beach energy limitedbeach energy limited, asian roadshow– 4-7 july 2011 slide 7 • fy11 guidance...

Beach Energy Limited, Asian Roadshow – 4-7 July 2011

Beach Energy LimitedBeach Energy Limited

Reg Nelson

Managing Director

Reg Nelson

Managing DirectorHong Kong – 4&5 July 2011

Singapore – 6&7 July 2011

‘Evolution and Revolution’


Overview


Compliance statements

Disclaimer

• This presentation contains forward looking statements that are subject to risk factors associated

with oil, gas, geothermal and related businesses. It is believed that the expectations reflected in

these statements are reasonable but they may be affected by a variety of variables and changes in

underlying assumptions which could cause actual results or trends to differ materially, including,

but not limited to: price fluctuations, actual demand, currency fluctuations, drilling and

production results, reserve estimates, loss of market, industry competition, environmental risks,

physical risks, legislative, fiscal and regulatory developments, economic and financial market

conditions in various countries and regions, political risks, project delays or advancements,

approvals and cost estimates.

• All references to dollars, cents or $ in this presentation are to Australian currency, unless

otherwise stated. References to “Beach” may be references to Beach Energy Limited or its

applicable subsidiaries.

• Unless otherwise noted, all references to reserves and resources figures are as at 30 June 2010

and represent Beach’s share.

Competent Persons Statement

• This presentation contains information on Beach’s Reserves and Resources which have been

compiled by Mr Gordon Moseby, who is a full time employee of Beach, is qualified in accordance

with ASX listing rule 5.11 and has consented to the inclusion of this information in the form and

context in which it appears.


Beach Energy Limited - A unique value proposition


Key catalysts for 2011

Multiple near-term catalysts with material re-rating potential


Large Resource base to build Reserves

2P Reserves

66 MMboe*

2P Reserves & Contingent Resources

363 MMboe*

* Volumes quoted are as at 30 June 2010 and do not incorporate 12 MMboe (Beach share) of additional

Cooper Basin 2P reserves announced by Santos Ltd in Feb 2011, nor the impact of the Impress Energy acquisition

Material resource additions likely for Cooper Basin gas activity

Cooper / Eromanga Other Cooper / Eromanga 2P Other

2P Reserves

are a fraction

of the total

resource base


• FY11 guidance of ~ 6.5 MMboe*

• Consistent Cooper Basin production

performance

• Short-term opportunities for

production growth given:

– Better land access for activities

following Cooper Basin floods

– Aggressive exploration and

development drilling for 2011/12

Solid production platform

0

2

4

6

8

10

12

FY 2006 FY 2007 FY 2008 FY 2009 FY 2010

Beach Operated Western Flank Oil

Gross Expected Ultimate Recovery (MMbbl)

* Production guidance is preliminary

Near-term production

uplift potential


Positioned for growth in Eastern

Australian gas markets


Beach owns a strategic suite of assets and infrastructure,

positioning it to supply gas for generations to come

Prolific acreage position


Eastern Australian gas markets are growing

• Current domestic gas demand

~ 715 PJ per annum:

– ~ 100 PJ from Cooper Basin

• Domestic gas demand expected

to grow to ~ 1350 PJ by 2025*:

– Driven by power generation

– Higher demand scenarios

possible

• Gladstone based LNG projects adds

a new dimension to gas market

dynamics

* Core Energy Group 2011

Beach is well placed strategically and

geographically to supply the market


Excellent prospects to increase Cooper Basin supply

• Strong predicted growth in Eastern

Australian gas demand

• Strong predicted growth in Asian LNG

demand

• Excellent channels to markets

• 2015+ opens up various domestic and

export linked opportunities

• Cooper Basin gas does not have the

potential challenges that may impact

long-term coal seam gas development

in Queensland and New South Wales

Increasing number of domestic and

export customers looking to buy gas

Source: Core Energy Group 2011


The impact of eastern Australian LNG projects

• Two projects have achieved FID

committing > 16 mtpa capacity

• BG Group has recently

announced it is marketing for

QCLNG Train 3

• APLNG recently announced a

4.3 mtpa contract with Sinopec

• More projects / contracts to

come in due course

~ 80% of East Coast 2P reserves are

owned by parties developing LNG

projects or with LNG aspirations

* Adapted from Energy Quest, February 2011

LNG markets provide access to oil-

linked gas pricing – a paradigm shift

from traditional domestic pricing

18.7%

17.5%

14.9%13.2%

6.2%

6.2%

9.7%

4.2%

2.3%

7.0%

Australian East Coast 2P Reserves*

BG Group

Santos / PETRONAS

/ TOTAL / KogasOrigin Energy

Conoco Phillips

Shell

PetroChina

BHP Billiton /

ExxonMobilAGL

Eastern Star Gas

Others


SACB/SWQ JV – Significant long-term

resource potential


SACB/SWQ JV – Its importance to Beach

• Equity interests of approximately

20% for the SACB JV and 23% for

the SWQ JV

• A significant land holding for these

interests of approximately 22,000 km2

• Situated in a proven and prolific basin

• Cooper Basin cumulative gross

production to date of approximately

6 Tcf

• Provides access to a large onshore

hydrocarbon province with:

– A proven reserve base

– A large booked contingent resource

– Significant upside from technological

development and cracking the ‘codes’

• Significant infill drilling program driving

resource to reserve conversion


SACB/SWQ JV – Ultimate potential is significant

Source: Santos

Remaining gross unrisked resource potential of over 4 billion barrels of oil

equivalent


SACB/SWQ JV - GLNG Project supply opportunity

• Discussions ongoing between SACB JV

and Santos for the supply of 750 PJ to

Santos’ GLNG Project*:

– Beach’s share of supply would be

~ 152 PJ

– 15 year contract - proposed to

commence in 2014

– Oil-linked gas pricing

• Highlights strategic importance of

Cooper Basin asset base

• Potentially creates new export supply

opportunities

• Enhances various opportunities in

the Cooper Basin

* Discussions between the South Australian Cooper Basin Joint Venture (SACB JV) and Santos are incomplete, and the terms of any potential

agreement remain subject to ongoing dialogue between all relevant parties


The Cooper Basin shale gas potential


• PEL-218 (Permian JV) potential shale gas in

place 40-80 Tcf

• Similar properties to successful US shale plays

• Encounter-1 and Holdfast-1 both successful

due to:

– Target zones either in line or thicker than

anticipated (300-400 metres)

– Gas saturated and over-pressured with no

water through the target zone

• Flow stimulation at Holdfast-1 has

successfully been completed

• First flow results expected July

• Flow results will assist in designing the pilot

well program (early 2012) and booking of a shale

gas resource

A commanding Cooper Basin shale gas acreage position

Encouraging results to date – material resource booking anticipated in 2011


• Semi desert country

• Strong relationship with one

pastoral owner

• Thick target zone to yield

more gas in place

• Fracture containment not

an operational constraint

• Deep shale target zone at

3,400 metres

• Eromanga aquifers well

above shale target zone and

isolated behind two strings

of casing

Advantages of PEL 218 shale acreage

Eromanga aquifers isolated

from target zone


• Holdfast-1 fracture stimulation

completed in seven stages

• Stages completed:

– Roseneath shale (3)

– Epsilon formation (2)

– Murteree shale (1)

– Patchawarra formation (1)

Goals

• Design fracture stimulation

program

• Understand gas flow potential

• Book gas resource

• Prioritise targets for

development

• Determine gas in place volumes

Fracture stimulation successfully completed

PEL-218 represents a potential large scale resource play


Comparison to US plays

Parameter PEL 218 Permian REM Barnett (Texas)

Haynesville

(Louisiana)

Depth (metres) 2,900 – 3,500 1,650 – 3,000 3,050 – 3,950

Shale thickness

(metres)120 – 260 75 – 150 60 – 90

Total Organic Carbon

Av%3 – 5 5 4

Pressure Gradient

(psi/ft)0.72 0.55 0.85

Gas in place (Av)

Bcf/sq.km40 - 80 40 80

Similar properties to successful US shale plays


Beach has ‘core’ and flank Nappamerri acreage

• Shale gas plays cover

thousands of square

kilometres

• ‘Sweet spots’ (e.g.,

the ‘core’ Haynesville)

may exist particularly

where the shale target

zone is:

– In the deepest parts of

the acreage

– Over-pressured

– Thick

– Gas saturated

• Key to profitability is

large positions in

sweet spots

*

PEL 218 has the potential attributes to form a ‘core’ area


• Average well recovery: 9 bcf

• BG net wells: 275 (2011-15)

• Average well cost: US$9 million

(~US$1.0/mmbtu)

• Operating cost: US$1.4/mmbtu

• Unit technical cost: US$2.4/mmbtu

• Economic breakeven: US$3.2/mmbtu

BG Group - Haynesville ‘core’ economics*

0

0.5

1

1.5

2

2.5

3

Typical well (bcfpa)

Robust economics

Australian vs US fiscal regime

• No land acquisition costs in Australia, US

acquisition costs of up to US$15,000 per acre

• Government royalties of up to 10% (7.5%

after expense offset)

• US shale gas royalties reported to be 25% for

Haynesville

Source: BG Group - 8 February 2011

* The information contained in this slide is provided for comparative purposes only. This information should not be taken as representative of

expectations or likely outcomes in relation to Beach Group activities.


