CAPITAL MARKETS PRESENTATION 6 th February 2014 Forward looking - - PowerPoint PPT Presentation

6th February 2014

CAPITAL MARKETS PRESENTATION

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.

6th February 2014 // Page 1

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...”

6th February 2014 // Page 2

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 sheet and funding position

6th February 2014 // Page 4

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

Significant cash flow growth

6th February 2014 // Page 5

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

6th February 2014 // Page 6

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

6th February 2014 // Page 8

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% 6th February 2014 // Page 9

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

Varadero Burgman Carnaby Bonneville

Field Determination Area

Field STOIIP Oil Reserves RF% 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

6th February 2014 // Page 10

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 and Tay intervals

• Post depositional re-mobilisation and injection of sands,

leading to high degree of vertical connectivity

6th February 2014 // Page 11

• 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

Catcher East (Tay) Catcher Cromarty

Seismic will assist with well placement

6th February 2014 // Page 12

Catcher development overview

6th February 2014 // Page 13

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 allow

effective sweep

• Two phases of drilling on each

field 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

6th February 2014 // Page 15

6th February 2014 // Page 16

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

6th February 2014 // Page 17

Production profile

6th February 2014 // Page 18

Catcher Licence Oil Gas 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 field discoveries and exploration

6th February 2014 // Page 19 Laverda Catcher North (CTP2)

Cost parameters

6th February 2014 // Page 20

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

6th February 2014 // Page 21

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

6th February 2014 // Page 22

Falklands Projects

Falkland Islands

Mid Atlantic Ridge

Antarctic Peninsula Drake Passage

Falkland Plateau Falkland Islands

NFB S FB

South American Plate Antarctic Plate Scotia Plate Antarctic Plate Nazca Plate

Weddell Sea

Borders & Southern

Premier Oil

FOGL Argos Falkland Oil and Gas Noble 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

6th February 2014 // Page 24

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

6th February 2014 // Page 25

PL004b PL004a PL004c PL032

Sea Lion structural and depositional setting

Syncline Axis Zebedee Casper Casper South Beverley SL10 SL20 SL30 Jayne E

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

6th February 2014 // Page 26

PL004b PL004c PL032

Key appraisal wells

6th February 2014 // Page 27

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 reservoir and 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

6th February 2014 // Page 28

Tension Leg Platform Floating Storage & Offloading Offtake Tanker Gas Disposal Wells

Concept Selection Highlights Permanent Drilling Rig Minimal Subsea Infrastructure Phased Development Improved Economics

Sea Lion Phase 1 development – TLP

6th February 2014 // Page 29

• 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 present

in the west – Well scheme will be adjusted if absent – 60 mmbbls upside

• Surplus gas will be injected

into gas caps

Phase 1 reservoir development plan

6th February 2014 // Page 30

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

6th February 2014 // Page 31

TLP analogues

Development Name Sea 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 400

Other Analogue TLPs

• Snorre 1992
• Ursa 1998
• Big Foot 2014

6th February 2014 // Page 32

Project organisation

6th February 2014 // Page 33

TLP build

Living Quarters Utility Module Drilling Module Flare Boom Process Module Survival Craft Support Structure

Topsides Fabrication and Integration

• U.S.
• Korea
• Singapore
• Dubai

Hull Fabrication

• Korea
• China
• Singapore
• Japan

Hull

6th February 2014 // Page 34

TLP transportation

6th February 2014 // Page 35

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

6th February 2014 // Page 36

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

6th February 2014 // Page 37

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 6th February 2014 // Page 38

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

6th February 2014 // Page 39

• 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

6th February 2014 // Page 40

• High quality dataset
• Size of exploration prize:

– 1,000 mmbbls prospective resources – 250 mmbbls risked

• Four E&A wells to be complete by end
• f 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

Jayne East Elaine- Isobel Orinoco Zebedee

Sea Lion fan outline

30km

Further Sea Lion scale opportunities

6th February 2014 // Page 41

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 South discovery Zebedee prospect (F2 fan) Fan input

3D visualisation of Casper South and Zebedee sands

Casper South discovery 14/15-4a 14/15-2 Zebedee (proposed location) F3 F2 F2 F3 F3 F1

2 km

Sea Lion discovery

6th February 2014 // Page 42

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

6th February 2014 // Page 43

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 B

PL 03 PL 04a PL 05

Isobel Deep

Isobel Deep

B

5km Single stratigraphic layer within Elaine/Isobel complex

6th February 2014 // Page 44

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...”

6th February 2014 // Page 46

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/w

subsea multiphase flow meter

• All production and water injection

piping fabricated from super duplex

Field Production Slots Water Inject Slots Catcher 5 2 Varadero 4 3 Burgman 5 3

6th February 2014 // Page 49

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 export riser systems

6th February 2014 // Page 50

• 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

6th February 2014 // Page 51

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

6th February 2014 // Page 52

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