CSG in Australia

Coal Seam Gas in Eastern Australia:

regional markets, global developments

AMPLA State Conference 2009Sheraton Mirage, Gold Coast

16 May 2009

Paul Balfe, Executive Director

ACIL Tasman

Slide 2

Agenda

Evolution of the Australian CSG industry since 1980s

Eastern Australia gas reserves

CSG technology & project commercialisation

Proposed CSG LNG developments

Key questions & challenges for CSG LNG

• Technical & Commercial

• Supply sufficiency

• Price effects

Slide 3

Agenda

Evolution of the Australian CSG industry since 1980s

Eastern Australia gas reserves

CSG technology & project commercialisation

Proposed CSG LNG developments

Key questions & challenges for CSG LNG

Slide 4

North Bowen CSG

South Bowen CSG

Surat CSG

Camden CSG

Clarence-Moreton CSG

Gunnedah CSG

Hunter Valley CSG Gloucester CSG

CSG commercial production

CSG under investigation

Geographical context

Queensland

CSG plays

New South Wales

CSG plays

Slide 5

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Queensland NSW

Australian CSG development timeline

1976 – First CSG drilling

in Queensland Bowen

Basin

Queensland

New South Wales

1995-96 – First CSG

production leases at

Fairview, Moura

1996 – First commercial

CSG sales (Moura)

2004 – First CSG production

testing in Surat Basin

2006 – First commercial CSG sales

from Surat Basin

1985 – 1995: Amoco, Pacific Power major CSG

programs in Sydney Basin

2002 – First PPLs granted

for Camden Project

1993–96 –

Conoco

+US$100MM in

SE Bowen Basin

1996 – Appin/Tower CMM

production commences

Slide 6

Queensland CSG projects and

prospects

GALILEE

BASIN

BOWEN BASIN

SURAT BASIN

Townsville

Mackay

Gladstone

Brisbane

Roma

Bowen

Moranbah

FairviewSpring Gully

ScotiaPeat

Berwyndale SouthTalinga

Kogan NorthTipton WestArgyle Kenya

MouraMungi

Dawson Valley

CSG production

CSG potential

Gas pipeline

Prospective for CSG

Source: ACIL Tasman

Slide 7

GUNNEDAH BASIN

CSGproduction

CSG potential

Gas pipeline

Prospective for CSG

SYDNEY BASIN

Hunter Valley

GLOUCESTER

BASIN

CLARENCE MORETON

BASIN

Sydney

Newcastle

Wollongong

Grafton

Camden

Narrabri

Casino

Stratford

New South Wales CSG projects

and prospects

“40TCF prospective resource”

(Santos March 2009)

AGL acquires dominant position in Gloucester Basin, Sydney Basin

(December 2008)

Source: ACIL Tasman

Slide 8

Agenda

Evolution of the Australian CSG industry since 1980s

Eastern Australia gas reserves

CSG technology & project commercialisation

Proposed CSG LNG developments

Key questions & challenges for CSG LNG

Slide 9

Gas supply:

Current 2P conventional reserves

Townsville

Mount Isa

Gladstone

Brisbane

Sydney

Melbourne

Adelaide

Hobart

LNG Terminal

Gas production hub

Gas infrastructure/supply

Existing transmission capacity

New transmission capacity

Conventional gas basin

CSG gas basin

Cooper

Basin

1,079 PJ

Surat/Bowen

Basin

250 PJ

Gippsland

Basin

7,840 PJBass Basin

430 PJ

Otway Basin

1,855 PJ

Source: ACIL Tasman compilation of public domain data

Slide 10

Eastern Australia conventional

gas reserves

Data source: Company disclosures, Geoscience Australia

Basin Field State Operator 2P Reserves (PJ)

Amadeus Mereenie, Palm Valley NT Santos 202

Bass Yolla/White Ibis TAS Origin Energy 430

Bonaparte Blacktip WA ENI Australia 680

Tern/Petrel NT Santos 1,525

Bowen/Surat Denison Trough QLD Origin Energy 92

Roma district QLD Santos/Origin 106

Churchie/Silver Springs QLD Mosaic Oil 77

SWQ Ballera region QLD Santos 200

Cooper Moomba region SA Santos 849

Gippsland Gippsland - Developed VIC Esso/BHP Billiton 6,038

Kipper VIC Esso/BHP Billiton 657

Basker-Manta-Gummy VIC Anzon Australia 384

Longtom VIC Nexus Energy 464

Patricia Baleen VIC Santos 63

Sole VIC Santos 196

Golden Beach VIC Cape Energy 38

Otway Katnook SA Origin Energy 33

Casino VIC Santos 296

Martha/Henry VIC Santos 156

Minerva VIC BHP Billiton 264

La Bella VIC BHP Billiton 217

Thylacine/Geographe VIC Woodside 922

Total 13,889

Slide 11

Gas supply:

