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2012 Investor Seminar 22 November 2012
2
Disclaimer & important notice
This presentation contains forward looking statements that are subject to risk factors associated with the oil and gas industry. It is believed that the expectations reflected in these statements are reasonable, but they may be affected by a range of variables which could cause actual results or trends to differ materially, including but not limited to: price fluctuations, actual demand, currency fluctuations, geotechnical factors, drilling and production results, gas commercialisation, development progress, operating results, engineering estimates, reserve estimates, loss of market, industry competition, environmental risks, physical risks, legislative, fiscal and regulatory developments, economic and financial markets conditions in various countries, approvals and cost estimates.
All references to dollars, cents or $ in this document are to Australian currency, unless otherwise stated.
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David Knox
Managing Director and CEO
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Mutineer-Exeter, Carnarvon Basin, Western Australia
4
Delivering 80-90 mmboe of production by 2020
Production
mmboe
-
10
20
30
40
50
60
70
80
90
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Producing
Aust: Cooper Basin, Carnarvon Basin, Queensland CSG, offshore Victoria, Mereenie
LNG: Darwin LNG
Asia: Chim Sáo, Indonesia, Sangu, SE Gobe
Likely sanction
Aust: Gunnedah
LNG: Bonaparte LNG
Asia: Peluang
Sanctioned
Aust: Fletcher Finucane, Cooper infill, Kipper
LNG: PNG LNG, GLNG
Asia: Dua
Producing
Sanctioned
Likely sanction
Upside potential
Aust: Zola, Winchester, Hurricane, Sole, Pedirka Basin
LNG: PNG LNG T3, Browse, Caldita Barossa
Asia: Vietnam, Indonesia CSG
5
2012 delivery
New projects sanctioned
Early shale success
Material exploration success
Progress on major projects
Cashflow growth
Earnings growth
Production growth Production up 10% to 38.9 mmboe to September
Underlying first-half profit up 20% to $283 million
Operating first-half cashflow up 7% to $728 million
PNG LNG 70% complete
GLNG 40% complete
Crown-1 gas discovery, Browse Basin
Australia‘s first commercial shale production; Moomba-191 shale well flows at 2.7 mmscf/day
Fletcher Finucane – Western Australian oil project Dua – Vietnam oil project
6
Safety performance
Personnel safety Process safety
A balanced focus on personnel and process safety
0
1
2
3
4
5
6
7
0
2
4
6
8
10
12
14
16
18
20
2007 2008 2009 2010 2011 Oct-12
Work
hours
(m
illio
n)
80%
85%
90%
95%
100%
2007 2008 2009 2010 2011 2012
99.9%
TRCFR performance (employees and contractors)
Safety critical compliance long-term trend
Loss of Containment (LOC)
Zero LOC in Tier 1 (process/occupied area)
Tota
l reco
rdable
case
fre
quency
rate
per
mill
ion h
ours
work
ed
Work hours TRCFR
7
Our people are the key to delivery
8
Today‘s agenda
Introduction David Knox
Funding and Guidance Andrew Seaton
LNG Markets Peter Cleary
GLNG Upstream Trevor Brown
GLNG Downstream Mark Macfarlane
Q&A followed by morning tea
WA&NT Business Unit John Anderson
Eastern Australia Business Unit James Baulderstone
Asia Pacific Business Unit Martyn Eames
Wrap-up David Knox
Q&A followed by lunch
9
Funding and Guidance Andrew Seaton
Chief Financial Officer
Moomba 191, Cooper Basin, Australia
10
0
300
600
900
1,200
1,500
1,800
2012 2014 2016 2018 2020
Drawn facilities Euro subordinated notes
ECA Undrawn bank facilities
0
1
2
3
4
5
6
7
A$ million
Cash Undrawn corporate
lines
Undrawn project line (PNG LNG)
Available liquidity Debt maturity profile A$ billion
Balance sheet capacity to fund execution of business strategy and minimise financing risk
Notes mature in 2070, with option to redeem in 2017
Charts as at 30 September 2012
Over $6 billion of funding capacity
ECA facilities
Beyond 2020
2.4
2.1
0.6
1.0
11
2013-15 Sources and uses of funds
0
2
4
6
8
10
12
Uses Sources
Capex
0
2
4
6
8
10
12
Uses Sources
2013-15 Sources and uses of funds at US$100/bbl oil
2013-15 Sources and uses of funds at US$75/bbl oil
No requirement for additional funding under reasonable scenarios
Capex
Exploration Exploration Net dividends Debt repayments
Operating cash flow
Cash drawn
Debt drawn
Undrawn facilities and cash
A$ billion
$2.9 billion
Net dividends
Undrawn facilities and cash
$1.9 billion
A$ billion
Debt drawn
Cash drawn
Operating cash flow
Debt repayments
12
Strong operating cashflow
Production and revenue growth, focus on cost control
Production growth from producing and sanctioned projects Increasing proportion of oil in project mix
- Chim Sao, Cooper oil, Stag performance - Fletcher Finucane and Dua projects underway
Rising gas prices in key markets
Strong revenue
Cost and productivity focus
Relentless focus on cost and productivity - Corporate costs down 15% - Rigorous approach to capital allocation - Technology enabling productivity improvements,
i.e. collaboration centres, remote operations - New rig fleet, pad drilling and simultaneous operations
reducing full cycle drilling and completion costs - Active contractor and supply chain management
13
Production guidance
Range
Production
0
10
20
30
40
50
60
2011A 2012F 2013F
51-55 53-57
mmboe 2013 production influenced by:
Continued forecast strong production from the base business
Chim Sáo on plateau
Start-up of Fletcher Finucane in 2H 2013 (average 6,600 bbl/day net to Santos in first 12 months of production)
2013 guidance 53-57 mmboe
47.2
14
2013 guidance $4 billion
Capex (excludes capitalised interest)
$billion
0
1
2
3
4
2011A 2012F 2013F
GLNG PNG LNG EA WA&NT Asia Exploration Total
$3.1 billion
$4 billion
Capex guidance
$3.5 billion
2013 capex guidance drivers:
Peak year for GLNG spend
PNG LNG includes project cost review increase announced on 12 November
