Premier Oil Results 2014

1. 2014 Annual Results
Presentation
26 February 2015

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.
February2015 | P1

3. Agenda
Introduction
Indonesia
Vietnam
Falkland Islands
Finance
Outlook
Tony Durrant
Roberto Lorato
Phil MacLaurin
Neil Hawkings
Richard Rose
Tony Durrant
February2015 | P2

4. 2014 achievements
Government approval received from DECC; project execution
underway
Production guidance
58-63 kboepd
Catcher sanction
Refinance 2015 bank
facility
Exploration
Disposal programme
Solan on-stream
Sea Lion progress
63.6 kboepd, record production and above upper end of
guidance; significantly improved operating efficiency
Refinanced on improved terms; facility increased to $2.5bn
>100 mmboeTuna discovery
$190m of non-core asset
sales completed
Further disposals anticipated
Facilities successfully
installed
First oil following completion
of commissioning programme
<$2bn capex solution being
progressed
Farm down process on-going
February2015 | P3

5. Solan project status
• Tank, jacket and topsides installed September 2014
• Initial drilling phase and subsea work completed October 2014
• Mechanical completion and commissioning adversely affected by
weather (December – February)
• Subsea work to tie-in P1 and W1 scheduled for March
• Optimising use of flotel/rig capacity to complete remaining work scope
• Drilling rig contracted for P2 and W2 programme
February2015 | P4
Targeting
plateau rate of
20-25 kbopd
by year-end

6. Indonesia
Roberto Lorato
Indonesia Business Unit Manager

7. Indonesia – strategically positioned
2014 highlights
•Naga on-stream
•Domestic gas sales
commenced
•>100 mmboeTuna
discovery
•Exited BlockA Aceh
GSA2
Domestic Gas Swap
GSA1
Growing
domestic
market
February2015 | P6

8. Natuna Sea Block A (NSBA) –
high performing cash generator
Opex
• Targeting opex of $9/boe
Revenue
• 14.4 kboepd in 2014; 45% share of GSA1 above
contractual share of 39.4%
• Take or pay contracts
• PSC regime
• 20% of 2015 Indonesian gas hedged at $90/boe
Cash flow
• 2014 net operating cash flow of $170m
Low capex
• Re-phasing discretionary spend
• $40m in 2015
96%
operating
efficiency
Record
cash flow
in 2014
February2015 | P7

9. Singapore gas market outlook
1800
1600
1400
1200
1000
800
600
400
Source IHS
BBtud
Singaporedemand
Contractedpipeline
naturalgas
Total contractedgas
Un-contracted
demand
2015-2019
• Protected by take or pay
• Increasing share of GSA1
~60% of GSA1 remaining
reserves on NSBA
2020+
• Opportunity to meet
excess Singapore
demand
February2015 | P8

10. Future growth options
Pelikan
• 75 bcf reserves
• First gasApril 2015
Lama play
• >1 tcf prospective
resource
• First gas mid-2015
Bison, Iguana,
Gajah Puteri
• >100 bcf reserves
• First gas 2018+
Tuna
• >100 mmboe
• On-stream 2020+
Illustrative Indonesia production profile
Portfolio of
growth
opportunities
February2015 | P9

11. Vietnam
Phil MacLaurin
Vietnam Business Unit Manager

12. 2004 – 2007
(Discovery and Appraisal)
2008 – 2011
(Development)
Leveraging
regional
knowledge
Chim Sáo,
Dua extension
& CRD discovered
Acquired
additional 25%
for $75 million
Facilities
installed
Cost savings
of $130 million
Chim Sáo
development
sanction
Development
drilling
Improved
operating
efficiency
Dua
on-stream
2012 –
(Production)
Acquired
37.5% in Block 12
for $6 million
Chim Sáo
on-stream
Sold CRD for
$45 million
Nam Con Son Basin – a full cycle success story
February2015 | P11

