Malaysia - Talisman Energy

Transcription

T
al
i
s
manEner
gy
Sout
heas
tAs
i
aPr
es
ent
at
i
on
Oc
t
ober
,2009
I
anWeat
her
don
Vi
c
ePr
es
i
dent
,I
nv
es
t
orRel
at
i
ons
(
403)2371
140
10/14/2009
www.talisman-energy.com
2 of 50
Operations: three core areas + global exploration. . .
Southeast Asia
North Sea
North America
Self funding
built in growth
Sustainable cash flow
Oil price leverage
Norway exploration
Growth through
Unconventional gas
. . .provides a balanced portfolio
2008 Production
2008 Commodity Exposure
Other
5%
SE Asia
21%
Gas
36%
North
America
42%
Oil
52%
Oil
Linked
Gas
12%
North
Sea
32%
North America 10yr ROACE (%)
International Portfolio 10yr ROACE (%)
Commodity Price US$ WTI
Commodity Price US$/mmbtu
40%
$4
40%
$40
30%
$6
30%
$60
20%
$9
20%
10%
10%
0%
0%
-10%
-10%
Conventional
10/14/2009
$90
Unconventional
North Sea
SE Asia
3 of 50
Robust strategy – a clear business strategy to
unlock value
1
Establish Long-term Profitable Growth
• North America unconventional
• Southeast Asia, Norway
2
Reposition International Exploration Portfolio for Renewal
• Support existing core areas
• Build new core areas
3
Focus Portfolio to Generate Cash for Re-investment
• Maximize value from existing mature assets
• Exit non-strategic areas
. . .and longer reserve life
Reserve Life Index 2008
2008 Year End 2P Reserves
Years
2.5 Billion boe
15–20
9
Unconventional
Gas
4%
North America
13
9
North Sea
15
Gas
50%
14
Oil
46%
SE Asia
22
1P
2P
Typical Industry Unconventional
1P Range
10/14/2009
4 of 50
Strategy drives lower F&D costs. . .
2008 % Undeveloped reserve bookings
60
40
38
33
18
Talisman
North America
Unconventional Gas Peers
Talisman 5 year historical F&D Cost (C$/boe)
23.5
20.3
20.2
10.9
SE Asia
North Sea
North America
Total
Capital expenditures reduced in 2009 but remain
focused on new strategy
Capital Expenditure
C$ billion
5.2
N America Unconventional
3.6
3.6
N America Other
SE Asia
Norway
UK
Intn’l Expl
2008
10/14/2009
2009
2010
5 of 50
Incremental production
Incremental 2P Production
Key Projects
mboe/d
200
North America
• Marcellus
• Montney
SE Asia
• Northern Fields
• Song Doc
• Corridor additional gas
• Tangguh
150
100
Norway
• Rev
• Yme
UK
• Affleck
• Auk North
50
Key projects to be sanctioned
• Burghley
• Kitan
• HSD/HST
0
2009
2010
2011
• PM-3 IOR
• Corridor additional
gas
Growth in SE Asia ca. 10% per annum over next 5 years
SE Asia production
Future projects
Rate (mboe/d)
Vietnam
• Nam Con Son gas
• Cuu Long
Indonesia
• Makassar Strait
• Tangguh Phase 2
160
Oil
Gas
ca. 10%
120
80
•
•
•
•
16%
40
Song Doc
PM-3 IOR
HSD/HST oil
Kitan oil
• Corridor additional gas
• Northern Fields
• Tangguh Phase 1
0
2002
2008
269
316
235
305
331
512
767
(82)
(82)
195
220
361
122
5
10/14/2009
2013
CAPEX
($C millions)
Free Cash Flow
($C millions)
6 of 50
. . .delivers 10% PA growth over the next 5 years
Incremental 2P production
Rate (mboe/d)
80
Key Projects to be Sanctioned
2P Reserves
mmboe
HSD/HST
60
Kitan Development
Corridor New Contracts
41
Corridor Additional Gas
PM-3 IOR
15
Song Doc / PM-3 IOR
HSD/HST
52
Northern Fields
Tangguh Phase 1
Future Opportunities
40
Vietnam:
Nam Con Son gas, Cuu Long
Full Field Development
Indonesia: Corridor Additional Gas,
Makassar Exploration,
Tangguh Phase 2
20
Australia:
Kitan
0
2009
2010
2011
2012
2013
Malaysia
10/14/2009
7 of 50
Talisman Malaysia 2010 Activity Summary
Myanmar
Hanoi
Laos
Thailand
Cambodia
Vietnam
Cambodia
Andaman
Sea
Ho Chi Minh City
Philippines
VIETNAM
South
China Sea
Vung Tau
Ho Chi Minh City
Can Tho
Brunei
Malaysia
Kuala Lumpur
Singapore
Hindi Ocean
Indonesia
Quang Long
LEGEND
Ca Mau
TALISMAN
ACREAGE
OIL FIELD
GAS FIELD
N
0
50
Block 4646-Cai Nuoc -33.15%
- Hoa Mai / SRKP Development
100
Kilometers
TH
A
MA ILAND
LA
YS
IA
Bid Round
VIPMPM
E -3 CAA
MA TNA
Sliver)Sliver)-41.44%
L(Including
AY M
S IA
- NF
development wells – 8 wells
Kota
Bharu
Resak
PENINSULAR
MALAYSIA
Kerteh
- IOR Phase 1 – 9 wells
- IOR Phase 2 – project planning
SB-309
MA
IND LAY
ON SIA
ES
IA
Thailand
PMPM-305 – 60%
- South Angsi grow or redevelop
SABAH
SB-310
PM3 CAA/Block: Operations Summary
Facility Design
Water Depth
54m
Total Oil:
60,000 b/d
Gas export:
320 mmscfd
Water Injection: 120,000 b/d
Gas Lift:
20mmscfd
Core Crew: 40 (BRA), 28 (BRE)
FSO
118,000 dwt (860,000bbls)
Turret Moored
TML owned, 3rd party operated
BKC Annex Install
CPP : Oil/Gas Processing & Compression
FIRST PRODUCTION (Fields)
• Bunga Kekwa
• Bunga Raya/Seroja
• Bunga Tulip
• BRE Gas Processing Plant
• TOTAL WELLS (Oil, Gas, WI, GI) - Some Dual
• TOTAL WELL HEAD PLATFORMS
JULY 1997
SEPT/NOV 2003
Oct 2006
MAR 2007
100+
6
BRE Processing Plant
10/14/2009
8 of 50
PM3 CAA: Main Process Facilities
BRE GAS PROCESSING PLATFORM
DRILLING RIG
BRB
BRD MOAB
BRA CENTRAL
PROCESSING
PLATFORM
PM-305/PM314 :South Angsi Development
Facility Design
Water Depth
72m
Topsides Wt:
4000t
Substructure Wt:
2800t
Total Oil:
30,000b/d
Water Injection: 32,000b/d
Gas Lift:
12mmscf/d
Core Crew:
24
FSO
65,000 dwt (470,000bbls)
Close Moored/Bridge linked
3rd Party Owned & Operated
•
•
•
•
•
•
DISCOVERY
PROJECT SANCTION
INSTALL JACKET & COMMENCE DRILLING
INSTALL TOPSIDES
INSTALL FSO
FIRST PRODUCTION
MAR 2003
JAN 2004
NOV 2004
JUN 2005
JUL 2005
AUG 14 2005
29 MONTHS FROM DISCOVERY TO FIRST OIL
10/14/2009
9 of 50
PM 305: South Angsi Facilities
Malaysia: Country Overview
•
•
•
•
•
•
Predominant ethnic groups
• Malay 50%
• Chinese 24%
• Indigenous Peoples 11%
• Indian 7%
Capital – Kuala Lumpur
Very Stable
Official Language – Malay (English widely
used)
Federal constitutional monarchy
Independence (from the UK) August 31, 1957
Area – 330,000km2 (127,000 sq miles).
• Population – 28 million
• GDP – US$200 billion,
• Growth ~ - 3.4 % (2009f)
• Literacy 89%
Principle Religions in Malaysia
• Islam 60%
• Buddhism 19%
• Christianity 9%
• Hindu 6%
10/14/2009
10 of 50
Malaysia: Country Overview
•
Evolution from commodities dependent nation to
a major world supplier of electronics and
computer parts in 40 years.
Largest producer of rubber, palm oil, pepper and
tropical hardwoods and a net exporter of crude
oil.
Significant capital spending in manufacturing,
services and oil and gas sectors.
•
•
Malaysia: Current Economic Outlook
•
•
•
•
•
Domestic economy continued to be affected by
the weak global economic activity.
The recovery excitement could evaporate if
stimulus plan fell short of the objectives.
Expected to improve in H2’09
– GDP shrank at a slower pace of - 3.9% in
Q2’09 (1Q’09: - 6.2%)
– The government’s fiscal stimulus and
monetary easing set to take effect
– Lower inflation (1.3% in Q2’09) and
continued access to financing.
Sign of a turnaround in the global economy
– External trade expected to improve in
Q3’09 and positive growth in Q4.
– 2010f GDP at 2.7%
Issue on massive government budget deficit
(7.6% of 2009 GDP = US$14 billion)
– Looking at ways to enhance its revenue
collection & reduce operating expenditure
Sources: BNM Report, Asia Monitor, The Edge Financial Daily
10/14/2009
11 of 50
Malaysia: Politics
•
•
•
•
•
Politically stable environment but some
wobbles
Race-based parties losing ground.
Leadership issue with MCA & MIC
Prime Minister Najib Razak promoting
“1 Malaysia” concept ~ equal & fair
treatment for all races
Government introduced 6 National Key
Reform Areas (NKRA) and KPI on all
government agencies.
Continued public squabbles on
transparencies, and on some racereligious related issues
Thaipusam celebration at Batu Caves, Selangor
Merdeka Day at Pulau Redang, Terengganu
Upstream Oil & Gas Business in Malaysia - History
 First oil well struck in 1910 at Canada Hill, Sarawak.
 First offshore field discovery by Shell in 1963 (Baram field)
 Concession system until 1974 when the Petroleum Development Act (PDA) led
to the formation of PETRONAS.
 First two PSCs were signed in 1976 Shell & ExxonMobil.
 Petronas owns Petroleum Rights and regulates operators.
10/14/2009
12 of 50
Malaysia Energy Key Statistics
•
•
•
•
•
•
•
•
•
•
Proven Oil Reserves (end 2008) – 4.7 billion barrels
Oil Production (2008) – 754,000 bbl/d
Oil Consumption (2008) – 475,000 bbl/d
Crude Oil Refinery Capacity (2008) – 515,000 bbl/d
Proven Natural Gas Reserves (end 2008) – 2.39 trillion cubic meters
Natural Gas Production (2008) – 62.5 billion cubic meters
Natural Gas Consumption (2008) – 30.7 billion cubic meters
Typical Coal Production – 1 million short tons/annum
Typical Coal Consumption – 19 million short tons/annum
Electricity Installed Capacity – 23 gigawatts
Source: BP Statistical Review Of World Energy June 2009; Malaysia Energy Data, Statistics and Analysis, Energy Information Administration;
Business Monitor International – Q3’09 Malaysia Oil & Gas Report
Le Tour de Langkawi 2009
Le Tour de Langkawi 2009
R/C PSC – Model Fiscal Terms
100%
Royalty
Higher Contractors take at the beginning
of the project or when the project is less
profitable
90%
Higher cost recovery ceilings
for an accelerated recovery of investment
70%
•Cost recovery for block
exploration after first
commercial discovery
minimizes risk
R/C = Cumulative Revenue /
Cumulative Costs
10/14/2009
Percentage of Gross
•High contractor take
during spend period
returns cash outlay quickly
80%
Petronas Profit
60%
50%
Contractors
Profit
40%
Additional
Additional incentives
incentives
for
for any
any $$ saved
saved
30%
20%
Maximum Allowable
Cost Recovery Levels
10%
0%
0.0
1.0
2.0
3.0
4.0
R/C Index
13 of 50
PM-3 CAA
Acreage and Field Locations
Ca Mau
Block 46/02
M
BO-B
WHRP
PM-3 CAA
Sliver Acreage
A
SI
AY
AL
Thailand
VIE
MA TNAM
LA
YS
IA
Kota
Bharu
Song Doc
WHRP
BO-D
BO-A WHRP
CPP
Resak
PENINSULAR
MALAYSIA
PM-314
FSO
FPSO
Gas Export Line
to VIETNAM
Block 46Nuoc
Hoa Mai
Cai
WHRP
SOUTHERN FIELDS
COMPLEX
BK-A
WHRP
BK-C
WHRP
Legend
BR-B
WHRP
BS-A
WHRP
FSO
PLEM
BR-A
CPP
Producing Platform
Gas
Prospects
Future Platform
BR-E Gas
Processing Facility
Pipeline
Oil
Gas
Water Injection
Gas Lift
Gas (future)
PM-305
Kerteh
PM-3 CAA
Oil
Block 46-CN
PM-3 CAA
BO-C
WHRP
BP-A WHRP
(Future)
NORTHERN FIELDS
COMPLEX
Block 46/02
TSJOC
MA
IND LAY
ON SIA
ES
IA
TN
AM
TH
A
MA ILAN
D
LA
YS
IA
VI
E
N
BR-C
WHRP
BR-D
MOAB
B.Tulip
WHRP
0
5
10
Gas Export Line
to Resak Platform
Kilometers
Northern Fields Facility
Current Progress as at end August 2009
BOC WHRP
BOBO-B WHRP
15th Nov ‘07
Legend
17th April’
April’08
Pipeline
BOD WHRP
13th Apr’
Apr’08
4”
GL
18”
O
il
6”
Bridge
15th
Apr’
Apr’08
GL
Oil
Gas
Gas Lift/Injection
Fuel Gas
12”
Roger Mowell
4.5k
m
BRE Topsides
16th Feb’
Feb’06
Remote Flare
il
G
el
as
29th Dec’
Dec’08
24”
PL
laid
BOD – BRE 24”
24” PL
28th MarMar- 14th
Apr’
Apr’08
O
Fu
”
10
4”
BOA CPP
26”
s
Ga
Drilling Rig
Remote Flare
O il
13k
mP
L la
id
BRE
Orkid FSO
25th Feb ‘09
10/14/2009
14 of 50
Northern Fields Facility
High Level Status – “Job near Complete”
Overall Progress as at end August 2009
Cumulative To
date
Description
Actual
Plan%
%
NF PROJECT- WHRP
100.00
99.90
NF PROJECT - BOA CPP
100.00
98.92
NF PROJECT - PIPELINE &
PLATFORM INSTALLATION
100.00
100.00
NF PROJECT - FSO
100.00
99.80
100.00
99.93
TOTAL
Northern Field BO-A CPP: July 2009