2P CSG reserves as at end 2008

LNG Terminal

Gas production hub

Gas infrastructure/supply

Existing transmission capacity

New transmission capacity

Conventional gas basin

CSG gas basin

Townsville

Mount Isa

Gladstone

Brisbane

Sydney

Melbourne

Adelaide

Hobart

Surat CSG

5,133 PJ

Bowen CSG

6,833 PJ

Clarence

Moreton CSG

247 PJSydney

Gunnedah CSG

451 PJ

Source: ACIL Tasman compilation of public domain data

Slide 12

Eastern Australia CSG reserves

Data source: Company disclosure,

ACIL Tasman research.

Resource estimates as at 3Q2008

Company Proven Probable Possible 1P 2P 3P

AGL Energy 154 353 1,062 154 507 1,569

Anglo / Mitsui 33 282 489 33 315 804

Arrow Energy 86 633 2,041 86 719 2,760

Beach Petroleum 10 60 836 10 70 906

CS Energy 0 42 78 0 42 120

Molopo Australia 11 154 279 11 165 444

Origin Energy 1,330 3,385 5,407 1,330 4,715 10,122

Queensland Gas Company/BG 609 1,806 4,748 609 2,415 7,163

Santos 371 986 0 371 1,357 1,357

Sunshine Gas 44 425 628 44 469 1,097

Other QLD 0 13 62 0 13 75

Total QLD 2,648 8,139 15,630 2,648 10,787 26,417

AJ Lucas/Molopo 15 155 189 15 170 359

Eastern Star Gas 21 164 1,115 21 185 1,300

Metgasco/CS Energy 0 247 1,142 0 247 1,389

Sydney Gas/AGL Energy 60 24 26 60 84 110

Total NSW 81 435 2,283 81 516 2,799

Total Eastern Australia 2,729 8,574 17,913 2,729 11,303 29,216

(Now BG/QGC)

(Now AGL)

(Now AGL)

Slide 13

Historical growth of CSG

reserves and production

Past seven years has seen rapid emergence of CSG as a major source of gas production and additional reserves

Trend continued through 2008, and expected to be maintained for at least the next three years

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reserv

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PJ)

Annual p

rod

uctio

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J)

Queensland NSW Reserves

Slide 14

Comparison of US CBM and

Australian CSG production and reserves

Australian CSG production

currently around 8% of US

CBM production

• but Australian 2P reserves are now 55% of US reserves

US CBM has 11 years of

reserves cover; Australian

CSG has 80 years of

reserves cover at current

production rate

• Australian CSG has rapidly “outgrown” the local market

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US Reserves (RHS) Aust reserves (RHS) US production Australia production

Slide 15

Agenda

Evolution of the Australian CSG industry since 1980s

Eastern Australia gas reserves

CSG technology & project commercialisation

Proposed CSG LNG developments

Key questions & challenges for CSG LNG

Slide 16

The CSG exploration and

demonstration process

Finding and proving up CSG resources involves a systematic process of

geological appraisal, with drilling (core holes and open holes) a key part

Gathering more data allows increasing confidence in resource definition

Source: Santos

Reporting standard: SPE Petroleum Resources Management System (PRMS) 2007

Slide 17

Pilot, production vertical drilling

• Early CSG exploration in Australia used

conventional oil field drilling rigs

• Move to simpler truck-mounted mineral

or coal exploration drilling rigs,

appropriately modified, lowered cost

and improved project economics

• Core drilling uses conventional coal

coring rigs with gas testing equipment

• Diagram at right shows standard vertical

O/H completion for pilot or production

well

Source: Queensland Gas Company

Slide 18

Alternative production technology –

SIS or “Surface to In-Seam” drilling

• SIS drilling uses a vertical or near vertical production well, and one or more deviated wells initiated on the surface typically 1 -2 km away

• The SIS well is steered along the coal seam to intersect the vertical well

• Multiple SIS wells may be drilled, in the same or different seams, to intersect the vertical production well thereby increasing production potential

• SIS is slower and more expensive to complete, but can result in much higher production rates because of greater exposure of the well bore to the coal seam

Source: AJ Lucas

Source: Eastern Star Gas

Slide 19

CSG commercialisation challenges

Proximity to markets, transmission pipelines critical

Reserves certification: up-front and continuing capital implications for financing; extended ramp-up; limited turn-down once flow is established• SPE-PRMS reporting standard and commerciality test; potential for

reserves write downs?

