Investor Presentation September 2012 Forward looking statements - - PowerPoint PPT Presentation

Investor Presentation

September 2012

September 2012 | Page 1

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.

September 2012 | Page 2

... is in an even stronger position than six months ago ...

• Stronger production and resource base
• Portfolio of operated developments will

deliver 100,000 boepd

• Acquisition activity positions us for future

growth beyond 100,000 boepd

• Transforming the exploration portfolio
• Existing projects, dividend and future

exploration programme fully funded

Premier today

Historic NAV/share CAGR of 14.2% at constant oil prices

... which is reflected in our first half results

• Production up 58% year-on-year;

pro-forma resources of 725 mmboe

• Solan, Pelikan, Naga and Dua approved;

Catcher moving forward

• Falkland Islands transaction
• Prospective resource portfolio increased

to 2.7 billion boe

• $1.3 billion of cash and undrawn facilities;

strongly rising cashflows and profitability

September 2012 | Page 3

Operations update

September 2012 | Page 4

Chim Sáo

• 1H Production averaged 26,000 boepd; higher level of

uptime achieved in Q2

• Currently producing at 35,000 boepd
• Water injection has commenced and rates are ramping up

to support reservoir pressure

• Two well supplementary drilling programme into additional

reservoirs completed in June – first well tied-in; initial production rate of 4,000 boepd – second well due on-stream in Q3

• Total well capacity in excess of 40,000 bopd

Dua

• Dua will develop ~10 mmbbls
• Prime Minister approval of FDP received in August
• Long lead items being procured and contracted
• Development drilling to commence in April 2013
• Subsea installation and tie-in in Summer 2013
• First oil 2014

Chim Sáo and Dua

September 2012 | Page 5

GSA 1 (Anoa)

• 1H production at maximum capacity

– Phase 4 expansion and Pelikan projects will access additional reserves and raise capacity

• Block A’s share of deliveries under GSA1 was 47%

against a contractual market share of 37%

• Block A’s share of remaining reserves dedicated to

GSA1 was 64% at start of year (before the Anoa Deep discovery)

GSA 2 (Gajah Baru)

• Production facility has performed very well
• All Singapore demand was met during the period but

build-up of rates has been slower than anticipated due to end user project delays

Gas Swap Agreement (Gajah Baru)

• Discussions to sell an additional 40 BBtud into the

Indonesian domestic market continue

Natuna Sea Block A

September 2012 | Page 6

• Development drilling completed in August

– To schedule and on budget – Better than expected well results – Debottlenecking study underway

• FPSO onshore modifications nearing completion
• Operator targeting sail away in September for

installation in October and first oil in December

• Drilling of East Rochelle, the first of the two

development wells, is in progress

• Upgrade of Scott Platform remains on track
• Subsea installation underway following the

arrival of the pipe lay vessel

• Operator expecting first gas in December

Huntington Rochelle

Huntington and Rochelle

September 2012 | Page 7

Solan

• Premier is Operator with 60% equity
• All significant contracts have been awarded

– Procurement and fabrication of platform (Burntisland Fabrications) – Heavy lift installation (Heerema) – Subsea tank fabrication (Dry Docks World Dubai) – Drilling rig (Awilco)

• Construction of topsides has commenced
• Phase 1 development drilling to commence in March 2013
• First oil targeted for Q4 2014 with an initial production

rate of 24,000 bopd

First Oil Government Approval

2012 2013 2014 Platform T ank Drilling Installation, Hook-up and Commissioning

FEED Design and Procurement Construction

September 2012 | Page 8

Significant licence changes

• Premier increased stake to 50% and appointed operator
• Strengthened partnership to progress development
• Time is needed to achieve consensus within new JV

Concept Selection work

• JV agreed subsurface work programme is in progress to

generate resource volume ranges

• Schedule and cost data for development concepts has

been validated through market enquiries

• Contracting strategies have been developed
• Concept Selection Recommendation has recently been

made to JV

• Continue to work with JV to expedite approval process

and first oil now modelled for early 2016, subject to FPSO contractor discussions

Catcher update

FPSO and Subsea Wells

September 2012 | Page 9

Sea Lion

Transaction details

• Farm-in for 60% of Rockhopper’s interests in the

Falklands

• Initial payment of $231 million plus an exploration and

development carry of up to $48 million and $722 million, respectively

• Fully funded from existing cash, facilities and cash

flow; commitment to fund dividend unchanged Development plan

• FPSO in 450m water depth; tanker offloading
• Associated gas used as fuel or re-injected
• 22 producers, 13 water injectors and a gas

injector, drilled from 3 subsea centres

• Insulated flowlines and risers
• HSPs for artificial lift and flow assurance
• Gross plateau rate of 80-85 kbopd
• Capex to first oil of ~$3 billion (purchased FPSO)
• Subsequent development of satellite fields

