2015 Half-Yearly Results 20 August 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.

August 2015 | P1

Agenda

Introduction

UK

Sea Lion

Exploration

Finance

Outlook

Tony Durrant

Stuart Wheaton

Neil Hawkings

Robin Allan / Dean Griffin

Richard Rose

Tony Durrant

August 2015 | P2

2015 1H performance

Above budget and guidance year-to-date driven by 94% operating efficiency

Operating cash flow of $513 million

Production of 60.4 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 into 2H and 2016)

Many initiatives on-going; <$14/boe opex

Reduction in net debt to $2,093 million, despite investments in Solan and Catcher

Renegotiated terms; vote of confidence by banks and bondholders

On track for Q4 first oil from Solan and 2017 from Catcher

Discoveries at Zebedee and Isobel Deep; resource additions at Anoa

Refocusing the exploration portfolio Low cost acreage additions in Brazil and Mexico

August 2015 | P3

UK Stuart Wheaton

UK Business Unit Manager

UK – underlying growth

2015 1H

• Averaged 16.9 kboepd

• Improved operating efficiency

• Opex $29/bbl, down 17% (1H 2014: $35/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

89% 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

August 2015 | P5

Solan – 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)

August 2015 | P6

Potential ullage?

Solan – 2015 1H highlights

• P1/ W1 tied in; P2 drilling

• Improved offshore productivity

• Removed partner funding concerns

• Reduced balance sheet exposure

• Cash spend to end July $1.65 billion

On track for Q4 first oil

August 2015 | P7

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 200-220 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 spudded

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 to spud

Commissioning of production systems

Commissioning of production systems

First oil

56,000 direct hrs to first oil

August 2015 | P8

Solan – drilling and subsea

P1 and W1

• Completed and tied-in

• P1 encountered 1,855 feet of sands

• 10-15 kbopd

• First oil Q4 2015

P2 and W2

• P2 nearing completion

• 3,000 feet of sands targeted

• W2 to spud in September

Field

• Ramp up to 25 kbopd once both producer/injector pairs on-stream

Subsea

• Tank tied in

• Commissioning to complete in September

Top Solan sand depth map

P2 cross-section

250m

500m Pressure

data suggests good

connectivity

W1

P1

W2

P2

Solan seal

Current bit position Solan pay sands

P2 on prognosis

August 2015 | P9

August 2015| P10

Catcher area

Reservoir upside

Near field tie-backs

Exploration upside

No tax

Catcher 5P, 2I

Varadero 4P, 3I

Burgman 5P, 3I

Catcher execution phase progressing

August 2015 | P11

• 96 mmboe (50 per cent, operator)

• $1.6 bn (gross budget to first oil)

• Post ramp up, peak production of c. 50 kbopd

Carnaby discovery

Formal concept select

Burgman and Varadero

discoveries

Acquired acreage as part of Oilexco

Catcher discovery

FPSO and SURF HUC

DECC approval Increased interest to 50% following

EnCore acquisition

2009-2011 2012 2013 2016 2015 2014 2017 2018

Near field exploration

First oil

FPSO and SURF fabrication

commenced

SURF installation

Development drilling

Catcher – FPSO

1H Highlights

• Turret and mooring system progressing

– Mating cone module fabricated and delivered

• Hull fabrication on-going in Japan and Korea

• Topsides fabrication underway in ProFab, Dynamac and Asia Offshore yards

August 2015 | P12

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 to

start in H2 • Fabrication of risers and

jumpers to commence in 2016

August 2015 | P13

Catcher – drilling

September 2014 | P14

CCI2

CCP3

CTP1

CTI1

Template 1

1H Highlights

• Ensco 100 rig on hire since July

• Pilot hole completed

• Batch drilling of 30” & 20” sections of first 4 wells completed

• Operations on schedule and within budget

– Drilling ahead at CTI1

22 wells (14P, 8WI)

Six 4-slot templates

2 phases of drilling on each field

August 2015 | P14

Catcher – CTI1 progress

• Operations on schedule and budget

• Reservoir on prognosis; ‘injectite wing’ and main reservoir found within 7 feet of pre-drill forecast

• Setting production casing and will drill ahead reservoir section seeking ~250 feet net pay in ~600 feet gross interval