13. Block 12w high performing cash generator
Cash flow
• 2014 net operating cash flow of >$300 million
Low capex
• No committed capex
Opex
• $15/boe planned for 2015
Revenue
• Production >20 kboepd (net) 2015 ytd
• PSC regime
• Premium to Brent
84%
operating
efficiency
Record
cash flow
in 2014
February2015 | P12

14. Growth opportunities to sustain production
Main field
Exploration
prospects
Satellite
drilling to
prove
additional
resources
Infill
drilling for
improved
recovery
Acid
stimulation
to increase
flow rate
Incremental production potential
February2015 | P13
0
5
10
15
2017 2018 2019 2020 2021 2022 2023
Infill
Satellites

15. Falkland Islands
Neil Hawkings
Falkland Islands Business Unit Director

16. Before…TLP for Phase 1
TLPTLPFSOFSOShuttle
tanker
Shuttle
tanker
ChathamChatham
Phase 2Phase 2
ZebedeeZebedee
Jayne EastJayne East
Additional
prospective
resources being
drilled in 2015
February2015 | P15

17. Sea Lion development reconfigured
• Phased development of at least 400 mmbbls
• Phase 1a will develop the north east of PL032
– 160 mmbbls using a leased FPSO
• Aim to take advantage of weaker supplier market during
2015 2H
• Option to sanction in 2016 1H
• Subsequent phases (1b and 2) will depend on the results
from the exploration programme and learnings from 1a
February2015 | P16

18. Now… Phase 1a
Subsea
drill centre
Subsea
drill centre
FPSOFPSO
Shuttle
tanker
Shuttle
tanker
ChathamChatham
ZebedeeZebedee
Jayne EastJayne East
• 14 development wells
– 8 producers
– 5 water injectors
– 1 gas producer / injector
– 9 pre-drilled
• 160 mmbbls over 15 years
February2015 | P17

19. Phase 1a facilities
Subsea drill centreSubsea drill centre
FPSOFPSOShuttle tankerShuttle tanker
8 well
production
manifold
8 well
production
manifold
5 well
water injection
manifold
5 well
water injection
manifold
Flowline to
gas well
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
PotentialPotential
for cost
reductions
in 2015
Cost reductions
expected
• Drilling
• Subsea
• Fabrication
February2015 | P18

20. Carry arrangements renegotiated
• Development carry remains $722m
– $48m expended to October 2014, RKH now paying 40% of costs until sanction
– 50% of remaining carry will apply to Phase 1a, 50 % to the next phase
• Standby financing
– Original standby financing cancelled, now a simple standby loan
– Permitted uses are development capex and guarantee fees
• Guarantee fee mechanism for capex remains
– Now extended to include FPSO contract
• Exploration carry
– Full $48m exploration carry available for use on upcoming campaign
• Letter ofAgreement signed, full documentation being progressed
February2015 | P19

21. North Falklands Basin –
2015 drilling: potential for up to 2.1 Bbbls
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 23-73-232mmbbls1 to
Phase 2
Isobel Deep
• Designed to de-risk un-drilled
SouthernArea of PL004
• 55-243-933 mmbbls1
1 Volumesquotedare gross
unriskedprospectiveresources
(mmbbls) Discovered
Most likely
prospective
Upside
prospective
Phase 1 308 387 448
Phase 2 87 325 751
Phase 3 - 243 933
Zebedee
Isobel
Deep
Jayne
East
Chatham
1. SL western
gas cap
app.
2. Extend F2
play south
3. Deepen
play into
F3
4. Prove-up
southern
area
• Phase 1 includes the initial
field development of
160mmbbl; subsequent
phases will be sanctioned
post first-oil
February2015 | P20

