Investor Presentation January 2018

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.

January 2018 | P1

Executive Summary

2017 – a year of strong delivery

Production

2017

Production 75.0 kboepd, in line with guidance

Cost Base

2017

Opex of $16.5/boe; FY capex $305m below revised guidance

Disposals

2017

Wytch Farm completed; Pakistan and ETS pipeline sales announced

Catcher

2017

First oil delivered on 23 December. On schedule and c30% below budget

Tolmount

2017

HoT signed with infrastructure partner; draft FDP submitted to OGA

Sea Lion

2017

Negotiating funding packages; LOI signed with contractors

Exploration

2017

World class oil discovery at Zama-1, Mexico

Net Debt Reduction

2017

Positive cash flow in the year; deleveraging underway

2018 Target

Guidance 80-85 kboepd (Catcher ramp up and 2017 disposals)

2018 Target

FY guidance of opex c$17-18/boe and capex (ex-Abex) of $300m

2018 Target

Complete Pakistan and ETS sales; other processes ongoing

2018 Target

Deliver production ramp up to 60,000 bopd; complete wells

2018 Target

Progress for FID in 2018

2018 Target

Progress financing, fiscal and commercial initiatives

2018 Target

Appraise Zama in H2/early 2019 and define development plans

2018 Target

Generate positive net cash flow and target debt reduction to 3x Net Debt/EBITDA

January 2018 | P3

Production overview

Largest 5 fields account for c. 70% of production

January 2018 | P4

Development portfolio

>800 mmboe of discovered

but undeveloped reserves and

resources

January 2018 | P5

Delivering on our strategy

• Opportunistic acquisitions

• c$16/bbl

• Operated

• FPSO’s

• Partner-funded

• Proven basins

• Under drilled

• 75 kboepd

Value

Stakeholder Returns

Debt Reduction

• Disposals – realising value

Production

Costs

Development Exploration

Portfolio Management

Acquisitions

January 2018 | P6

Future plans

Balance Sheet Management

Value

Stakeholder Returns

Debt Reduction

Production

Operating Costs

Development Exploration

• $17-$18/bbl

• Catcher

• Tolmount

• Sea Lion

• Zama

• Tuna

• High value, near field

• Material upside in Mexico and Brazil

• Continuing growth

• Reserve life >10 yrs

• Free cash flow 2018-2022 reducing debt

• Net debt : EBITDA <3x

Portfolio Management – Acquisitions

• Disposals by majors

• Tax optimisation

Portfolio Management – Disposals

• Non core assets

• Mitigating risk

January 2018 | P7

Producing Portfolio

Chim Sáo, Vietnam (53.125%, operator)

20P 5IPST1

2017 • 14.9 kboepd • High operating efficiency and strong

reservoir performance • $9/boe operating cost • 2 infill wells completed; 6,500 boepd (gross)

production added

0

5

10

15

20

25

30

35

2016 2017 2018 2019 2020

CurrentPrevious

Improved Production Profile kboepd (gross)

59 mmboe reserves

remaining

55 mmboe at sanction

57 mmboe produced

to date

January 2018 | P9

Natuna Sea Block A, Indonesia (28.67%, operator)

2017 • 12.9 kboepd, above budget • Singapore demand above take or pay (49%

of GSA vs 47% contractual share) • High operating efficiency • Opex of c.$8.7/boe • Lama development well (WL-5X) tied into

production; producing 20-25 mmscf/d

Outlook • Singapore demand stable • GSA1 market share increasing • BIGP first gas 2019

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NSBA Production net to PMO (kboepd)

Market Share GSA1 (%)

BIGP

30% IRR

93 Bcf

$340m gross capex

January 2018 | P10

Huntington, Central North Sea (100%, operator)

2017 • 13.0 kboepd, 28% above budget

− High FPSO operating efficiency − Strong reservoir performance − HoT agreed on lease extension

and extended Shell term deal

Outlook • Maximise production

Currently producing ~13 kboepd

January 2018 | P11

Solan, West of Shetlands (100%, operator)

2017 • 5.9 kboepd • Central reservoir on prognosis; Eastern area of field under-performing

Outlook • P1 producing steadily on free flow • P1 workover deferred • Options to improve production being

evaluated; potential infill well 2019

P1

W2

P2

W1

500m

Top Solan Sand Depth Map

January 2018 | P12

Elgin-Franklin, Central North Sea (5.2%)

