) (107) 239
Exploration/New Business (52) (50)
General and administration costs (8) (13)
Disposals - (84)
Operating profit/(loss) (167) 92
Financial items (48) (41)
Profit/(loss) before taxation (215) 51
Tax credit/(charge) (160) 122
Profit/(loss) after taxation (375) 173
Income statement
Operating costs ($/boe)
* excludes insurance receipts of $4.7m
Cost of sales breakdown
2015 1H 2014 1H
UK $28.8 $34.9
Indonesia $8.9 $10.1
Pakistan $3.2 $2.7
Vietnam $10.1* $15.5
Group $13.7 $18.5
Profit before tax and impairments 171 195
November 2015 | P30
0
250
500
750
Operatingcosts
Stockunderlift
Royalties DD&A Impair-ment
Cost ofsales
Non-cash items
$3.3 bn of UK tax losses and allowances
Liquidity and balance sheet position
At 30 June 2015
$m
At 31 Dec 2014
$m
Cash 372 292
Bank debt (1,482) (1,230)
Bonds (753) (955)
Convertibles1 (230) (229)
Net debt position (2,093) (2,122)
Covenant headroom $417 $700
Gearing2 59% 53%
Cash and undrawn facilities 1,446 1,940
1 Maturity value of US$245 million 2 Net debt/net debt plus equity
Average debt costs of 4.7% (fixed) and 2.2% (floating)
Net debt/ EBITDAX Old covenants Amended covenants
November 2015 | P31
307 362
1238
558
0
200
400
600
800
1000
1200
1400
2015 2016 2017 2018 2019 2020-2024
Drawn debt maturities ($m)
0
1
2
3
4
5
20151H
2015FY
20161H
2016FY
20171H
2017FY
End 2014 2P reserves and resources
November 2015 | P32
Falklands Indonesia Mauritania Norway Pakistan UK Vietnam Total
2P
On Production – 33.7 0.4 – 16.3 26.5 26.0 102.8
Approved for Development
– 10.5 – – – 74.2 1.4 86.1
Justified for Development
– 29.1 – 23.2 – 2.2 – 54.4
Total Reserves – 73.3 0.4 23.2 16.3 102.8 27.3 243.3
2C
Development Pending
98.0 – 3.1 37.5 0.6 0.1 – 139.3
Development Unclarified / on hold
142.0 170.8 3.6 5.1 3.0 16.9 7.4 348.7
Development not viable
33.8 4.5 1.3 2.4 – 18.2 2.2 62.4
Total Contingent Resources
273.7 175.4 8.0 45.0 3.6 35.1 9.6 550.5
Total Reserves + Contingent Resources
273.7 248.7 8.4 68.2 19.9 137.9 36.9 793.8
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
November 2015