Annual results presentation14

2013

ANNUAL RESULTS

PRESENTATION //

27 February 2014

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.

27 February 2014 // Page 1

Agenda

Introduction, Highlights, Production

Business Units review

Exploration update

2013 financial results

Summary / Outlook

Simon Lockett

Robin Allan

Andrew Lodge

Tony Durrant

Simon Lockett


Introduction

Premier today

• Robust cash flow and profitability

• 800 mmboe reserves and resources

• Key exploration campaigns in

Indonesia, Norway and Falklands

• NAV >£5 per share (broker

consensus)

• Production increased to 68 kboepd

year to date

• Cash dividend and buyback

programme

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...”


Highlights

• Strong and rising cash flows of

$833m ($808m*)

• Cash of $449m ($187m*)

• Facilities increased to $1.2bn

($900m*) – extended maturities at

attractive rates

• Recommended dividend of 5p/sh

• Up to £75m buyback

• Successful asset sales in 2013 –

further disposals planned in 2014

*2012


• Production currently 4 kboepd ahead

of budget

• Dua, Pelikan and Naga expected

in 2014

• Solan – progressing towards

sail-away

• Catcher – final sanction imminent

• Sea Lion – TLP and phased

development concept selected

• 6 discoveries from 7 exploration wells

• Focusing on emergent exploration

plays

Production

Delivery capacity is the lower of field well

capacity, facilities capacity or the expected market

demand for output

Operating efficiency is the actual production rate

divided by the delivery capacity


Business Units review

North Sea

Production

• 14.9 kboepd (2012: 12.1 kboepd)

• Strong production from Wytch Farm and

Scott/Telford

• Huntington production reached 35 kboepd

Development

• Solan, Catcher and Bream

• Kyle redevelopment due on-stream in Q3

2014 – $55m insurance claim settled

Exploration

• Discoveries at Luno and Bonneville

• Farmed into Bagpuss/Blofeld

• Increased position on Mandal High

• 23 licences divested


North Sea – Solan

Development drilling

• Reservoir reached on prognosis

• Pressure data indicates good reservoir

connectivity

• 2nd phase of drilling to start in April 2014

Platform and subsea

• Tank, topsides and jacket over 80% complete

Key milestones

• Installation planned July & August 2014

• First oil Q4 2014

Project metrics

• 24 kbopd gross post ramp up

• Capex $26/bbl; Opex $18/bbl

• 60% equity – rapid project payback from

75% of cash flows


Topsides in Methil, Scotland

Subsea tank in Dubai, UAE

Jacket in Methil, Scotland

North Sea – Catcher

• First oil 2017

• Capex ~$24/bbl

• 2P reserves of 92 mmboe

– Upside of 140 mmboe

• Development drilling starts 2015

• Rig and well systems contracts awarded

Update

• Field Development Plan submitted to

DECC, project budget to partners

• Negotiations with FPSO provider

concluding

Catcher area development scheme


North Sea – Bream Area

Development concept

• 2C resource estimate: 70 mmboe

• Mackerel – 17km tie-back to

Bream FPSO

• Herring prospect – upside potential

Key milestone

• Year-end partner

sanction decision

Bream

Mackerel

Herring


North Sea – looking forward

• Optimise levels of operating efficiency

• Rising cash flow from new developments returning >20% IRR

• Maximize the benefit of our UK CT losses and allowances of $2.3bn

• Exploration reduced to a smaller number of key wells

• Current disposal programme of non-core assets

– Includes Luno and Scott area


Pakistan

Production

• 14.9 kboepd (2012: 15.6 kboepd)

• Gas demand and cash flows remain strong

• Improving recovery

– Infill wells established new zones in

Badhra, Bhit and Kadanwari

– Adding compression at Badhra, Bhit

and Qadirpur

Exploration

• Success at K-32 and Badhra B North-2

– 8 consecutive E&A successes

• 5 E&A wells planned in 2014


Kadanwari

Bhit

Vietnam

Production and development

• 2 year payback

• 14.1 kboepd (2012: 15.2 kboepd)

– Reduced due to gas export pipeline

damaged by 3rd party

• Year to date production of 18 kboepd (net)

• ~$6/bbl premium to Brent oil price

• Dua on-stream mid-2014

– Subsea development tied back to FPSO

– Development drilling underway

Exploration

• Block 121 – 2D seismic planned for 2014

Portfolio management

• Sale of Block 07/03 for $45m cash

– $55m contingent upside


West Telesto on Dua

Dua template installation

Indonesia

Production

• Singapore demand remains above

minimum contract volumes

• 13.7 kboepd (2012: 14.2 kboepd)

• Average price of $17/mcf achieved

(GSA1)

