Premier oil

6th February 2014

CAPITAL MARKETS PRESENTATION

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Falkland Islands’ office fire evacuation

6th February 2014 // Page 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.


Introduction

Premier Today

• Robust cash flow and profitability

• 800 mmboe reserves and resources

• Production of 66 kboepd (January 2014)

• Key exploration campaigns in Indonesia, Norway and Falklands

• NAV >£5 per share (broker consensus)

Going Forward

The Board will:

• Give priority to balance sheet strength

• Focus investments on our highest return projects

• Reduce capital exposure to the Sea Lion project

“...our strategy is to invest in high-quality developments whilst maintaining balance sheet strength...”


Balance Sheet Strength and Flexibility

• Current net debt of $1.45 bn

– Gearing of 41%, well within Board guidelines

• Significant headroom on financial covenants today and going forward

– Cash flow cover at 2x (covenant of <3x)

– Interest cover at 8x (covenant of >4x)

• Excellent access to debt markets

– $700 m raised in Q4 2013 on competitive terms

– Maturities extended (2017 – 2022)

– Zero drawings on existing principal bank facility

• Continuing strong market appetite from debt investors

– Anticipate attractive terms for re-financing during 2014

– Reverse enquiry from investors on MTN programme

– Initial favourable indications from export credit funding markets

Robust balance sheetand funding position


Financial Outlook

• 2014 guidance 58-63 kboepd– Positive start to 2014 production– Changing mix generates higher

cash flows

• Solan, Catcher fields– Add up to 30,000 bopd of valuable

UK barrels– Value per barrel continues to rise

• UK production growth monetises high value UK tax loss position

– Unlikely to pay UK CT until end of decade

Cash Flows (Current Oil Prices)

2013 2014 Post Solan Post Catcher

Averag

e CAGR of

17%

Significant cash flow growth


Prudent Financial Management

• Planning case $85/bbl

• Active disposal programme

• Will seek partner for Sea Lion

• Production base line of 75 kboepd

• Future discretion on exploration and unsanctioned projects (eg Bream)

• >US$1 bn covenant headroom

• Gearing in line with current levels

Portfolio optionality

Significant Flexibility

• Current oil price $105/bbl

• Active disposal programme continues

• Will seek partner for Sea Lion

• Substantial capacity for:

– Debt reduction, or

– Enhanced shareholder distributions, or

– Incremental investment in quality projects


Catcher Development

• Project Sanction – Pre-tax IRR >20% based on $85/bbl

• Gross reserves (2P) of 92 mmboe within initial development– Upside of 140 mmboe

• Excellent reservoir qualities– 35% porosity and very high permeabilities

• Fully defined development scheme– Leased Floating Production Storage and Offloading (FPSO) model – Subsea tie-backs of the Catcher, Varadero and Burgman fields to FPSO– Expected to produce at peak ~50,000 bopd (~6% of the entire UKCS production)– $2.2 bn gross Capex including ~30% of allowances and contingencies– Development drilling of 14 producing wells and 8 water injector wells commencing 2015

• First oil in 2017 and an expected life of field of 10+ years

Catcher development overview


New North Sea hub

• Location: Block 28/9 • Water depth: 300 feet• 3 fields as part of initial development • 22 wells to be drilled

Catcher area discoveries: • Catcher August 2010• Varadero January 2011• Burgman March 2011• Carnaby June 2012• Bonneville April 2013

Block 28/9

Premier (Op.) 50.0%

Wintershall 20.0%

Cairn Energy 30.0%


• All exploration and appraisal wells encountered hydrocarbon bearing sands:

– Tay sands in 28/9-1Z, -3, -2,-4, -4Z, -5A, -6 and -6Z (all fields)

– Cromarty sands in 28/9-1,-1Y and -3 (Catcher only)

