Investor Presentation
November 2014
Forward looking statements
November 2014 | P2
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.
Government approval received from DECC
Building on our track record anddelivering our short term targets
November 2014 | P3
Production guidance 58-63 kboepd
Catcher sanction
Refinance 2015 bank facility
Exploration
Disposal programme
Solan on-stream
Sea Lion progress
~4 kboepd above guidanceDua, GSA5, Kyle, Pelikanand Naga
Refinanced on improved terms; facility increased to $2.5bn
~100 mmboe discovery on Tuna Block; continued licence divestment in UK & Norway; 2015/16 prospects matured
$190m of non-core asset sales announced
On course to achieve$300m target
Facilities successfully installed
First oil following completion of commissioning programme
<$2bn capex solution being progressed
Farm down process on-going
Production
Production – higher operating efficiency
November 2014 | P5
Indonesia• GSA1 market share 45%;
above contractual shareof 39.4%
• Additional 40 Bbtud via domestic swap agreement
• Naga on-stream
0
5
10
15
20
2013 2014 ytd
Vietnam• Chim Sáo achieved
25 mmbbls milestone• Dua on-stream
0
5
10
15
20
2013 2014 ytd
Group
• Improved operating
efficiency
• Higher liquids
production
• Growing cash flows
Group
• Improved operating
efficiency
• Higher liquids
production
• Growing cash flows
0
10
20
30
40
50
60
70
2013 2014 ytd
Guidance
ytd 2014
average:
64.0
kboepd
North Sea• Strong performance from
B-Block and Wytch Farm• Higher production from
Huntington and Rochelle
05
10152025
2013 2014 ytd
Pakistan• In-line with expectations• New Kadanwari wells
brought on-stream• Bhit compressor project
underway
0
5
10
15
20
2013 2014 ytd
OE
75%
OE
83%
OE64%
Production (kboepd)Production (kboepd)
Production (kboepd)Production (kboepd)
OE71% OE
70%
OE83%
OE90%
OE95%
OE96%
OE96%
November 2014 | P6
Chim Sáo – significant operational improvements
Operating efficiency improved from 70% in 2013 to c. 83% ytd 2014
Persons on boardincreasedBoilers upgradedDua on-stream
Operations
improvement
project
Additional diesel generators installed
November 2014 | P7
Balmoral –improving operating efficiency & delivery capacity
Production ytd 2014 up c. 30% on 2013
Operations improvement project
Power generatorsrecommissioned
Reinstatementof wells
>1 million
man-hours
without a
LTI
November 2014 | P8
Indonesia – highest priced gas delivered by pipeline
GSA1• DCQ 341.25 bbtud; 90% ToP
• 15% premium to HSFO
• Contractual share:
– NSBA – 39.4%
– Kakap – 14.5%
– Block B – 46.1%
• Actual market share ytd14:
– NSBA – 45%
• Premier equity:
– NSBA – 28.67% (op.)
– Kakap – 18.75%
• Term – 2029
• Anoa, Pelikan
ToP – Take-or-PayHSFO – High Sulphur Fuel OilDCQ – Daily Contracted Quantities
GSA2• DCQ 90 bbtud; 90% ToP
• 10% premium to HSFO
• Premier 28.67% (op.)