Resource variability: wide range of performance• Gas content of coal• Gas saturation• Coal permeability => Average flow rate

Dry gas: no added value from liquids

BUT on the positive side:• Coal seams easy to find• Large in-situ resource• Low unit well cost• Scalable

Slide 20

Agenda

Evolution of the Australian CSG industry since 1980s

Eastern Australia gas reserves

CSG technology & project commercialisation

Proposed CSG LNG developments

Key questions & challenges for CSG LNG

Slide 21

LNG proposals

Four active proposals for CSG-based LNG at Gladstone• Santos/Petronas: 3 to 4 mtpa trains *2

• Arrow/LNG International: 1.3 mtpa trains *2

– Shell’s intentions?

• BG/QGC 3 to 4 mtpa train * 2 or 3

• Origin/ConocoPhillips 3.5 mtpa train * 4

Two “dormant” proposals

• Sojitz (ex Sunshine) 0.5 mtpa trains *2

• LNG Impel 0.7 to 1.3 mtpa trains * 3

Potentially >40 mtpa LNG

• 40 mtpa LNG would require about 2,500 PJ/a (approx 2,500 bcf) inc. gas used in production, compression, transportation & processing

– cf East Australia domestic market 675 PJ/a

Rationale: access high volume, value international markets

Four projects all targeting FID in

2010-11, first gas 2012-14 =>

strong logic for rationalization and

coordination

Slide 22

CSG LNG technical & commercial

challenges

No operating precedent

Aggregating sufficient CSG reserves

• 2 * 4 mtpa LNG requires 20 years @ 450 PJ/year = 9,000 PJ; about 1,800 initial production wells; average 150 – 200 replacement wells per year

Very “lean” gas (methane, v. little C2+) => lower heating value

• No liquids value kick (cf. liquids contribution 30% - 40% total revenue for NWSJV, Darwin LNG)

• May require HV adjustment for some markets and/or price penalty

Limited “turndown” on CSG wells

• => “Ramp Gas” issue

Water disposal

Slide 23

Agenda

Evolution of the Australian CSG industry since 1980s

Eastern Australia gas reserves

CSG technology & project commercialisation

Proposed CSG LNG developments

Key questions & challenges for CSG LNG

Slide 24

Key questions arising from

Gladstone LNG proposals

What impacts on domestic gas availability?

• Will there be enough gas, after exports, to meet domestic market needs?

– In particular, increased gas for electricity to meet requirements of Qld Govt 18% gas policy and CPRS

What impacts on domestic gas prices?

• Will gas prices in Eastern Australia move to “international parity”?

• Will we follow Western Australian experience of steep domestic gas price increases?

The answers to these questions are inter-related

Slide 25

Potential scale of LNG development will be dependent on supply cost curve

• Abundant low cost-to-produce CSG (blue line) will support

large scale LNG development, as well as incremental supply for domestic market

CSG Supply Cost Curve

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Co

st t

o P

rod

uce

($/G

J, n

om

inal

20

18

)

Cumulative Resource (PJ)

Indicative Queensland CSG Supply Cost Curves for two alternative LNG Development Scenarios

6-train LNG (24 Mt)

2-train LNG (8Mt)

Improved drilling & completion technologies plus

efficiency gains will shift the supply cost curve to the

right over time

“The larger the LNG development,

the greater the “vote of confidence” in

the reliability, competitiveness and

scalability of CSG production.”

Source: ACIL Tasman “Gas Market Review & Outlook

2009”

Slide 26

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Prod

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J/a

NSW CSG

Qld CSG

NT Conv

SA Conv

Tas Conv

NSW Conv

Qld Conv

Vic Conv

Modelled gas consumption: CSG 60% of

East Australia gas production by 2030

900 PJ/a CSGETS +

8 mtpa LNG

600 PJ/a

conventional

460 PJ/a CSG to

domestic market

Slide 27

Conclusions re: potential supply

impacts of Gladstone LNG proposals

Will there be enough gas, after exports, to meet domestic market needs?

• Almost certainly; CSG resources can be expanded incrementally. Large scale LNG development will only occur if very large resource base is demonstrated

– Large, low-cost CSG resources will support LNG plus incremental resource development for domestic markets

– CPRS will allow large gas users to pay higher prices, justifying more investment for domestic production

Will enough gas be available to meet Qld Govt 18% gas policy and new CCGT generation under CPRS?

