2010 Annual Results Presentation - Premier Oil · information that both represents management's...

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.


Agenda

Highlights and progress against strategy Simon Lockett

2010 financial results Tony Durrant

Exploration update Andrew Lodge

Operations update Neil Hawkings

Summary Simon Lockett


2010 highlights

• On track for production of 75,000 boepd in 2012

• Development portfolio building towards100,000 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


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 reservesand 100 kboepd production in the medium term


2010 financial results


Production and income statement

12 months to31 Dec 2009

Average gas pricing ($/mcf)2010 2009

Singapore $13.9 $11.0Pakistan $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 $23.2Indonesia $8.5 $10.0Pakistan $2.0 $1.9Group $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

Highlights12 months to31 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 revenuesCost of salesGross profitExcess of fair value over purchase considerationExploration/New BusinessGeneral and administration costsOperating profit Financial ItemsProfit before taxationTaxation creditProfit after tax

44.240.266.35.2

$m621

(361)260

6(77)(18)170(90)

8033

113

42.838.379.76.3

$m764

(531)233

-(87)(18)128(27)10129

130


Overseas

UK

PRT

CT

Prior period revisions

Current charge

Deferred tax credits

Tax credit for the year


$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


$m

56.9

25.9

nil

(21.3)

61.4

(90.4)

(29.0)


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


$m 2010

Development

Exploration

Estimated Capex split ($m)

349

165

514

2010 2009

Cash

Net Debt

Balance sheet ($m)

251

245

398

300

406

902Undrawn facilities

419

(71)

348

(303)

(643)

(55)

(20)

(673)


$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


Forward economics

80

2010A

70

60

50

0

10

20

30

40

OPEXTaxCash Margin

2012E 2014E 2012E 2014E

$79/bbl $75/bbl $100/bbl

New projects lead to improved cash margins

$/bo

e


Exploration update


Progress towards 200 mmboe of discoveries

200

100

50

02010 2011

150

2012 2013 2014

250Target cumulative risked additionsActual cumulative proved and probable discovered resourcesActual 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


Exploration drilling 2011

Firm Wells:Rig Contracted

Firm Wells:Rig TBC

Contingent Wells

All well timings aresubject to revision for operational reasons

Asia 2011Q1 Q2 Q3 Q4

Vietnam 07/03 CRD Appraisal104/109-05 Jackfruit

Indonesia Tuna Gajah Laut UtaraBelut Laut

Buton BentengNatuna Sea Block A Anoa Deep

Biawak BesarBlock A Aceh Matang-1

North SeaNorway PL406 (8/3) Gardrofa

PL378 Grosbeak AppraisalUK P1430 Burgman

CarnabyP1466 Bluebell

Middle East - PakistanPakistan Kadanwari K-25ST

K-28K-29K-27 SE-1

Bhit/Badhra Badhra-6 (Parh)Badhra Appraisal

Egypt North Red Sea Cherry

Ocean GeneralOcean General

Songa Delta

West CallistoWest Callisto

Weatherford 812

Stena Forth

Weatherford 812

Weatherford 812

• > 300 mmboeunrisked resource

• 2011 full year exploration expenditure ~ $200 million pre-tax

Ocean General

Bredford Dolphin

Galaxy II

Weatherford 812Weatherford 812

Aquamarine

12 to 15 exploration and appraisal wells already planned in 2012


CRD-2X

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

Anomalies associatedwith 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


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 GajahLaut 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

PRIMARYTARGET

SE

SECONDARYTARGET

Belut LautPTD 4300m MD (3870m TVD)

NW

2 Km

PRIMARYTARGET

W E

SECONDARYTARGET

PTD

Gajah Laut UtaraPTD 4250m MD (3550m TVD)


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

PTD3D Seismic Inversion

indicating gas pay

Top Arang DepthC.I.=100 metres

2000m

Iguana Discovery

Biawak Besar-1

Bison Iguana Biawak Besar

PRIMARYTARGET

500m

SENW


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

T600Coals

T1000 Base Tertiary

T500

T700

W E


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

CatcherNorth

Varadero

Burgman

CatcherEast

Burgman

Catcher

Varadero


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

NS

Fulmar

Cromarty

Upper Tay

Burgman

Carnaby

Lower Tay

NW SE

Catcher Main

Catcher E

Burgman

VaraderoCromarty Depth Structure

Burgman location

Burgman Burgman ST


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


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 PLATFORMMOMBASA

HIGHINBOARD

TERTIARY RIFT

Rift Margin Plays

INVERTED JURASSIC RIFT

EW Inverted Rift Play

L10BBG 45%Premier 25%Cove 15%Pancon 15%

L10ABG 40%Premier 20%Cove 25%Pancon 15%

New Rift Plays


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 2013UK – 15/9, 10, 13b, 14 and 15• Lower Cretaceous and Tertiary play fairways• 3D acquired in 2010• One well planned in 2012UK – 15/23g, 14/30b, 15/26c• Near field exploration • Successful West Rochelle well in 2010UK – 21/7b • Tertiary amplitude play• Well planned for 2012UK – 22/21c, 22/26c• Pre Cretaceous target• 3D planned in 2011