EABU includes Cooper Infrastructure Expansion Program
Exploration $325 million
15
LNG Markets Peter Cleary
VP Strategy & Corporate Development
16
Focused Asian
growth
Strong Australian
base
LNG channel
Domestic channel
A leading energy
company in Australia and Asia
LNG markets
A leading gas producer in high-growth
markets
Dual channel strategy
Santos vision and strategy
17
Santos has equity in 3 fully contracted LNG projects
DLNG
Contracted to 2023
PNG LNG
Contracted to 2034
GLNG
Contracted to 2035
3.3 mtpa Santos share of long-term, oil-linked contracts in place
18
0
2
4
6
8
10
12
14
16
18
20
$3
$1 $3
$6.50
Oil-linked LNG at US$120/bbl
Oil-linked LNG at US$80/bbl
Source: Henry Hub 2020 forecast provided by PIRA; ―Other‖ includes Pipeline & Fuel; Contracted Asian LNG demand from Wood Mackenzie
LNG Pricing: Henry Hub-linkage vs oil-linkage
2020 Forecast Liquefaction Other Shipping Traditional Priced LNG
US$/mmBtu
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~180 mtpa
New trains required to meet anticipated demand1
~50 mtpa Contestable Market
~45 ~12 Global LNG Demand (mtpa)
1Assuming LNG train nominal capacity of 4 mtpa Source: Santos based on Wood Mackenzie
New sources of supply will be required to meet robust global demand for LNG
0
100
200
300
400
500
2000 2005 2010 2015 2020 2025
Pacific Basin Demand Atlantic Basin Demand Global Contracted LNG Supply
20
US LNG exports are not expected to overwhelm the market
Asia Pacific LNG Supply/Demand
0
50
100
150
200
250
300
350
2025 2020
mtpa
Source: Wood Mackenzie and Santos analysis
Contracted LNG Supply
Contestable Market
US LNG 30-40 mtpa Contracted
Sabine Pass
~140 mtpa
21
New regions of supply are emerging
12
East Africa 3
Australia
West Africa
6 Indonesia PNG .
North Africa
5
Russia 4
1
South America
Number of Operating Liquefaction Projects
Number of Under Construction / Proposed Liquefaction Projects
1
Norway
2
1
5
7 Qatar
1 1
2 3
Other Middle East
1 5
1
Non-exhaustive and indicative
Malaysia
12 3
3 3
2 1
United States
Canada
3
Greenfield
Greenfield
Brownfield
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$1,212
$1,680
$2,693
$3,016
Capex intensity (including upstream)
Australian LNG must address cost inflation
New Australian LNG projects are 80% more capital intensive than operating Australian LNG projects
1 Deutsche Bank 2 BREE (April 2012 Project listing)
US$m/mtpa
3,500
3,000
2,500
2,000
1,500
1,000
500
+80%
Collaboration & Innovation
Productivity
Global Average1
NWS/ Darwin1
2011 Estimate1
2012 Estimate2
Cost inflation must be tackled on all three fronts
Regulatory
23
Santos‘ LNG customers & partners
Bonaparte LNG Darwin LNG
PNG LNG
GLNG
24
GLNG Upstream Trevor Brown
VP Queensland
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Fairview, Roma, Arcadia, Scotia GLNG project areas
670 landowner agreements with 300 landowners in place
34,000 hectares of land owned
- Used for key development activities and environmental offsets
480 wells drilled to date
Around 1,000 wells online by end 2015 out of a total well stock of 1,3001
Roma underground storage
- Injection ramping-up
Deliverability focused drilling campaign combined with wet weather in Q1 2012 will impact reserve and resource bookings
GLNG Upstream overview
Scotia Area
Arcadia Area
Roma Area
Fairview Area
Strong acreage position
1 Well stock includes appraisal wells, some of which are likely to be converted to development wells
26 26
Compression capacity and gas purchases
0
200
400
600
800
1,000
1,200 2 train requirement
1 train requirement
Investment in upstream facilities provides 890 TJ/day of compression capacity by end 2015; gas purchases to date provide a further 265 TJ/day
GLNG net share compression capacity at the end of 2015 and gas purchases
TJ/day
1 Includes Roma underground storage 3 Purchase of 100 TJ/day from Origin Energy over 10 years 5 Acceleration projects subject to sanction by the GLNG partnership
2 Purchase of 140 TJ/day from Santos portfolio over 15 years 4 Combabula purchase of 25 TJ/day
Existing Acceleration5
3rd party gas3
Fairview
Fairview
Roma1
Scotia
Santos Horizon2
3rd party gas
Fairview/Roma
Sanctioned at FID
Compression capacity Gas purchases
Combabula4
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PERMEABILITY
Fairview: world-class CSG asset
Permeability Up to 100‘s of mD
Core holes Development wells
Core holes Desorption data
Wells Seismic
Image logs DST data
Pilot well flows & tests
159 producing wells Flank pilot wells &
developments underway
Coal Thickness 4-16 m
Gas Content 6 to 15 m3/t (daf)
Coal Depth 250 to 1550 m
Current Capacity 220 TJ/day
Fairview - Depth vs Permeability
0.01
0.10
1.00
10.00
100.00
1000.00
10000.00
400 500 600 700 800 900 1000 1100 1200 1300
Depth (mKb)
Pe
rm
ea
bilit
y (
mD
)
DSTFairview -SG productionP10P90Expon. (P1)Expon. (DST_ed)Expon. (P10)Expon. (P90)
P1
Pony Hills East 1
DM16
Pony Hills East 1
DS1
DM16
SG60
P10
P90
Fairview field is amongst the world‘s best in terms of reservoir properties
PRODUCTION COAL DEPTH GAS CONTENT NET COAL
28
Fairview
F118
F176
F001
Efficient de-watering and strong gas rates
29
Fairview well performance as of 1 November 2012
Fairview production performance
Average flow rate 1.4 TJ/day per well
Development wells drilled - 290 Currently producing - 159 Current capacity - 220 TJ/day Average gas rate building - 1.0 TJ/d (2010) > 1.3 (2011) > 1.4 (2012)
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Conventional gas >50 years
CSG pilots >8 years
Geological trends are well understood
− gas content
− thickness
− permeability
On trend with APLNG & QCLNG key development areas
135 CSG wells drilled
- 74 wells with DST test data
- 29 wells with pilot production data
Santos has a long history operating in the Roma area
Undulla Nose
Roma Combabula
Surat Basin Coal - Gas Content Fairway
GLNG tenements
