2012 Half Yearly Results 23 August 2012 - Premier Oil...Singa / Kuda Laut MatangBonneville Badhra-6...

2012 Half Yearly Results 23 August 2012

23 August 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.


Agenda

Introduction Simon Lockett

Operations update Neil Hawkings

Exploration update Andrew Lodge

Financial results Tony Durrant

Outlook Simon Lockett


... 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


Operations update


Production update

• Production averaged 58,400 boepd, up

58 per cent

– Q2 production in excess of 60,000 boepd

• Chim Sáo and Gajah Baru performing well

• Strong Pakistan production due to compression

upgrades and successful infill drilling

• Improved uptime at Balmoral and good

production from a new well at Scott

• Increased share of Wytch Farm production

following completion of acquisition

• 75,000 boepd, once Huntington and Rochelle

on-stream

80,000

2012 Production

(bbls/day)

40,000

20,000

0

60,000

Q1 Q3 Q2 Year end

run rate

70,000

Q4

50,000

30,000

10,000

Huntington/Rochelle

Other UK

Pakistan & Mauritania

Vietnam

Indonesia


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


GSA 1 (Anoa)

• 1H production at maximum 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


Anoa Phase 4

• Project will increase Anoa reserves by ~200 bcf

by lowering surface flowing pressures

• Also increases Anoa capacity above 200 BBtud

• Construction barge has arrived on location;

compression modules currently being installed

• Second construction campaign prior to first gas

in Q3 2013

Anoa Phase 4, Pelikan and Naga

Pelikan and Naga

• Pelikan and Naga will develop ~150 bcf of gas

• EPCI contract awarded in May

– Construction of jacket / topsides commenced

• Construction of pipeline material underway

• Tendering process to secure a rig for 2013 and

2014 development drilling commenced

• First gas 2014


• 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


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 expected to

commence in

March 2013

• First oil targeted for

Q4 2014 with an

initial production

rate of 24,000 bopd


Solan development schedule

First Oil Government Approval

FEED

Design and Procurement

Construct

2012 2013 2014

Platform

Tank

Drilling

Installation, Hook-up and Commissioning


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


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

operators 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


Sea Lion – transaction rationale

• Progresses Premier’s strategy of growth through

investment in high quality development projects

• Provides a further operated core area for Premier

in a new oil prone basin

• Leverages Premier’s strong operatorship and

FPSO development capabilities

• Ongoing exploration opportunities in the North

Falklands basin, leveraging Rockhopper’s proven

exploration expertise

• Adds approximately 200 mmbbls of net discovered

2C resources at a low upfront cost, together with

net risked prospective resources of 175 mmboe

• Significantly extends Premier’s production growth

beyond current development projects and is an

excellent fit with strongly rising cash flows

• Fully funded from a combination of existing cash

resources, facilities and cashflow from operations;

commitment to fund dividend unchanged

Pro-forma 2P Reserves and 2C Contingent Resources

Split by Region

North Sea

31%

Falkland Islands

28%

Pakistan & Mauritania

9%

Asia

32%

Pro-forma 2P Reserves and 2C Contingent Resources

(mmboe)

800

600

400

200

0 2P Reserves 2C

Contingent

Resources

2P Reserves

& 2C

Contingent

Resources

Falkland

Islands

Farm-in

Pro-forma 2P

Reserves & 2C

Contingent

Resources

Total

~725

mmboe


• 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

• Hydraulic submersible pumps (HSPs) for artificial

lift and flow assurance

• Gross plateau rate of 80-85 kbopd

– 120 kbopd produced fluids

– 200 kbwipd

– 140 kbwpd power fluid for HSPs

– 60-90 mmscfd gas handling

• Assumed capex to first oil of $3.2 billion

(purchased FPSO)

• Subsequent development of satellite fields

Sea Lion – development plan


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

Wax management


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


STUDY DESIGN EXECUTE PRODUCE

Concept Selection Project Sanction First Oil

Provisional Sea Lion development schedule

2012 2013 2014 2015 2016 2017 2018

Concept Validation Studies

FDP Preparation, Submission and Approval

Subsea

FPSO

Wells

Offshore Installation, Hook-up & Commissioning


Exploration update


Exploration vision

Deliver material resource and value to the company

• 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)*

1.6 billion boe of net resource targeted Existing New

Ex

istin

g

1. Known geologies

and/or skills in

existing areas

3. New skills and/or

geologies in

existing areas

Ex

istin

g

Ne

w

2. Known skills and/or

geologies in new

areas

4. New skills and/or

geologies in new

areas

Ne

w

Existing New

Asia Rest of

World

and

ENB

North

Sea

* DeGoyler & MacNaughton estimate


• Unrisked prospective resource portfolio – 2,723

mmboe*

– 616 mmboe in prospects

– 2,093 mmboe in leads

• Portfolio increased since December 2011

– Increased lead and prospect inventory in the Falklands,

Iraq and Vietnam

– APA 2011 and UK deferred 26th Round awards added

• Risked prospective resource portfolio – 453 mmboe

– 174 mmboe in prospects

– 268 mmboe in leads

– Greater focus to lead maturation in 2012/2013

Prospective resource portfolio

increased significantly during 1H 2012

Risked Net Prospective Resource (mmboe)

