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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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Pro
ven &
pro
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(PJ, B
CF
)
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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2P
reserv
es (
PJ)
Annual p
rod
uctio
n (P
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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G 2
P R
ese
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J)
CB
M/
CS
G P
rod
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(P
J/a
)
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
ucti
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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 $3/GJ?
• Competitive constraints on domestic gas prices
Slide 29
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LNG
pri
ce (U
S$/m
mb
tu)
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
$10.00
$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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De
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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: p.balfe@aciltasman.com.au
Paul Balfe, Executive Director, ACIL Tasman