Catcher

Licence

Oil

Gas

P1430

NB Bonneville extends further south,map limited by HD data extent

Varadero

Burgman

Carnaby

Bonneville

FieldDetermination

Area

Field STOIIPOil

ReservesRF%

Catcher 129 38.6 30

Varadero 77 21.7 28

Burgman 86 23.3 27

Catcher Area 289 83.6 29

Exploration and appraisal success


Joseph C. DeVay et al, 2000, AAPG Memoir 72 / SEPM Special Publication No. 68

Tay

Cromarty

Good understanding of the rocks

Region of deposition of original Cromarty and Tay sands

• Late Palaeocene/early Eocene turbidite sand systems

• High porosity (~35%) and permeability (Darcy permeabilities) sands deposited in Cromarty andTay intervals

• Post depositional re-mobilisation and injection of sands, leading to high degree of vertical connectivity


• Excellent quality seismic imaging at the reservoir level due to shallow depths and simple overburden

• High quality, fine line spacing (high density) seismic was shot in 2011

• Oil-filled sands in the Tay and Cromarty have AVO response and are clearly identifiable

Catcher Cromarty Catcher East (Tay)

GOC

OWC

Polarcus HD seismic (far stack coloured inversion)

Chalk

Balder

CatcherEast (Tay)Catcher

Cromarty

Seismic will assist with well placement


Catcher development overview


Catcher area development scheme

• 22 well development including 14 producers and 8 injectors

• Wells target thickest oil sands to maximise rate and recovery

• Wells positioned to alloweffective sweep

• Two phases of drilling on eachfield allows:– Optimisation of production

profile– Learnings from drilling shorter

wells to be applied to later longer wells

Producers

Injectors

Oil pore volume thickness map

VI3

VP2

VP1

VI1

VP4

VP3

VI2

CCP5

CCI2

CCP6

CTP1

CCP3

CTI1

CTP7

BP1

BP2

BI3

BP4

BP3

BI1

BI2

BP5

Reservoir depletion optimised



Rig and well systems contracts awarded

• Wells drilled over six - 4 slot templates from a Heavy Duty Jack-Up

• Subsea well system with HP riser

• Subsea trees run from Jack-Up (similar to Huntington development)

• Ability to workover wells with an intervention vessel, Jack-Up or Semi-Submersible

• Concluded a highly competitive tender process– 3 international companies– Re-fit versus new build

• Formal announcement of preferred bidder imminent

• 750,000 bbls oil storage • Designed for Functional Spec• 125,000 bpd liquids

– Oil – 60,000 bopd– Gas – 60 mmscfd– Sea water injection 75,000 bpd– Future tie-ins

– Spare risers included in current design

FPSO build


Production profile


Catcher

Licence

Oil

Gas

P1430

NB Bonneville extends further south,map limited by HD data extent

Varadero

Burgman

Carnaby

Bonneville

Exploration (Laverda)• 25 mmbbls STOIIP• Low cost tie-back to Catcher development

Catcher North (CTP2 well)• 2-4 mmbbls reserves• Possible subsea tie-back or

ERD from Catcher drill centre

Carnaby (Burgman extension)• Discovered August 2012 by 28/9-5A• 28 mmbbls STOIIP

Bonneville• Discovered April 2013 by 28/9a-6 and -6Z wells

– Drilled at >70° as a “test” for Catcher• 30 mmbbls STOIIP

Area synergies• Capacity of the vessel could support other

area discoveries

Upside – near fielddiscoveries and exploration


Laverda

CatcherNorth(CTP2)

Cost parameters


Catcher tax attributes

Bare-boat Charter

• Industry-wide discussions are ongoing with HMT regarding the possible introduction of taxation on bare-boat charter income

Small Field Allowances

• The Small Field Allowance shelters £150 m taxable profits from the Supplementary Charge (SCT) saving tax at 32% for each qualifying field with P50 reserves <45 mmbbls

• The Catcher, Burgman and Varadero fields will separately qualify for the Small Field Allowance, resulting in total gross allowance for the development of £450 m

Tax synergies

• Premier has CT/SCT losses and allowances of $2.4 bn at 31 December 2013

• No UK CT expected to be payable until at least 2019


Major milestones

• Premier’s Board has approved the project– Formal Sanction on completion of the contracts and receipt of