Goodrich - Haynesville type curve*

Robust economics

Source: Goodrich Petroleum Corporation

Low (6.5 Bcfe) Base (7.5 Bcfe) High (8.5 Bcfe)

IP rate (MMcf/d) 14.0 15.5 19.5

IP rate (30 day avg. MMcf/d) 10.0 11.0 15.5

Gross EUR (Bcf) 6.5 7.5 8.5

Pretax IRR 20% 30% 49%

F&D ($/Mcfe) $1.87 $1.62 $1.43

PV10 ($MM) $2.0 $3.6 $5.6

Breakeven Price ($M/cf)(1) $3.75 $3.25 $2.75

Acreage Value (PV10/spacing) $25,553 $45,053 $70,027

(1) Natural gas price required to generate a pre-tax 10% rate of return.

* The information contained in this slide is provided for comparative purposes only. This information should not be taken as representative of

expectations or likely outcomes in relation to Beach Group activities. All prices in US dollars.

Note: Pretax IRR, F&D and PV10 figures assume $5.00/Mcf natural gas price (less $0.50/Mcf price differential), $8.5MM drilling and completion cost,

and 100%/70% working interest and net revenue interest, respectively. Acreage values calculated using 80-acre spacing for horizontal wells. LOE

estimated at $0.36/Mcfe over life of well. Severance tax abatement for first two years then $0.165/Mcfe thereafter.

Source: Goodrich Petroleum Corporation, EnerCom’s London Oil & Gas Conference, June 16 2011


Shale gas - Cost reduction driven by…..

Technology

• Multi-stage fracture stimulation

techniques

• Pad drilling

Techniques

• Restrictive choke techniques being

adopted

• Choke settings reduced along with

initial production rates

• Rate of decline significantly less

(approximately half)

• Compression may be deferred four to

five years

…in turn reducing development

costs and increasing reserves and

production

Rate MMCFD: Conventional (24-28/64 “ choke) vs

‘optimised’ (14/64” choke)

Source: Frank D. Mango, Daniel M. Jarvie and Eleanor Herriman1. Proc Royal Soc, April 21, 2010


Next steps and indicative timeline

With successful proof of concept:

• Design pilot horizontal wells targeting highest yield zones in REM

• Drill further vertical delineation wells across acreage

• Expand production pilot to multiple wells

• Seek to monetise early production via existing facilities

• Determine market potential and processing requirements

Encounter-1 well site

Drill and core Holdfast-1 & Encounter-1

vertical exploration

wells

Q4 2010/

Q1 2011

Fracture stimulate wells

~ 8 zones/well

Q2 2011

Flow test

Q3 2011

BOOK GAS RESOURCE

Q3 2011

Pilot Production

Wells

Q1/Q2 2012


Dominant Western Flank oil

acreage position


Cooper Basin – Western Flank Oil

Western Flank oil is a core contributor due to:

• High net back per barrel (total opex including

transport and royalty of approx. $25/barrel)

• Strong equity positions

• Quick drill and tie-in periods

• Established infrastructure

• High flow rates from wells

• Good understanding of the geology

• Multiple play types

Impress takeover:

• Completed in late April 2011

• Delivered 40% of highly prospective Western

Flank oil acreage with 7.9 million barrels of

oil reserves (gross), as booked by operator

A high profit area with significant

remaining exploration potential


Potential risked reserves addition of six million barrels of oil

Western Flank drilling program

Beach operated

• Five exploration wells in PEL 91

(Beach 40%)

• Eleven wells in PEL 92 (Beach

75%), five exploration and six

development/appraisal wells

• Success rate to date is 64% from

eleven wells drilled

Senex operated

• Proposed ten well program

including four development

wells on the Growler field

• Identified 25 highly prospective

exploration targets covered by

3D seismic


Birkhead Formation Channel Sand

Birkhead channels can be imaged on seismic, significantly reducing risk

Source – Senex, 2011


‘Big oil’ potential, Tanzania


• Beach 100%

• Underexplored area with high

potential

• Lake Tanganyika South acreage is

approximately 7,000 km2

• Potential for large (> 200 MMbbl)

discoveries:

– Natural oil seeps on Lake

Tanganyika indicate a working

petroleum system

• Airborne gradiometric gravity and

hi-resolution aeromagnetic data

acquired in 2010

• 2D seismic survey planned for

Q3/Q4 2011

Lake Tanganyika, Tanzania – East African Rift

Initial prospect and leads

generation in 2011


• Tullow identified this East African rift

basin opportunity in 2001

• Lake Albert area approximately

5,300km2

• The Lake Albert rift basin is part of a

string of Pliocene-Miocene age rift

basins that cut through East Africa

• Lake Albert characterised by

abundant oil seeps

• Oil in place estimated at 2.5 billion

barrels of oil

• 37 of 38 wells successful to date

• US$2.9 billion Tullow/Total/CNOOC

transaction* confirms East African

Rift potential

Lake Albert, Uganda – major success to date

Oil discoveries at Lake Albert have

been company and country changing

Source: Tullow Oil plc

* On 30 March 2011, Tullow announced the divestment of two thirds of its Lake

Albert acreage to CNOOC and Total for US$2.9 billion


Lake Tanganyika natural oil seeps


Lake Tanganyika South Seismic Line – 2D

Lake Tanganyika South vs Lake Albert - Analogy

1.5 sec -

2.0 sec -

2.5 sec -

Lake Albert Seismic Line – 3D

Deeper water in Lake Tanganyika

Source: Tullow Oil plc – EAPCE, 2011Source: Beach Energy Ltd – Project Probe data


Lake Tanganyika North – Gazettal tender

• Tanzanian government recently

gazetted the Lake Tanganyika North

block

• Similar potential to South block based

on available seismic

• A competitive gazettal process with

nine companies submitting tenders

• Government evaluation of tenders

expected to be completed in

September

• Beach identified potential of the South

block and acquired it in 2008, PSA

finalised in 2010

Beach identified Lake Tanganyika

South potential ahead of competitors


Egypt – Established and growing portfolio


Egypt overview

• Beach interests range 15 – 22%

• An established and growing

portfolio

• Exposure to prolific and emerging

hydrocarbon basins:

– Portfolio of near-term

development & exploration

opportunities

• North Shadwan expected to

produce first oil in 2011

• Abu Sennan six well appraisal /

exploration program commenced

in December 2010

• Mesaha* has the potential to

contain 100 MMbbl+ targets

* Subject to Ministerial approval


Abu Sennan concession

• Beach 22%

• 3D seismic coverage over whole

concession which has been the

key to success for Apache in the

surrounding tenements

• Apache recently acquired

tenements from BP adjacent to

Abu Sennan

• Initial six well program

underway, with the potential for

at least ten wells

• ZZ-4 well completed, oil shows

being evaluated

• Al Ahmadi well to spud

imminently


Gulf of Suez

• Beach 20% interest

• High potential Gulf of Suez

acreage

• Three existing oil discoveries:

– NS 377 and 385

(‘near shore fields’)

– NS 394 ‘Burtocal’

• First oil expected in 2011

• North Shadwan delays due

to pipeline operator sign off

on oil mix in pipeline

• Proposed exploration well

for South East July in late

2011


• Beach interest 15%*

• One of the largest concession

areas in Egypt at 57,000km2

• Wildcat basin with the right

ingredients

• Possible rift basin similar to Gulf

of Suez/Lake Albert/Lake

Tanganyika

• Potential for very large oil fields

(~ 100 MMbbl+)

• 2D seismic activities completed

to delineate basin architecture

• Southern infill seismic being

acquired

Mesaha concession

*Subject to Ministerial approval Source: Melrose Resources plc - Investor presentation, 18 January 2011

Wildcat exploration with rift

graben potential


Appendices


Australian pipeline growth

Pre - 1995 Post - 1995

• Approx 10,500 km

• Point-to-point pipelines

• Majority government owned

• Approx 20,000 km

• Interconnected pipelines

• Privatisation

Source: APA investor presentation, April 2010


The importance of REM section for shale & tight gas

• Thick target section

• Gas charged

• Over-pressured

• Favourable mineralogy

• Lacustrine play, with similar

litho/geochem properties to

North American marine

shale plays

Key attributes confirmed to

date provide significant

encouragement


Nappamerri Trough – thick Early Permian shale sequence

Shale play thickness:

• Roseneath 80-200 metres

• Epsilon ~100 metres

• Murteree ~80 metres

Over-pressured tight gas play:

• Epsilon – mid and basal zones

sandier

• Patchawarra – multiple sands

Other tight gas in section:

• Daralingie

• Toolachee

US shale plays:

• Haynesville 200 metre gross section

• Barnett 100 metre gross section

The REM target zone is a substantial shale gas target


PEL 218 Shale - Favourable mineralogy

The REM has similar mineralogy to major US shale plays

40-60% Clay:

• Similar to Barnett and Haynesville

10-20% Carbonate:

• Carbonate in the form of siderite

25-50% Quartz:

• Important for brittleness

Total Organic Carbon:

• Gas volumes – both adsorbed and

free

• Preliminary 3-5%

• Barnett/Haynesville/Eagleford 4-5%

0

20

40

60

80

100

Cla

ys %

020406080100

Carbonate %

0

20

40

60

80

100

Sil ica + other %

BarnetEagle FordHaynesvilleUticaNappamerri

BarnetHaynesvilleEagle FordUticaNappamerri


PEL 218 Shale - Over-pressured at REM level

0 2000 4000 6000 8000 10000

Pressure (psi)

0

1000

2000

3000

4000

Dep

th (m

)

Regional pressure data –over-pressures confined to Nappamerri Trough

Beach Acreage

The REM target zone is over-pressured

- desirable in US gas plays

Formations outside Trough

• Normally pressured - hydrostatic

gradient

• All 0.43 psi/ft

Exploration wells – in Trough

• Over-pressured

• DST information – Epsilon and

Patchawarra

• Mud weights Roseneath and deeper

• ~0.72 psi/ft

Pressure advantage:

• More gas stored

• More drive

• Eagleford 0.65 psi/ft

• Haynesville 0.85 psi/ft


Parsons-1

Namur

PARSONS-1

Western Flank oil - Namur Sandstone

Namur Sandstones plays:

• Widespread high net to gross braided channel

environment

• Subtle structures delineated on 3D seismic data

• Very high permeability

• Parsons-3 clean up flow 5,200 bopd


Western Flank oil - Birkhead Formation Channel Sand

Growler 3

Birkhead Sandstones plays:

• Deposited in meandering channels

• Do not necessarily rely on structural traps

– can be extensive accumulations

• Can be imaged on seismic data


Tanzania – Attracting the majors

• Various phases of exploration

undertaken since 1952 with very

few exploration wells drilled

• Early wells drilled with poor quality

or inadequate seismic control

• Tanzania has now attracted

attention of the large players, eg:

– Shell

– Statoil

– Petrobras

– Exxon Mobil

– Total

Tanzania is becoming a frontier

exploration ‘hotspot’Source – TPDC, 2010


Rift systems - Gulf of Suez vs Lake Tanganyika

Gulf of Suez:

• Rift valley system

• Area approximately

9,000km2

• 800+ exploration wells

drilled

• 9.5 billion barrels of oil

discovered

Lake Tanganyika

• Rift valley system

• Area approximately

32,900km2

• Two exploration wells

drilled

• No discoveries to date

Gulf of Suez Lake Tanganyika

Lake Tanganyika is more than three times the size of the Gulf of Suez


• Typical rift graben/half

graben geometries

• Seismic indicates large

structures with

bounding faults

• Play types are:

– Stratigraphic traps

– Fault traps

– Three way structured

traps against

basement

– Anticlinal traps

• These are similar to

successful play types in

Uganda, Lake Albert

Lake Tanganyika South – play types

Large stacked structures under Lake Albert appear similar to

those within the Lake Tanganyika South concession


• Eleven year PSA structured into

phases of 4 + 4 + 3 years

• Phase 1 minimum commitment

expenditure of ~ US$7 million

• One exploration well required in

Phase 2 & Phase 3

Phase 1 planned exploration

• Seismic reprocessing of previous

seismic data (in progress)

• Aeromagnetic, gradiometric

aerogravity and bathymetry survey

over entire PSA area (completed)

• Acquisition of 1,800 kilometres of

new 2D seismic data

• Review drilling options

Lake Tanganyika South – Beach exploration program

Beach will be undertaking the first multi-faceted

exploration program in Lake Tanganyika


Beach Energy Limited – Head office

25 Conyngham Street

Glenside SA 5065

Tel: +61 8 8338 2833

Fax: +61 8 8338 2336

Website: www.beachenergy.com.au

Chris Jamieson

Investor Relations Manager

Tel: +61 8 8338 2833

Mob: +61 8 (0)487 173 244

Email: [email protected]

Contact information

beach energy limitedbeach energy limited, asian roadshow– 4-7 july 2011 slide 7 • fy11 guidance...

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