2010 Annual Results Presentation 24 th March 2011 24 th March 2011 - - PowerPoint PPT Presentation

2010 Annual Results Presentation

24th March 2011

2010 Annual Results Presentation 24th March 2011

24th March 2011 | 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.

24th March 2011 | Page 3

Agenda

Highlights and progress against strategy Simon Lockett 2010 financial results Tony Durrant Exploration update Andrew Lodge Operations update Neil Hawkings Summary Simon Lockett

24th March 2011 | Page 4

2010 highlights

• On track for production of 75,000 boepd in 2012
• Development portfolio building towards

100,000 boepd in 2014

• 8 out of 14 exploration and appraisal wells

successful

• Operating cashflow up 25% to $436.0 million
• Record profits after tax of $129.8 million
• $1.1 billion of UK tax allowances - mitigating the

impact of proposed tax changes

• Cash and undrawn bank facilities of $1.2 billion

24th March 2011 | Page 5

Building three quality E&P businesses

Strategy

• Grow near-term production to

75 kboepd from existing 2P reserves of 261 mmboe

• Deliver further growth by

commercialising contingent resource base of 228 mmboe

• Add 200 mmboe through

exploration by focusing on core geologies

• Make value-adding acquisitions

in three core areas

• Maintain a conservative

financing plan

Creating an overall business with 400 mmboe of reserves and 100 kboepd production in the medium term

24th March 2011 | Page 6

2010 financial results

24th March 2011 | Page 7

Production and income statement

12 months to 31 Dec 2009 Average gas pricing ($/mcf) 2010 2009 Singapore $13.9 $11.0 Pakistan $3.5 $3.2 Average Brent oil price was $79.5/bbl (2009: $61.7/bbl) Operating costs per barrel ($/bbl) 2010 2009 UK $28.7 $23.2 Indonesia $8.5 $10.0 Pakistan $2.0 $1.9 Group $13.9 $12.2 2010 includes non-cash mark to market gain on hedging of $39 million (pre-tax) Tax credit arises due to UK tax allowances acquired with Oilexco Highlights 12 months to 31 Dec 2010 Includes impairment charges of $65.3 million (2009: $24.0 million) Working Interest Production (kboepd) Entitlement Interest Production (kboepd) Realised oil price ($/bbl) Realised gas price ($/mcf) Sales and other operating revenues Cost of sales Gross profit Excess of fair value over purchase consideration Exploration/New Business General and administration costs Operating profit Financial Items Profit before taxation Taxation credit Profit after tax 44.2 40.2 66.3 5.2 $m 621 (361) 260 6 (77) (18) 170 (90) 80 33 113 42.8 38.3 79.7 6.3 $m 764 (531) 233

• (87)

(18) 128 (27) 101 29 130

24th March 2011 | Page 8

Overseas UK PRT CT Prior period revisions Current charge Deferred tax credits Tax credit for the year 12 months to 31 Dec 2009 $m

Group taxation position

73.0 23.2 (23.4) (24.6) 48.2 (81.3) (33.1) Allowances remaining at 1/1/10 Net additions in 2010 Recognised as deferred tax asset Currently unrecognised Tax allowances carried forward UK Tax Allowance Position at 31 Dec 2010 $m 1,098 14 1,112 972 140 1,112

Outlook

• UK cash corporate taxes not anticipated until at least 2016
• Mitigates impact of proposed tax changes
• UK allowances of $140 million not yet recorded

12 months to 31 Dec 2010 $m 56.9 25.9 nil (21.3) 61.4 (90.4) (29.0)

24th March 2011 | Page 9

Cash flow

Cash flow from operations Taxation Operating cash flow Capital expenditure (Acquisitions)/disposals, net Finance and other charges, net Pre-licence expenditure Net cash flow 12 months to 31 Dec 2009 $m

2010 Development Exploration

Estimated Capex split ($m)

349 165 514 2010 2009 Cash Net Debt

Balance sheet ($m)

251 245 398 300 406 902 Undrawn facilities

419 (71) 348 (303) (643) (55) (20) (673) 12 months to 31 Dec 2010 $m

2009 195 108 303

505 (69) 436 (514) 13 (70) (19) (154)

Outlook

• Forecast full-year 2011 spend of $500m (development) and $200m (exploration)
• Peak net debt of around $800 million in 2012 using $75/barrel