Possible outline schedule

• Concept Selection in Q2 2013
• Project Sanction in mid 2014
• First Oil in Q3 2017

September 2012 | Page 10

Fully funded programme

Development Funding

• Dividend, exploration

and all existing projects are fully funded at $85/bbl

• Capacity to increase

spend on exploration and new development projects at higher oil prices

• Forward profile funded

by cash flow and facilities even at $65/bbl

1800

Development capex

(US$ million)

400 200 800 600 1200 1000 1400

*Assumes standby funding is taken up by Rockhopper. Purchased FPSO case.

2013 2012 2015 2014 2016 2017

* * 1800

Investment Profile

(US$ million)

400 200 800 600 1200 1000 1400

2013 2012 2015 2014 2016 2017

1600

Acquisitions / disposals Exploration expenditure Development Capex Sea Lion Existing Assets

Note: Assumes exploration expenditure of $250 mm pa from 2013.

1600

September 2012 | Page 11

Exploration update

September 2012 | Page 12

Exploration 1H 2012 and vision

Vision

• 1.6 billion boe resources over life of plan, at a finding cost of

< $3/boe

• Opportunity to invest up to $500mm per annum from 2015
• Focus on geologies (Rift or Frontal fold belts) in existing or

new areas

• Building on $2.7 billion of NPV from Premier discoveries

(since 2005)* 1H 2012

• Success at Carnaby in the Catcher area, Anoa Deep on Natuna

Sea Block A and Badhra B North-1 appraisal well in Pakistan

• Unrisked prospective resource portfolio increased to 2,723 mmboe

(453 mmboe risked)** – Increased lead and prospect inventory in the Falklands, Iraq and Vietnam – APA 2011 and UK deferred 26th Round awards added

* DeGoyler & MacNaughton estimate ** Excludes PL23 and PL24 in the Falkland Islands, which are subject to licence extension

Portfolio increased by ~ 1 billion boe to 2,723 billion boe (net, unrisked) during 1H 2012

1.6 billion boe of net resource targeted

Existing New Existing

• 1. Known geologies

and/or skills in existing areas

• 3. New skills and/or

geologies in existing areas

Existing New

• 2. Known skills and/or

geologies in new areas

• 4. New skills and/or

geologies in new areas

New Existing New

Asia Rest of World and ENB North Sea

September 2012 | Page 13

<10 <100 >100 >250 Net NPV10 $mm >10 >25 >50 <10 Net EMV10 $mm

(shown as circle inside NPV)

Transforming the exploration portfolio

* Excludes PL23 and PL24 in the Falkland Islands

September 2012 | Page 14

Asia

12W 07/03 Tuna Buton Block A Aceh & Andaman Sea

LEARNINGS

Block 121 NSBA Phu Khanh Basin

• Anoa Deep success

– Play opener – More than 4 wells planned 2013/2014

• Buton Success

– Establish commerciality

• Matang to be drilled in Q4 2012
• 2 exploration wells planned in the

Nam Con Son basin in 2013

• Oligocene learnings transferred to

frontier geographies – Andaman Sea JSA – Block 121 in Vietnam

LEARNINGS

September 2012 | Page 15

Ca Voi prospect

Ca Voi (Whale) Prospect (Vietnam Block 121)

• Premier 40% equity (subject to Government approval)
• First test of the Oligocene clastics play in the Phu Khanh

Basin – Primary target is the Ca Voi prospect, a four-way dip closed structure below the Mid Miocene Unconformity – The Oligocene syn-rift sands are a proven hydrocarbon bearing reservoir in the region, including Premier’s Nam Con Son and Natuna Fields

• Risk assessment: high (a true

frontier wildcat)

• Gross prospective resource

assessment: 40-100-200 mmbo

• Well planned for 1H 2013
• Significant follow on potential

September 2012 | Page 16

L10A & L10B

• Potential to extend East African successful plays

into offshore Kenya (Tertiary rifts and Cretaceous fans)

• 2,535 km2 of 3D and 1030 km 2D acquired
• Preliminary dataset highlights prospectivity
• New 3D over Inboard play planned for Q4 2012
• Potential well(s) in 2H 2013