2017 • 5.4 kboepd • Low opex of c.$8/boe

Outlook • Long field life; production forecast

to continue until 2037 • 350 mmboe remaining reserves • Ongoing infill drilling, well

intervention programme and exploration upside

January 2018 | P13

Portfolio Potential

September 2017 | P15

Catcher – first oil achieved 23 December

• Arrived in North Sea in October

• Hook up and Commissioning programme executed in c. 2 months

• First Oil from Catcher field achieved 23 December and from Varadero on 12 January

• Phased ramp up of production underway

• Important cornerstone of Premier’s debt reduction

• All 12 wells planned pre-first oil completed confirming good quality oil

• Subsea activities complete including short campaign to support hook-up and commissioning operations post arrival of FPSO

Project capex down 29% on sanction

January 2018 | P15

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

Dai

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il P

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nti

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Catcher Varadero Burgman

Catcher Final Commissioning & Production Profile

• Catcher is the initial field on production due to it’s ability to produce oil in a stable fashion for the first stages of the FPSO plant commissioning

• Each field will be brought on in the following manner – Well clean up (initial clean up restricted by rig surface equipment) – Well test through the subsea multi-phase meters – Restricted rate to manage gas rates through commissioning period

• Following gas train commissioning completion and the introduction of Burgman fluids the plant will be run at 60 kbopd

Fuel Gas

Import

Catcher First Oil

Oil Stabili- sation

Fuel Gas

Varadero First Oil

Permeat. Comp

Water Injection

Gas Lift

Gas Export Comm.

Burgman First Oil

Flash Gas

Comp

Primary Gas

Handling

Produced Water

January 2018 | P16

Improved production profile anticipated

Catcher – continuing positive drilling results

• 14 wells completed to date

– 4 on each of Catcher, Varadero and Burgman fields planned pre first oil

– Phase 2 drilling on Catcher underway

• Good test results:

– Net pay encountered by the 8 production wells > 30 % longer than forecast

– Initial production delivery rate per well >40% higher than predicted on average

• Improved production profiles anticipated of c.60 kboepd

• Review of FPSO capacity underway

Varadero

Catcher

Burgman

Plateau production up 20% on sanction

January 2018 | P17

Tolmount – infrastructure partnership

• Partnership with Dana Petroleum and CATS Management Ltd (1)

• Dana and CML will jointly own: – platform – export pipeline

• Tolmount gas will use the facilities – LoF tariff

• Premier’s share of project capex $100m

• Premier retains 50% equity interest in the licence

• Excellent project economics – IRR >50% at gas price of 30p/therm

Estimated Tolmount Capex (Gross) $m

Development Scope Gross Capex (Real, $mm)

% pre 1st gas

Platform 90 100%

SURF (20” pipeline to beach) 100 100%

Host Terminal modifications 150 85%

Drilling (2) 140 64%

PMT 70 92%

Total 550 -

High return project robust down to low

gas prices

PMO 19%

Dana 50%

CML 31%

Capex Split

(1) an Antin Infrastructure Partners portfolio company (2) Based on plan where one well is on-stream pre-1st gas January 2018 | P18

Tolmount – progressing on schedule for FID in 1H 2018

• Initial phase: targeting 540 Bcf resources

• Peak production capacity 300 MMscfd

• FEED contracts awarded; engineering underway

• Evaluation of proposals received for major project scopes (including platform and pipeline) underway

• Draft FDP submitted to OGA

• Timing: – FID 2018 – First gas 2020

Subsurface Depletion Plan • 4 initial development wells in Tolmount • Future phases TE , TFE & Mongour Offshore Facilities • NUI platform with 6 slots / 4 wells • Offshore PWT treatment • Riser / J-tube pre-investment for area development • 20” x 48kn Gas Export pipeline • 3” MeOH (and CI) import pipeline Host Terminal • Dimlington host • New reception & condensate processing • Shared gas processing & compression

Perenco Dimlington SNSPS (Cleeton / Ravenspurn) West Sole (connected to Perenco Easington) Tolmount

Centrica Easington Rough & York

Dimlington Terminal >1 bcf gas processing capacity, 600 mmscfd installed compression capacity plus additional condensate processing

Tolmount

Gassco Langeled Ormen Lange

January 2018 | P19

Tolmount – future phases planned

Tolmount East • Subsea tie-back or small platform • 2019 well planned to confirm resource

Tolmount Far East • Subsea tie-back or small platform to

Tolmount or Tolmount East

Mongour • Subsea tie-back or extended reach

well from Tolmount East

3rd party business potential • A new hub with 20+ year life

Tolmount

Mongour

Tolmount East

Tolmount Far East

Tolmount area

~ 1 Tcf

Indicative production profile

42/28d-12 NE SW

Tolmount Tolmount East

Tolmount Far-East

Gas water contact

January 2018 | P20

ENSCO 8503

Flat Spot

• Major hydrocarbon discovery in shallow water, offshore Mexico

• Initial gross oil in place estimates are 1.2 – 1.8 Bnbbls (unrisked P90-P10 resources of 400-800 mmboe), exceeding pre-drill estimates

