2009 Half-Yearly Results Presentation 27th August 2009

2009 Half-Yearly Results Presentation 27th August 2009

27th August 2009 | 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

2009 highlights Simon Lockett

Finance Tony Durrant

Operations update Neil Hawkings

Exploration update Andrew Lodge

Summary Simon Lockett


2009 highlights – a transformational first half

• Oilexco: a favourable price and a step change in North Sea• Additional equity in Block 12W; material interest in key project• Reserves and resources increased by 17%

Acquisitions

Exploration• Success in Vietnam on Block 07/03• Premier’s first well in Norway also a success• Focus in 2010 returns to South-East Asia

• Production up 4% at 39,700 boepd• Step up following Oilexco acquisition, Shelley now on-stream• Record Pakistan production and strong performance from Anoa

Production

Development• Asian developments progressing well• Lower cost estimates as result of re-tendering/re-designing• Huntington – concept selection targeted by end 2009

• Extended debt facilities and successful rights issue• Fully funded forward development plan• Flexibility to take advantage of further opportunities

Finance

• OGP survey results: Premier best performing company for TRIF* in Drilling• Production TRIF* performance in top quartile• Premier TRIF* <1 per million man hours, 350% improvement over 5 years

HSE

* Total Recordable Injury Frequency


Strategy

Strategy

• Targeting production growth to 75,000 bopd by end 2013

• Exploration programme within disciplined spend

• Acquisitions focus on our three core areas

• Conservative financing plan

Progress

• Projecting 60,000-65,000 boepd at end 2011 post start up of Gajah Baru and ChimSao

• Up to 15 exploration and appraisal wells over next 15 months

• Oilexco and Block 12 (Vietnam) completed; non-core divestitures underway

• Demonstrated ability to access debt and equity markets

90

Production forecast(kboepd net)

50

40

20

10

02009 2010 2011

30

60

20142012 2013 2015

70

80North Sea developmentsAsian developmentsExisting production


Half-yearly financial results


Production and income statement

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 taxationTaxationProfit after tax

6 months to30 Jun 2008

38.033.1

110.06.6

$m386

(139)247

-(32)(11)204(13)191

(119)71


39.737.053.0

5.0

$m214

(117)9760

(25)(7)

125(52)

73(46)

27

Average gas pricing ($/mcf)1H 2009 1H 2008

Singapore $8.94 $16.16Pakistan $3.86 $3.28

Average Brent oil price was $52 (1H 2008: $110/bbl)

Operating costs per barrel ($/bbl)2009 2008

UK $16.1 $21.7Indonesia $ 7.6 $ 6.5Pakistan $ 1.6 $ 1.3Average $ 8.2 $ 9.6

Includes mark to market adjustment on hedging of $44.2 million (pre-tax)

Includes write-off of $17.9m for PSC B, Mauritania

Includes $22.7m of additional depreciation in respect of Chinguetti downgrade


Oilexco acquisition accounting (at completion)

$million

501

10

511

Nil

569

144

(10)

(126)

577

66(6)

60

Purchase consideration

Acquisition expenses (external)

Cost of Acquisition

Allocation:Exploration and evaluation assets

Oil and gas properties

Deferred tax assets

Net current assets

Decommissioning obligations

Fair value

Excess of fair value over purchase considerationLess acquisition expenses (internal)

Net effect on the income statement


Hedging

• Policy remains to underwrite value of projects by putting inlow cost floors

• 2009 Hedging Transactions:

– Existing $40/$100 floor/cap revised to $50/$80 for 2010and 2011 for half existing oil production

– New hedging in place for Oilexco acquisition; 50% production at floor of ~$53/bbl for 2H 2009-2011

• Hedging impact$m

Cash premia paid 12.5

Mark-to-market movement (non-cash) 31.7

Charge to income statement 44.2

• Group-wide ~25% of 2009-2011 oil and gas production hasan average floor of $52/bbl (oil) and $45/boe (gas) production

– Pakistan gas is unhedged


Cash flow

260

(69)

191

(74)

-

-

(7)

110

Cash flow from operations

Taxation

Operating cash flow

Capital expenditure

ONSL acquisition cost

Finance charges, net

Pre-licence expenditure

Net cash flow


$m

H1 2009 H1 2008

Development

Exploration

Estimated Capex split ($m)


$m

142

(29)

113

(111)

(511)

(18)

(7)

(534)