Roma: on trend with other CSG fields
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Permeability Up to 100‘s of mD
PRODUCTION COAL DEPTH PERMEABILITY GAS CONTENT
Core holes Development wells
Corehole Desorption data
Wells Seismic
Image logs DST data
Pilot wells flowtest
>100 wells providing dynamic data & developments
underway
Coal Thickness 7 to 14 m
Gas Content 3 to 5 m3/t (daf)
Coal Depth 250-1000m
Pilot Production 14 multi-well pilots
being brought online, 9 more planned
NET COAL
Roma field is comparable to other CSG fields on the Surat Fairway
Roma geology well understood
32
Roma pilot data
14 multi-well pilots in NE where 1st phase development is underway
9 additional pilots to be added in west & centre 2013-14
Data used to calibrate gas & water type curves for reserves and production forecasting
Early data confirming individual well potential in excess of 0.5 TJ/day
Early pilot production is confirming good gas flow potential
Initial Pilot Locations
Gas
Water
Typical Pilot Well Performance
Months
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Manny Sessink General Manager
Drilling and Completions
34
Drilling: rigs and wells
Drilling capacity secured to meet forecast well requirements
Current rig fleet of eight drilling rigs and four completion rigs - Commissioned two new drilling rigs in third quarter 2012
- Commissioning eighth drilling rig and fourth completion rig
Rig fleet fit-for-purpose - New Saxon directional rigs
- Pad drilling
- Reduced footprint, higher productivity
480 wells drilled to end September 2012
On target to drill 150 wells in 2012
250-300 wells per annum in 2013-15
Land access secured for 200 wells of the 2013 drilling program
Expect to maintain circa 300 wells per annum post-2015
35
Drilling: cost efficiencies
0
600
1,200
1,800
RM
13-0
9-5
RM
13-0
9-3
RM
13-0
9-4
RM
13-0
9-2
RM
02-2
0-2
RM
12-1
0-4
RM
08-0
7-1
RM
08-0
7-2
RM
08-0
7-3
RM
12-0
6-1
RM
12-1
0-1
RM
12-1
0-2
RM
12-1
0-3
RM
08-0
2-1
RM
08-0
2-2
RM
08-1
1-4
RM
12-0
6-2
RM
12-0
6-3
RM
12-0
6-4
RM
02-2
4-1
RM
08-0
1-1
RM
08-0
8-1
RM
08-0
8-2
RM
08-1
1-1
RM
08-1
1-2
RM
08-1
1-3
RM
02-2
4-2
RM
02-2
4-3
RM
02-2
4-4
RM
07-1
7-1
RM
07-1
7-2
RM
08-0
1-2
RM
08-1
5-1
RM
08-1
7-1
RM
08-0
6-1
RM
08-1
5-2
RM
08-1
5-3
RM
08-1
5-4
RM
08-1
7-2
RM
08-1
7-3
RM
08-1
7-4
RM
12-1
4-2
RM
12-1
4-3
RM
12-1
4-4
RM
07-1
9-1
RM
07-1
9-2
RM
07-2
1-1
RM
08-0
6-2
RM
12-1
1-3
RM
12-1
1-4
RM
12-1
4-1
RM
12-1
1-2
Actual controllable cost Linear (Actual controllable cost)
$000
40% reduction in drilling cost for Roma deviated wells achieved in 2012
2012 Roma deviated well drilling cost Significant time and cost efficiencies are continuing to be achieved as a result of:
Significant reduction in well types to a few core designs
Defined groups of wells has led to a factory drilling approach, increasing operational performance both cost and time
36
Roma and Fairview development
GTP
HCS-5
HCS-4
HCS-2
QGP
Wallumbilla
RUGS
CRWP
PCS
CS3 CS2
Arcadia Area
Fairview Area
Roma Area
Acceleration
Acceleration
Existing facilities
Sanctioned at FID
Acceleration
HCS: hub compressor station PCS: pipeline compression station RUGS: Roma underground storage
QGP: Queensland Gas Pipeline CRWP: Comet Ridge to Wallumbilla pipeline GTP: Gas transmission pipeline
37
Fairview surface facilities
420 TJ/day gross compression capacity sanctioned at FID, in addition to 140 TJ/d existing gross capacity
Additional ~70 wells from acceleration projects
Two Hub compressor stations (HCS4 &5) being built in addition to two existing Fairview stations
Bi-directional flow
- Via CRWP into RUGS
- Via GLNG GTP to Curtis Island
Currently 220 TJ/d Fairview gross wellhead capacity from 159 commissioned wells
Gross Production ~130 TJ/d including injection into RUGS
GTP
HCS-5
HCS-4
HCS-2
QGP
Wallumbilla
RUGS
CRWP
PCS
CS3 CS2
Arcadia Area
Fairview Area
Roma Area
Acceleration Scope: Total wells ~70
Acceleration
Acceleration
38
Fairview Hub 4
HCS-4: 250 TJ/day gross capacity
Combined gas processing, compression and water treatment
Hub construction underway - Overall construction 15% complete
- Bulk earthworks >75% complete, piling >40% complete
- First foundation concrete pours in September for the Multi Media Filtration & Softener Foundations
- Gathering network piping installation >50% complete
- Gas Turbine Alternators and Wellpad Separators delivery to site commenced
Mechanical completion targeted by end 2013
Construction underway on associated wellpads, gathering systems, roads and permanent camps
Piling
Site works
39
Fairview Hub 4
35ML pond construction of spillway, transfer pump sump in background
Multi Media Filtration concrete pour – Water Desalination
Commencement of driven piles for NCS compressors
40
Fairview Hub 5
HCS-5:170 TJ/d gross capacity
Combined gas processing, compression and water treatment
Hub construction underway - Bulk earthworks commenced, cut
and fill >80% completed
- Underground pipeline installation underway
- Hub access road constructed
- Overhead power pole installation and stringing underway, installation of fibre optics ongoing
Mechanical completion targeted by end 2013
Construction underway on associated wellpads, gathering systems, roads and permanent camps
AWAF3 storage tank foundations
41
Roma surface facilities
145 TJ/d compression capacity sanctioned at FID, including 75 TJ/d RUGS injection / withdrawal capacity
Additional ~250 wells and 280 TJ/d compression from acceleration projects
One Hub compressor station (HCS-2) being built
RUGS – storage in conventional depleted Roma gas fields – strategy to manage ramp gas requirements during plant commissioning, restarts and upsets
Planned production in 2014 for dewatering and gas injection into RUGS
GTP
HCS-5
HCS-4
HCS-2
QGP
Wallumbilla
RUGS
CRWP
PCS
CS3 CS2
Arcadia Area
Fairview Area
Roma Area
Acceleration Scope: Total wells ~250 New hub compression 280 TJ/d