24th March 2011 | Page 10

Forward economics

80 2010A 70 60 50 10 20 30 40

OPEX Tax Cash Margin

2012E 2014E 2012E 2014E $79/bbl $75/bbl $100/bbl

New projects lead to improved cash margins

$/boe

24th March 2011 | Page 11

Exploration update

24th March 2011 | Page 12

Progress towards 200 mmboe of discoveries

200 100 50 2010 2011 150 2012 2013 2014 250

Target cumulative risked additions Actual cumulative proved and probable discovered resources Actual cumulative plus possible resources

Global exploration: Forecast resource additions (mmboe)

2009

Exploration and Appraisal Drilling

• 14 wells drilled, 8 successful
• Discoveries at Catcher, Catcher East,

Varadero, Blåbaer and West Rochelle

• 27 mmboe reserves and resources added

– Upside to 50 mmboe with appraisal New Ventures

• Licence round awards:

– 19 blocks awarded in UK

• Farm-ins:

– UK block 15/26c (West Rochelle) – UK block 15/13b (Eagle) – North Red Sea Block 1 (Cherry)

• Under negotiation:

– 2 blocks in Kenya

24th March 2011 | Page 13

Exploration drilling 2011

Firm Wells: Rig Contracted Firm Wells: Rig TBC Contingent Wells All well timings are subject to revision for

• perational reasons

Asia

2011 Q1 Q2 Q3 Q4

Vietnam 07/03 CRD Appraisal 104/109-05 Jackfruit Indonesia Tuna Gajah Laut Utara Belut Laut Buton Benteng Natuna Sea Block A Anoa Deep Biawak Besar Block A Aceh Matang-1

North Sea

Norway PL406 (8/3) Gardrofa PL378 Grosbeak Appraisal UK P1430 Burgman Carnaby P1466 Bluebell

Middle East - Pakistan

Pakistan Kadanwari K-25ST K-28 K-29 K-27 SE-1 Bhit/Badhra Badhra-6 (Parh) Badhra Appraisal Egypt North Red Sea Cherry Ocean General Ocean General Songa Delta West Callisto West Callisto Weatherford 812 Stena Forth Weatherford 812 Weatherford 812

• > 300 mmboe

unrisked resource

• 2011 full year

exploration expenditure ~ $200 million pre-tax

Ocean General Bredford Dolphin Galaxy II Weatherford 812 Weatherford 812 Aquamarine

12 to 15 exploration and appraisal wells already planned in 2012

24th March 2011 | Page 14

CRD-2X

Appraisal – Vietnam – Block 07/03 – Cá Rồng Đỏ

Anomalies associated with Gas

CRV CRD-1X CRD-2X

Top Cau Depth Map

Cau Sequence

SE NW

Cá Rồng Đỏ

• Premier 30% equity
• Gross resource estimate 10-60-80 mmboe
• CRD-2X appraisal well spudded 10 February 2011

Well status

• TD at 3785 metres
• Drill stem testing hydrocarbons discovered in Oligocene sands

CRD-1X

24th March 2011 | Page 15

Exploration – Indonesia – Tuna Block

Belut Laut / Gajah Laut Utara

• Reserves estimate 40-90-200 and 65-160-350 mmboe respectively
• Targeting multiple stacked Miocene and Oligocene reservoirs in fault

dependent closures – Belut Laut prospect is independent of Gajah Laut Utara

• Belut Laut is amplitude supported

– Belut Laut: low risk for gas, moderate risk for oil – Gajah Laut Utara: moderate risk for oil and gas

• Back to back wells planned for Q2 2011 following CRD well

PTD

2 Km

PRIMARY TARGET

SE

SECONDARY TARGET

Belut Laut

PTD 4300m MD (3870m TVD)

NW

2 Km

PRIMARY TARGET

W E

SECONDARY TARGET PTD

Gajah Laut Utara

PTD 4250m MD (3550m TVD)

24th March 2011 | Page 16

Exploration – Indonesia – Natuna – Biawak Besar

Biawak Besar (Natuna PSC)

• Premier 28.67% equity
• Reserves estimate 66-79-92 bcf
• Targeting Miocene reservoirs in a stratigraphic trap, off structure from

the Iguana gas discovery

• Seismic attribute analysis and 3D inversion supports presence of gas
• Play opening well – low risk for gas
• Planned for Q4 2011