BO-A CPP Topsides achieved First Oil on the 25th March 2009

BO-A CPP Topsides successfully delivered compressed dry gas to BR-E on the 26th July
2009

BO-A CPP Ca. 7.4 million manhours expended without LTI

Remaining systems targeted to be operational within October 2009
Northern Fields BO-A CPP
Current Status: “Nearing completion of Commissioning”
•
Seawater frame plate
exchangers repaired and
functional

Glycol Dehydration Operation
now functional for dry gas
mode

Booster Compressor
Reliability has improved

Flash Gas Compressor now
on line (1 of 2 completed)

Water Injection
Commissioning has just
commenced

All commissioning works will
be complete by 4Q 2009
10/14/2009
15 of 50
Bunga Orkid WHRPs
Current Completion Status “Complete and online”
BOC WHRP
BO-B, BO-C and BO-D WHRPs
 BOB First Oil delivered to BO-A
CPP 15th March 2009
 BOD switch-over from Early
Gas mode to normal operating
mode (dry gas production) on
26th July 2009
 All 3 WHRPs now producing.
 Batch drilling from Roger
Mowell continues on BO-C
BOB WHRP
BOD WHRP
Northern Field Facility – FSO Orkid Fully
Operational
 MVOT completing punch lists and final commissioning
 To close-off all commercial issues within October 2009
10/14/2009
16 of 50
PM-3 CAA North Project Background
Ca Mau
Block 46/02
M
BO-B
WHRP
A
SI
AY
AL
BO-D
BO-A WHRP
CPP
PM-3 CAA
Sliver Acreage
Thailand
Resak
PENINSULAR
MALAYSIA
FSO
PM-314
FPSO
Gas Export Line
to VIETNAM
Block 46Nuoc
Hoa Mai
Cai
WHRP
SOUTHERN FIELDS
COMPLEX
BK-C
WHRP
FSO
BS-A
WHRP
PLEM
BR-B
WHRP
BR-A
CPP
Producing Platform
Gas
Prospects
Future Platform
BR-E Gas
Processing Facility
Pipeline
Oil
Gas
Water Injection
Gas Lift
Gas (future)
PM-305
Kerteh
BK-A
WHRP
Oil
VIE
MA TNAM
LA
YS
IA
Kota
Bharu
Song Doc
WHRP
PM-3 CAA
Legend
Block 46-CN
PM-3 CAA
BO-C
WHRP
BP-A WHRP
(Future)
NORTHERN FIELDS
COMPLEX
Block 46/02
TSJOC
MA
IND LAY
ON SIA
ES
IA
TN
AM
TH
A
MA ILAN
D
LA
YS
IA
VI
E
N
BR-C
WHRP
BR-D
MOAB
B.Tulip
WHRP
0
5
10
Gas Export Line
to Resak Platform
Kilometers
Bunga Orkid Development Drilling
September 30th 2009 – “Strong Drilling Progress”
30 of 45 wells currently drilled by PM3-CAA Partnership

6 BOB wells drilled and completed,

2 horizontal oil wells drilled and on production.

2 deviated oil producers drilled and on production

2 Gas injectors drilled and waiting for commissioning of the gas injection system

14 BOC wells drilled and completed,

11 gas wells drilled and completed.

3 horizontal oil producers drilled and on production

10 BOD wells and completed,

8 gas wells drilled and on production.