• Term – 2028
• Gajah Baru, Naga
Domestic Gas Swap• Up to 40 bbtud
• Domestic prices
• Replaces GSA3 & GSA4
• Gajah Baru
1H14
average
gas price
~$17/mcf
Development
Development – sustained growth
Catcher (50% op.)• 96 mmboe
• ~50 kbopd at peak
• $2.25bn capex
• IRR >20% ($85/bbl)
Solan (60% op.)• >40 mmbbls
• 24 kbopd at peak
• $1.3bn capex spent to date
Bream (50% op.)• 40 mmbbls
• $1bn capex
• Progressing through
FEED
Pelikan & Naga
(28.7% op.)• Backfill our existing
contracts
• Naga on-stream
Sea Lion Phase 1a
(60% op.)• c. 160mmbbls
• <$2bn capex pre-first oil
• 50-60 kbopd
Increasing
delivery
into
Singapore
November 2014 | P10
Progressing
phased,
lower capex
solution
Future
growth
potential
Monetising
high value
UK tax pool
November 2014 | P11
Solan – offshore installation complete
Hook up
completed;
commissioning
underway
Subsea tank,
jacket and
topsides
installed
Good flow
rates
achieved at P1
and W1
completed
November 2014 | P12
Catcher – execution phase progressing to schedule
Drilling• Contract awarded to Ensco
• Commence mid-2015
• 14 producers, 8 water
injectors
Model tanktesting
successful
Mooringsite surveycompleted
Subsea• EPCI: Subsea 7
• Template: Aquaterra
• Xtree and well production
systems: Dril-Quip
FPSO• Contract awarded to BWO
– 7yrs + options
– BWO financing in place
• Key sub-contracts awarded
– Hull: IHI
– Topsides design: Aibel
– Turret & mooring system: APL
Well sequencing
agreed
Fabricationcommenced
Carnabydiscovery
FPSO and SURF design and fabri-
cation commences
Formal concept select
Burgman and Varadero
discoveries
Catcher – look ahead
November 2014 | P13
Acquired acreage as part of Oilexco
Catcher discoveryBonneville discovery
FPSO and SURF HUC
DECC approval Increased interest to 50% following
EnCore acquisition
• Experienced project team– >250 years project delivery experience across
leadership team • Cost certainty
– Leased FPSO– Lump sum contracts– 95% of contracts awarded or issued for tender
• Future opportunities– Reservoir upside– Bonneville and Carnaby– Exploration wells planned
for 2016
2009-2011 2012 2013 201620152014 2017 2018
SURFinstallation
Exploration
Development drilling
First
oil
Today
November 2014 | P14
Bream – development plan outlined
Key milestones
• Concept select
• Award FEED
• Investment decision – year end
Development plan:
• Focus on Bream
• Mackerel and
exploration
upside
Capex ~$1bn
40 mmbbls
Robust project
economics
Sea Lion – phased, lower capex solution
November 2014 | P15
Subsequent phases
• Phase 1b: recover
remainder of PL032
resource
• Phase 2: recover
resource on PL004
(including satellites and
exploration success)
• Phase 3: determined by
outcome of Isobel Deep
Phase 1a
• Targets north east area
– Reduced well count
(8 Prod. & 5 Inj.)
– 1 subsea drill centre
– c. 160 mmbbls in 15
years
– Plateau rate of
c. 50-60 kbopd
• Likely FPSO solution
• <$2bn (gross) capex
• A 1 year extension to
the FDP submission
date is being discussed
Exploration
Exploration drilling schedule
November 2014 | P17
All well timings are subject to revision for operational reasons
November 2014 | P18
Indonesia – Tuna
Development
concepts under
evaluation
Kuda Laut/Singa Laut Discovery
• Premier 65%
• Oil and liquid-rich gas discovery
• Estimated resource
– 83- 110-160 mmboe
• Plan is to appraise in 2015 , subject to rig
availability
Kuda Laut/Sing Laut
Structure Map
Kenya – Block 2B, southern Anza Basin
• Premier equity 55%
• Play opening test of the Tertiary
• Badada prospect
– Robust closure confirmed by
new 2D
– Premier gross resource
estimate: 13-90-363 mmbbls
(high value barrels)
– Spud late 2014 or
early 2015
A B
Badada-1~Base Quat
Mid Paleog
Base Neog
Mid Neog
Anza BasinAll 10 wells drilled
have oil / gas shows
Albertine Basin2.5 Bbbls discovered in
Tertiary fields
Lokichar Basin2 Bbbls discovered in
Tertiary fields
A
B
Look-a-like plays
to those proven
in Albertine and
Lokichar Basins
November 2014 | P19
Muglad Basin4 Bbbls discovered in
Cretaceous fields
Norway – Mandal High
November 2014 | P20
• Myrhauk well – Q3 2015
– Play opening test
– Robust closure
– Gross prospective resource:
10-50-135 mmboe
• Significant running room
– >500 mmboe unrisked gross
prospective resource
Similar play
elements as at
Utsira High
North Falklands Basin –a proven, well calibrated petroleum system
Mature oil source kitchen area
Brown = oilgeneratingsource rock
50k
m
F3 reservoir distribution
Zebedee
Chatham
Jayne-East
Isobel-Deep
Basement structure
Blue = DeepRed = Shallow
Sea Lion and satellites
November 2014 | P21
North Falklands Basin –2015 drilling: potential for up to 2.1 Bbbls
November 2014 | P22
Phase 1
Phase 3
Phase 2
Chatham• Sea Lion western gas cap
appraisal
• If no gas, adds 60 mmbbls to
Phase 1
• Exploration tail targets
4-19-80 mmbbls1
Zebedee• Low risk / high value prospect
• Targets 61-165-432 mmbbls1
to Phase 2
Jayne East• Low risk / high value prospect
• Adds 23-73-232 mmbbls1 to
Phase 2
Isobel Deep• Designed to derisk un-drilled
Southern Area of PL004
• 55-243-933 mmbbls11 Volumes quoted are grossunrisked prospective resources
(mmbbls) DiscoveredMost likelyprospective
Upside prospective
Phase 1 308 387 448
Phase 2 87 325 751
Phase 3 - 243 933
ZebedeeIsobelDeep
Jayne East
Chatham
1. SL western gas cap app.
2. Extend F2 play south
3. Deepen play into F3
4. Prove-up southern area
Indonesia – Lama
October 2014 | P23
>1 TCF
gross
prospective
resource on
blockDeep Anoa Deep
appraisal
and new 3D
planned for
2015
• Proven by Premier’s Anoa Deep in 2012
– 17 mmscfd
• Identified look-a-like opportunities from
shows in existing wells
Anoa North
Anoa West
Ratu Gajah EastProspect Kuskus Lead
UK – Bagpuss/Blofeld
November 2014 | P24
>2 Bbbls
gross
STOIIP
• Well defined basement high
within the Inner Moray Firth
• Discovery in 1981 proved play
but not cored or tested
• Heavy oil targets located on
the Halibut Horst
Appraisal
well planned
for 2015
Brazil – Ceará Basin
November 2014 | P25
Under-explored
emerging plays
in a proven
rift basin
3D seismic 3D seismic
being
acquired in
2015
• Potential pre-drill
farm down to
manage capital
exposure
• Two well
commitment; first
well likely 2017Pecem Discovery
• Discovered by Petrobras
in 2012
• Largest structure in basin
• Gross STOIIP range 250 –
1500 mmstb
Finance
6 months to30 June 2014
6 months to30 June 2013
Working Interest production (kboepd) 64.9 58.6
Entitlement production (kboepd) 59.8 53.1
Realised oil price (US$/bbl) - pre hedge 109.4 107.2
Realised gas price (US$/mcf) - pre hedge 9.1 8.7
US$m US$m
Sales and other operating revenues 885 758
Cost of sales (646) (472)
Gross profit 239 286
Exploration/New Business (50) (22)
General and administration costs (13) (9)
Operating profit 176 255
Disposals (84) -
Financial items (41) (40)
Profit before taxation 51 215
Tax credit/(charge) 122 (54)
Profit after taxation 173 161
Increasing profitability
Operating costs (US$/bbl)
1H 2014 1H 2013
UK $35.0 $39.0
Indonesia $10.3 $9.4
Pakistan $2.9 $2.6
Vietnam $15.4 $14.4
Group $18.5 $16.0
Includes impairment charge of US$55m
(after tax) for Balmoral area and Huntington
Accounting profit from Scott area and Luno
II disposals will be booked on completion
offsetting recorded Block A Aceh disposal
UK tax credits for small field allowances for
Catcher fields and ring-fence expenditure
supplement
Liquids hedging
2H 2014 1H 2015
% hedged 53% 35%
Average price $103 $106
($/boe)
November 2014 | P27
Capital expenditure ($m)
1H 2014 FY 2014(e)
Exploration $91 $180
Development $415 $1,000
Total $506 $1,180
Will be repaid from enhanced share of
cash flows post first oil
Block A Aceh ($40 million), Scott area
($130 million) and Luno II ($17.5 million)
disposals to complete in 2H 2014
Strong, rising cash flows
6 months to30 June 2014
US$m
6 months to30 June 2013
US$m
Cash flow from operations 609 488
Taxation (110) (117)
Operating cash flow 499 371
Capital expenditure (506) (436)
Partner funding (Solan) (104) (51)
Disposals - -
Finance and other charges, net (48) (49)
Dividends/share buy back (77) (40)
Net cash out flow (236) (205)
Record first
half operating
cash flows
November 2014 | P28
Liquidity and balance sheet position
November 2014 | P29
At30 June 2014
$m
At31 Dec 2013
$m
Cash 255 449
Bank debt (721) (686)
Bonds (997) (992)
Convertibles 1(226) (224)
Net debt position (1,689) (1,453)
Gearing2 43% 41%
Cash and undrawn facilities 1,430 1,600
1 Maturity value of US$245 million2 Net debt/net debt plus equity
Drawn debt maturity profile (including
Letters of Credit)
Average debt costs of 4.8% (fixed) and
2.2% (floating)
Cash and undrawn facilities increased to
$2.7 billion after refinancing in July 2014
-
100
200
300
400
500
600
700
US
$ m
illi
on
s
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 2014
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