51

23

74

70

41

111

Forecast full-year 2009 spend of $230m (development) and $140m (exploration)

Development Exploration

Asia

MEP

Estimated 2009 Regional Capex split ($m)

32

0

9

19

15

36North Sea

4170


Net debt and funding programme

$m

117

(534)

237

(3)

(183)

Current balance sheet

Opening net cash

Net cash out flow

Equity issued

Non cash movements

Closing net debt*

Forward plans

• ONSL bridge facility ($175m) being extended in size and maturity to match main facility

• On completion of financing, expected cash and undrawn facilities of around $500million

• Available funding and covenant headroom to meet capex requirements at $45/bbl

* Includes $71m of restricted cash

600

Development capex forecast (2P reserves)($m)

200

100

02009 2010 2011

300

20142012 2013 2015

400

500

North Sea developmentsAsian developmentsExisting production


Operations update


Production update

50000

Production (Working Interest)(boepd)

30000

25000

10000

5000

02006 2007 2008

15000

20000

35000

North SeaAsiaMiddle East-Pakistan

Forecast fullyear 2009

• Deliveries from expanded plants meeting strong Pakistan gas demand

• Good production performance from Anoameeting strong Singapore gas demand

– Kakap production impacted by gas compression issues

• Balmoral area production currently impacted by acceleration of shutdowns and system bottlenecks

• Shelley now on-stream

• Good performance on Wytch Farm and Kyle but Scott impacted by plant issues

• Average full year production projected to be around 46kboepd

40000

45000


MEP – Pakistan – producing fields

• Capitalising on completed plant expansions to take advantage of strong local gas demand

• Ongoing infill development drilling and compression projects to maintain rates

• Qadirpur (27.2 mmscfd, net)– Plant capacity enhancement (end 2008)– Compression project and tie-in to local

power plant planned for 2010

• Kadanwari (7.6 mmscfd, net)– K-14 successful and tied in

• Zamzama (41.5 mmscfd, net)– Infill wells 6 and 7 onstream and tie-in of

Zamzama North

• Bhit/Badhra (20.3 mmscfd, net)– Improved production from phase 2 plant

• Kadanwari gas price capped at $8.50/mmbtu; licence extended to 2022 from 2017

KadanwariBhitZamzamaQadirpur

16000

Pakistan Production (boepd)

12000

10000

4000

2000

02006 2007 2008

6000

8000

14000

1H 2009


Asia – Indonesia – West Natuna Block A

• Continued strong demand from Singapore market• Consistent overperformance on Anoa allowing 3 well

development programme to be postponed to 2010• FEED work underway on Anoa compression project• Conceptual studies commenced on future GSA1 field

developments


Gajah Baru• Delivering significant cost reductions:

– Latest capital expenditure estimate $196mm net to Premier– Positioned to capture lower rig rates and development drilling costs

• First gas 2011 meets contractual obligations with gas buyer in Singapore• Overall project progress around 20%• Transportation agreements supporting Batam GSAs targeted for H2 2009

Asia – Indonesia – West Natuna Block A


• FEED completed in February, further optimisation studies ongoing• Latest cost estimate $210mm net to Premier• EPCI and rig tenders being prepared with bids targeted for year end• PSC signature for North Sumatra Block A delayed awaiting Indonesian government• First gas expected from Alur Rambong in 2011 and from Alur Siwah in 2012

Asia – Indonesia – North Sumatra Block A


Chim Sáo

• Petro-Vietnam announced intention to back in for 15%

• Acquisition of additional 21.25% from Delek for $72 million

• Construction work on jacket 37% complete at 30 June

• Latest capital expenditure estimate $450mm net

• Two FPSO solutions, both with finance available, are in final stages of negotiations

• First oil targeted for mid-2011

Block equities (post PV back-in)Premier Oil plc 53.125%PetroVietnam 15.000%Santos 31.875%

Asia – Vietnam – Block 12W


North Sea – UK – Balmoral Area

• Average daily contribution of 12,600 boepd

• Riser renewal work accelerated from 2010 into 2009

• Debottlenecking work nearing completion– Gas lift system– Produced water system– Subsea Pump

• Infill drilling now planned for 2010

• Burghley development progressing– Commercial arrangements completed– Well being drilled– Platform tie-in work under way– Opex-sharing commences in 2010