Summary:
2 horizontal oil producers drilled and on production.
9 oil wells drilled and on production
19 gas wells drilled and on production.
2 gas injection wells drilled and waiting on commissioning.
10/14/2009
17 of 50
DRILLING & COMPLETING MONOBORES FASTER
1H 09 Well Drill / 10,000 ft Performance
Performance improved by 2
days for monobores
BOC-6,9
Expand Facility Gas Capacity Beyond 290 mmcf/d
Orkid Reserves Evaluation
Based on Latest Development
Drilling
ONGOING
East Bunga Orkid Deep
Exploration Well
Success in L Sands at BOC-14
Deep Evaluation H1 2009. IN
PROGRESS
Legend
Oil Field
Gas Field
Bunga Orkid
Song Doc &
Satellites (SRKP) IN
PROGRESS
Prospects
Hoa Mai
Bunga Pakma
Re-evaluation H2 2009
IN PROGRESS
West
B. Matahari
Bunga Matahari
Re-evaluation H1 2009
Currently Uneconomic
Southern Fields IOR
Block 46
PM-3 CAA
Bunga Kekwa
Early/Pre-Tertiary Prospectivity
under Kekwa/Raya
Bunga Seroja
Bunga Raya
N
0
5
Kilometers
10/14/2009
10
Upgrades at BRD to
increase Export
Capacity.
INTERNAL AFE
APPROVED. EXTERNAL
AFEs Circulating
Sliver Appraisal Well
Q3/4 2009
Bunga Tulip
Untapped Raya Gas
Caps
Sliver
Tulip Gas
Caps
18 of 50
PM-3 CAA South
Ca Mau
Block 46/02
BO-B
WHRP
BO-D
BO-A WHRP
CPP
PM-3 CAA
Sliver Acreage
Thailand
Resak
PENINSULAR
MALAYSIA
FSO
Hoa Mai
WHRP
Gas Export Line
to VIETNAM
Block
46Cai
Nuoc
SOUTHERN FIELDS
COMPLEX
FSO
BS-A
WHRP
BR-B
WHRP
PLEM
BR-A
CPP
Producing Platform
Gas
Future Platform
Pipeline
BR-E Gas
Processing Facility
N
Oil
Gas
Water Injection
Gas Lift
Gas (future)
0
5
PM-305
Kerteh
BK-C
WHRP
Prospects
PM-314
FPSO
BK-A
WHRP
Oil
VIE
MA TNAM
LA
YS
IA
Kota
Bharu
Song Doc
WHRP
PM-3 CAA
Legend
Block 46-CN
PM-3 CAA
BO-C
WHRP
BP-A WHRP
(Future)
NORTHERN FIELDS
COMPLEX
Block 46/02
TSJOC
MA
IND LAY
ON SIA
ES
IA
TN
AM
TH
A
MA ILAN
D
LA
YS
IA
VI
E
BR-C
WHRP
BR-D
MOAB
B.Tulip
WHRP
10
Gas Export Line
to Resak Platform
Kilometers
Kekwa Cross Section
•
•
10/14/2009
Reservoirs range from 1600m to 2400m TVDss
Kekwa has 22 Reservoirs – 9 gas only, 13 oil rims with gas caps
19 of 50
IOR Phase I
“Well results as good or better than promised”
Well
Prognosed
Net Sand
Thickness
(m TVD)
Actual
Net Sand
Thickness
(m TVD)
Prognosed
Initial Rate
(stbpd)
Actual
Initial Rate
(stbpd)
BKC-25
24
37
1700
1200
BKC-26 (RR)
20
19
1700
3200
BKC-27 (KK)
15
18
1500
2500
Optimization of Drilling Costs
“Alternative Well Designs & Methods”
Evaluation
Evaluationof
ofRig
RigTechnologies
Technologies- -complete
complete
–– Hydraulic
Work
Over
Unit
Hydraulic Work Over Unit
–– Jack
JackUp
UpDrilling
DrillingUnit
Unit
–– Coil
Tubing
Drilling
Coil Tubing DrillingUnit
Unit
–– Platform
PlatformType
TypeDrilling
DrillingUnit
Unit
–– Tender
Assist
Drilling
Unit
Tender Assist Drilling Unit
10/14/2009
Evaluation
Evaluationof
ofWell
WellDesign
DesignOptions
Options- -on-going
on-going
–– Comingled
production
&
Injection
Comingled production & Injectionwells
wells
–– Monobore
Monoboreproducing
producingwells
wells
–– Openhole
Openholecompletions
completions
–– Optimization
Optimizationofofdrilling
drillingand
andcompletion
completion
methods
and
technology
methods and technologyselection
selection
–– Rigless
Riglessabandonments
abandonments
20 of 50
Optimization of Platform Costs
“New BIPOD Platform Option”
Indonesia
10/14/2009
21 of 50
Country Map & Key Facts
Government
Democratic Republic
GDP per capita
$1,800
Area
1,920,000 sq km
Currency
Rupiah (US$ = 9,600)
Archipelago
18,000 islands
Capital
Jakarta
Climate
Tropical, hot, humid
Language
Bahasa Indonesian
Population
235 million
Religion
Muslim 90% Christian 8%
History, Business Environment & Security
History
• Three centuries of Dutch colonial rule ends in 1945
• Sukarno “Bung Karno” the country's first president leads for 20 years
until 1967
• Suharto president for 30 years until 1997 and Asian crisis
• Susilo Bambang Yudhoyono SBY elected President in 2004 and has
overseen a period of political stability.
• Re-elected this year by an overwhelming majority
Sukarno
Business Environment
• Economy impacted by global economic crisis but weathering the storm
well – banking system more robust following 1998 collapse
• 2009 growth forecast at between 4-5%
• Inflation low and currency generally stable
Suharto
Security
• Events of 17th July served as a tragic reminder of security concern
• Prior to that there had been a long period of calm on the security front
• No incidents on any oil & gas facility
SBY
10/14/2009
22 of 50
Geographical perspective
Scale Reference to US
60 proven hydrocarbon basins of which only 22 have been extensively explored
Oil reserves
NAD
120
Natuna
M
A
AL
400
East Kalimantan
I
YS
A
122
North Sumatra
817
4,271
Central Sumatra
South Sumatra
9
758
Lampung 185
Bangka
Belitung
South
63 Kalimantan
99
South Sulawesi
15
686
West Java
Papua
Central Sulawesi
145
69
Moluccas
690
East Java
8.6
billion
Remaining 2P Oil Reserves (MMbbls)
Source: BPMIGAS
10/14/2009
23 of 50
Oil reserves holding flat but production in decline
Oil reserves
Oil production
Reserves (2P) of 8.6 billion bbls oil and production of just under 1 MMbbls/d
Source: BPMIGAS
Gas reserves
NAD
5
Natuna
M
54
A
AL
East Kalimantan
I
YS
A
1
North Sumatra
49
Papua
Central Sumatra
8
Bangka Belitung
South Kalimantan
<1
<1
South Sumatra 24
South Sulawesi
<1
Lampung <1
6
West Java
Central Sulawesi
24
4
Moluccas
1
10
East Java
185
Remaining 2P Gas Reserves (Tcf)
Source: BPMIGAS
10/14/2009
24 of 50
Gas reserves increasing and
production holding flat
Gas reserves
Gas production
Reserves of 185 Tcf gas and production of 7.5 Bcf/d
Source: BPMIGAS
Mboe/d
Combined oil & gas production holding flat
Source: BPMIGAS
10/14/2009
25 of 50
Growing gas supply gap in W Java market
West Java Supply and Demand
2,500
2,250
2,000
1,750
BBtu/d
1,500
1,250
1,000
750
500
250
0
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
West Java Contracted and Committed
South Sumatra Contracted and Committed
Total Demand West Java
Source: Wood Mackenzie
…. driving rising domestic gas pricing
150
US$/bbl
Oil Price
100
50
-6
Sumatra - Other
Sumatra - PLN
5
Java - Other
Java - PLN
US$/MMBtu
4
3
2
1
2009
2009
2008
2008
2008
2008
2008
2007
2007
2007
2007
2007
2007
2007
2007
2006
2006
2004
2003
2003
2002
2001
1992
1990
0
Today, most end users pay delivered price around $5/MMBtu to PGN,
including PLN in West Java and South Sumatra
Source: Wood Mackenzie & latest published deals (2Q 2009)
10/14/2009
26 of 50
Regulatory & Fiscal environment
•
Sector still the dominant contributor to the economy, almost 30% of state revenues
•
Regulatory framework has undergone major changes since 2001. Pertamina no longer has ‘cradle to
grave ‘ dominance.
– ESDM: Ministry of Mines & Energy
– MIGAS: strategy, policy, licence awards
– BPMIGAS: upstream administration
– BPHMIGAS: downstream administration
•
Production Sharing Contract (PSC) regime
Contractor can offset exploration and development expenditures again production stream before
fiscal apportionment.
•
•
Traditional (Government / Contractor) after tax model profit splits are:
– 85/15 oil and 70/30 gas, which have been improved for frontier and deepwater areas to
– 65/35 oil and 60/40 gas
The PSC contractor is protected from further taxation (import/export taxes, VAT, regional taxes, etc..)
•
Investment Credit can be offered as further incentive for marginal developments.
•
Rising level of cost recovery is driving review of regulatory framework
•
Ability to export gas (pipeline or LNG) subject to government approval after Domestic Market
Obligation (DMO) has been met
Competitors