PTD

3D Seismic Inversion indicating gas pay

Top Arang Depth C.I.=100 metres

2000m Iguana Discovery Biawak Besar-1

Bison Iguana Biawak Besar

PRIMARY TARGET

500m

SE NW

24th March 2011 | Page 17

Block 104-109/05

• Premier 50% equity
• Exploration well to test prospect with reserves

range estimate of 30-60-140 mmboe

• High risk for oil, moderate risk for gas
• Planned for Q3 2011

Base Tertiary

Exploration – Vietnam – Block 104-109/05

T300 T400 T600 Coals T1000 Base Tertiary T500 T700

W E

24th March 2011 | Page 18

Exploration – UK – Block 28/9 – Summary

Block 28/9 (P1430)

• Combined Eocene and Palaeocene play
• Shallow (1350m)
• Amplitude supported
• Six penetrations drilled to date on Catcher,

Varadero and Burgman – Excellent reservoir quality – High oil saturations (80-90%) – 24° to 31° API oil, low viscosity

• Catcher North, thin Cromarty sands conform to low

amplitudes on seismic data

• Exploration well campaign ongoing

– Burgman currently being sidetracked – Carnaby well deferred

• Development planning on going

– New 3D seismic is planned on the block in 2011

Block 28/9

Eocene – Tay Amplitudes

Catcher Main Carnaby Catcher North Varadero Burgman Catcher East Burgman Catcher Varadero

24th March 2011 | Page 19

Burgman

Exploration – UK – Burgman

Burgman

• Premier 35% equity
• Burgman vertical well encountered:

– 22 feet net hydrocarbon pay in Tay section – 12 feet of gas in the Upper Tay – 10 feet oil in the Lower Tay sandstones – 400 feet oil column – Cromarty and Jurassic sands were not hydrocarbon bearing

• Well being sidetracked to the South East
• Prospective resource estimates 15-35-60 mmbo

N S

Fulmar Cromarty Upper Tay

Burgman Carnaby

Lower Tay

NW SE

Catcher Main Catcher E Burgman Varadero

Cromarty Depth Structure

Burgman location

Burgman Burgman ST

24th March 2011 | Page 20

Cherry (North Red Sea – Block-1)

• Premier 20% equity
• Hess operator - proven deep water expertise
• Water Depth - prospects/leads in ~700m WD
• Multi-billion barrel unrisked potential in two

independent plays

• NRS-2 well present depth 4500m, estimated

time to target 20-30 days

Exploration – Egypt – North Red Sea – Block 1

New Rift Plays

24th March 2011 | Page 21

Exploration – Kenya – Deep water Rift plays

L10A & L10B

• Provisional award accepted by joint venture

– Subject to fully termed PSA – Expect award in 2Q 2011

• Premier equity

– L10A: 20%, L10B: 25%

• BG operator
• Area >10,000 sq km
• Water depth 500-1700m
• Commitments:

– Seismic acquisition in first term (2 years)

• Forward Plan:

– Acquire 2D and 3D seismic data (2011/2012)

Blocks L10A & L10B

CENTRAL PLATFORM MOMBASA HIGH INBOARD TERTIARY RIFT

Rift Margin Plays

INVERTED JURASSIC RIFT

E W

Inverted Rift Play

L10B BG 45% Premier 25% Cove 15% Pancon 15% L10A BG 40% Premier 20% Cove 25% Pancon 15%

New Rift Plays

24th March 2011 | Page 22

North Sea – acquisition / new ventures

UK: 2010 New acreage

• In 2010 Premier secured interests in 19 new

North Sea exploration blocks

UK – West Orkney

• Frontier acreage targeted a Devonian pre-rift system
• Existing data to be reprocessed in 2011 with an optional well in 2013

UK – 15/9, 10, 13b, 14 and 15

• Lower Cretaceous and Tertiary play fairways
• 3D acquired in 2010
• One well planned in 2012

UK – 15/23g, 14/30b, 15/26c

• Near field exploration
• Successful West Rochelle well in 2010

UK – 21/7b

• Tertiary amplitude play
• Well planned for 2012

UK – 22/21c, 22/26c

• Pre Cretaceous target
• 3D planned in 2011

Norway: 2011 New acreage

Norway – 35/12

• Upside potential to Grosbeak

Norway – 2/6

• Multiple target block secured on a drill or drop option

24th March 2011 | Page 23 Total Portfolio Unrisked Prospective Resource Total Portfolio Risked Prospective Resource