JV and Government approvals

• The FDP will be submitted to DECC next week– Environmental Statement already submitted

• All major contracts are near to completion – In final stages with acceptable Ts&Cs

• Targets and plans in place to deliver upside potential– Reservoir recovery rates and future tie-backs

• Project team in place and will deliver first oil in the summer of 2017


Falklands Projects

Falkland Islands

Mid Atlantic Ridge

Antarctic Peninsula

Drake Passage

Falkland PlateauFalklandIslands

NFB

SFB

South American Plate

Antarctic Plate

Scotia Plate

Antarctic Plate

Nazca Plate

Weddell Sea

Borders & Southern

Premier OilFOGLArgos

Falkland Oil and GasNoble Energy

Location• Situated on the southern part of the

South American Plate on the Falkland Plateau

• 220km from the Falkland Islands in the North Falkland Basin

• Water depth 450m

Regulatory environment• Petroleum legislation modelled on UK• Falkland Islands Government is

responsible for regulation and has advice from UK DECC, HSE, BGS

Fiscal terms• Attractive fiscal terms:

– 26% corporation tax– 9% royalty


Premier’s Falkland Islands portfolio

Licence PL032• Premier 60%, operator; Rockhopper 40%• Contains Sea Lion discovery made in 2010, extensively

appraised in 2011• Chatham exploration prospect

Licence PL004• Premier 36%, operator; FOGL 40%; Rockhopper 24%• Contains Casper, Casper South, Beverley• Exploration includes Zebedee (PL004b), Jayne East (PL004c)

and Isobel/Elaine (PL004a)

Phased Development• Phase 1 – Sea Lion (PL032)• Phase 2 – Satellite fields and southern extent of Sea Lion

Exploration Upside• Four well programme scheduled for 2015


PL004b

PL004a

PL004c

PL032

Sea Lion structural anddepositional setting

Syncline Axis

Zebedee

CasperCasper SouthBeverley

SL10SL20SL30

Jayne E

Stratigraphically trapped in overlapping deep water lacustrine fans - younger to the south


PL004b PL004c

PL032

Key appraisal wells


Extensive appraisal dataset• Discovered by well 14/10-2 and appraised by 8 wells (plus 2 sidetracks to core)• 3D data full stack reflectivity seismic (2007 and 2010, merged in 2011/12)• Well data

– Extensive suite of high quality well data– ~500 MDT pressures and samples from all wells (gas, oil and water)– Extensive core inventory: 455m core– 2 DSTs: 14/10-5 & 14/10-2; 13 Mini DST’s (IPTT): 14/10-4, 14/10-5, 14/10-6, 14/10-7, 14/10-9, 14/15-

4a

Dataset and key reservoirand fluid parameters

Key Parameters

Oil gravity 28° API

Wax content 23% - 35%

Gas/oil ratio 270 – 420 scf/stb

Reservoir oil viscosity 5 – 6 cP

Average porosity 21%

Average permeability 160 mD

Oil-water contact 2476 mSS

Gas-oil contact (seen in Casper & Casper South fans) 2402 mSS

Discovered oil in place (with/without SL20 gas cap) 1.2 / 1.4 billion stb

Discovered free gas in place (with/without SL20 gas cap) 1.9 / 1.6 Tscf


Tension Leg Platform

Floating Storage& Offloading

OfftakeTanker

Gas Disposal Wells

Concept Selection Highlights

Permanent Drilling Rig

Minimal Subsea Infrastructure

Phased Development

Improved Economics

Sea Lion Phase 1 development – TLP


• Active waterflood with multiple pore volumes of water injection over field life (~5 bbl per bbl of oil recoverable)