• Super-Majors (strong historical presence)
– Chevron largest oil producer Caltex in Sumatra, ex-Unocal deepwater E. Kalimantan
– ExxonMobil Arun LNG Aceh, Cepu E. Java, deepwater Makassar
– ConocoPhillips W Natuna Block B, Corridor, other Gulf Canada assets
– BP ARCO acquisition ONWJ, Tangguh LNG
– TOTAL largest gas producer Bontang LNG
– ENI deepwater E Kalimantan, VICO assets
• Indonesian Companies (important but not the dominant players)
– Pertamina 3rd largest oil producer, extensive fallow acreage position, increasing participation
– Medco extensive interests, widely respected, Mitsubishi stake, international aspirations
– EMP, Star Energy, other PT companies very influential
• NOCs (growing influence)
– Petronas, China (CNOC, PetroChina, Sinopec, Citic), Kufpec, PTTEP …etc
• Japanese and Korean conglomerates (securing energy supplies)
– INPEX (2nd largest gas producer), Japex, Mitsubishi, Nippon, KNOC
• Independents (comparatively few but coming back to exploration)
– Hess, Santos, Premier, Marathon, Husky, Murphy, Talisman
10/14/2009
27 of 50
Government actions to increase production
•
Promotion of greater exploration investment
– continue to improve fiscal terms,
– incentive packages,
– annual licence rounds
•
Promotion of gas exploration and development
– review of gas policy
– ability to export
– DMO and pricing
– LNG and pipeline infrastructure issues
•
Clarification taxation regime
– to introduce Clarity, Certainty and Consistency into regulations
•
Resolution of Cost Recovery debate
– within traditional successful PSC regime
– cost recovery now part of state budget
– uncertainty problematic
•
Less beaurocracy within regulatory bodies (MIGAS /BPMIGAS)
– improve procurement procedures,
– speed up approvals process WP&B, POD, AFE
Talisman History in Indonesia
• Corporate acquisitions
– Encor 1993
– Bow Valley 1994
– Paladin 2005
• Farm-ins
– Nila
• PSC Awards
– Madura Offshore 1996
– Pasangkayu 2006
– Sageri 2007
– Andaman III 2009
• Asset purchases
– Tangguh 2008
• Exploration Joint Study Awards (JSAs)
– Sadang JSA
– South Sageri JSA
– Additional Study Areas
10/14/2009
28 of 50
Activity Map
•Long production-life asset (Tangguh)
•Significant YTF gas potential
North Sumatra
•Core producing region
__________
__________
•Full-year Tangguh ph 1 prod’n
•Growth through additional
Corridor gas sales
•Potential Study Areas
•Facility expansion
Makassar Strait
Eastern Indonesia
South Sumatra/West Java
•Potential high-value exploration
__________
High-impact deep-water exploration
•Work begins on newly awarded PSC
•Significant YTF potential
__________
Production
•First drilling on PK in 2010
•Conversion of JSAs to PSC
Exploration
53
Strategic Fit
1
Talisman Corporate Strategy
Long-term, Profitable Growth
• Long life material portfolio with built-in self funding growth
• Net Cash flow positive throughout plan horizon
1
Establish Long-term Profitable
Growth
2
Transition International Exploration
Portfolio for Renewal
3
Focus Portfolio to Generate Cash
for Re-investment
• Growth through additional GSAs
• Regional gas demand provides local markets
• Economic growth remains healthy through downturn
• Continued conversion from diesel to gas-fired power
• Strong NOC relationships and regional reputation provides
opportunities currently being pursued with Pertamina
• A&D opportunities being pursued
• Established strong operated position in under-explored basins
• Large YTF resources
• Potential for large discoveries
10/14/2009
29 of 50
Strategic Fit
• Stable fiscal regime
•
New incentives are “tweaks” to terms within the existing regime
• Stable political environment
•
Peaceful re-election of incumbent president hailed as a “coming of age” for
Indonesian democracy
• High returns
•
Low finding costs
•
Predictable cost-recovery structure
•
Low operating costs
• Mix of oil and high-value gas
•
Unexplored oil-prone basins
•
Access to gas export markets and strong domestic demand
• Long-life projects
•
LNG Potential
• Opportunity to continually renew and refresh portfolio
•
Active A&D deal flow
•
Transparent and predictable licencing rounds
•
Indonesia represents a core producing area with strong in-built production growth
Corridor PSC – Strategically Positioned
105º
100º
LEGEND:
DURI
SSWJ Phase 1
SSWJ Phase 2
Gas Plant
PGN Station
Compressor
Singapore
Pemping St
Pemping St
Minas
Duri market
Singapore market
Gas for Chevron’s
steamflood program.
Oil Linked Pricing
Belilas St
0º
Large power generation
and industrial demand.
Oil Linked Pricing
Future
Compressor
site
Padang
(also Batam island)
K.Tungkal St
Jabung
Sakernan St
Jambi
Grissik
CORRIDOR
Phase II
36”
Access to large gas
markets via three major
transmission pipelines
Pagardewa
OGAN
KOMERING
PhaseFuture
I
Compressor
site
-5º
INTEREST:
ConocoPhillips – 54%
(Operator)
Talisman – 36%
Pertamina – 10%
10/14/2009
West Java market
32”
Heavily industrialized and
populated region. Large
industrial and power generation
demand. Domestic Pricing
Terbanggi
Besar
32”
Labuhan
Maringgai
32”
32”
Muara Bekasi
(Jakarta)
Cilegon
Tegal Gede
0
50
100
200 Km
Serpong
Waiahar
Gleungsi
30 of 50
Corridor Fields and Reservoirs
Dayung
Grissik
Gelam
To
Jambi
Tetangga
N
To Duri and
Singapore
Grissik
Sumpal
Lalang River
Sialang
Dayung
Rebonjaro
0
20km
Kilat
Ikan Mas
Sambar
Da
wa
sR
iver
Leko
Tengah
Puyuh
Safir
Suban
iv e
r
Suban
Rawa
Bertak
Ganteng
Ramba
Suban
10”
Keban
Letang
Ca
lik
R
Gas Field
Oil Field
Prospect / Leads
(TAC)
Keri
Te
lu
k
Te
ng
gu
la
ng
R
iv
er
TJ.Laban
Mangunjaya
Mu
si R
Tran
s Su
mat
ra H
ighw
ay
ive
r
Karang Ringin
Corridor PSC Area
2,258 square km
Dayung Compression Phase 1 and
Grissik Debottleneck
Grissik
Dayung
Install compression facilities at Dayung and debottleneck Grissik plant by
expanding high CO2 processing facilities from 310 MMscf/d to 460 MMscf/d
Dayung Compression
Grissik Debottlenecking
• Install 3x33% gas compressors totaling 24 kHP
• Install additional Inlet Cooler, Inlet Separator,
Suction/Discharge Scrubber, Air Compressor,
Compressor After Cooler, Gas Engine Generator
• PLC Safety System, Produced water pump,
Pipeline for Fuel Gas System, Utilities Facilities
• Install 2 new TSA Regen 200 HP Gas
Compressors
• Install 2 membrane pretreatment systems, 3
additional membrane skids, 1 Amine Contactor
• Install 1 additional Glycol Dehydration Train
• Add 1 Waste Heat Boiler
• Install 2 new Thermal Oxidizers
10/14/2009
31 of 50
Suban Phase 3
Expand the existing Suban facilities by installing 150 MMscf/d gas processing
train, drilling 3 new development wells and adding additional compression.
Tie-in new drilled wells, install new processing train & utilities at the existing gas plant area, and inlet
compression when reservoir pressure depletes, to capture additional gas sales:
• Install 150 MMscf/d processing train to meet CO2, H2S, Dew Point spec, & condensate stabilization
• Tie-in 3 additional new gas wells and 4 new water disposal wells
• Install 26” gas transport pipeline to Grissik
• Upgrade support facilities and utilities
Tangguh – Long-term LNG production
Talisman net production
Mboe/d
10
8
6
Condensate
Gas
4
2
20
09
20
12
20
15
20
18
20
21
20
24
20
27
20
30
20
33
0
POSCO &
K-Power
1.15 MMtpa
Fujian
2.6 MMtpa
Diversion
Options
(up to 50%)
$3.9 to circa $9.5
$3.3
$4.3
Sempra 3.7
MMtpa
$4.4
Tangguh LNG
Delivered Prices in $/MMBtu based on US$60/bbl oil (Except Fujian – FOB)
10/14/2009
32 of 50
Tangguh
61
Other Assets: Ogan Komering JOB and
Ramba TAC
Ogan Komering JOB
Talisman: 50% Joint Operator with Pertamina 50%