Acceleration
Acceleration
42
Roma Hub 2
HCS-2: 145 TJ/d capacity (including RUGS injection / withdrawal)
Combined gas processing, compression and water treatment
Hub construction underway
- Overall Construction 10% complete
- Bulk earthworks >85% complete
- Underground pipeline installation commenced
- Concrete works on pipe-rack installation commenced
- Hub piling 30% complete
- Gathering Network piping installation > 50% complete
Mechanical completion targeted by end 2013
Concrete pouring
Roma Hub 2 camps
43
Brisbane Operations Centre
O&M Philosophy - centralised control, high level of automation, smaller hubs, minimise driving
- Minimise ongoing disturbance to land holders and community
- Reduce operational costs
- Consistent performance
24/7 monitoring and operations of all upstream assets including vehicles from single point
- Immediate awareness of asset integrity issues or downtime
- Enabling rapid response driving high safety outcomes and operational availability
World class technology deployed
44
On track for first LNG in 2015
Milestone Date
Long lead procurement commenced Q1 2011
First access to site Q2 2011
Commenced hub compressor stations Q1 2012
Roma water production system mechanical completion
Q4 2013
Compressor station mechanical completion Q4 2013
45
GLNG Downstream Mark Macfarlane
VP GLNG OPL
46
Pipeline, Plant and Port
Gladstone
Rockhampton
Maryborough
Brisbane
ROMA
INJUNE
WALLUMBILLA
WANDOAN
ARCADIA VALLEY
TAROOM
ROLLESTON
SPRINGSURE
Bauhinia
Oombabeer
Moura Banana
Biloela
Caliope
SURAT BASIN
BOWEN BASIN
CURTIS ISLAND
Bundaberg
0 100
Kilometres
47
Gas transmission pipeline
100-km of the mainland pipeline right of way has been cleared and graded as at November 2012
420 km of 42" pipe 35,000 joints All pipe manufactured and shipped Peak workforce of 1,300 on pipeline
by April 2013 Pipeline completion Q2 2014
48
70 km of pipeline strung along right of way
Clearing and grading
Pipe stringing
Pipe unloading
Beveling
49
1,000 joints have been welded
Welding preparation Welding
Welded pipe on right of way
50
Pipeline marine crossing
51
Pipeline marine crossing
52
Marine crossing – installation sequence
53
Curtis Island – May 2011
54
Curtis Island – December 2011
55
Curtis Island – October 2012
56
Curtis Island
31 October 2012
57
1,344 room accommodation complete
Capacity for future staged expansion to 2,208 rooms Curtis Island site workforce peaks at 2,050 in Q2 2014
31 October 2012
58
Material offloading facility
31 October 2012
59
LNG Train 1
31 October 2012
60
LNG Tanks
31 October 2012
61
LNG Tank B
31 October 2012
62
Module yard, Batangas
Fin fans Propane condenser steelwork
Placement of pipework onto LNG jetty modules
63
On track for first LNG in 2015
Milestone Date
First Curtis Island works May 2011
First permanent structural concrete for Train 1 propane refrigeration compressors
February 2012
First concrete LNG tanks – LNG Tank B July 2012
First module arrives Q1 2013
Pipeline completion Q2 2014
First commissioned gas to LNG train Mid-2014
First LNG Train 1 2015
64
Western Australia & Northern Territory Business Unit
John Anderson VP Western Australia & Northern Territory
Fletcher 5 clean-up, Carnarvon Basin
65
WA&NT – delivery today/growth for tomorrow
Highest ever production from Carnarvon Basin, driven by Reindeer and Spar
Winchester and Zola to be drilled in 2013, success will offer multiple growth options
Domestic Gas
Fletcher Finucane development on budget, on schedule for first oil in 2H 2013
Other oil tie-in opportunities identified
Carnarvon Oil
Material success in the Browse Basin with Crown-1 well
Caldita Barossa unlocked: SK farm-in for up to US$520 million
Strong production from DLNG following the planned shutdown in 2Q
Northern Australia
66
Record Carnarvon gas production
Gas production up 50% in 2012 to highest ever of 49.5 PJ to end Q3
Varanus Island
Strong production from John Brookes and Halyard well
Considering follow-on projects − Spar 2 tie-back project
− John Brookes low inlet compression project
Reindeer/Devil Creek
Opportunity to increase production through new sales
Room for expansion at Devil Creek Processing Plant including brownfield train 3
Hurricane gas discovery
Currently being appraised
0
3
6
9
12
15
18
2010 2011 2012
Santos Carnarvon gas production PJ/Qtr
Devil Creek Gas Processing Plant
Site of potential train 3
2010 2011 2012
67
Zola and Winchester: early 2013
Zola
WA-13-L
Spar
Barrow Island
John Brookes
Varanus Island
Winchester
WA
WA-323-P
Indian Ocean
Winchester
Santos 75% and operator
Exploration drilling Q1 2013
Ensco 109 jack-up
Shallow water (60-80m)
Material prospect with potential high liquids
On success case, multiple development options including domestic gas and tie-back to third party LNG
Zola
Santos 24.75%
2011 discovery, 100m of net gas pay in excellent quality reservoir
Appraisal drilling program Q1 2013
Multiple development options including tie-back to Wheatstone LNG Ensco 109
68
Carnarvon Oil: Fletcher Finucane
3 well, subsea tieback to Mutineer Exeter FPSO
- FPSO will undergo dry dock during Q1 2013
Average gross production rate of 15,000bbl/day in the first 12 months
Fletcher 5 development well complete, both Finucane development wells underway
Follow-on oil opportunities proximate to the FPSO identified
− Wells to add oil production
− Near field exploration prospects
Project is over 65% complete and on schedule for first oil in 2H 2013
Manifolds and PLEM set up for factory acceptance testing
69
Darwin LNG/Bayu-Undan
Successfully completed shutdowns in 2012 - Improved operability and reliability
- 5% increase in gross gas production Q3 2012 v Q3 2011 taking advantage of previous system enhancements
Land available for Darwin expansion, with government environmental approval in place for up to 10 mtpa
FEED commenced for Bayu Undan Phase 3 offshore expansion - Extend production plateau