Resource under appraisal 105 mmboe Leads 1000 mmboe Prospects 800 mmboe Total >1900 mmboe Leads 80 mmboe Prospects 160 mmboe Total >340 mmboe

• Unrisked prospect portfolio of 1800 mmboe

– 800 mmboe in prospects – 1000 mmboe in leads

• Represents a 300 mmboe increase during 2010

– New acreage aquired in the North Sea and Egypt – Prospect maturation in the North Sea

• The total portfolio on a risked basis is 240 mmboe

– The prospect inventory is 160 mmboe – The lead inventory is 80 mmboe

Prospective resource portfolio

On track to deliver 200 mmboe

• f 2P reserves by 2015

Resource under appraisal 105 mmboe

24th March 2011 | Page 24

Operations update

24th March 2011 | Page 25

Operations highlights

• Good production performance in Indonesia and Pakistan

– Offset by recent downtime in the UK portfolio

• Material progress on Chim Sáo, Gajah Baru and Huntington

– On target for 75,000 boepd in 2012

• Continued progress on the future development portfolio

– New Asia projects progressing for 2013/14 start-up – MoU signed on Solan participation – On track for 100,000 boepd in 2014

24th March 2011 | Page 26

Production update

• Continued growth in Pakistan

production in 2011

• Industry HSE related downtime in

the UK in 1Q 2011

• Singapore gas demand strong
• 2011 full year production forecast

in the range 45-50 kboepd

Current production split 63% gas and 37% oil, but 62%

• f production is linked to oil price

50

Production (working interest) (kboepd net)

20 10 25 35 45 2006 2007 2010 2008 2009 2011E 40 30 5 15

Middle East-Pakistan North Sea / W. Africa Asia

24th March 2011 | Page 27

• Successful infill drilling at Kadanwari has increased

production rates

• Minor impact from flooding seen at Zamzama
• Qadirpur initial licence term was extended by five years
• Compression projects on schedule:

– Qadirpur and Bhit completed – Zamzama due May 2011

• Continued strong production is anticipated

Pakistan production update

3000

Kadanwari Production - Net WI (boepd)

2006

2500 2000 1500 1000 500

2007 2008 2009 2010 2011E

24th March 2011 | Page 28

UK production update

• Industry wide issue driven by a need to

improve performance and increased HSE enforcement action

• Wytch Farm shutdown in November to

address pipeline integrity issues

• Balmoral shutdown in December to

address fabric maintenance issues

• Various maintenance related production

restrictions / shutdowns at Scott

• Consistent production from Kyle

UK Production by Week (kboepd net)

18 12 10 4 2 Sep 10 6 8 14 16 Oct 10 Nov 10 Dec 10 Jan 11 Feb 11 Mar 11

Balmoral Area Wytch Farm Scott and Telford Kyle and Others

2011 group production expected at low end of range, no impact on 2012

24th March 2011 | Page 29

Indonesia production and development update

• 2010 was a record year for Block A gas sales

– Sold 160 bbtud vs a DCQ of 126 bbtud – Opportunity to increase GSA1 DCQ at 1/1/2014

• Gajah Baru builds up to a DCQ of 130 bbtud in 2012
• In 2011 expect to approve:

– Anoa phase 4 compression expansion (2013) – Pelikan and Naga field developments (2013)

• Total sales capacity will increase to 400 bbtud

180

West Natuna Sales to Singapore (GSA1 Only) (bbtu/d)

40 80 20 60 100 120 140 160

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Natuna ‘A’ 2014

24th March 2011 | Page 30

Development drilling at Anoa

24th March 2011 | Page 31

Progress towards 75,000 boepd

Gajah Baru Chim Sáo Huntington

24th March 2011 | Page 32

• Phase 1 development drilling successfully completed

– Wellhead platform installed in September 2010 – 5 wells drilled and completed – Significantly higher deliverability than planned – Small reserves increase anticipated

• Central Processing Platform (CPP) progressing well

– Jacket was 86.9% complete at end Feb – Installation planned for late May-early June – Topsides were 78.9% complete at end Feb – Installation planned for early July – Gas Export Pipeline to be installed in June-July

• First gas remains on schedule for October 2011
• Premier 28.67% equity

Gajah Baru development update

24th March 2011 | Page 33

Gajah Baru CPP jacket to be installed in June

24th March 2011 | Page 34

Gajah Baru CPP topsides nearing completion

24th March 2011 | Page 35

• Very successful 2010 installation program:

