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: premier@premier-oil.com

www.premier-oil.com

November 2015