Catcher Discovery wells

Tay reservoir

Cromarty reservoir

August 2015 | P15

1.5km to nearest offset well Reservoir encountered on depth

CTI1

Sea Lion Neil Hawkings

SE Asia & Falkland Islands Director

De-risking the Sea Lion development

August 2015 | P17

• 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 are to be selected ahead of FEED

• Financing plans progressing well

• Upside in the area has increased and become better defined

• Stakeholder discussions continuing

Exploration Robin Allan – N. Sea and Expl’n Director

Dean Griffin – Head of 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

August 2015 | P19

2015 North Falklands Basin campaign

2015 1H 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 2H look ahead

• Jayne East (36% op interest) – would add resource to Phase 2

• Chatham (40% op interest) – would add resource to Phase 1b

Beyond 2015

• Additional exploration/appraisal prospects identified for drilling in 2017/2018

Chatham Pmean

47 mmbbls

50 mmbls

Zebedee

Southern exploration

leads

Phase 2 prospects

PL032 prospects

Jayne East Pmean

39 mmbbls

Aim • Demonstrate exploitation potential of F2 • Explore upside potential of F3

Isobel / Elaine

Pmean

400 mmbbls

August 2015 | P20

Jayne East and Isobel Deep

Full stack amplitude at F3G horizon • Jayne East targets northern end of F3 fan sequence and shallower F2 horizons

• Further drilling at Isobel / Elaine complex to confirm significant resource potential of southern F3 fan system (unrisked Pmean 400 mmbbls)

North Falkland Graben

Isobel / Elaine Re-drill Isobel Deep

Jayne East

Zebedee

Jayne East

Isobel Deep

Isobel / Elaine

August 2015 | P21

10Km

Brazil – high quality address

• Limited drilling in the deeper water parts of the northern Brazil basins

• Recent significant discoveries in the Ceará, Potiguar and Sergipe Basins

• Success of West African Transform Margin (WATM) not yet fully tested in Brazilian basin equivalents

• Regional play work to identify sweet spots within high graded basins with proven active petroleum systems

Source IHS/Petroview

WATM Basins Jubilee – 771 MMboe

Baobab – 356 MMboe Enyenra – 200 MMboe

Keta-Togo-Benin Basin Ojo oil discovery

Douala Basin

Rio Muni Basin Ceiba – 264 MMboe

Okume – 107 MMboe Offshore Potiguar Basin

Pitu discovery

Ceará Basin Pecem & 1-CES-161

Barreirinhas Basin 1-MAS-036 gas discovery?

Para-Maranhao Basin Harpia discovery?

Foz do Amazonas Basin

Pernambuco Paraíba Basin

Sergipe-Alagoas Basin Sergipe discoveries (x5)

795 MMboe total

August 2015 | P22

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 3Q15

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

• Dominant position in basin

• Low cost farm-in to 661

• 3 wells drilling late 2017/18

• Premier coordinating rig-share

Mean gross unrisked resource

> 2 bn bbls

August 2015 | P23

Mexico – low cost entry

Strong partnership

Proven but under-explored

hydrocarbon basin

Low cost entry

August 2015 | P24

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

Finance Richard Rose

Finance Director

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 3.5 m

Average price ($/bbl)

$103 $92 $69

2015 1H FY 2015 E

Exploration $115 $240

Development $403 $900

Total $518 $1,140

August 2015 | P26

Significantly reduced costs

August 2015 | P27

30% reduction in opex

• Sale of Scott area

• Renegotiation of contracts

• Operating efficiencies

• Lower insurance & fuel costs

• Reduced headcount

• Contractor rate cuts

0

500

1000

1500

2014 2015 2016 2017 2018 2019

Committed capex ($m) P&D Capex

Exploration

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

August 2015 | P28

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

August 2015 | P29

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

Summary Tony Durrant

CEO

20 19

17

14 16

0

5

10

15

20

2013 2014 2015budget

2015 1H 2015forecast

Outlook

August 2015 | P31

0

500

1000

1500

2014 2015F 2016 2017 2018 2019

P&D Capex

Exploration

• 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.

Illustrative capital allocation @ $60/bbl

P&D committed capex

Cash available for debt reduction

Exploration commitments

Committed capex $m

Opex ($/boe)

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

August 2015