- Incremental liquids recovery
Continued strong production and cashflow…
70
Northern Australia: key part of Santos‘ future
Caldita Barossa (Santos 25%)
New Asian partner and Korean energy major, SK E&S
SK E&S will fund up to US$520 million in appraisal drilling, pre-FEED, FEED and milestone payments to JV partners
Planning for 3 well appraisal program underway
Development options include Darwin LNG expansion
Bonaparte LNG (Santos 40%)
GDF Suez 60% and operator
Federal Government Environmental Approval, only the second for floating LNG in Australia
Competitive Concept Definition phase underway
KBR and Technip awarded contracts to complete independent designs of the floating LNG facility
Caldita Barossa unlocked in June 2012 with SK E&S farmin for up to US$520 million; BLNG environmental approval achieved
71
Browse: Crown success unlocks material play
Significant gas discovery at Crown-1 − Well-positioned in close
proximity to existing and proposed LNG projects in the Browse Basin
Farm-in to 30% interest in Total-operated WA-408-P − Dufresne-1 and Bassett
West-1 to be drilled immediately following Crown
Multiple commercialisation options available
Crown discovery located in close proximity to existing and proposed LNG projects; Santos farmin to adjacent permit WA-408-P
Gas field Prospect
Santos acreage Oil field Ichthys to Darwin pipeline under construction
WA-274-P
WA-410-P
WA-274-P
WA-281-P
WA-411-P
Crown
Poseidon
Brecknock
Calliance
Torosa
Burnside
WA-281-P
Argus
Western Australia
Bassett West Dufresne
Browse LNG Project
Ichthys LNG Project
Prelude LNG Project
WA-408-P
WA-274-P
72
Crown-1 gas-condensate discovery
Large, simple Jurassic fault block structure
Wireline logging:
- 61 metres net gas pay in Jurassic-aged Montara, Plover and Malita sandstones
- Pressure data (30 points) implies single hydrocarbon-bearing gas condensate column in good quality reservoir rock
- Multiple condensate-bearing gas samples have been recovered to surface. Preliminary analysis indicates the presence of 10-12% CO2
- A gas-water contact has not been encountered in the well to date
Drilling is progressing to a proposed total depth of 5,320 metres
Good quality 3D seismic dataset implies highside case of structural communication between Crown and adjacent Treasury structure
Crown to Treasury Seismic Transect
Crown-1 Treasury
Preliminary contingent recoverable resource estimate 0.5-5 TCF
73
Browse Basin – exploration follow-up
Crown 0.5 – 5 TCF
Grande Prospect
Bassett West Prospect Dufresne Prospect
Lasseter Prospect
Treasury-1 Proposed
Prospect ―D‖
The Browse inventory presents material exploration running room for Santos…
Luxor Contingent Recov Resource 0.6 TCF
Astrolabe Prospect
WA-274P
Unrisked Prospective Recoverable Resource Ranges for Prospects vary from
0.5 to 5 TCF
74
500m
7km
Winchester – Carnarvon Basin
Winchester-1 Parker-1
Wilcox-2
Wilcox-1
Winchester Seismic Transect Winchester Prospect, Carnarvon Basin, Western Australia
Winchester-1
Wheatstone
Iago
Pemberton
Sculptor Rankin
Dockrell Echo/Yodel Goodwyn
Dixon
Wilcox
Winchester Proposed Well Location Mean Recov. Gas 680 BCF Mean Recov. Cond 25 MMbbls
Parker-1, 1979, TD 4737, Abandoned without evaluation due to operational difficulties
The Winchester Prospect is a large structural trap downdip from the prolific Goodwyn – Rankin trend
The Winchester-1 well is substantially updip of the Parker-1 well (200 metre strong mud gas shows), which was abandoned without evaluation due to operational difficulties
High gas liquids (condensate) content anticipated Drilling to commence in Q1 2013
75
302 368 377
339
423
0
100
200
300
400
500
600
700
800
2010 2011 2012
WA&NT – delivery today/growth for tomorrow
Proven track record of delivery while generating future growth opportunities
WA&NT EBITDAX (excluding asset sales)
2012 Delivery
EBITDAX margin 75% Crown success Carnarvon gas production
up 50% Caldita Barossa unlocked Fletcher Finucane
sanctioned
Growth catalysts
Winchester and Zola drilling in Q1 2013
Dufresne and Bassett West drilling in 1H 2013
Varanus Island and Devil Creek upside
Fletcher Finucane first oil on track for 2H 2013
$million
1H 2H
76
Eastern Australia Business Unit James Baulderstone VP Eastern Australia
Tindilpie 6-well pad during fracture stimulation "SIMOPS", July 2012
77
Key 2012 Delivery
Cooper Gas transition on track
Santos 2011 reserves booking of 330 PJ/68 mmboe, highest booking since 1997
Significant progress towards U.S. style gas development with first 6 well pad online which will produce 15 mmscf/day
Moomba infrastructure upgrade plans well developed
Cooper Oil Formation of dedicated Cooper Oil team Delivering the highest production since 2009 Increasing value from 3rd party processing
NSW set to move into development
phase
Legacy issues managed Government enabling regulation in place Two phase development program set Focused drilling program commencing early 2013
Unconventional resource success and expansion – across Central Australia
Australia‘s first commercial shale gas well, flowing at an initial rate of > 3 mmscf/day
Dedicated program targeting material production of sales gas by 2015 Secured 19 million acres of highly prospective permits in Central
Australia, with tie-back potential to Mereenie and Moomba
78
EABU Key Themes
1. Cooper Gas transition
2. Delivering Cooper Oil
3. Central Australia unconventional resources
4. NSW program
79
EABU positioned to capture new market opportunities
0
500
1,000
1,500
2,000
2,500
3,000
3,500
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
Retail and C&I Power generation QCLNG (T1&2)
GLNG (T1&2) APLNG (T1 & T2) Arrow LNG (T1&2)
PJ/a 3 fold demand growth from today
Eastern Australia gas supply costs (ex-field)1
Eastern Australia gas demand
1 Source: Fuel cost projections, natural gas and coal outlooks for AEMO