22. Finance
Richard Rose
Finance Director

23. Capital expenditure ($m)
Excludes $49m from the BlockAAceh sale
and ~$30m positive adjustment fromScott
area disposal whichwillbe received inQ1 2015
Liquids hedging
Cash flows
12 months
to 31 Dec
2014
12 months
to 31 Dec
2013
Working Interest production (kboepd) 63.6 58.2
Entitlement production (kboepd) 57.7 52.4
Realised oil price (US$/bbl)- pre hedge 98.2 109.0
Realised gas price (US$/mcf) - pre hedge 8.4 8.3
US$m US$m
Cash flow from operations 1,133 1,031
Taxation (209) (223)
Operating cash flow 924 803
Capital expenditure (1,196) (878)
Partner funding (Solan) (318) (186)
Disposals 131 61
Finance and other charges, net (120) (91)
Dividends (44) (40)
Share buy back (93) -
Net cash out flow (716) (331)
1H 2015 2H 2015 2016
Barrels
hedged
2.7 m 2.85 m 1.2 m
Average price
($/bbl)
$103 $92 $67
February2015 | P22
2013 2014 2015
Exploration $207 $165 $220
Development $658 $1,017 $700
Other $14 $14
Total $878 $1,196 $920

24. 12 months to
31 Dec 2014
US$m
12 months to
31 Dec 2013
US$m
Sales and other operating revenues 1,629 1,540
Cost of sales (1,771) (1,035)
Gross profit (142) 505
Exploration/NewBusiness (84) (136)
General and administration costs (25) (20)
Operating profit (251) 349
Disposals 3 4
Financial items (136) (68)
Profit before taxation (384) 285
Tax credit/(charge) 174 (51)
Profit after taxation (210) 234
Income Statement
Operating costs (US$/boe)
* Includes one-offcredits totalling $20m
Cost of sales breakdown
2013 2014
UK $43.3 $37.2
Indonesia $10.9 $10.0*
Pakistan $2.5 $3.3
Vietnam $20.9 $14.6*
Group $19.7 $18.5
February2015 | P23

25. Liquidity and balance sheet position
At
31 Dec 2014
$m
At
31 Dec 2013
$m
Cash 292 449
Bank debt (1,230) (686)
Bonds (955) (992)
Convertibles1 (229) (224)
Net debt position (2,122) (1,453)
Covenant headroom $700 $1,110
Gearing2 53% 41%
Cash and undrawn facilities 1,940 1,600
1 Maturityvalue of US$245 million
2 Net debt/netdebt plus equity
Drawn debt maturity profile – 31 Jan 2015
(excluding Letters ofCredit)
Average debt costs of 4.7% (fixed) and 2.1%
(floating)
February2015 | P24

26. Re-setting the cost base
20
18 17
0
5
10
15
20
25
2013 2014 2015 2016 2017
Opex ($/boe)
0
200
400
600
800
1000
1200
1400
2014 2015 2016 2017 2018 2019
Committed capex profile (US$m)
Chrysaor loan
P&D Capex
Focus of cost savings
• G&A 20% reduction in 2015
• Contractor rates cut by 10%
• Contracts review on-going
• Operating cost efficiencies
• Supplier engagement on unsanctioned
projects
Identified expenditure reductions
through 2017
Opex & Royalties $140m
Capex $285m
Exploration $180m
Total >$600m
February2015 | P25

27. Outlook
Tony Durrant
CEO

28. 2015 targets
Reach plateau rate of 20-25 kbopd (gross) by year-end
Production
Solan
Catcher
Sea Lion
Exploration
Finance
Disposals
Maintain operating efficiency levels and meet guidance of
55 kboepd (before Solan)
Maintain project budget and schedule; seek cash savings
Complete FDP preparation ahead of sanction decision 2016 1H
Targeting ~150 mmbbls of net prospective resources
Maintain covenant headroom Cost reductions
Further disposals planned for 2015
February2015 | P27

29. Well financed, low cost producer with
growth opportunities
February2015 | P28
A $10/bbl oil
price recovery
generates c. $150m
of incremental after
tax cash flow
(2016)• Unsanctioned growth projects
• Substantial resource base
• Funding available for acquisitions
Leverage
to oil price
recovery
• Stable production base
• Improving portfolio mix
• Low cost base
• Low commitments
Cash flow
positive at
$50/bbl
from 2016

30. Q&A

31. 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
February 2015