Premier Oil Q3 2014 Presentation

1. Investor Presentation
November 2014

2. 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.
November 2014 | P2

3. Building on our track record and
delivering our short term targets
Government approval received from DECC
Production guidance
58-63 kboepd
Catcher sanction
Refinance 2015 bank
facility
Exploration
Disposal programme
Solan on-stream
Sea Lion progress
November 2014 | P3
~4 kboepd above guidance
Dua, GSA5, Kyle, Pelikan
and 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

4. Production

5. Production – higher operating efficiency
Production (kboepd) Production (kboepd)
25
20
15
10
5
20
15
10
5
November 2014 | P5
Vietnam
• ChimSáo achieved
25 mmbblsmilestone
• Dua on-stream
20
15
10
OE
71% OE
5
70%
Indonesia
• GSA1 market share 45%;
above contractual share
of 39.4%
• Additional 40 Bbtudvia
domestic swap agreement
• Naga on-stream
20
15
10
5
0
2013 2014 ytd
0
2013 2014 ytd
Group
• Improved operating
efficiency
• Higher liquids
production
• Growing cash flows
70
60
50
40
30
20
10
0
Guidance
2013 2014 ytd
ytd 2014
average:
64.0
kboepd
North Sea
• Strong performance from
B-Block and Wytch Farm
• Higher production from
Huntington and Rochelle
0
2013 2014 ytd
Pakistan
• In-line with expectations
• New Kadanwariwells
brought on-stream
• Bhit compressor project
underway
0
2013 2014 ytd
OE
75%
OE
83%
OE
64%
Production (kboepd) Production (kboepd)
OE
83%
OE
90%
OE
95%
OE
96%
OE
96%

6. ChimSáo – significant operational improvements
Operating efficiency improved from 70% in 2013 to c. 83% ytd 2014
November 2014 | P6
Persons on board
Dua on-stream Boilers upgraded increased
Operations
improvement
project
Additional diesel
generators installed

7. Balmoral –
improving operating efficiency & delivery capacity
November 2014 | P7
Production ytd 2014 up c. 30% on 2013
Operations
improvement project
Power generators
recommissioned
Reinstatement
of wells
>1 million
man-hours
without a
LTI

8. 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-Pay
HSFO – High Sulphur Fuel Oil
DCQ – Daily Contracted Quantities
November 2014 | P8
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

9. Development

10. 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
Progressing
phased,
lower capex
solution
November 2014 | P10
Future
growth
potential
Monetising
high value
UK tax pool

11. Solan – offshore installation complete
November 2014 | P11
Hook up
completed;
commissioning
underway
Subsea tank,
jacket and
topsides
installed
Good flow
rates
achieved at P1
and W1
completed

12. Catcher – execution phase progressing to schedule
November 2014 | P12
Drilling
• Contract awarded to Ensco
• Commence mid-2015
• 14 producers, 8 water
injectors
Model tank
testing
successful
Mooring
site survey
completed
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
Fabrication
commenced

13. Catcher – look ahead
• Experienced project team
– >250 years project delivery experience across
Carnaby
discovery
FPSO and SURF
design and fabri-cation
commences
Formal concept
select
leadership team
Burgmanand
Varadero
discoveries
Acquired acreage
as part of Oilexco
Catcher discovery
November 2014 | P13
Bonneville
discovery
FPSO and SURF
HUC
DECC approval
Increased interest
to 50% following
EnCore acquisition
• 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
Development
drilling
2009-2011 2012 2013 2014 2015 2016 2017 2018
SURF
installation
Exploration
First
oil
Today

14. Bream – development plan outlined
Key milestones
• Concept select
• Award FEED
• Investment decision
– year end
November 2014 | P14
Development plan:
• Focus on Bream
• Mackerel and
exploration
upside
Capex ~$1bn
40 mmbbls
Robust project
economics

15. 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

16. Exploration

17. Exploration drilling schedule
All well timings are subject to revision for operational reasons
November 2014 | P17

18. Indonesia –Tuna
November 2014 | P18
Development
concepts under
evaluation
Kuda Laut/Sing Laut
Structure Map
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

19. 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
Anza Basin
All 10 wells drilled
have oil / gas shows
Badada-1
~Base Quat
Mid Neog
Base Neog
Mid Paleog
Albertine Basin
2.5 Bbbls discovered in
A B
Tertiary fields
Lokichar Basin
2 Bbbls discovered in
Tertiary fields
A
B
Look-a-like plays
to those proven
in Albertine and
Lokichar Basins
November 2014 | P19
Muglad Basin
4 Bbbls discovered in
Cretaceous fields

20. 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

21. North Falklands Basin –
a proven, well calibrated petroleum system
Mature oil source kitchen area
Brown = oil
generating
source rock
50km
F3 reservoir distribution
Basement structure
Blue = Deep
Red = Shallow
Sea Lion
and satellites
Chatham
Jayne-East
Zebedee
Isobel-Deep
November 2014 | P21

22. North Falklands Basin –
2015 drilling: potential for up to 2.1 Bbbls
Jayne East
• Low risk / high value prospect
• Adds 23-73-232 mmbbls1 to
Phase 2
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
Zebedee
1. SL western
gas cap
app.
2. Extend F2
play south
3. Deepen
play into
F3
4. Prove-up
southern
area
(mmbbls) Discovered
Isobel
Deep
Jayne
East
Most likely
prospective
Chatham
Isobel Deep
• Designed to derisk un-drilled
Southern Area of PL004
1 Volumes quoted are gross • 55-243-933 mmbbls1
unrisked prospective resources
Upside
prospective
Phase 1 308 387 448
Phase 2 87 325 751
Phase 3 - 243 933

23. Indonesia – Lama
>1 TCF
gross
prospective
resource on
block
October 2014 | P23
Anoa DDeeeepp
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
AnoaWest
Ratu Gajah East
Prospect Kuskus Lead

24. UK – Bagpuss/Blofeld
>2 Bbbls
gross
STOIIP
November 2014 | P24
• 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

25. Brazil – Ceará Basin
• Potential pre-drill
farm down to
manage capital
exposure
• Two well
commitment; first
well likely 2017
November 2014 | P25
Under-explored
emerging plays
in a proven
rift basin
33DD sseeiissmmiicc
being
acquired in
2015
PecemDiscovery
• Discovered by Petrobras
in 2012
• Largest structure in basin
• Gross STOIIP range 250 –
1500 mmstb

26. Finance

27. Increasing profitability
6 months to
30 June 2014
6 months to
30 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
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

28. 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 ($17.5 million)
disposals to complete in 2H 2014
Strong, rising cash flows
6 months to
30 June 2014
US$m
6 months to
30 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

29. Liquidity and balance sheet position
November 2014 | P29
At
30 June 2014
$m
At
31 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$245 million
2 Net debt/net debt plus equity
Drawn debt maturity profile (including
Letters of Credit)
700
600
500
400
300
200
100
-
US$ millions
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

30. Premier Oil Plc
23 Lower Belgrave Street
London
SW1W 0NR
Tel: +44 (0)20 7730 1111
Fax: +44 (0)20 7730 4696
Email: premier@premier-oil.com
www.premier-oil.com
November 2014