• Yes. Modelling shows ~30% of Queensland electricity generation in 2020 gas-fired—comfortably exceeding government’s 18% target.

– CPRS supports higher gas prices, drawing out supply and allowing CCGT to compete with base load coal.

Slide 28

Impacts on domestic price

Potential impacts on domestic gas prices require consideration of:

• How LNG prices are set

• How LNG prices compare with Australian domestic gas prices

– The concept of LNG netback price

– Is $6/GJ always better than $3/GJ?

• Competitive constraints on domestic gas prices

Slide 29

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pri

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Oil Price (US$/bbl)

PLNG

LNG contract pricing

Contract price vs Spot Price

Contract price:• Price formula linked to oil

price =/- adjustments for local alternatives eg natural gas

• Europe/USA/Canada – price formula linked to oil price but also reflects competition with natural gas

Price formula: PLNG = A * Poil + B

Typical Contract Price Relationship

Example with slope A = 0.12; B = 1.25

Typical range 0.10 – 0.14; A = 0.17

represents full parity with oil (energy

equivalent basis)

Cap &collar limit

upside & downside

price risk => typical

“S-curve”

Slide 30

Recent Asian Spot LNG Prices

LNG spot pricing

Emergence of LNG spot market is a relatively recent development• Traders swap cargoes

within portfolios• Pacific and Atlantic Basin

spot markets largely separate

Spot prices based on individual cargoes

Spot price more volatile than contract price• Reflects supply/demand

dynamics

$US/mmbtu

Data source: RIM Intelligence

$20 -

$15 -

$10 -

$5 -

Apr-09Jan-09Oct-08Jul-08Apr-08

Peak LNG price

US$20.80/mmbtu in mid-August

2008 = about 90% of JCC price

Slide 31

LNG netback estimation

This gives netback to the upstream gas processing plant

(ie into transmission pipeline)

To estimate netback to the wellhead account also needs

to be taken of upstream initial and ongoing capex (drilling,

gathering, in-field compression, processing, compression

to pipe)

AssumptionsOil price range USD/bbl $40 to $80

AUD/USD Rate 0.7

LNG/Oil parity range 50% to 100%

Conversion mmbtu => GJ 1.05

Supply chain costs

Regasification (USD/mmbtu) 0.25$

Shipping (Australia - China) (USD/mmbtu) 0.45$

Liquefaction (USD/mmbtu) 3.00$

Feed gas transportation (AUD/GJ) 0.50$

Slide 32

Implied field netback relative to

oil price

Source: ACIL Tasman analysis

-$5.00

$-

$5.00

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$15.00

$20.00

$25.00

50% 60% 70% 80% 90% 100%

Oil price parity percent

Value ex field processing plant (AUD/GJ)

US$40/bbl

US$60/bbl

US$80/bbl

US $120/bbl

Slide 33

Is $6/GJ always better than $3/GJ?

Need to consider:

• Capital barriers to entry

• Resource barriers to entry (critical mass)

• Risk/return and price volatility

– Proposition: A 20-year contract at $3/GJ indexed at CPI with a quality offtaker, perhaps willing to take some upstream risk, and requiring minimal up-front capital costs may yield higher expected value than a $6/GJ LNG contract linked to volatile oil prices with heavy upfront capital and resource thresholds

Suppliers outside the LNG projects can’t get LNG netback, even if they sell to LNG producers

• Their best price is likely to be “what the local market will bear”

Slide 34

Modelled impact of 2 * 4mtpa LNG

development on wholesale gas prices

Modelled impact: up

to $0.80/GJ; 17%

increase.

Size of price impact

will vary depending

on CSG supply

performance

Impact diminishes

with distance from

LNG production site

Source: ACIL Tasman analysis

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With 2*4Mtpa LNG No LNG

Slide 35

Conclusions re: potential price

impacts of Gladstone LNG proposals

Will gas prices in Eastern Australia move to “international parity”?• No. Netback equivalent only relevant to producers with access to LNG plant,

while they are in the reserves build phase.

– Consider: reserves dedication; limited opportunities for third parties to access LNG; risk profile LNG vs domgas

Will we follow Western Australian experience of steep domestic gas price increases?• No. The situation in WA is driven by supply constraints rather than

international LNG prices

– Consider: concentrated resource ownership; increased finding & development costs; cost of alternative energy

Coal Seam Gas in Eastern Australia:

regional markets, global developments

AMPLA State Conference 2009Sheraton Mirage, Gold Coast

16 May 2009

Phone: +61 7 3009 8715

Mobile: 0404 822 317

Email: [email protected]

Paul Balfe, Executive Director, ACIL Tasman