Appraisal

11 (3%)

Drillable

55 (12%)

Prospects

119 (26%)

Leads

268 (59%)

Total

453

mmboe

Unrisked Net Prospective Resource (mmboe)

Appraisal

14 (1%)

Drillable

169 (6%)

Prospects

433 (17%)

Leads

2,093 (77%)

Total

2,723

mmboe

Portfolio increased by ~ 1 billion boe to

2,723 billion boe (net, unrisked) during 1H 2012

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


Norway

PL378:

Grosbeak &

Skarfjell

.

Norway

PL374S:

Blabaer

Appraise Drill Evaluate

Acquire Licence Gate

Drill Decision

Gate

Appraisal

Approval Gate

Project

Extension

Gate

Re

st

of

Wo

rld

N

ort

h S

ea

As

ia

Pre-

Development

Spaniards

East

Mackerel

K-32

Badhra-7

New York

Lacewing

Silver

Sillago Singa /

Kuda Laut

Matang

Badhra-6

Parh

Vietnam

Block 12W: CS Cau

Leads Prospects Mature

Prospects

Herring

Drillable

Prospects

Bonneville

Indonesia

Buton: Benteng

Ca Voi

Cyclone

Luno II

<10 <100 >100 >250

Net NPV10 $mm

>10 >25 >50 <10

Net EMV10 $mm (shown as circle inside NPV)

Badhra

South

Transforming the exploration portfolio

Falkland Islands*

Block 121

Norway and

Inner Moray Firth

Swordfish

Iraq

Peer Review

Peer Assist

* Excludes PL23 and PL24 in the Falkland Islands


Asia 1 3

2 4

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

• Chim Sáo North West (CS-3X)

drilled

• 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


• Premier has added 600 bcf of net reserves

through conventional exploration

• Exploration focussed on the Kirthar Frontal

Fold-belt and Foreland basin

– The basin is now mature for conventional

exploration

– Value adding near-field exploration

continues (K-30 and Badhra-7)

• Can unconventional resources reset

the curve?

– 2012 pilot project on Kadanwari

Pakistan assets

700

Net Cumulative Initial Reserves

(bcf)

400

200

0

500

1990

600

100

300

1995 2000 2005 2010

1 3

2 4


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 1 3

2 4

Outboard Play Inboard Play

SW NE


Approximate position of Block 12

1 3

2 4

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


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

1 3

2 4 North Sea

Cyclone amplitude response

on 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


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

1 3

2 4

PL 567

PL 539 is a key focus

for prospect maturation

Premier operates

four licences

Luno II


PL 539

• Targeted for early

2014 drilling

• Jurassic onlap to a

basement high

• Premier equity 40%

2km 2km

SW

3/7-4

NE SE NW

Myrhauk Trym Field Myrhauk

Mandal

High Mandal

High

Target play

below BCU

Target play

below BCU

1 3

2 4 PL539 Myrhauk Lead


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


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

1 3

2 4


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


Exploration – delivering the strategy

Key deliverables over the next 18 months...

Established areas

• Drill effective plays tests at Luno II and Lacewing

• Mature drillable prospects for 2103/2014 drilling

– Mandal High (Norway)

– Inner Moray Firth (UK)

– Lama Play (Indonesia)

New areas

• Drill an effective play test in the Phu Khanh

Basin (Vietnam)

• Mature drillable prospects in Kenya and the Falklands

• Secure 2 high impact new ventures

1.6 billion boe of net resource targeted


Financial results


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


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


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


$m 2012

Development

Exploration

Estimated capex split ($m)

207

111

318

Regional split ($m)

246

(4)

242

(297)

(87)

(24)

(10)

(176)


$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)


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


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

0

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

0

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


Outlook


• Strong growth in cash flow generation

– $2.6 billion per annum once Catcher

on-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

offers 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

23 August 2012 | Page 42 www.premier-oil.com 23 August 2012

2012 Half Yearly Results 23 August 2012 - Premier Oil...Singa / Kuda Laut MatangBonneville Badhra-6...

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Transcript of 2012 Half Yearly Results 23 August 2012 - Premier Oil...Singa / Kuda Laut MatangBonneville Badhra-6...