North Sea – UK – Shelley

• Development stalled by Oilexco administration

• Post-acquisition:– Contract re-negotiated with Sevan– Innovative short duration risk sharing

contract– Hook up completed and onstream

August 6th– Since start-up production has averaged

over 8000 bopd with some well downtime– Reservoir performance is uncertain


• Successful infill wells 2 and 3 leading to fourth well

• Expect full plant availability in H2 2009 • Partnership actively developing long term

3rd party business strategy• Near term satellite developments include:

– Bugle– Rochelle– Blackhorse

North Sea – UK – Scott Area


North Sea – UK – Huntington

• Premier equity in Block 22/14b is 40%

• Concept selection process ongoing:– targetted for end 2009– tie backs to hosts eg ETAP– FPSO/FPV options

• First production forecast for 2012

• Unitisation process underway to establish:– equity in unit area / voting arrangements /

unit operatorship


North Sea pre-development portfolio

Grosbeak

Frøy

Bream

Moth

Fife

Huntington

Scott satellites

Caledonia

• North Sea pre-development portfolio has significantly increased due to:– Exploration success in Norway– Acquisition of Oilexco

• Contingent resource base of75 mmboe


Reserves and resources

500

Reserves and resources(mmboe)

2005

450

400

350

0

150

200

250

300

2006 2007 2008 Proforma30 June 2009

2C reserves2P reserves

100

50

181

265


Production and development forecast

90

Production forecast(kboepd net)

50

40

20

10

02009 2010 2011

30

60

20142012 2013 2015

70

80North Sea developmentsAsian developmentsExisting production

600

2P reserves development capex forecast($m)

200

100

02009 2010 2011

300

20142012 2013 2015

400

500

North Sea developmentsAsian developmentsExisting production


Exploration update


Exploration strategy

• Currently focused on the growth of the company’s resource base through “Greenfield” discoveries in areas of expertise.

• In 2009/2010 this Greenfield focus is on three basins:

– Asia: Nam Con Son Basin (Vietnam and Indonesia)

– North Sea: Northern North Sea (Norway)

– West Africa: Congo Basin (Congo)

• In addition to Greenfield drilling, “Nearfield” exploration wells are planned in Premier’s existing core areas.


Asia – Vietnam – Block 07/03

• First well completed in June 2009

• Flow test from two zones 3,265 bopd plus 8.1 mmscfdthrough 48/64” choke

• Premier 30% equity and operator

• Discovery in sandstone reservoirs of the Thong MangCau, Upper Dua and Cau formations

Cau

Middle Dua

Approx Basement

NCS carbonate

2.5 km

NW SE

M MioceneUnconformity

Wellbore

TMC & UpperDua Sandstones

CauSandstones


Tuna • 65% operated interest• Discovery in Vietnam has reduced the risk on

Tuna acreage• 3D seismic planned for Q4 2009• Two-well programme beginning Q3 2010

NW SEGajah Laut

10km

Asia – Indonesia – Tuna


West Africa – Congo – Marine IX

Frida• Operated by Premier• Well spudded 23 July 2009• Target depth reached on 22 August 2009; no

hydrocarbons encountered• Well will be plugged and abandoned• Results being integrated to determine potential

of Ida (contingent well Q4 2010)Frida


MEP – Pakistan – Bado Jabal

• Vertical well spudded Q1 2009 • Targeting the deeper Lower Goru (Early Cretaceous)

and Chiltan (Jurassic) Limestone horizons • Reserves target 1 tcf• Premier’s equity 6%


North Sea exploration and appraisal portfolio

Grosbeak

Moth

• Evaluation of acquired Oilexcoportfolio ongoing

• Two licences awarded from the 25th Licensing Round:– Block 15/23e is adjacent to the

Bugle area, near the Scott Field– Block 29/7b includes a pre-existing

discovery near the Kyle Field

• Active programme:– Grosbeak/Gnatcatcher– Bream/Gardrofa– Greater Luno– Blåbaer– Bugle North– Moth

Gardrofa

Greater Luno

Blåbaer

Bugle North

Bream


North Sea – UK – Bugle North

Bugle North (15/23d, 15/23e)• Premier 41% equity and operatorship• Nearfield exploration opportunity• Reserves estimate 5-7-10 mmboe• Adjacent Bugle discovery flowed 7,398 bopd and 9.06 mmscfd gas• Drilling planned for Q2 2010