modelling (December 2011)
$0
$2
$4
$6
$8
$10
$12
$14
$16
0 50,000 100,000 150,000 200,000
LR
MC
(R
eal
$2012-1
3)
Reserves/Resource (PJ)
Contracted Uncontracted
$/GJ
Santos price range of $6-$9/GJ
Santos‘ Eastern Australia Resource Footprint
Step-change in gas demand Increased gas prices Unlocking Santos‘ extensive Eastern Australia resources
Amadeus/ Pedirka
Cooper/ Eromanga
Surat/ Bowen
Gunnedah
Otway Gippsland
…which will deliver profitable growth
80
Upstream Infill Development Multi-well pad drilling technology – 4 rigs by 2014
SIMOPS approach to drilling, completions and connections
30% production growth to 2015 leads to step-change in cost reductions
Field Compression Satellites Expansion of five field compression stations
Flexibility / cost reductions through staged expansion and relocatable compression packages
Moomba Gas Plant – Phased Expansion Sales gas processing capacity rationalisation, re-life and expansion, flexible up to ~600 TJ/d (Ballera additional 100+ TJ/d)
Ultimate capacity subject to Santos and 3rd party upstream developments
Cooper Gas transitioning Higher volume, lower cost business through…
…multi-well pad drilling technology, SIMOPS and flexible compression and processing expansions
0
25
50
75
2010A
2011A
2012F
2013F
2014F
2015F
# W
ell
s D
rill
ed
Flood impacts
Enabled through multi-well pad drilling technology and SIMOPS
81
Developing pad drilling and SIMOPS capabilities
Tindilpie 6 well pad on-line from October 2012
Cowralli 16 well pad committed for 2013, with forecast 16% lower well costs
Frac efficiency 30% increase in 2013
Cooper Basin delivering rate and reserve: YE2011 RRR of >200%
Production costs reducing by 30% to ~$9/boe by 2015
Growing volume increases satellite and plant utilisation
Driving operations and maintenance costs down ~$35m p.a. (11%) by 2015
Maintenance strategies successfully delivering record downtime levels leading to production benefits
Transforming development and production delivery
‗Factory style‘ field development and production cost reductions…
…on track to capture volume and margin growth
0
5
10
2012F
2013F
2014F
2015F
Ave
. co
st
pe
r w
ell
($2012M
)
25+% drilling cost reductions by 2015
0%
10%
20%
30%
2007A
2008A
2009A
2010A
2011A
2012F
2013F
2014F
2015F
Co
op
er
Ga
s D
ow
nti
me
Wet weather Scheduled downtime Unscheduled downtime
Unscheduled downtime to below 10% by 2015
82
Cooper Infrastructure Expansion Program
Phased Field Compressor Station Expansions
Big Lake (7,200hp)
Daralingie (3,200hp)
Moomba North (7,200hp)
Gidgealpa (14,400hp)
Tirrawarra (7,200hp)
Phased Expansion of Moomba Gas Plant
Initial installation of single 1,000 ktPa train for additional CO2 removal processing
Rationalisation and re-life of existing plant
New Moomba Export Compression Facilities
Phased installation of up to 67,500hp
Enables firm delivery of sales gas from Moomba to Qld (Mt Isa, Wallumbilla etc) from Q2 2014
Flexible ‗Phase 1‘ to match field development pace comprising…
Cooper Infrastructure Expansion Program
CIEP Phase 1: Up to ~$800M
CIEP Phase 2
Upstream Infill Development
Four new pad drilling rigs over 15 Years
110 pads with 600 new wells
300km of gathering network infrastructure
83
EABU Key Themes
1. Cooper Gas transition
2. Delivering Cooper Oil
3. Central Australia unconventional resources
4. NSW program
84
Creation of a dedicated Oil Asset Team in 2011 delivering results
Greater than 100% reserve replacement underpins sustainability
Extensive oil infrastructure generates $35m Santos profit from processing 3rd party volumes, forecast to grow by ~30% in 2013
New technology applied to lower unit costs and weatherproof key oil fields
0
1
2
3 2010A
2011A
2012F
2013F
Pro
du
cti
on
(M
mboe)
2012 Cooper Oil Delivery Refined Cooper Basin Oil strategy delivering with best production year since 2009
Spider plough in action
Sustained production growth…
New collaboration centre
85
EABU Key Themes
1. Cooper Gas transition
2. Delivering Cooper Oil
3. Central Australia unconventional resources
4. NSW program
86
Commercialising world class unconventional resources across Central Australia Capturing unconventional reservoir opportunities
1 Includes Cooper, Eromanga, Amadeus and Pedirka Basins 2 Gross estimates
Substantial unconventional contingent and prospective resources across the Central Australian Basins(1)
U.S. technology & learnings are being applied to accelerate unlocking Australia‘s unconventional potential
Substantial resources
Amadeus/ Pedirka
Cooper/ Eromanga
Santos first to flow commercial shale gas from Moomba 191
Santos dedicated frac spread in Cooper Basin
Santos‘ extensive geologic knowledge and 50+ years of development experience in the Cooper Basin
Santos‘ strong infrastructure position
Competitive advantages
~$200 million(2), 3 year (2012-14) Cooper focused capital program to evaluate optimal well and frac designs, convert resources into reserves and establish material production by 2015
Cooper program comprises drilling three horizontal and six vertical wells, together with multiple in-wellbore projects
Core acquisition and multiple fracture stage in Mereenie
Focused evaluation and
commercialisation plan
87
Moomba 191 is an extraordinary result…
Dedicated shale well commissioned on 28 September 2012
Initial flow rate >3 mmscf/d
First month average flow rate of 2.7 mmscf/d
Gas composition is consistent with that produced in the Moomba Big Lake area
0
0.5
1
1.5
2
2.5
3
3.5
28 Sep 08 Oct 18 Oct 28 Oct 07 Nov
Ga
s P
rod
ucti
on
Ra
te
(MM
scfd
)
Moomba 191: Production History
Australia‘s first shale gas reserve booking
Moomba 191 Gas Flare
Bcf 1P 2P 3P
Accessed OGIP 2 4 9
Ultimate Recovery 1.5 3 7
Santos EUR Estimates YE 12
88
Comprehensive Cooper Basin unconventional program targeting our most prospective play types
Net Santos Cooper Basin Prospective Unconventional Resources1