Corridor
PSC
• Net production 2,600 boe/d in 2009 (60% oil / 40%
gas)
Ramba TAC
OK JOB
• Excellent optimization and exploitation opportunities
• Lowest opex onshore Indonesia
• Provides experienced skill base for growing Talisman
elsewhere in Indonesia
Ramba TAC (Corridor TAC)
Talisman: 40%
El Nusa 60% (Operator)
• Net production 1,500 bbls/d in 2009 (all oil)
• ConocoPhillips exited block as Operator in
September 2007
• El Nusa, a Pertamina subsidiary now operator
• Pursuing extensions (TAC expires in 2010)
62
10/14/2009
33 of 50
Other Assets: ONWJ & SES PSCs
Offshore North West Java PSC (ONWJ)
Talisman: 2.45%
Pertamina 46.00% (Operator)
• Net production 1,300 boe/d in 2009 (40% oil)
• Gas sold at domestic prices ($2.65 to $3.63/MMbtu)
to PLN, PGN and Fertilizer
• Operational challenges focused on maintaining
aging facilities
• PSC Expires in 2017
South East Sumatra PSC (SES)
Talisman: 7.48% CNOOC 65.54% (Operator)
• Net production 3,000 boepd in 2009 (mainly oil)
• Processed oil is stored in floating vessels and
exported via two Single Point Mooring systems
• Gas sold to PLN in West Java ($2.68/MMbtu)
• PSC expires in 2018
Exploration Macro Plays of Southeast Asia
Discovered 2P Reserves
Sundaland Rifts Macroplay:
36.6 BBO (48%)
239.7 TCF (52%)
Under-explored in Outer Sundaland Basins
Shelf & Deep Water Borneo Macroplay:
16.1 BBO (38%)
158.3 TCF (62%)
Emerging, under-explored in several Basins
Eastern Indonesia Macroplay:
0.8 BBO (15%)
26.9 TCF (85%)
Complex, poorly explored and understood
Wallace Line
64
Source: IHS 2005
10/14/2009
34 of 50
Indonesia has vast exploration potential
• Indonesia is a major, world class hydrocarbon province
• 60 proven hydrocarbon basins, only 22 have been extensively
explored
• 75% of YTF resources in SE Asia expected to be found in Indonesia
(circa 120 billion boe)*
• All super-major oil companies operating in the country
• Potential of deep water frontier areas being disclosed due to
technological advances and improved tendering process making
vast areas available for licencing at more favourable terms
• Several potentially attractive basins still completely un-explored
* Based on USGS and other sources
Indonesia Exploration Strategy –
Screening Criteria
• Systematic regional work carried out in the last 4 years to identify high potential
areas with all the necessary ingredients for a working petroleum system
• Large expected "Yet to find resources" due to low exploration level as a
consequence of:
a) Physiographic condition (principally water depth and/or remoteness)
b) Political discontinuities
c) Lack of adequate data
• Large expected mean field size based on basin and analogue basins statistics
• Ability to leverage TLM in house knowledge of plays into other similar under-explored
basins
• Ability to capture acreage via licencing round, JSAs and farm-ins
Three main areas for growth:
•
•
•
10/14/2009
Sundaland Margin
North Sumatra
Eastern Indonesia
35 of 50
Exploration – where is Talisman focusing?
• Establish a strong operated position in Indonesia focusing on under-explored basins with
large YTF resources and high to moderate geological risk with potential for large discoveries
Estimated Resource Potential
2
1
• Andaman III (2009)
• Pasangkayu PSC (2006)
• Sageri PSC (2007)
• South Sageri JSA (2008)
• Sadang JSA (2008)
1) Sundaland Margin
:10 BBOE
2) North Sumatra
: 4 BBOE
3) East Indonesia
:11 BBOE
3
• Regional work
• JSA applications (2009)
Source: USGS, Pertamina, Indonesia Petroleum Atlas
Sundaland Margin (Makassar)
acreage distribution
Surumana
SE Ganal IPasangkayu
Kuma
Karama
Malunda
Licencing round
2006 & 2007 PSCs:
• Surumana
• Pasangkayu
• Kuma
• Karama
• Karana
• Sebuku
• Mandar
• Sageri
2008 PSCs:
• West Sageri
• SE Ganal
Karana
Sebuku
Mandar
Sadang S.Mandar
W.Sageri
Sageri
JSA 2008:
• Malunda
• South Mandar
• Sadang
• South Sageri
S.Sageri
10/14/2009
36 of 50
Makassar Straits Exploration Consortium (MSEC)
•
•
•
•
•
•
•
•
Marathon is the Lead Operator
Members provide resources to support the consortium
Leveraging experience and providing synergy opportunities
Secured long term deepwater rig contract (GSF Explorer)
Procuring major drilling related services and equipment (ca. 30 contracts)
Acting as a single entity on procurement issues with the regulator
Lessons Learnt shared between operators
Standardization of some operating procedures
Shared Marine Base
•
•
•
•
MSEC Members will use Balikpapan as their Marine Base
Regional oilfield supply area
Central to the MSEC operations
Cost reduction in setting up various bases
Main Helicopter
Operating Base
with Forward Bases
• Majority of Helicopter operations for MSEC Members out of Balikpapan
• Talisman and ENI will operate Forward Operating Bases for Helicopters
• Reduced flight hours
• Safer situation
MSEC Formed
North Sumatra: Andaman III Licencing Round
1
N. Sumatra Bid Round
Three large blocks offshore North Sumatra
Moderately deep water 1000-1500 m
Gas and condensate play
Close to infrastructure
2
Andaman III Block Prospectivity
Main target Miocene Carbonate
Additional Clastic play in stratigraphic closure
Total prospective resource in excess of 1,200 MMboe
Pg 20%
3
Submitted Bid For Andaman III Block
Signature bonus
7.6
G&G
2.0
3D Seismic
15.0
1 Well
30.0
TOTAL
54.6
•
•
•
•
10/14/2009
Andaman
III PSC
0
50
100 km
Block awarded on September 11th
PSC signature expected 8th October
3D Seismic in 2010
Exploration well in 2012
37 of 50
North Sumatra Basin:
LNG Facilities and Local Market
Arun LNG
Andaman
Block I
Andaman
Block II
Arun LNG Plant
NSO Block • Contract signed 1973
PSC
• First delivery 1977
Andaman
Block III
• 3 LNG trains expanded to 6 trains
in 1983
• Peak deliveries 400,000 bcd
• Currently only 4 trains shut-in due
to low volume
• Estimated end of Field life is 2015
Arun LNG
Fertilizer Plants
PIM I & II &
Industrial Users
North Aceh Regency
Area:
Population:
3,478 km2
632,000
NSBB PSC
(Arun Field)
NSBA
PSC
(ConocoPhilips)
Summary and Conclusions
•
Indonesia represents a core producing area with strong in-built
production growth
•
This is combined with an exciting, high impact exploration portfolio
designed to extend the long term growth
•
The operation generates significant net cash flow
•
Focus on building a substantial operating capability
•
With a goal of becoming Talisman’s centre of excellence for
deepwater activity
•
While leveraging our strong relationships with key stakeholders in
the industry
71
Government & Politics – Relationships
Papua New Guinea
TLM has a presence in PNG
PPL235 Seismic Acquisition 2008
PPL235 Seismic Acquisition 2008
Vietnam
Vietnam – The Country, growing strongly
•
•
•
•
•
•
Population: 86 million
– 13th highest populated country in the world
– Median age 26 years
– 94% literacy rate
Consistent strong GDP growth, despite recession
– Growth rate (1995-2008): 7%
– Projected 2009: 5.5%
– 2nd highest in Asia
Socialist government - high political stability
Fastest rate of poverty reduction in the world
Raising profile
– Accession to WTO
– Hosted APEC 2006
– Voted member of the UN Security Council
But the growth is creating energy challenges
– Power demand growth averagely 15% pa
during 2000-2008
– 60% LPG consumption is now imported
– $US 3 billion investment in power needed per
year. Now importing electricity from China
Source: World Bank East Asia & Pacific Update
World Bank Energy and Mining in Vietnam
Vietnam – Transition to market economy is driving
the country’s growth
•
Strengthening private sector – now accounts