• 32 development wells

– 19 producers and 11 water injectors

– 2 subsea gas injection wells

– 12 wells pre-drilled

• Recovers 293 mmstb over 25 years

• Assumes a gas cap is presentin the west

– Well scheme will be adjustedif absent

– 60 mmbbls upside

• Surplus gas will be injectedinto gas caps

Phase 1 reservoir development plan


TLP oil producer well design

• Conventional Gas Lift

• Horizontal up to 1500 m• Cemented Liner• Cased and Perforated

• Downhole Wax Inhibitor• Electrical Tubing Heating

Water Injection Wells• Inclined trajectories• Cased and perforated• Hydraulically fractured• Heated water


TLP analogues

Development NameSea Lion

(Pre-FEED)Olympus(MARS B)

Operator Premier Shell

Region S. Atlantic GoM

WD (ft) 1,372 3,000

Oil (mbpd) 120 100

Gas (mmscfd) 165 180

Manning Level 175-200 192

Slots 32-36 24

Date Installed TBA 2013

Benchmark Payload (short tons)

45,000 42,200

Displacement (short tons) 118,000 109,000

Hull Weight (short tons) 28,400 35,800

Deck Dimensions (ft) 300 x 300 300 x 400Other Analogue TLPs• Snorre 1992• Ursa 1998• Big Foot 2014


Project organisation


TLP build

Living Quarters

Utility Module

Drilling Module

Flare Boom

Process Module

Survival CraftSupport Structure

Topsides Fabricationand Integration• U.S.• Korea• Singapore• Dubai

Hull Fabrication• Korea• China• Singapore• Japan

Hull


TLP transportation


Exploration drilling support model• Drilling base in Stanley from which supply boats and helicopters support the rig • Regular freighter supplies from the UK to the drilling base • Fortnightly charter flight from the UK for personnel on 28/28 rota• Maximum of circa 100 people offshore

1. Pre-drilling• Similar model to exploration drilling• More personnel, more equipment and a bigger onshore drilling base • Maximum of circa 120 people offshore

2. Production and TLP drilling• Production base is a relatively small increment to the drilling base• Maximum of circa 200 people offshore• Premier will be Duty Holder but supported by two major contractors:

– Production operations contractor; – Drilling operations contractor

3. Production only• Much lower level of supply boat activity • Normally circa 120 people offshore• Activity peaks during planned maintenance shutdowns• Revert to Phase 2 during infill drilling and workovers

Planning status• Discussions underway with potential logistics providers• Modelling of materials and personnel requirements is under way• Working operations and logistics cost model has been developed

Operations and logistics


Design phase milestones

18 month “Design” phase

• Concept Selection to the start of execution (award of the EPC contract(s))

• Award of FEED Contracts in Q2 2014

• Shortlisting of EPC bidders in Q4 2014

– Updated cost estimates available

• Q4 2014 onwards – formalised financing and farm down process

• Submit draft FDP at end 2014

• EPC tenders in Q1 2015

• Sanction in Q2 2015


Phase 1 development costs

Indicative costs subject to FEED

• Surface Facilities Capex $3.5 bn– TLP $2.4 bn– Subsea and risers $0.45 bn– Project management and other costs $0.65 bn

• Drilling Capex $1.7 bn

• Total Phase 1 Capex $5.2 bn

• Spend to first oil $3.8 bn

• 25 year annual Opex $260m per year – Includes FSU rental and well interventions

All numbers are un-escalated $ 2013


Economics and financing

Economics

• Discount of $6.50 to Brent is assumed to account for oil quality and transportation

• Sea Lion Phase 1 yields an IRR of around 20% at an oil price of $85/bbl (real)

Project Funding Strategy

• Corporate funding remains an option

• Given attractive terms, base case assumes construction-related project financing

for 60% of TLP cost

• Reduces pre first oil “equity” requirement to approx. $2.5 bn (gross)

– Illustratively a 30% farm down would reduce Premier’s share to

approx. $1.8 bn


• Development of Casper, Casper South– Plus the southern extent of Sea Lion

• Single manifold subsea tie-back to the TLP• More detailed development studies underway• Development plan will incorporate results from exploration

– Could change the scheme to be a second TLP

Phase 2

Phase 2 development


• High quality dataset

• Size of exploration prize:– 1,000 mmbbls prospective

resources– 250 mmbbls risked

• Four E&A wells to be complete by end of 2015:

– Upside in Sea Lion west flank/Chatham

– Development-changing potential in Zebedee and Jayne East

– Large fan complex – Elaine/Isobel area

• Rig tenders being evaluated– Follow-up exploration and appraisal

wells possible through options

Lower F2 amplitude extraction F3G amplitude extraction

JayneEast

Elaine- Isobel

Orinoco

Zebedee

Sea Lionfan outline

30km

Further Sea Lion scale opportunities


Zebedee – high impact near field

• Zebedee prospect– Onlaps the Sea Lion field– Onlapped by the Casper South discovery

• Extends the proven SLMC (F2 sequence) play• Gross prospective resource (F2)

– 28-46-150 mmboe (low risk)• Multiple reservoir (F1 & F3) also targeted• Gross prospective resource (F1, F2, F3)

– 28-165-400 mmboe

Casper Southdiscovery Zebedee

prospect (F2 fan)

Fan input

3D visualisation of Casper South and Zebedee sands

Casper Southdiscovery

14/15-4a 14/15-2Zebedee(proposed location)

F3

F2

F2

F3

F3

F1

2 km

Sea Liondiscovery


Jayne East – high impact near field

• Equity increased to 36%, partner equity interests now aligned and fully funded

• Well to test five potential reservoirs levels across the F2 and F3 sequences– Beverly, Casper SE and Zebedee East (F2)– Jayne East and Ida (F3)

• Gross prospective reserves:– 14-37-87 mmboe

• Overall risk assessment – moderate– Key risk: updip seal

Zebedee

Jayne East

Jayne East(proposed location)

F2

F3

Amplitude extraction – F2 lower fan


Isobel/Elaine – another Sea Lion?

• Equity increased to 36%, partner equity interests now aligned and fully funded

• Stacked targets exclusively within F3 sequence• Gross prospective resources:

– 7-44-226 mmboe• Overall risk assessment - moderate

– Key risks: reservoir and updip seal

Irene

Isobel

Elaine

2 km

A

A BPL 03

PL 04aPL 05

Isobel Deep

Isobel Deep

B

5km

Single stratigraphic layer within Elaine/Isobel complex


Key Messages

Key messages

• Balance sheet strength, financial flexibility supported by asset disposals

• Catcher: high quality project, attractive returns

• Sea Lion: high quality project, will seek partner before sanction

“...our strategy is to invest in high-quality developments whilst maintaining balance sheet strength...”


Q&A

Appendix

Subsea – In-field manifolds (3-off)

• Common design for each manifold structure

• 9-slot assemblies (6x production + 3x water injection)

• Slab sided structures with piled foundations (estimated 230 tonnes)

• Fishing friendly

• Incorporates production test header c/wsubsea multiphase flow meter

• All production and water injectionpiping fabricated from super duplex

Field Production Slots

Water InjectSlots

Catcher 5 2

Varadero 4 3

Burgman 5 3


Subsea – riser base structures (3-off)

• Similar design for each riser base tie-in structure

• Open sided (estimated weight 100 tonnes)

• Dropped object protection only (i.e. all structures are located within FPSOs 500m safety zone so not exposed to fishing)

• Gravity base foundations

• Include SSIVs for production,gas lift & gas exportriser systems


• Three similar bundle systems planned for tie-back of the developments

• Each bundle circa 3.5km in length, comprising a 38” outer carrier pipe designed to house the 12” production, 10” water injection and 4” gas lift flow-lines plus steel tubed E/H control and chemical injection lines

• Manifolds and riser-base tie-in structures integrated into the bundle towheads

Subsea – bundle option


Subsea – gas export structure

• Slope sided to resist trawl gear snagging loads and promote over trawl-ability

• Approximate weight of 110 tonnes

• Supports connection of a temporary subsea pig receiver c/w DB&B isolation

• Supports entry of a future tie-in c/w DB&B

• All valves diver / ROV actuated


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