Net Santos Cooper Basin Contingent Unconventional Resources2
Tcf Low Mid High
Total Recoverable Gas 10 33 83
1. Evaluated by DeGolyer and MacNaughton, 2008
2. Verified by DeGolyer and MacNaughton, as at 2011
PJ 1C 2C 3C
Total Recoverable Gas 1,156 2,345 4,561
Moomba REM Shale
Combination of vertical and horizontal wells to optimise well and frac design
Horizonal wells will be drilled with differing lengths and fracture stages
Utilising micro seismic facture diagnostics
Nappamerri Trough Basin Centred Gas
3 vertical wells to further define the resource potential
Prioritising two significant resource plays…
89
Central Australia‘s further unconventional potential
Mereenie and North Mereenie unconventional reservoir potential
Significant unconventional recoverable prospective resource
Core acquisition and fracture stimulation to define and appraise the resource potential1
Leveraging existing operational infrastructure at Mereenie
Santos‘ farm-in to ~19 million acres across the Amadeus & Pedirka basins provides:
Significant exposure to conventional and unconventional resource with potentially large estimated recoverable resource
Commitment to acquisition of 2,100km of 2D seismic over farm-in acreage and 1 exploration well
Further options to add 1,000km 2D seismic and up to additional 9 exploration wells
Nth Mereenie Block
Amadeus Basin
Pedirka Basin
Eromanga Basin Gladstone
Sydney
Moomba
Adelaide
Darwin
Mereenie
Mereenie
Alice Springs
South Australia
Moomba
Cooper Basin
Northern Territory
Queensland
Santos acreage
Santos right to earn up to 70%
Santos right to earn up to 56%
1. Operationally combined with conventional resource oil development program
Legend
Oil field
Gas field
Oil pipeline
Gas pipeline
90
EABU Key Themes
1. Cooper Gas transition
2. Delivering Cooper Oil
3. Central Australia unconventional resources
4. NSW program
91
Reserves and resource(1):
1,427 PJ 2P
3,531 PJ 2C
~12,000 PJ contingent resource
Energy Australia– 20% partner in PEL 238
Commercialise through:
NSW energy challenges:
NSW is the only state with no significant gas production
Uncontracted between 2014-2017
Reliance on imported gas will expose NSW to significant gas price increases
CRP(2) / MSP(3) connect Access strong Eastern Australia market demand ~170km
Wallumbilla Major supply hub for LNG ~470km
Newcastle Industrial demand and site of proposed Newcastle LNG plant ~350km
Acquired interest in 2009 & 2011
Three commercialisation
pathways
NSW energy security
Represents East Australia‘s largest onshore uncontracted 2P volumes…
A robust investment opportunity
…positioned to provide energy security to NSW
0
50
100
150
200
250
2011 2013 2015 2017 2019 2021 2023 2025
Contracted Supply
PJ/a
NSW / ACT Demand and Contracted Supply
Uncontracted volumes
Wallumbilla
Gunnedah Basin
Newcastle
Sydney
PEL 427
PEL 428
PEL 6
PEL 238
PEL 434
PEL 450
PEL 462 PEL 1 PEL
12
PEL 433 PEL 456
PEL 452
Goondiwindi
Moree
Narrabri
Gunnedah
Tamworth
Scone Dubbo
Coonabarabran
New South Wales
Queensland
1. Gross basis 2. Central Ranges Pipeline 3. Moomba Sydney Pipeline
92
2012 progress enables forward program
2013 – 2014 activity to progress towards FEED
Commence 3 year drilling program across Bohena and Bando: build reserves and resource bookings
Drilling program targets confirming lateral drilling technology, well de-watering time and key subsurface information
Construction of state-of-art water treatment facilities at Leewood
Submission of project environmental approvals
Strong progress from legacy issue management to development planning…
…with three year forward drilling and seismic program to prove development concepts and build reserves
Legacy issues dealt with in 2012
Legacy integrity issues being resolved
Government policy enacted enabling license extension and development
Community engagement to address key concerns continuing
Landholder compensation arrangements implemented
Remediation works well progressed
Focused drilling program
9 pilot and 22 core wells
Production data gathering
16 work-overs
Remediation targets
Bohena (PEL 238)
Bando (PEL 1 & 12)
before after
93
Commercialise 1,500 to 2,500 PJ resource
Early gas sold into Wilga Park Power Station and/or domestic market via CRP
Production ramping from 2017 to reach >100 TJ/d by 2020
Concentrated appraisal program 2013-15
Commercialise additional ~1,500 PJ resource
Production continuing to build towards 250 TJ/d post 2020
Phasing of development will allow additional consultation with key stakeholders
Two phase project1 based initially around the mature Narrabri asset…
Focussed development plan
1All numbers gross project basis
Historic Results:
Six production pilots and 34 core-holes drilled (confirming thick coal packages)
Four pilots successfully apply lateral technology
Impressive results from Bibblewindi West tri-lateral: > 2 mmscf/d after 1 month production
…building on the 10 years of existing exploration and appraisal activity
Bibblewindi lateral pilot
Bibblewindi West pilot
Tintsfield lateral pilot
Dewhurst pilots
Bibblewindi 9-Spotpilot
Bohena pilot
WPPS
Bo
he
na
Ph
ase
1
Ba
nd
o
Ph
ase
2
94
287 300 312
290 333
0
100
200
300
400
500
600
700
800
2010 2011 2012
Eastern Australia – leveraging the past to capture the future
EA EBITDAX (excluding asset sales) Cooper
Basin
Unconvent-ional
Resources
$million
1H 2H
Positioned to meet East Coast‘s growing energy demand
NSW
Transitioning to a new low cost regime, leveraging existing infrastructure, resource base and rapidly growing market
Utilising learnings from the U.S., extensive resource knowledge, processing and transport infrastructure to accelerate commercialisation and extend into additional prospective opportunities
Platform established to enable valuable gas resource to be developed to meet peak demand 2015-2020
Insert picture
