CORPORATE PRESENTATION November 2014
TALISMAN OVERVIEW TALISMAN – TWO CORE REGIONS OVERVIEW Americas
Asia-Pacific
Core: Asia-Pacific • Self-sustaining, grows ~5% p.a. • Constructive macro environment for gas • Significant exploration and development potential • Generates ~$1.2 billion cash flow, $400 million free cash flow per year
Greater Edson & Duvernay HST/HSD Marcellus PM3-CAA
Core: Americas
Eagle Ford Corridor
• “Right sized” well positioned in 5 basins • 25% liquids production, grows to 40% by 2018 • Significant running room • Generates ~$1 billion cash flow, free cash flow turning point 2015*
Colombia
*Assumes COGEH price deck
TALISMAN OVERVIEW TWO CORE REGIONS IN PERSPECTIVE ~90% of production
~90% of cash flow
~90% of 2P value
~70% of capital
UK
Norway Kurdistan
November 2014
Americas
Americas
Americas
Americas
Asia-Pacific
Asia-Pacific
Asia-Pacific
Asia-Pacific
Non core
Non core
Non core
Non-core
NYSE: TLM | TSX: TLM
www.talisman-energy.com
Page 1
CORE REGIONS – GROWING AND LIVING WITHIN MEANS Production
Cash flow**
Capital
mboe/d
$ million
$ million
500
4,000
Americas
Americas
Asia-Pacific
Asia-Pacific
Asia-Pacific
10-12% CAGR
5% CAGR
400
4,000
Americas
3,000
3,000
2,000
2,000
1,000
1,000
300
200
100
0
0 2013
2014
2015
2016
2017
2018
0 2013
2014
2015
2016
2017
2018
2013
2014
2015
2016
2017
2018
* Includes corporate costs (allocated) ** Assumes COGEH price deck
BUILDING A SUSTAINABLE BUSINESS IN TWO CORE AREAS Americas – Free cash flow turning point 2015*
Foundation
Developing
Future
Asia-Pacific – 5% mid-term production growth
Foundation
Developing
Future
• Marcellus
• Eagle Ford
• Duvernay
• Corridor
• Red Emperor
• Sabah
• Greater Edson
• CPO-9
• CPE-6
• PM-3
• Kinabalu
• Sakakemang
• HST/HSD
• Jambi Merang
• Business Development
• Chauvin • Equion
* Assumes COGEH price deck
November 2014
NYSE: TLM | TSX: TLM
www.talisman-energy.com
Page 2
CORE ASSETS Materiality
Cost Structure
Competitive Advantage
Marcellus Edson Chauvin Eagle Ford
Evolving
Duvernay
Evolving
Colombia
Evolving
Malaysia Indonesia Vietnam
CATALYSTS FOR NEAR-TERM SUCCESS
November 2014
1
Colombia
2014/15
2
Marcellus
2014
3
Greater Edson
2014/15
Wilrich/Dunvegan appraisal and development
4
Duvernay
2014/15
Duvernay well results JV partnership and funding
5
Kurdistan
2014/15
Kurdamir/Topkhana appraisal Potential exit
6
Red Emperor
7
North Sea
2015 2014 +
NYSE: TLM | TSX: TLM
Akacias development & Block 9 exploration upside Marcellus midstream divestment
Project sanction and development follow-on Improved reliability, progress on major projects, dilution/divestment
www.talisman-energy.com
Page 3
NORTH AMERICA – HEALTHY BUSINESS UNDERPINNED BY BALANCED PORTFOLIO Dry Gas Marcellus
Heavy Oil Chauvin
Liquids Rich Gas Greater Edson
Liquids Rich Gas Eagle Ford
Liquids Rich Gas Duvernay
• Free cash flow positive
• Free cash flow positive
• Free cash flow positive
• Operational excellence
• High value oil production
• Liquids growth
• Free cash flow positive by 2016
• Proved high liquids yield
• Low risk stacked reservoirs…running room
• High value liquids growth
• Running room
• Strategic infrastructure
• Technology upside
• Egress secured
• Low risk/cost infill drilling
• Running room
• Proximal infrastructure
• Improved operations
Foundation
Developing
Future
FOCUSING ON HIGH MARGIN CORE AREAS North America liquids – Field cash flow margins**
North America gas – Field cash flow margins**
$/boe