Norway: 2011 New acreageNorway – 35/12• Upside potential to GrosbeakNorway – 2/6 • Multiple target block secured on a drill or drop option


Total Portfolio Unrisked Prospective Resource

Total Portfolio Risked Prospective Resource

Resource under appraisal105 mmboe

Leads1000 mmboe

Prospects800 mmboe

Total>1900

mmboe

Leads80 mmboe

Prospects160 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 mmboeof 2P reserves by 2015

Resource under appraisal105 mmboe


Operations update


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


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 split63% gas and 37% oil, but 62%

of production is linked to oil price

50

Production (working interest)(kboepd net)

20

10

0

25

35

45

2006 2007 20102008 2009 2011E

40

30

5

15

Middle East-PakistanNorth Sea / W. AfricaAsia


• 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

02007 2008 2009 2010 2011E


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

0Sep 10

6

8

14

16

Oct 10 Nov 10 Dec 10 Jan 11 Feb 11 Mar 11

Balmoral AreaWytch FarmScott and TelfordKyle and Others

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


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)

0

40

80

20

60

100120140160

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Natuna ‘A’ 2014


Development drilling at Anoa


Progress towards 75,000 boepd

Gajah Baru Chim Sáo Huntington


• 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


Gajah Baru CPP jacket to be installed in June


Gajah Baru CPP topsides nearing completion


• 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-S10PCS-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


Chim Sáo – Lewek Emas FPSO

March 2010 March 2011

October 2010


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


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

15/26b15/26c

Kopervik pinch-out

Rochelle FDA


Progress towards 100,000 boepd

SolanCatcherFrøy


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


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 commencein Q2 followed by FPSO market enquiries

• Project sanction targeted for mid 2012

• First oil targeted for mid 2014

Illustrative Catcher Development


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


A path to 100,000 boepd

120

Production(kboepd net)

40

20

0

60

80

100

Development capex($m)

2011 2012 20152013 2014 2016

Future Asia developmentsFuture Norway developmentsFuture UK developmentsHuntingtonChim Sáo, Gajah BaruOn production

800

200

100

0

300

400

500

2011 2012 20152013 2014 2016

Future Asia developmentsFuture Norway developmentsFuture UK developmentsHuntingtonChim Sáo, Gajah BaruOn production

700

600


Summary


Target Asia MEP North Sea

75,000 in 2012 Chim Sao andGajah Baru Pakistan growth Huntington

Commercialise potential developments

Future Singapore gas

Tight gasopportunity

Catcher, SolanNorway

Add 200 mmboefrom 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


Appendix


Reserves and resources

500

2006

450

400

350

0

150

200

250

300

2007 2008

100

50

Reserves and contingent resources(mmboe)

Production Additions &Revisions

End 20102009

2C contingent resources2P reserves

227

261


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


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 oron 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


Indicative Net New Field Rates Equity%

Net InitialRate (boepd)

2012UK Huntington 40.00 9,000

Rochelle TBA 2,0002013UK Solan 60.00 7,200

Caledonia / Ptarmigan Area 80.00* 5,000Norway Bream 20.00 6,000Asia Dua 53.13 5,0002014UK Catcher Area 35.00 10,000

Fyne 39.90 8,000Norway Froy 50.00 18,000Asia Block A Aceh 41.67 5,000

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

Indicative field rates


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


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 2011Matang-1 PTD 3000m MD

EW

1500m

Top Peutu DepthC.I.= 50 metres (structure)

Carbonate Isochore (color fill)2500m

Matang-1


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

BentengNW SE

0 5000


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

PRIMARYTARGET

SE

Anoa Deep

NW

5 Km

Top Lama DepthC.I.=50 feet

5000m

1400 acre

Lowest Closing Contour

WL5


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


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


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


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 CatcherN & E

Catcher Main

Catcher E

Carnaby

Varadero

NS

Cromarty

Tay

Horda

Burgman

Cromarty Depth Structure

Carnaby Prospect

Eocene amplitude extraction

Carnaby


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 Devonianbasins, withBreached oilfields

Metamorphic highs; exposed at seabed

Half grabens with possible Devonian source and reservoirs and proven Zechstein seal

24th March 2011 | Page 6025th March 2010 | Page 60

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