– Wellhead platform – Gas Export Pipeline – Sub-sea flow-lines

• Development drilling commenced in June

– 5 producers and 3 injectors will be available at first oil – MDS-5 reservoir is better quality than anticipated – MDS-6 reservoir is close to prediction

• FPSO (Lewek Emas) is 90% complete and

approaching mechanical completion – Commissioning is now the key project activity

• Development project in line with budget
• First oil is forecast for late July 2011
• Premier 53.125% equity

Chim Sáo development update

OWC CS-S10P CS-S7P CS-S14I CS-N2P CS-S8P CS-N1P CS-N3P CS-S11P CS-S15I CS-N4I CS-S9P CS-N5I CS-S13I CS-S12I CS-1X-ST1 CS-2X CS-S6P

24th March 2011 | Page 36

Chim Sáo – Lewek Emas FPSO

March 2010 March 2011 October 2010

24th March 2011 | Page 37

Huntington – on schedule for 2012

• Field development plan approved – project sanctioned early November 2010
• Contract awarded to Sevan for provision of Voyageur FPSO
• Drilling template installation late March 2011
• Ensco 100 jack up rig selected, spud expected May 2011 – four well initial programme
• Subsea installation to commence July 2011
• FPSO sail-away October 2011
• Target first oil is Q1 2012

24th March 2011 | Page 38

Rochelle development update

• Western Rochelle well and sidetrack

encountered gas-bearing sands

• DECC have determined a single field

development area

• Phase 1 covering East area –

sanction in May for 4Q 2012 first gas

• Phase 2 West area to be integrated

later in 2011

• Scott tariff arrangements – parties

working towards early conclusion

• Plan for unitised development with

15/27, equity under discussion

Rochelle

15/26b-10 15/26b-10z 15/26b 15/26c Kopervik pinch-out Rochelle FDA

24th March 2011 | Page 39

Progress towards 100,000 boepd

Solan Catcher Frøy

24th March 2011 | Page 40

Frøy development status

• Technical concept selection near complete

– Sevan 300 FPSO bridge linked to a WHP – Water and gas injection to optimise reservoir development (70 mmbbl) – Third party field tie-ins being prioritised

• Work programme for Q2 is focused on commercial

arrangements – FPSO contracting – Third party field tie-in arrangements – Gas offtake arrangements

• FEED studies to commence mid year
• Project sanction gate in Q4 2011
• Target first oil for late 2014

24th March 2011 | Page 41

Catcher development scenario

• Current exploration drilling programme on Block

28/9 is nearing completion – Reserves distribution is being clarified – New 3D seismic shoot planned for April/May

• Premier keen to progress to development

– Most likely scenario is a standalone FPSO – Sub-sea tie backs from Varadero and Burgman – Reservoir modelling ongoing for Catcher and Varadero, due to complete mid year – Drilling studies currently focused on wellbore stability and completion design – Gas export pipeline

• Formal concept selection process to commence

in Q2 followed by FPSO market enquiries

• Project sanction targeted for mid 2012
• First oil targeted for mid 2014

Illustrative Catcher Development

24th March 2011 | Page 42

Solan development status

Development Concept

• Changed to conventional jacket with Not

Permanently Attended accommodation, but still with a sub-sea tank

• Two producers and two injectors
• Internal project reviews ongoing to

validate reserves, costs and schedule

• Full project sanction expected Q2 2011
• First oil Q3 2013

Commercial Arrangements

• Premier and Chrysaor signed MoU on 16 March 2011
• Premier will participate in the development with a 60% equity
• Premier will provide Chrysaor with a bridging loan to fund their remaining project costs
• Chrysaor will repay the loan via a cash sweep to Premier of a share of their revenue
• Operatorship arrangements still to be discussed
• Intention is to sign a full SPA by mid April

24th March 2011 | Page 43

A path to 100,000 boepd

120

Production (kboepd net)

40 20 60 80 100

Development capex ($m)

2011 2012 2015 2013 2014 2016

Future Asia developments Future Norway developments Future UK developments Huntington Chim Sáo, Gajah Baru On production

800 200 100 300 400 500 2011 2012 2015 2013 2014 2016

Future Asia developments Future Norway developments Future UK developments Huntington Chim Sáo, Gajah Baru On production

