COMMERCIALISATION OF SHALE/TIGHT GAS IN AUSTRALIA

U B S A U S T R A L I A N R E S O U R C E S , E N E R G Y & U T I L I T I E S C O N F E R E N C E , S Y D N E Y

G E O F F B A R K E R , PA R T N E R

1 3 J U N E 2 0 1 2

DISCUSSION TOPICS

1. SHALE / T I G HT G AS POTENTI AL

2. COMMERCI AL ISAT ION CHALLENG ES

3 . SOME THOUG HTS ON AUSTRAL I AN LNG

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RISC Advisory

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Offices in Perth, Brisbane, Dubai and London

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Disclosure The statements and opinions in this presentation are given in good faith and in the belief that such statements are neither false nor misleading. RISC recommends that specific advice relating to your particular circumstances be obtained before implementing actions mentioned in this presentation.

SHALE/TIGHT/BCG GAS POTENTIAL

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Shale/Tight/BCG Gas Prospective Resources

545 Tcf potential prospective resources (RISC 2010/2012 & EIA 2013)

EIA 437 Tcf in 6 Basins (2013)

1300 Tcf ACOLA/AWT (2013)

Infrastructure

Bowen, Cooper/Eromanga, Gippsland and Otway Basins close to well developed production infrastructure

Liquids

Approx 40% gas considered to be liquids prone which is important for commercialisation

Areas of Canning, Cooper, Perth and McArthur Basins stand out

545 Tcf Prospective Resources

Source: RISC Analysis

SHALE/TIGHT GAS ACTIVITY HIGHLIGHTS

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Commercial Maturity Profile

Cooper, Perth and Amadeus Basin have been producing tight gas for decades

Focus now on ultra low permeability shale/basin centred gas prospects

Strong JV’s with major players

Cooper (Beach, Santos/Origin) most advanced 11 “shale/tight gas” vertical wells fracced and successfully tested, horizontal drilling underway. 1 Well hooked up and producing (Moomba 191)

Perth Basin (AWE, Norwest, Transerv) 4 vertical “shale/tight gas” wells fracced and successfully flow tested

Canning Laurel BCG (Buru) – 1 well fracced and tested gas/condensate, 5 wells drilled and ready for testing

Georgina (Petrofrontier) 1 horizontal well fracced and tested did not produce

Buru Mitsubishi NSE Conoco Petrochina Hess

AWE Origin Norwest Bahrat Transerv Alcoa Empire

Santos Central Beach Origin Drillsearch Senex QGC Chevron

Petrofrontier Statoil Hess Santos Armour

Cooper Lakes Armour

LNG Hub

LNG Hub

LNG Hub

SHALE-TIGHT GAS CONTINUUM

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SHALE VS. S ILTS VS SANDSTONE

Tight gas, shales, and hybrids are all different petroleum systems:

– Petrophysics,

– Completion,

– Stimulation,

– Economics,

Each lithology exhibits high vertical and lateral variability (despite lateral continuity)

Marcellus Horn River Barnett/ Fayetteville/ Woodford/Bakken Haynesville/Eagle Ford Glacier Montney Unita

Mixed Pore Hybrid shales BCGA

SHALE GAS TECHNICAL SUCCESS FACTORS

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USGS Screening Criteria

Canning Basin

Goldwyer Fm

Perth Basin IRCM

Caringinia Kockatea

Cooper Basin REM

Amadeus Basin

Horn Valley Siltstone

Beetaloo Basin

Kyall Fm Velkerri Fm

Georgina Arthur Ck

Fm

McArthur Barney Ck

Fm

Otway Basin

Eumerella Fm

Casterton Fm

TOC > 2%

Porosity > 4%

Overpressure × ×

Dry Gas Ro > 1.2% - 3.5%

Wet Gas Ro > 0.8-1.2%

×

Thickness > 30m

Clay < 40%

Brittleness

Natural Fracture Potential

High Lateral Continuity

× ×

BASIN CENTRED GAS (BCG)

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Criteria Canning Basin Laurel Fm

Cooper Basin Nappamerri BCG

???