for 50% investment, contributes 65% of
manufactured products and 70% of non-oil
exports to the economy
•
Massive privatization – state-owned firms cut
by half in last five years, including major
banks; energy/ infrastructure companies
•
–
PVN Subsidiaries: PVD, PTSC, PVFC,
PVI, PVTrans, PV PDC, etc.
–
EVN Subsidiaries: generation (Baria,
Thac Mo, Ninh Binh, etc.); engineering &
construction (VNECO, PECC)
–
Vietcombank, Incombank
Improving state-owned enterprises – tough
competition is forcing SOE to become
profitable
The World Bank estimates that this transition will be complete within the next five years
Source: International Development Agency
Vietnam – Growing Petroleum Industry
•
•
•
•
•
•
•
Typical Fiscal Terms
Proven recoverable reserves:
600 million barrel of oil & 7 tcf of
gas
Significant yet-to-find reserves
in under-explored basins
Production (2008) 320,000 bbl/d
oil and 700 mmscfd gas
Net crude exporter (till 2015)
Upstream industry dominated
by PetroVietnam, and regulated
by Ministry of Industry and
Trade
Production Sharing Contract
regime
Excellent frontier fiscal terms for
un-explored basins
Contractor
25%
Gov't
55%
Capex
Opex
Source: PetroVietnam
Wood Mackenzie SEAGAPS Feb 2009
Vietnam Infrastructure – Established Gas Transportation
System
1
• Bach Ho P/L: Transport associated gas
from Bach Ho and nearby fields
• Startup 1995
• 150km, 16” with LPG extraction terminal.
Capacity 175 mmscfd dry gas, 500 tons
condensate and 1000 tons LPG daily
• PV built and operates with 100% equity
2
• Nam Con Son P/L:Transport nonassociated gas from Nam Con Son basin
• Startup 2003
• Two-phased 370 km 26” offshore + 30km
30” onshore & terminal. Capacity: 700
mmscfd.
• BCC: PVN 51%, BP 32.7%, CoP 16.3%.
• Operatorship transferred from BP to PVN
since 2008.
3
• PM3 – Camau P/L: Transport gas from
PM3-CAA
• Startup 2007
• 300km offshore 18” + 30 km onshore.
Capacity: 200 mmscfd
• PV built and operates with 100% equity
4
• Block B – Omon P/L: Transport nonassociated gas from Block B
• Startup planned 2012
• 400km 28” pipeline. Capacity: 800 mmscfd
• BCC: PVN 51%, CVX 30%, MOECO 15%,
PTTEP 5%
1
4
2
3
Vietnam Infrastructure – Expanding Power Generation
Capacity
2020
2010
2007
4%
15%
1%
23%
14%
Legend
45%
Coal
30%
37%
Hydro
Gas & Oil
28%
36%
40%
27%
11,600 MW
20,400 MW
Others
75,000 MW
Vietnam Power Demand Growth
Power demand growth is forecasted at 13-15%
pa till 2010, 10-12% pa 2011+
20
•
Power Master Plan No. 6 plans to double
installed generation capacity in 2010
15
•
Hydro component decreases due to hydro
resource dry-up; gas component is subject to
new gas availability
•
9600 MW new built gas-fired power is planned
by 2020. 2850 MW has been installed by
end’09
Forecast
Historical
10
5
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
2009
2008
2007
2006
2005
2004
2003
2002
2001
0
2000
y-o-y growth (%)
•
Source: Institute of Energy, Electricity of Vietnam
Vietnam Infrastructure – Developing Refinery
22nd
ndRefinery
Refinery--Nghi
NghiSon
Son
Investors:
PVN
Investors:
PVN(25.1%),
(25.1%),Kuwait
Kuwaitvia
viaKPE
KPE
(35.1%),
(35.1%),Idemitsu
IdemitsuKosan
Kosan(35.1%),
(35.1%),
Mitsui
Chemicals
(4.7%)
Mitsui Chemicals (4.7%)
Capacity:
180,000
Capacity:
180,000bbl/d
bbl/d
Start-up:
2013
Start-up:
2013
Crude
Crudesource:
source: Kuwait
Kuwait
FEED
FEEDininprogress,
progress,due
duecompletion
completionOct’09
Oct’09
Ha Noi
Nghi Son
Da Nang
Dung Quat
Crude
Oil
HCMC
Long Son Crude
Oil
Bach Ho Oil Field
11ststRefinery
Refinery--Dung
DungQuat
Quat
Capex:
US$3
Capex:
US$3billion
billion
Investor:
PVN
Investor:
PVN100%
100%
Capacity:
148,000
Capacity:
148,000bbl/d
bbl/d
Start-up:
early
Start-up:
early2009
2009
Products:
Propylene,
Products:
Propylene,LGP,
LGP,Gas
Gasoil,
oil,Kerosene,
Kerosene,
Diesel,
Diesel,Fuel
Fueloil
oil
Crude
Crudesource:
source: Mainly
MainlyBach
BachHo,
Ho,the
therest
restprovided
providedby
byBP
BP
Now
Nowininproduction,
production,meet
meet30%
30%of
ofdomestic
domesticdemand
demand
33rdrdRefinery
Refinery--Long
LongSon
Son
Investors:
to
Investors:
tobe
bedecided
decided
Capacity:
200,000
Capacity:
200,000bbl/d
bbl/d
Start-up:
2015
Start-up:
2015
Why Vietnam?
Strategy
•
Running
Room for
Future
•
•
•
•
Medium
Term
Growth
Good
Base
Assets
Environment
•
•
Strong demand for oil & gas, fuelled by
domestic growth
Material yet-to-find resources
Under-explored – access to acreage
Excellent frontier fiscal terms for un-explored
basins
Block 133/134 farm
in with operatorship
granted Feb 09
Submitted bid for
Block 135/136 PSC
license Sep 09
Block 15-2/01 three
early discoveries.
Prospective resource:
75-250 mmboe
Stable political, fiscal, and regulatory regime
– Talisman – right size, Canadian partner
– Successful record and good reputation
– Good relationship with Government
A strong existing asset base poised for
production growth
Production to start in
2012, ramp up to
35,000 bbl/d in 2013
(WI: 60%)
Block 46/02 started
Nov. 2008.
Production 15,000
bbl/d (WI: 30%)
Good economic metrics
– Low F&D
– Early cost recovery – High ROACE
Talisman Vietnam – Holding Acreage & Potential
Opportunities
CAMBODIA
VIETNAM
Ho Chi Minh City
Vung Tau
Block 15-2/01 Thang Long JOC
Blocks 133/134
Song Doc Development
Area (Block 46/02)
Truong Son JOC
Malaysia
Talisman acreage
Oil Field
Gas Field
Potential opportunities
Equity (%)
46/02
15-2/01
133/134
PVEP
40
40
30
Talisman
30
60
70
Thang Long
JOC
TVL
Petronas
30
Operator
Truong Son
JOC
Block 15-2/01 – Prospects and Lead maps
•
87 mmboe discovered 2P
reserves (gross WI).
•
150 mmboe yet-to-find
Prospective resources.
•
Plan in place to continue
appraise Hai Su Den and
explore other
prospects/leads.
Hai Su Den Reservoir
F
Basement granite, potential seven blocks.
HSD-1X discovery in Block B. HSD-4X is
being drill to test Flank A.
E
D
C
B
A
Block 15-2/01 – HST-HSD Development Plan
• Early Production Scheme to develop
HST and HSD Block B (100 mmboe).
FPSO
• Status: Field Development Plan
preparation. Oil production expected in
2012
Early Production Scheme
HSDHSD-B
Well Head
Riser
Platform
Legend
Oil
4.8
km
Water Injection
Gas Lift
PLEM
Gas Export
(pipeline
provided by
others PVGas)
4.8
km
HSTHST-A
Gas export
Well Head
Riser
Platform
Block 133/134 – Leads Maps
Lead C
133
134
Lead A
40 km
Lead B
First exploration well
planned for next year
Prospect C
Plays:
WD:
Reservoir:
Source:
Seal:
Trap:
Oligo-Miocene Clastics
900m
Deeper water to Marginal Clastic Reservoirs
Coaly Deltaic/Lacustrine
Intraformational fault seal
3-way fault closures
Prospect B
Plays:
WD:
Reservoir:
Source:
Seal:
Trap:
Oligo-Miocene Clastics
750m
Deeper water to Marginal Clastic Reservoirs
Coaly Deltaic/Lacustrine
Intraformational fault seal
3-way fault closures
N
W
S
E
25
km
Forward-Looking Information
This presentation contains information that constitutes “forward-looking information” or “forward-looking statements”
(collectively “forward-looking information”) within the meaning of applicable securities legislation. This forwardlooking
information includes, among others, statements regarding: business strategy and plans; expected first
production; planned and potential dispositions; planned drilling, development, redevelopment, sanctioning, and
exploration; targeted drilling and completions costs; planned production growth, incremental production and future
projects; forecasted free cash flow and netbacks; planned capital expenditures and program; planned prospective
resource additions and expected prospect size; planned reduction of F&D and extension of reserves life; targeted EUR