Kenya

Outboard Play Inboard Play

SW NE

September 2012 | Page 17

Approximate position of Block 12

Block 12

Gravity Map

• Premier (30%) has agreed to join Bashneft on Block 12
• 8,000 km2 block in the foreland of the Zagros fold belt up dip from

producing fields

• Multiple stacked reservoirs targeted
• Gross prospective resource potential in excess of 1 billion bbls
• Forward plan to acquire seismic over the block in 2013

SW NE

Iraq

September 2012 | Page 18

Pushing the plays wider

• Premier has the regional database to pursue amplitude

supported Tertiary prospects throughout the Central North Sea (CNS)

• Eocene prospects: Carnaby (drilled) and Cyclone

(remains to be drilled)

• 2014 drilling will target Inner Moray Firth

Pushing the Plays Deeper

• HPHT Triassic test at Lacewing

– Learnings will be applied to UK and Norway

• Jurassic test at Luno II

North Sea

Cyclone amplitude response

• n far stack data

Balder

Cyclone

Cyclone

Eocene Turbidite Sand Fairway

Carnaby

Lacewing

Lacewing Luno II Inner Moray Firth

PL 359

BCU Time Map

C.I. 100 ms

10km Johan Sverdrup Luno/Apollo Ragnarrock Luno II Prospect

September 2012 | Page 19

Norway

• Acquired three operated Norwegian concessions

from Nexen for $5.5 million in 2011

• Builds on Premier’s knowledge in the CNS

– Consistent with the Play Master approach – Adjacent to Premier-operated Freki Licence (PL 567, Premier 60%)

• Jurassic plays on the margin of the Mandal High

identified

• Adds > 250 mmboe to Premier’s net

un-risked lead portfolio

• Prospect maturation via seismic reprocessing

and geological studies

• Potential 2014 drilling targets

2km

SW 3/7-4 NE

Myrhauk Trym Field

Mandal High Target play below BCU PL 567 PL 539 is a key focus for prospect maturation Premier operates four licences Luno II

September 2012 | Page 20

PL032/033

• Unrisked prospect and lead portfolio >1 billion

boe (175 mmboe risked)

• Cretaceous fan and delta plays
• Deep Jurassic gas potential
• New 3D acquired and under evaluation

PL023/024

• Unrisked lead portfolio >2 billion boe

(100 mmboe risked)

• No CPR assessment
• Requires licence extension
• Yet to be evaluated by Premier

Falkland Islands

Sea Lion 14/10-9

At least 3 wells planned for 2014

September 2012 | Page 21

2012 New Venture activity

North Sea (Rift theme)

• UK and Norway Licence Rounds
• EnCounter partnership

Asia (Rift and Frontal Fold Belt themes)

• Andaman Sea
• East Vietnam
• Frontier Basins of East Indonesia

Rest of the World (Rift and Frontal Fold Belt themes)

• East Mediterranean (Cyprus) and Egypt
• Pakistan and Iraq
• Falkland Islands / Southern Africa

September 2012 | Page 22

Q3 Q4 Q1 Q2 Vietnam Block 121 Ca Voi 100 High Indonesia Block A Aceh Matang 40 Moderate PL359 Luno II 120 Moderate PL378 Skarfjell Appraisal P1655 Spaniards East 30 Moderate P1784 Cyclone 30 Moderate P1181 Lacewing 58 High P1430 Bonneville 10 Low P1887 Norfolk Kadanwari K-32 7 Low

Bhit-Badhra

Badhra South Deepening-1 38 High Kenya L10A & L10B Inboard 3D seismic Mauritania Commitment well TBC TBC Norway UK Middle East - Africa - Pakistan Pakistan Asia 2012 2013 P50 gross unrisked resource (mmboe) Risk North Sea

Weatherford 812 Bredford Dolphin Maersk Resiliant Wilphoenix Wilphoenix SLB Rig-23 Century Rig 28

Exploration drilling programme

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

The three key wells in the next 12 months are Luno II, Lacewing and Ca Voi, targeting at least ~100 mmboe of net unrisked prospective resources

Seismic acquisition

September 2012 | Page 23

Outlook

September 2012 | Page 24

• Strong growth in cash flow generation

– $2.6 billion per annum once Catcher

• n-stream
• Higher impact exploration

– Luno II, Lacewing and Ca Voi – 2013/14 programmes in Kenya, Norway and Falklands

• Continuing acquisition activity

– Financial strength and access to capital

• ffers continuing opportunities
• Dividend commitment
• Portfolio focussed on value creation

What can you expect from Premier?