Perth Basin IRCM

Caringinia Kockatea

Abnormal Pressure ×

Low Permeability <0.1 mD

Continuous Gas Saturation ×

No Downdip Water Leg ×

DOMESTIC GAS +20 YEARS Western Australia

Circa 10 Tcf demand

Circa 2 Tcf supply shortfall

Eastern Australia

Circa 20 Tcf domestic demand

Circa 10-15 Tcf supply shortfall

Opportunity

12-17 Tcf Domestic Gas

Export required to monetise more than this

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Source: Office of Energy, Energy 2031 - Strategic Energy Initiative: Directions Paper

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500

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2013 2015 2017 2019 2021 2023 2025 2027 2029 2031

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Domgas + LNG Demand Domestic demand

Supply - 2P Conventional + 3P CSG Reserves Supply - 2P Conventional + 3P CSG Reserves (No NSW)

Domestic Supply (inc Conventional and CSG) Domestic Supply - 2P Conventional + 3P CSG Reserves (No NSW)

Source: AEMO GSOO2012, AER, RISC

WA

ES

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Increase in Gross

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Condensate Gas Ratio bbl/MMscf

L I Q U I D S C O N T E N T I M PA C T S L N G R E V E N U E S T R E A M S

MODERATE L IQUIDS CONTENT IN PRODUCED GAS CAN BOOST PROJECT REVENUE BY MORE THAN 20%

Assumes LNG sold at energy value parity to condensate Source: RISC Analysis

Prelude, Ichthys

Sunrise, Crux

Browse

Wheatstone, Pluto, Gorgon

E Africa, CBM, Regas Terminal Conversion

DISTANCE TO MARKET IS ALSO A FACTOR

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S IGNIFICANT SHIPPING DIFFERENCES FOR PROJECTS TO REACH KEY MARKETS WILL INFLUENCE COST COMPARISON.

THIS EXAMPLE SHOWS ONE-WAY DISTANCES FROM PRODUCERS TO JAPAN

7000 nm

3700 nm

3900 nm

9100 nm

ESTIMATED TRANSPORT COSTS TO JAPAN SHIPPING TO MARKET COSTS FALL IN THE RANGE OF 10-20% OF CARGO VALUE

Notional costs include: BOG, fuel, ship charter. Source: RISC Analysis

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Operating LNG & Export

Operating Pipeline

Operating Upstream

Capital LNG & Export

Capital Pipeline

Capital Upstream

DES to Japan

DES to China

DES to India

DES to Europe

UNIT COST OF DELIVERED LNG TO JAPAN

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Operating LNG & Export

Operating Pipeline

Operating Upstream

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Capital Pipeline

Capital Upstream

DES to Japan

CAN AUSTRALIAN UNCONVENTIONAL GAS COMPETE FOR REGIONAL LNG MARKETS?

Challenges

Production infrastructure

Services (rigs, frac spreads)

Well Costs

Australian well drilling, completion and stimulation costs currently 3-4 times higher than N America

US Rig rates, drilling rates, frac costs all significantly better

Well Cost a major driver in value

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“Greenfield” shale gas example

6 bcf/well, 25 bbl/MMscf liquids

3000 m well with 2500 m lateral, 12 stage fracs

US well cost $6-8 mill drilled and completed

Aus well cost $12-14 mill (assumes learning curve)

HOW CAN AUSTRALIAN SHALE GAS COMPETE?

“Business as Usual) Cost Reduction

30% savings on current cost

Campaign drilling

Pad drilling

Drilling learning curve

Well will still cost 2X US equivalent

Still not enough

Even with 30% savings, result is breakeven costs of supply 60% higher than US comparable

Stretch target should be 50-60% savings on current costs to achieve even greater efficiencies

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Site preparation

logging/testing fees

completion equipment/material costs

drilling material & services

site survey/positioning

basic rig hire

mob/demob

Aus Current Cost Aus Business as Usual US Current Cost

30% savings expected “business as usual”

50-60% savings “stretch target”

HOW CAN AUSTRALIAN OPERATORS DRIVE FURTHER IMPROVEMENT?

Due to market/geographical issues, Aus costs unlikely to reach US benchmarks

Remote locations, flooding and lack of infrastructure will all inevitably add to costs

“Technical Limit” Concept

50% improvements the norm

Different business model required

– Imperative from CEO down required

– Different skill sets, continuous improvement systems and culture

– Whole supply chain approach

– Re-engineering of well construction, supply and development process: need campaigns

– Integrated contract alignment with service providers essential

– Manpower intensive compared to current operations, but good engineering is cheap

Not a new idea, been around since the 80’s

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Bond, D.F. et al.: “Step Change Improvement and High Rate Learning are Delivered by Targeting Technical Limits on Sub-Sea Wells,” SPE 35077 March 1996.

OUTLOOK FOR AUSTRALIAN SHALE GAS

Vast resource potential 500+ Tcf

Domestic market potential circa 15 Tcf over next 20 years

Access to export market the key to unlocking the full scale potential

Basins close to markets and Export infrastructure favoured

Cost a major value driver making Australian shale gas 60% more costly than N American equivalents

Scale, vision and a different business model is required to unlock the challenge

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