Moth

• 50% equity in 23/21

• 57.5% operated equity in 23/22b

• 70% operated equity in 7/7d and 7/10a

• Moth discovery max flow rate 24.4 mmscfd gas and 2460 bopd

• Appraisal of Moth and potentially a deep pre-Cretaceous target are under evaluation

• Timings subject to partner approvals

North Sea – UK – Moth

Moth Appraisal(Planned)


North Sea – Norway – Block 35/12, 36/10

Grosbeak/Gnatcatcher• Successful Grosbeak well completed in July 2009• Operated by Wintershall• Close to nearby infrastructure• Hydrocarbons in both Upper Jurassic and Middle

Jurassic sandstones• Estimated 35-190mmboe• Premier 20% equity

Gnatcatcher

SW NE


North Sea – Norway – Bream/Gardrofa

Bream (17/12)• Brent age oil discovered 1971, close to Yme Field• 17/12-4 and its sidetracks wells appraised this

discovery, testing 2,516 boepd• Operated by BG• Estimated reserves 39-50-63mmboe

Gardrofa (8/3)• Premier’s first operated licence in

Norway• Maersk Guardian will drill well in 2010• Estimated reserves 20-40-90 mmboe• Potential value-add opportunity to the

Bream discovery


Blåbaer Jordbaer

34/2-434/2-334/2-2

Blåbaer (34/2,5)• Premier 15% equity• Operated by BG• Reserves estimate 15-30-75 mmboe• Drilling planned for late 2009/early 2010

North Sea – Norway – Blåbaer


North Sea – Norway – Greater Luno

Greater Luno (16/1[part], 16/4)• 30% interest• Operated by Lundin• Targeting Jurassic sandstones related to the

Luno discovery (95mmboe) on adjacent Lundin-operated block; Luno extension currently drilling

• Statoil farm-in to Lundin equity in April 2009• Estimated reserve range 30-150-250 mmboe• Drilling planned for Q4 2009


Exploration outlook

2009Q3 Q4

2010AsiaVietnam: 07/03

104-109/05

Indonesia: Tuna

Natuna Sea Block A

N. Sumatra A

Buton

West AfricaCongo: Marine IX

North SeaNorway: PL359 (16/1,4)

PL374S (34/2,5)

PL406 (8/3)

UK: 15/23d, 15/23e

28/9, 28/10c

Middle East/PakistanPakistan: Badhra

Kadanwari

Contingent WellsFirm Wells: Rig Contracted Firm Wells: Rig TBC Seismic Programme

All well timings are subject to revision for operational reasons

Q1 Q2 Q3 Q4Beta

Anoa Deep

Ida

Gardrofa

Greater Luno

Blåbaer

Bugle North Appraisal

Catcher

Bado Jabal (Badhra Deep)

K-19


Summary


What next?

Tactics and execution

• North Sea Business Unit– Build on capability now organisation is integrated

• Progress Asian programme– Development projects proceeding– Capturing cost reduction opportunities

• Drill out significant exploration programme– Follow up on Vietnam success– Actively explore in Indonesia and Norway

• Seek new greenfield opportunities

• Take advantage of active acquisition market in North Sea and Asia– Selective focus to ensure value– Asset sales to focus portfolio

• Maintain liquidity in cash or undrawn facilities – Underwritten by hedging

Strategy

• Targeting production growthto 75,000 bopd by end 2013

• Exploration programme within disciplined spend

• Acquisitions and divestitures; focus on core areas

• Continue to operate conservative financing strategy


Appendix


HSE performance

• Recordable Incident Rate has been declining

• Performance is top quartile in the industry

• Challenge is sustainability

• TRIF = Lost Time Injury (LTI) + Reduced Work Day Case (RWDC) + Medical Treatment Case (MTC) frequency per million man-hours

• There was 1 LTI and 0 RWDC incidents in 2008• There have been no LTI or RWDC in the first half of 2009

Association of Oil and Gas Producers Benchmarking Survey, H1 2009

20

Total recordable injury rate - ProductionPer million hours worked by company with contractors

18

1416

121086420

20

Total recordable injury rate - DrillingPer million hours worked by company with contractors

18

1416

12108

46

20

6

Total recordable injury frequency (TRIF)

5

4

3

2

1

02003 2004 2005 2006 2007 2008 1H 2009

Premier TRIF

27th August 2009 | Page 44www.premier-oil.com 27th August 2009

Documents

2009 Half-Yearly Results Presentation 27th August 2009