Rapidly rising production and cash flow (kboepd)

2011 Huntington 2012 Sea Lion Catcher 40 75 60 100+ 100

Historic NAV/share CAGR of 14.2% at constant oil prices

September 2012 | Page 25

Appendix

September 2012 | Page 26

Record profitability

6 months to 30 June 2011 Operating costs ($/bbl) 1H 2012 1H 2011 UK $33.5 $34.2 Indonesia $9.1 $9.6 Pakistan $1.9 $2.1 Vietnam $15.3 – Group $14.7 $14.0 Highlights 6 months to 30 June 2012 Working Interest production (kboepd) Entitlement production (kboepd) Realised oil price ($/bbl) – pre hedge Realised gas price ($/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 Taxation Profit after tax 36.9 33.8 109.7 8.3 $m 342 (200) 142 (91) (9) 42 (9) 33 56 89 58.4 52.4 110.5 9.0 $m 744 (394) 350 (92) (13) 245 (50) 195 (49) 146

• 28% of 2012 production hedged at

$100/bbl

• 1H 2012 impact of $19.3 million

post-tax

• Forward sales for 2013 averaging

$110/bbl – currently 10% of production hedged Hedging

September 2012 | Page 27

Group taxation position

Overseas UK PRT CT Current charge* Deferred tax credits Tax charge/credit for the year

6 months to 30 Jun 2011 $m

16.0 33.1 (0.6) 48.5 (104.5) (56.0) Tax losses/allowances brought forward Losses/allowances for the period RFES Small field allowances Tax losses/allowances carried forward* UK Tax Losses/Allowances Position 1,360 175 68 46 1,649

6 months to 30 Jun 2012 $m

75.6 14.1 (3.6) 86.1 (37.3) 48.8

* fully recognised as deferred tax asset

Tax charge

* Current tax charge – 35% of operating profit

30 Jun 2012 $m

No UK CT cash taxes until 2018

September 2012 | Page 28

Rising cash flows

Cash flow from operations Taxation Operating cash flow Capital expenditure Disposals/(acquisitions), net Finance and other charges, net Pre-licence expenditure Net cash flow 6 months to 30 June 2011 $m

2012 Development Exploration

Estimated capex split ($m)

207 111 318

Regional split ($m)

246 (4) 242 (297) (87) (24) (10) (176) 6 months to 30 June 2012 $m 466 (141) 325 (318) 25 (103) (15) (86)

North Sea $180m Asia $124m Total $318m MEAP $14m

Full year capex forecast of $650 million (development) and $180 million (exploration)

September 2012 | Page 29

Strong liquidity position

Cash Bank debt Bonds Convertibles Net debt position Gearing (net debt/net debt + equity) Cash and undrawn facilities at 31 Dec 2011 $m 309 (484) (341) (228) (744) 36% 1,116 at 30 Jun 2012 $m 290 (316) (573) (232) (831) 31% 1,300

• Additional bank and bond debt raised in 1H 2012 of $585 million raising cash and

undrawn facilities (after some debt repayment) to $1,400 million

• No requirement for bank refinancing until 2015

September 2012 | Page 30

Wax management

Chim Sáo vs Sea Lion

• The wax content of the Sea Lion crude is

significantly less than the Chim Sáo crude

• However, the reservoir and seawater

temperatures at Sea Lion are significantly lower than Chim Sáo Chim Sáo

• Downhole Pour Point Depressant (PPD) injection
• Vacuum insulated tubing risers
• Crude oil storage and transportation at 55°C
• Insulated flowlines
• Round trip pigging to clear any wax deposition
• Gas injection for artificial lift

Chim Sáo Sea Lion Wax Content 30% 22% Wax Appearance Temperature 82°C 62-72°C Seabed Temperature 20°C 2°C Reservoir Temperature 150°C 82°C

Sea Lion

• In addition to the measures used at Chim Sáo:

– Selection of HSPs rather than gas lift – Heating of the power fluid to the HSPs – A higher degree of insulation to the production flowlines

• Costs built into base case

September 2012 | Page 31

Logistics

• No requirement for supply bases in Africa or South America
• This model successfully used for exploration and appraisal
• Cost structure assumed in base case

September 2012 | Page 32

Non-operated projects

Bream

• Completed SPA with Skeie in July; increased

equity in Bream to 40%

• FPSO and SURF FEED near completion
• Operator planning project sanction in October

– Cost pressures – Scope for area development exists

• Operator targeting 2015 for first oil

Frøy

• Joint Area Studies are underway with other
• perators to identify and evaluate the

preferred options for an area development Block A Aceh

• EPCI re-tender resulted in higher than

anticipated bids – Revisiting gas price with buyer

September 2012 | Page 33

North sea and Asia assets

September 2012 | Page 34

www.premier-oil.com September 2012