and IP; planned increases in operational efficiencies; planned seismic acquisitions; and other expectations, beliefs,
plans, goals, objectives, assumptions, information and statements about possible future events, conditions, results of
operations or performance.
The forward-looking information included in this presentation is based on Talisman 2009 capital program as
announced on January 13, 2009. The material assumptions supporting the 2009 capital program are (1) 2009 annual
production of approximately 430mboe/d (2) a US $40/bbl WTI oil price for 2009 and (3) a US $5/mmbtu NYMEX
natural gas price for 2009. 2009 production estimates are subject to the timing of development activities and include the
anticipated completion of planned dispositions. The completion of any contemplated disposition is contingent on
various factors including market conditions, the ability of the Company to negotiate acceptable terms of sale and
receipt of any required approvals of such dispositions. Forward-looking information for periods past 2009 assumes
escalating commodity prices.
Undue reliance should not be placed on forward-looking information. Forward-looking information is based on current
expectations, estimates and projections that involve a number of risks which could cause actual results to vary and in
some instances to differ materially from those anticipated by Talisman and described in this presentation. The material
risk factors include, but are not limited to: operational risks in exploring for, developing and producing crude oil and
natural gas, market demand and unpredictable facilities outages; risks and uncertainties involving geology of oil and
gas deposits; the uncertainty of reserves and resources estimates, reserves life and underlying reservoir risk; the
uncertainty of estimates and projections relating to production, costs and expenses; the impact of the economy and
credit crisis on the ability of the counterparties to the Company’s commodity price derivative contracts to meet their
obligations under the contracts; potential delays or changes in plans with respect to exploration or development projects
or capital expenditures; fluctuations in oil and gas prices, foreign currency exchange rates and interest rates; the
outcome and effects of any future acquisitions and dispositions; health, safety and environmental risks; uncertainties as
to the availability and cost of financing and changes in capital markets; risks in conducting foreign operations; changes
in general economic and business conditions; uncertainties as to the availability and cost of financing and changes in
capital markets; the possibility that government policies or laws may change or governmental approvals may be
delayed or withheld; and results of the Company’s risk mitigation strategies, including insurance and hedging
activities. The foregoing list of risk factors is not exhaustive. Forward-looking information is based on the estimates
and opinions of the Company’s management at the time the statements are made. The Company assumes no obligation
to update forward-looking statements should circumstances or management’s estimates or opinions change, except as
required by law.
Oil and Gas Information
Reserves
Canadian securities regulatory authorities have granted Talisman an exemption which permits Talisman to provide
certain disclosure in accordance with U.S. disclosure requirements. In Talisman’s Annual Information Form dated
March 9, 2009, the Company discloses 2008 year end proved reserves in accordance with US disclosure requirements
and also voluntarily discloses 2008 year end proved, probable and proved plus probable reserves in accordance with
Canadian disclosure standards under National Instrument 51-101 ("NI 51-101"). This presentation includes 2008 year
end reserves determined in accordance with NI 51-101 which are based on forecast prices. Information on the
differences between the U.S. requirements and the NI 51-101 requirements is set forth under the heading “Note
Regarding Reserves Data and Other Oil and Gas Information” in Talisman’s Annual Information Form. The
exemption granted to Talisman also permits it to disclose internally evaluated reserves data. While Talisman annually
obtains an independent audit of a portion of its reserves, no independent qualified reserves evaluator or auditor was
involved in the preparation of Talisman’s reserves data disclosed in this presentation.
Resources
In this presentation, Talisman also discloses contingent resources, prospective resources and OGIP as at December 31,
2008. Talisman also discloses prospective undiscovered resource additions. Where not otherwise indicated, the
contingent and prospective resources included in this presentation are best estimates. Information on the high and low
estimates can be found at the end of these advisories.
Contingent resources are defined as those quantities of petroleum estimated, as of a given date, to be potentially
recoverable from known accumulations using established technology or technology under development, but which are
not currently considered to be commercially recoverable due to one or more contingencies. In North America, the
contingencies that prevent the resources from being classified as reserves are: additional testing, production and
performance appraisal activities; demonstration of economic viability; facilities and egress; access to equipment and
services; frac technology; commodity prices and regulatory approvals. There is no certainty that it will be commercially
viable to produce any portion of the resources.
Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from
undiscovered accumulations by application of future development projects. Prospective resources have both an
associated chance of discovery and a chance of development. There is no certainty that any portion of the resources will
be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the
resources. Talisman’s prospective resources in the Nam Con Son Basin are partially risked for chance of discovery, but
have not been risked for chance of development. If a discovery is made, there is no certainty that it will be developed
or, if it is developed, there is no certainty as to the timing of such development. Talisman’s 6 billion barrels of global
prospective resources are not risked for chance of development or chance of discovery. Where not otherwise
indicated, references to “resource adds” in this presentation refer to unrisked prospective resources.
OGIP is defined as original gas in place and is that quantity of petroleum that is estimated to exist originally in
naturally occurring accumulations. It includes that quantity of gas that is estimated, as of a given date, to be contained
in known accumulations, prior to production. All OGIP estimates in this presentation are discovered with the exception
of the OGIP estimate for Quebec which is undiscovered. There is no certainty that any portion of the Quebec resources
will be discovered. A recovery project cannot be defined for this volume of undiscovered original gas in place at this
time. There is no certainty that it will be commercially viable to produce any portion of the resources.
Gross Production
Where not otherwise indicated, production volumes are stated on a gross basis, which means they are stated prior to the
deduction of royalties and similar payments. In the U.S., net production volumes are reported after the deduction of