700 600

24th March 2011 | Page 44

Summary

24th March 2011 | Page 45

Target Asia MEP North Sea 75,000 in 2012 Chim Sao and Gajah Baru Pakistan growth Huntington Commercialise potential developments Future Singapore gas Tight gas

• pportunity

Catcher, Solan Norway Add 200 mmboe from exploration Natuna Sea / Nam Con Son North Africa rift plays UK Central North Sea and Norway Acquisitions Targeting core area acquisitions Financially conservative Debt capacity increased and maturity extended Building three quality businesses delivering 100 kboepd from 400 mmboe

Building three quality E&P businesses

24th March 2011 | Page 46

Appendix

24th March 2011 | Page 47

Reserves and resources

500

2006

450 400 350 150 200 250 300

2007 2008

100 50

Reserves and contingent resources (mmboe)

Production Additions & Revisions End 2010 2009 2C contingent resources 2P reserves

227 261

24th March 2011 | Page 48

Hedging

• Policy unchanged: secure cashflows via floors or

forwards to fund investment programme even at low oil prices

• 2010 Impact

– Income statement gain of $39 million as past provisions unwind – Cash cost of $8 million on maturing hedges Outlook

• Approximately 26% of forecast liquids production for

2011/12 capped at average of $87

• Approximately 19% of forecast gas production from

Indonesia for 2011/12 and 1H 2013 is capped at $500 / MT

• Future hedging plans will depend on development

programme requirements relative to cashflow

24th March 2011 | Page 49

End 2010 2P reserves and contingent resources

North Sea/ W Africa Asia MEP Total 2P Reserves On production 31.0 23.5 26.1 80.6 Approved for development 11.7 83.8 15.4 110.9 Justified for development 20.8 46.9 1.6 69.3 Total Reserves 63.5 154.2 43.1 260.8 2C Contingent Resources Development pending 50.6 0.3 0.0 50.9 Un-clarified or

• n hold

32.0 30.1 18.9 81.0 Development not currently viable 30.8 63.6 1.4 95.9 Total Contingent Resources 113.4 94.0 20.3 227.7 Total Reserves & Contingent Resources 176.9 248.2 63.4 488.5

These figures do not include prospective resources

24th March 2011 | Page 50

Indicative Net New Field Rates Equity % Net Initial Rate (boepd) 2012 UK Huntington 40.00 9,000 Rochelle TBA 2,000 2013 UK Solan 60.00 7,200 Caledonia / Ptarmigan Area 80.00* 5,000 Norway Bream 20.00 6,000 Asia Dua 53.13 5,000 2014 UK Catcher Area 35.00 10,000 Fyne 39.90 8,000 Norway Froy 50.00 18,000 Asia Block A Aceh 41.67 5,000

Figures are Unrisked * Caledoneia 100%, Ptarmigan 60% equity

Indicative field rates

24th March 2011 | Page 51

Progress on other developments

Bream (Norway)

• Preferred FPSO identified
• Negotiations in progress
• Gardofa to be drilled in Q3

Grosbeak and Blåbær (Norway)

• Grosbeak appraisal imminent
• Blabaer is a possible tie-back to Jordbaer (PDO submitted)

Block A Aceh (Indonesia)

• PSC extension approved
• EPCI tender to be issued shortly

Caledonia and Ptarmigan (UK)

• Awaiting results from Bluebell

exploration well Dua (Vietnam)

• FEED in progress
• Development being optimised

24th March 2011 | Page 52

Exploration – Indonesia – Block A Aceh

Matang (Block A Aceh)

• Premier 41.67% equity
• Medco operator
• Gross reserves estimate 20-40-70 mmboe
• Low risk for gas

– Gas is the expected phase – Critical factor is reservoir presence – 250 bcf follow on potential in the success case

• Well planned for Q3 2011

Matang-1

PTD 3000m MD

E W

1500m

Top Peutu Depth

C.I.= 50 metres (structure) Carbonate Isochore (color fill)

2500m Matang-1

24th March 2011 | Page 53

Exploration – Indonesia – Buton

meters

‘B’

Bentang (Buton PSC)

• Premier 30% equity
• Japex operator
• Prospect reserve estimates 35-100-300 mmboe
• High risk for oil, in fold belt theme
• Drilling planned Q3 2011

Benteng NW SE

0 5000

24th March 2011 | Page 54

Exploration – Indonesia – Natuna – Anoa Deep

Anoa Deep (WL-5 extension) (Natuna PSC)