– Contractual share increased to

39.4%

– Year to date actual ~47%

Development

• Anoa Phase 4 successfully completed

• Pelikan and Naga onstream 2014 2H

– Platforms loaded out and installed

– Development drilling to commence

shortly

Exploration

• Matang gas discovery in 2013

• Kuda/Singa Laut results 2014 1H

• Follow-up drilling to Lama play discovery at

Anoa Deep


Concept selection highlights

• Tension leg platform with permanent drilling rig selected

– Minimal subsea infrastructure

– Better economics than a new build FPSO scheme

• Phased development

– Phase 1 recovers 293 mmstb over 25 years

from 32 wells

– Phase 2 development plan will

incorporate results from exploration

Schedule

• Award of FEED Contracts in Q2 2014

• Farm down process prior to sanction

Falkland Islands – Sea Lion


Exploration

2013 exploration results

• 6 discoveries from 7 exploration

wells

– Luno II and Matang

– 40 mmboe of resources added

– Finding costs $5.3/boe (pre-tax)

• >800 mmboe unrisked prospective

resources added

– Brazil and onshore Kenya

– North Falklands Basin

– Bagpuss/Blofeld, UK

– Mandal High, Norway

• Portfolio management

– 25 licences divested

2013 drilling success rate of >80%


2014 indicative exploration

drilling programme


5 high impact wells planned

Indonesia – Kuda/Singa Laut

• 2 wells planned to drill the

Kuda/Singa Laut prospect

• Kuda Laut is a four way dip

closure targeting Miocene sands

• Singa Laut is the adjoining

three-way structure with

reservoirs in the lower Miocene

and Oligocene

• Low risk for gas, high risk for

commercial oil

• Gross prospective resource:

10-37-99 mmbbls

NW Belut Laut-1TD 4977m

MMU

L.Terumbu

Arang

Gabus


Chim Sáo analogue

SE

Kuda Laut

Singa Laut

Indonesia – Lama play


• Proven by Premier’s Anoa Deep

in 2012 – 17mmscfd

• Identified look-a-like

opportunities from shows in

existing wells

• 5 prospects and leads

– Ratu Gajah Q1 2014

– Anoa Deep appraisal Q4 2014

• Gross prospective resource

on block ~2 TCF

Kuskus lead

Ratu Gajah

East

prospect

Ratu Gajah

prospect

Anoa North

High impact potential from the “missed” gas pay zones

Anoa West

Indonesia – Ratu Gajah well

• Gross prospective resource:

60-225-700 bcf

• Follow up potential at Ratu Gajah

East

• Originally drilled in 1984 – not flow tested

– Gas readings, high resistivity and mud losses,

same as Anoa Deep

– Similar in Babar-1 and Koko-1 wells Raja Gajah-1

Ratu GajahTop Sand A (Top Lama)

depth map

Babar-1

Koko-1

Ratu Gajah-1

proposed location

Ratu Gajah

East prospect

Re-drilling an existing gas discovery


Norway – Luno II

• First oil discovery on south west margin

of Utsira High

• Luno II Central segment to be

appraised in Q2 2014

• Further exploration potential remains on

PL 359 – including Luno II North

Central 1

Discovery

North 2

North 1

Johan SverdrupLuno/Apollo

Ragnarrock

PL 359

BCU Time MapC.I. 100ms

10km

Luno II discovery

16/4-6 16/5-5Luno II

appraisal

Luno II Central Luno II S.Luno II North

(Prospect)

BCUTop Chalk

Balder

Basement


Appraising a material discovery

Norway – Mandal High

• Built on acreage position around Mandal High

– 20% equity in PL663 – 2013

– 70% and 50% in PL725 and PL726 – 2014

– Drill or drop options

• >500 mmboe of gross unrisked prospective

resources

• Myrhauk

– Rig contracted; spud Q4 2014

– Gross prospective resource:

10-50-135 mmboe

– Critical risk: reservoir presence


Myrhauk Prospect

MANDAL HIGH

3 way dip closure with

up-dip pinch-out trap

NESW

Play opening test


• Over 9 bnbbls discovered in the

Muglad, Albertine and Lokichar

Basins

• Look-a-like plays identified in the

Anza Basin

• Farmed into Block 2B to drill the

Badada prospect

– 55% equity

• Targeting Tertiary reservoirs similar

to Albertine and Lokichar Basins

• Gross unrisked prospective

resource on block >1.5 bnbbls

• Badada prospect

– Robust closure confirmed by

new 2D

– Critical risk: source maturity

and charge

Kenya – Southern Anza Basin

Source: Taipan Resources

Play opening test of the South Anza Basin

• Under-explored, emerging plays in

proven deep water basins offshore

NE Brazil

– Plays targeted are above

and within Cretaceous rifts

– Access to >1 bnbbls unrisked gross

resources

• Awarded 3 blocks in Brazil’s 11th Bid Round

– 5 year exploration periods

– 3D seismic being acquired in 2014/15

in each block

• Cost mitigation by multi-client seismic

acquisition and future rig share

• Potential pre-drill farm down to

manage capital exposure

• Earliest well late 2016

Brazil exploration – new country entry

Exposure to high impact emerging plays27 February 2014 // Page 25

• High quality dataset

• Unrisked mean gross prospective

resource of 1bn bbls (250 mmbbls

risked)

• Four E&A wells to be completed 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