Asia Pacific Business Unit Martyn Eames VP Asia Pacific
96
Asia Pacific – delivery in 2012
Wortel delivered in January 2012 on budget
Farm in to additional South Sumatra CSG licences
Indonesia
Chim Sáo producing > 25,000 bbls/day
Dua oil project sanctioned, first oil on track for 1H 2014
Vietnam
PNG LNG on track for first LNG in 2014
Project 70% complete
Capacity increased to 6.9 mmtpa
PNG
Focus on three core countries; Indonesia, Vietnam and PNG
97
Indonesia – established business
Wortel gas project delivered in January 2012 on budget − Oyong/Wortel combined gross production
90 mmscf/d gas and 2,200 bbl/day oil
Increased margins from rising domestic gas prices − New gas volumes sold at > US$6/mmbtu
with escalation
Peluang targeting FID in early-2013 − Tie-back to Maleo with start-up expected
in 1H 2014
− Currently finalising Gas Sales Agreement negotiations
− Anticipated gross peak production of 25 mmscf/day
Strong base business in East Java with increased margins and incremental growth
0
1
2
3
4
5
6
7
8
2006 2007 2008 2009 2010 2011
Indonesia Net entitlement production
mmboe
*
*2011 impacted by lower PSC net entitlement to production following the favourable Maleo price review
98
Indonesia - unconventional growth
Leverages Santos‘ CSG experience in Australia and operating experience in Indonesia
Licences located close to the South Sumatra-West Java pipeline
Santos now holds interests in four Sugico-owned licences, following two farmins in 2012
Up to 60 metres of coal thickness identified in the west of the licences
Five sites and access prepared
6-well commitment drilling program to commence in 1H 2013
Farm-in to two additional CSG licences in 2012; South Sumatra CSG drilling program to commence in 1H 2013
Belida
Air Komering
Ogan Komering
II
Ogan Komering
I
99
Vietnam - high margin oil business
Chim Sáo on plateau; Dua on track for first oil in 1H 2014
Chim Sáo (Santos 31.875%)
Gross oil production rate >25,000 bbl/day for last seven months
Cargoes achieving premium to Dated Brent
Reserve increase possible
Dua (Santos 31.875%)
Project sanctioned in August 2012 as a three well subsea tie-back to Chim Sáo
10,000 bbl/day gross with first oil on track for 1H 2014
Project progressing on schedule
Gross oil and gas 2P reserves 9 mmboe
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov
Gross average daily Chim Sáo oil production
bbl/day
2011 2012
25,000
100
Vietnam - significant exploration upside
Active exploration program underway in the Nam Con Son and Phu Kanh basins
Block 13/03 (Santos 65%, operator)
>1,000km2 3D seismic acquired in 2Q 2012
Hon Khoai well planned for 2H 2013
Water depth 89 metres
Gross mean prospective resource estimate 50 – 100 mmboe
Follow up prospectivity in Hon Sao
Block 123 (Santos 50%, operator)
564km2 3D seismic completed in June 2012
Exploration well to be drilled in 2014
S N Arbitrary Line
Top Reservoir
Hon Khoai
10 Km
Hon Khoai
Hon Sao
101
PNG LNG on track for first LNG in 2014
Project is 70% complete - Drilling underway on the first two
production wells
- Mobilisation of second drill rig is underway
- Offshore pipelay is complete
LNG plant capacity increased to 6.9 mtpa - Discussions underway with potential
buyers
Gross capex estimate increased to US$19 billion - Santos total share of increase is
US$450 million
- Planned funding in line with Project‘s existing financing terms; 70% debt and 30% equity
Capacity increased to 6.9 mtpa; gross capital cost estimate increased to US$19 billion due to FX impacts and logistics challenges
Rig 702 drilling at Hides
102
PNG LNG – Potential expansion
Potential areas for expansion are being assessed
- Hides development drilling underway
Plans are being developed to drill Hides Deep in 2014 (Santos 24% equity)
- Optimal access to project infrastructure
Existing infrastructure can support potential future expansion
Train 3 Location
103
PNG LNG — upstream progress
104
PNG LNG — LNG plant site
105
Asia Pacific – growth and margin expansion
2012 Delivery
Wortel delivered
Chim Sáo on plateau
1H EBITDAX up 270%
EBITDAX margin 78%
Growth catalysts
Peluang FID in early 2013
Vietnam/Indonesia CSG exploration drilling
Dua oil in 1H 2014
PNG LNG in 2014
$million
Strong track record and material growth
65 47
175 46 110
0
50
100
150
200
2010 2011 2012
1H 2H
Asia Pacific EBITDAX (excluding asset sales)
Insert picture
Wrap-up David Knox
Managing Director and CEO 106
Mutineer-Exeter, Carnarvon Basin, Western Australia
Insert picture
107
2012 Investor Seminar 22 November 2012
108
Well name
Basin / area
Target
Santos Interest
%
Timing
Winchester-1 Carnarvon Gas 75 Q1
Dufresne-1 Browse Gas 30 Q1
Cooper Unconventional – 5 well program Cooper Gas 66.6 Q1 – Q3
Cooper NFE – 4 well program Cooper Gas Various Q1 – Q4
NSW CSG – 4 well program Gunnedah CSG Various Q1 – Q3
Indonesia CSG – 4 well program South Sumatra CSG 60 Q1 – Q2
Bassett West-1 Browse Gas 30 Q3
Hoi Khoai-1 Nam Con Son Oil 65 Q3
Mt Kitty 1 Amadeus Gas 70 Q3
Mereenie Unconventional Cores Amadeus Gas 100 Q3
Queensland CSG – 2 well program Denison CSG 50 Q4
2013 exploration schedule
The exploration portfolio is continuously being optimised, therefore the above program may vary as a result of farmout, rig availability, drilling outcomes and maturation of new prospects
Gross Success Case Highside Outcome >100 mmboe
109
Contact information
Head office
Adelaide
Ground Floor, Santos Centre
60 Flinders Street
Adelaide, South Australia 5000
GPO Box 2455
Adelaide, South Australia 5001
Telephone: +61 8 8116 5000
Facsimile: +61 8 8116 5050
Useful email contacts
Share register enquiries:
Investor enquiries:
Andrew Nairn
Group Executive Investor Relations
Level 10, Santos Centre
Direct: + 61 8 8116 5314
Email: [email protected]
Nicole Walker
Investor Relations Manager
Level 10, Santos Centre
Direct: + 61 8 8116 5302
Email: [email protected]
Website:
www.santos.com
109