• Premier 28% equity
• Estimated reserves 47-57-90 bcf
• Targeting Lama Formation reservoirs directly underlying the West

Lobe platform on Anoa field. Lama Formation produces oil and gas in nearby Kakap field

• Moderate risk for gas
• Dilliing planned for Q2 2011

Top Lama Top H Top A PTD PRIMARY TARGET

SE Anoa Deep NW

5 Km

Top Lama Depth C.I.=50 feet

5000m 1400 acre Lowest Closing Contour WL5

24th March 2011 | Page 55

Appraisal well

Exploration – Norway – Grosbeak appraisal

Grosbeak (PL378)

• Premier 20% equity
• Successful Grosbeak well completed in July 2009

– Close to nearby infrastructure – Oil in Middle Jurassic sandstones – Estimated reserves 35-80-190 mmboe

• Appraisal well scheduled for Q2 2011

1500m

S N

Top Brent

Discovery well

Grosbeak

24th March 2011 | Page 56

Exploration – Norway – Bream, Gardrofa

Bream (PL406)

• Premier 20% equity
• BG operator
• Brent age oil discovered 1971, close to Yme Field
• In 2009,17/12-4 and its sidetracks wells appraised

this discovery, testing 2,516 boepd

• Estimated reserves 39-50-63 mmboe
• Formal concept selection targeted Q2 2011

Gardrofa (PL407)

• Premier’s first operated licence in Norway
• Premier 40% equity
• Untested trap flanking a Salt dome feature
• Estimated reserves 15-70-115 mmboe
• Moderate risk for oil
• Well planned for Q3 2011

9/1-1 Gardrofa Prospect Well Location

Success at Gardrofa will lead to a new core area for Premier in Norway

24th March 2011 | Page 57

P1466 Bluebell Prospect (15/24c,15/25f)

• Premier 60% equity
• Palaeocene Forties reservoir
• Reserves estimate 9-19-31 mmboe
• Partial carry by farm-in partner
• Well planned for Q3 2011
• Valuable tieback opportunity for Brenda/Balmoral

Exploration – UK – P1466 Bluebell

Top Forties Depth SS, CI=5 m Top Forties Lambda Rho Extraction Top Forties Lambda Rho Extraction Near Offset Lamda Rho, HC Indicator Bluebell Bluebell

Bluebell Well Location Bluebell Site Survey

Bluebell

Bluebell Well Location Bluebell

24th March 2011 | Page 58

Carnaby

Exploration – UK – Carnaby

Carnaby

• Premier 35% equity
• Prospective Resource estimates:

– Tay reservoir: 20-35-60 mmbo – Cromarty reservoir: 15-20-30 mmbo

• Expected phase oil

– Gas in shallower Eocene targets (Horda Fm)

• Risk assessment

– Moderate risk at Tay level - oil quality – High risk at Cromarty level - reservoir presence

Varadero Carnaby Catcher N & E

Catcher Main Catcher E Carnaby Varadero

N S

Cromarty Tay Horda

Burgman

Cromarty Depth Structure

Carnaby Prospect

Eocene amplitude extraction

Carnaby

24th March 2011 | Page 59

Exploration – UK – West Orkney Basin

P1577: West Orkney Basin

• Premier 100% equity
• 1,700 km2 acreage covering West Orkney Basin depo-centres
• Shallow water, low cost environment
• Frontier Rift Basin exploration opportunity
• Target is Pre-rift Devonian system preserved in Mesozoic rifts

– Petroleum system proven - exhumed oil accumulations on Orkney – Key uncertainty is presence and preservation of traps – Material unrisked play potential, presently high risk

• Work programme commensurate with risk reduction

– 6 year concession with a drill or drop option – Purchase 6,000 km of existing 2D data – Reprocess selected lines

• Go Forward plans

– Firm: Purchase, reprocess and interpret data 2011 – Optional: Acquire new seismic data 2012 and Drill 2013

A’ A Terraces with probable Devonian source and reservoirs and probable Zechstein seal

West Orkney Basin Structure Top Devonian Orkney Isles

Half grabens with Pre-rift section: Potenential for Devonian source and reservoirs plus Zechstein seal Orkney Islands; Inverted Devonian basins, with Breached oilfields Metamorphic highs; exposed at seabed Half grabens with possible Devonian source and reservoirs and proven Zechstein seal

24th March 2011 | Page 60

25th March 2010 | Page 60

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24th March 2011