Jayne

East

Elaine- Isobel

Orinoco

Zebedee

Sea Lion

fan outline

30km

Falklands – high impact drilling in 2015


• Reducing E&A investment in the UK North SeaReducing exposureto mature basins

• Active disposal and relinquishment programme of assets that do not meet internal metrics

• Management of equity exposures pre-drill

Capital efficiency

• Drilling in Indonesia, Kenya and Norway in 2014

• Maturing prospects across Brazil, Kenya, Iraq, Vietnam

and Norway for drilling in 2015/2016

• Falklands matured for drilling in 2015

Exploration business model

Focus on high

impact

opportunities in

emerging plays


2013 Financial Results

Income Statement

12 months to31 Dec 2012

Operating costs (US$/bbl)

2013 2012

UK $43.3 $41.9

Indonesia $10.9 $11.2

Pakistan $2.5 $2.3

Vietnam $20.9 $13.7

Group $19.7 $16.2

Highlights12 months to31 Dec 2013

Working Interest production (kboepd)

Entitlement production (kboepd)

Realised oil price (US$/bbl) - pre hedge

Realised gas price (US$/mcf) - pre hedge

Sales and other operating revenues

Cost of sales

Gross profit

Exploration/New Business

General and administration costs

Operating profit

Financial items

Profit before taxation

Tax credit/(charge)

Profit after taxation

57.7

51.6

111.4

8.3

US$m

1,409

(742)

666

(187)

(24)

455

(95)

360

(108)

252

58.2

52.4

109.0

8.3

US$m

1,540

(1,035)

505

(133)

(20)

352

(67)

285

(51)

234

• 32% of 2014 production sold forward

at average equivalent of US$104/boe

• Currently unhedged for 2015

Hedging

Includes impairment charges of

US$179m (pre-tax)

Effective tax rates (%)

2013 2012

Overseas 38 42

Group 18 30


Cash Flow Statement

Cash flow from operations

Taxation

Operating cash flow

Capital expenditure

Partner funding (Solan)

(Acquisitions)/disposals, net

Finance and other charges, net

Dividends

Pre-licence expenditure

Net cash out flow


$m

1,041

(233)

808

(772)

-

(211)

(163)

-

(29)

(366)


$m

1,061

(228)

833

(878)

(186)

61

(91)

(40)

(30)

(331)

2013 2012

Exploration $207 $187

Development $658 $569

Other $14 $16

Total $878 $772

Capital expenditure ($m)

Highlights

Development costs include pre development projects

• 2014 guidance of $1bn of development

and $180m of exploration (pre-tax)


Cash

Bank debt

Bonds and loan notes

Convertibles

Net debt position

Gearing

Cash and undrawn facilities

187

(500)

(578)

(220)

(1,110)

36%

1,100

449

(686)

(992)

(224)

(1,453)

41%

1,600

• Average interests costs are 4.7% (fixed)

and 1.9% over LIBOR (floating)

• Split 75/25 between fixed/floating

• Continue to switch to longer maturity

bond market instruments

1 Maturity value of US$245 million

At 31 Dec 2012US$m

At 31 Dec 2013US$m

1

2 Net debt/net debt plus equity

2

Liquidity and balance sheet position

3 Excludes uncommitted letter of credit facilities of $275 million

Repayment of drawn facilitiesand committed LCs

3


Forward Financial Profile


• The business is managed using $85/bbl base case

– Asset cash flows supplemented by disposal programme

– Discretion around exploration spend / unsanctioned projects

– Self-imposed covenant headroom / maximum gearing levels

• At current oil prices, substantial capacity for:

– Debt reduction

– Enhanced shareholder distributions

– Incremental investment projects

Outlook

Outlook

• Maintaining financial strength, flexibility

and growing cash flows

• Dua, Pelikan, Naga and Solan on-stream

• Catcher JV sanction; Bream sanction

decision

• Sea Lion partner prior to sanction

• Key wells: Tuna block, Kenya, Norway,

Falklands

• Disposal programme ongoing

• Commencing buyback

2013 2014 PostSolan

PostCatcher

Cash Flows (Current Oil Prices)


Appendix

End 2013 2P reserves and

contingent resources

Falkland

IslandsIndonesia Norway

Pakistan &

MauritaniaUK Vietnam Total

2P ReservesOn production - 34.5 - 19.6 37.4 24.3 115.9

Approved for

development- 22.7 - 2.6 30.0 9.1 64.5

Justified for

development- 24.5 - 1.1 53.5 - 79.0

Total Reserves - 81.7 - 23.3 121.0 33.4 259.4

2C

Contingent

Resources

Development

pending230.5 - 72.7 3.8 4.2 - 311.3

Development un-

clarified / on hold41.5 78.9 23.6 8.7 21.0 7.4 180.9

Development not

currently viable- 4.5 2.3 5.5 27.7 2.2 42.1

Total Contingent

Resources272.0 83.3 98.6 18.0 52.8 9.6 534.4

Total Reserves & Contingent

Resources272.0 165.0 98.6 41.4 173.8 43.0 793.8


www.premier-oil.com27 February 2014

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Annual results presentation14