• Contiguous gross oil bearing interval of over 335m, with over 200m of net oil bearing reservoir

• Light oil : 28-30° API

Full stack reprocessed seismic data in depth

E W Zama-1 Well

Good conformance of seismic amplitude with structural contours

Zama-1 oil discovery - volume estimates

Gross oil bearing interval to scale

January 2018 | P21

Potential to leverage Mexican fabrication capability

Zama – illustrative development scenario

Location of Zama discovery

Indicative development metrics

Resources 400-800 mmboe1

Daily peak production 100-150 kbopd

Capex +/- $1.8 billion

Appraisal 2018-19

First oil 2022-23

Block 7 prospect map

Zama

(1) Including the extension onto the neighbouring block

Amoca

Zama

Hokchi

January 2018 | P22

Project status • FEED substantially completed • Breakeven reduced to c$45/bbl

− Capex to first oil reduced to $1.5bn − Field opex reduced to $15/bbl − Indicative FPSO cost of $10/bbl (LoF)

• LOIs signed with contractors

Outlook • Positive commercial and fiscal

engagement with FIG • Positive engagement with contractor

market and senior debt providers • Licence extension to May 2020

Sea Lion, Falkland Islands (60%, operator)

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Years from first production

Phase 2Phase 1

January 2018 | P23

Tuna, Indonesia (65%, operator)

Highlights • Discovered in 2014 by the Singa

Laut-1 and Kuda Laut-1 wells >90 mmboe • Evaluation of potential development

scenarios ongoing • Government agreement signed with

Vietnam and Indonesian governments re: connection to existing infrastructure in Vietnam

• Granted 3 year extension to exploration period of licence

January 2018 | P24

Ceara Basin, Brazil – exploration

• Largest acreage holder in the Ceara basin

• 4,000 km2 of fast-track seismic data across all 3 blocks received in 2016

• Final depth migrated broadband seismic data received in April 2017

• Well locations to be selected during 2017

• Licence extensions received for all 3 blocks

• Drilling operations planned for 2019

CE-M-661 CE-M-665

CE-M-717

Excellent imaging on new broadband seismic of Upper Cretaceous turbidite channel sands

Maraca K40

Ganza K40

Pecem K40

Berimbau Up-dip pinch out and fault offset

Berimbau

Pecem K50 discovery

1-CES-158 1-CES-112 SW NE

CE-M-717

Data Proprietary to PGS Investigacoa Petrolifera Limitada 8km

January 2018 | P25

Financials

Net debt and hedging

Drawn Debt Total Facilities(incl cash)

Cash & Undrawn

$4.0 bn Facilities confirmed 1

$3.4 bn

0

1,000

2,000

3,000

4,000

2017 2018 2019 2020 2021 2022

Previous

Revised

Maturities extended 1

1 FX as at when facilities entered into

Net debt

• Net debt of $2.7bn

• Positive cash flow in 2017 including disposals; debt reduction accelerating as Catcher production ramps up

• Average cost of debt c7% going forward

• Targeting Net Debt/EBITDAX <3x by end 2018

Comprehensive refinancing completed

Other key amended terms • Covenant profile re-set with headroom • Enhanced economics (~1.5%) to lenders • A warrant package to lenders • Convertible bond re-priced • Corporate governance controls

January 2018 | P27

Liquids and UK gas hedging as at 31 December

• 40% of 2018 oil production hedged:

• 10% with options, floor price $55/bbl

• 30% swaps and fixed term sales, average price $57/bbl

• 24% of 2018 UK gas production hedged at 47p/therm

Capex

2014-2017

• Reduced from over $1.0bn pa. to $305m in 2017

• Reduced forward commitments

2018-2020

• Maintain at current run rate depending on new projects

• Disciplined approach to capital allocation

Operating Costs

2014-2017

• Down from c$20/boe to c$16/boe

• Over $300m of absolute cost savings delivered since 1/1/2015

2018-2020

• Stable operating cost base at current levels $17-18/boe

Net debt

2014-2017

• Increased due to investment and weakness in oil price

• Reducing by end 2017

2018-2020

• Leverage ratio below 3.0x and falling

• Priority remains reduction in absolute levels of net debt

Portfolio management

2014-2017

• Over $350m realised from disposals

• Significant value created through E.ON acquisition

2018-2020

• Further disposals to accelerate deleveraging

Financial outlook

January 2018 | P28

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

January 2018