these amounts. U.S. readers may refer to the table headed “Continuity of Proved Net Reserves” in Talisman’s Annual
Information Form dated March 9, 2009 for a statement of Talisman’s net production volumes.
Boe/Mcfe conversion
Throughout this presentation, barrels of oil equivalent (boe) is calculated at a conversion rate of six thousand cubic feet
(mcf) of natural gas for one barrel of oil and is based on an energy equivalence conversion method. This presentation
also includes references to mcf equivalent (mcfe) which are calculated at a conversion of rate of one barrel of oil to six
thousand cubic feet of gas (1 bbl:6 mcf). Boes and mcfes may be misleading, particularly if used in isolation. A boe
conversion ratio of 6 mcf:1 bbl and an mcfe conversion ratio of 1 bbl:6 mcf are based on an energy equivalence
conversion method primarily applicable at the burner tip and do not represent a value equivalency at the wellhead.
Reserves life index
Talisman discloses reserves life index (“RLI”) for each of the Company, North America, the North Sea and Southeast
Asia. 1P RLI is calculated by dividing the 2008 year end proved reserves at forecast prices by the Company’s 2008
gross production. 2P RLI is calculated by dividing the 2008 year end proved plus probable reserves at forecast prices
by the Company’s 2008 gross production.
F&D
In this presentation, Talisman discloses historic 5 year average finding and development costs per boe (“F&D”) for
each of the Company, North America, North Sea and Southeast Asia. The annual F&D costs for the Company and
each area by year, for the last 3 years included in the 5 year average are as follows: Company: 2008-$42.83, 2007$25.85, 2006-$21.70; North America: 2008-$34.39, 2007-$22.62, 2006-$22.96; North Sea: 2008-$38.81, 2007-$28.77,
2006-$18.47; Southeast Asia: 2008-$166.03, 2007-$20.11, 2006-$124.77. Historic F&D is calculated by dividing the
total costs incurred in oil and gas activities (excluding acquisition costs) by the gross proved reserves additions which
include additions and revisions of gross proved reserves. Gross proved reserves include proved developed and proved
undeveloped reserves and represent Talisman’s working interest. Various factors impact both historic reserves
additions including: successful wells, improved recovery, new sales contracts and revisions to the economic parameters
of a field as a result of changes in commodity prices, development costs or operating costs. All 2008 F&D numbers
exclude the impact of price revisions on reserves resulting from SEC year end prices in 2008. F&D is used by the
Company to determine the cost of reserves additions in a period. Talisman’s reported F&D may not be comparable to
similarity titled measures used by other companies. It should be noted that F&D is a measure that has limitations. As
an annual measure, the ratio is limited because it may vary widely, based on the extent and timing of new discoveries,
project sanctioning and capital expenditures. The Company uses a five year average F&D measure to reduce the
inherent variability of an annual F&D measure, which may better represent the underlying trend in F&D. F&D may
not reflect full cycle finding and development costs. The predictive and comparative value of F&D is limited for the
aforementioned reasons.
Netbacks
Talisman also discloses netbacks for the UK, North America and Corridor in this presentation. Netbacks per boe are
calculated by deducting from the sales price associated royalties, operating and transportation costs.
Analogous Information
Throughout this presentation, Talisman discloses analogous information as defined by NI 51-101 which is relevant to
the Company for comparative purposes. The Company cannot confirm that the analogous information was prepared by
a qualified reserves evaluator nor that it was prepared in accordance with the COGEH Handbook.
Canadian Dollars and GAAP
Dollar amounts are presented in Canadian dollars, except where otherwise indicated. Unless otherwise indicated, the
financial information is set out in accordance with Canadian GAAP which may differ from U.S. GAAP. See the notes
to Talisman’s Annual Consolidated Financial Statements for the significant differences between Canadian and U.S.
GAAP.
Non-GAAP Financial Measures
Included in this presentation are references to financial measures used in the oil and gas industry such as cash flow, free
cash flow and ROACE. These terms are not defined by GAAP in either Canada or the U.S. Consequently, these are
referred to as non-GAAP measures. Talisman’s reported results of cash flow, free cash flow and ROACE may not be
comparable to similarly titled measures reported by other companies. Cash flow represents net income before
exploration costs, DD&A, future taxes and other non-cash expenses. Cash flow is used by the Company to assess
operating results between years and between peer companies using different accounting policies. Cash flow should not
be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities
or net income as determined in accordance with Canadian GAAP as an indicator of the Company’s performance or
liquidity. A reconciliation of cash provided by operating activities to cash flow for the years ended December 31 2008,
2007 and 2006 is located at page 46 of the Company’s 2008 Annual Report Summary located at www.talismanenergy.
com . The presentation also discloses free cash flow for the UK and Southeast Asia reporting segments, which
represents cash flow less capital expenditures, excluding acquisitions. Free cash flow is used by management to
measure the underlying cash generating ability of these segments. ROACE (return on average capital employed) is
used to measure returns realized by the Company on capital employed and is calculated for each region by dividing
normalized after-tax income by average capital employed.
Reserves and Resource Estimates
NAO Contingent resources:
Marcellus: Best 9.8tcfe, Low 7.9tcfe, High 11.8tcfe
Outer Foothills: Best 2.3 tcfe, Low 1.6tcfe, High 2.8tcfe
Montney: Best 17.7 tcfe, Low 7.7 tcfe, High 30.5tcfe
NAO: Best 30tcfe, Low 17.3tcfe, High 45.4tcfe
SE Asia
PM-3 CAA 1P 89mmboe, 2P 154mmboe
Song Doc 1P 2.7mmboe, 2P 5.4mmboe
Corridor 1P 1.73 tcfe, 2P 2.4 tcfe, P3 660 bcfe
PM-3 1P 0 mmboe, 2P 15 mmboe, 3P, 53 mmboe
Corridor New Contracts1P 15mmboe, 2P 41mmboe
PM-3 IOR 1P 0 mmboe, 2P 15mmboe (to be drilled)
HSD/HST 1P 0mmboe, 2P 52mmboe (not yet sanctioned)
UK and Norway
Auk South: 1P 23mmboe, 2P 29mmboe
Auk North Target Area: 1P 13mmboe, 2P 17mmboe
Auk South Target Area: 1P 23mmboe, 2P 29mmboe
Monarb Hub: 1P 23mmboe, 2P 72mmboe, P3 40mmboe
Fulmar Hub: 1P 83mmboe, 2P 112mmboe, P3 42mmboe
Auk South: 1P 23mmboe, 2P 29mmboe
Auk North: 1P 13mmboe, 2P 17mmboe
Burghley: 1P 2mmboe, 2P 3mmboe
Affleck 1P 4mmboe, 2P 9mmboe
Slide 20: Rev: 1P 16mmboe, 2P 25mmboe
Yme: 1P 28mmboe, 2P 43mmboe

Malaysia - Talisman Energy

Transcription

Similar documents

_____________________________________________________ 17 September 2013 FOR IMMEDIATE RELEASE

how to make and use talismans

Term Insurance Developments

Introducing our new, exclusive CAA Corporate Membership.

business performance management in e-commerce

Corporate Presentation May 2014

annual report 2005

Noor Fadzli Yahaya UniKL MICET, 2006

Step 1

we want to hear from you

OOur Thesis Remains in Place to Emerging Markets Bonds

annualreport 2 0 0 6

april 2008 - Fortuna Silver Mines

Join CAA at Corporate Discounted Rates

career camp - Northmont City Schools