$/mcfe Royalty
80
Opex + Transport
Royalty
6
Field Margin*
Opex + Transport Field Margin*
70 60 4
50 40 30
2
20 10 0
0
Chauvin
Eagle Ford
Marcellus
95% liquids
>60% liquids
Proximity to premium markets
* Revenue – Royalty – Direct Opex & Transport – Local taxes ** YTD
November 2014
NYSE: TLM | TSX: TLM
Greater Edson Enhanced liquids recovery
*Revenue – Royalty – Direct Opex & Transport – LocalTaxes ** YTD
www.talisman-energy.com
Page 4
NORTH AMERICA – SELF-FUNDING CAPITAL PROGRAM Sources and uses of cash*
Production***
$ million
mboe/d
2,000
Capital
220
Cash flow**
Gas
Liquids
200 180
1,500
160 140 120
1,000 100 80 60
500
40 20
0
0
2013
2014
2015
2016
2017
2018
* Includes results from ongoing operations and assumes 50% joint venture in Duvernay ** Assumes COGEH price deck
November 2014
NYSE: TLM | TSX: TLM
2013
2014
2015
2016
2017
2018
*** Assumes 50% joint venture in Duvernay
www.talisman-energy.com
Page 5
MARCELLUS – OVERVIEW 2014 asset summary Production YTD (mmcf/d) Production mix
457 100
(gas %)
Land (net acres) 2P reserves*
~190,000 2.6
(tcf)
2C Contingent resources* (tcf)
6
2P reserve life index (years)
16
TLM operated Cabot
2014 guidance
Chief/Keeton/Radler
FY production (mmcf/d)
~440
SWEPI/Ultra
Capex ($ million)
~400
Chesapeake/Statoil/ Anadarko
Rigs (average)
~1.5
Tennessee gas pipeline
Horizontal wells drilled (net)
North Penn gas pipeline
40
Proposed TLM pipeline
20
TLM pipeline TLM compressor station
0
2012
2013
2014 (e)
* As at December 31, 2013
MARCELLUS – LOW RISK, PROFITABLE LONG-TERM UPSIDE Materiality
Marcellus type curve mmcf/d
•
Sustainable at ~500 mmcf/d for >15 years
•
~6 tcf of 2C contingent resource
6 4 2
Cost Structure
0
•
$0.30/mcf field opex, $0.35/mcf transportation
•
Half-cycle break-even of $3.25/mcf
0
5
10
15
20
25
30
35
Well economics
Competitive Advantage
IP 30 day (mmcf/d)
~5
•
High value midstream infrastructure
EUR (bcf)
~6
•
Firm long-haul transport of 625 mmcf/d, access to Henry Hub, ~150 mmcf/d on Empire and ~475 mmcf/d on Tennessee
D&C costs ($ million)
5.6
•
Exceptional production and development track record
IRR (% BT)
November 2014
40
Months
NYSE: TLM | TSX: TLM
Drilling locations (net)
www.talisman-energy.com
~1,100 35-40
Page 6
OPERATIONAL EXCELLENCE – PRODUCTION OPTIMIZATION
10% Improvement in volumes
SIGNIFICANT OPTION VALUE FROM HIGHER PRICES Source and uses of cash
Source and uses of cash
Source and uses of cash
$ million
$ million
$ million
1,400
1,400
1,200
1,200
1,000
1,000
800
800
600
600
400
400
400
200
200
200
0
0
1,400 1,200 1,000 800 600
2013
2014 2015 2016 2017 2018
0
2013
2014 2015 2016 2017 2018 Capital
November 2014
2014 2015 2016 2017 2018
Cash flow
~450 mmcf/d
~600 mmcf/d
($4.00/mcf)
($5.00/mcf)
NYSE: TLM | TSX: TLM
2013
~700 mmcf/d
www.talisman-energy.com
($6.00/mcf)
Page 7
EAGLE FORD – OVERVIEW 2014 asset summary TLM/STO land Oil
Karnes County
Liquids
DeWitt County
Production YTD (mboe/d)
34
Gas (mmcf/d)
77 23
Liquids (mbbls/d)
~60,000
Land (net acres)
Gas
2P reserves* (mmboe)
118
2C Contingent resources* (mmboe)
322
Prospective resources* (mmboe)
74
2P reserve life index (years)
11
2014 guidance
La Salle County
Live Oak County
McMullen County Talisman operated
Statoil operated
FY production (mboe/d)
~34
Product mix (%)
40 27 33
Gas NGLs Condensate
~550
Capex ($ million)
2.5
Rigs (net) Horizontal wells drilled (net)
60 40 20 0 2012
2013
* As at December 31, 2013
2014 (e)
** Best Estimate at December 31, 2013
EAGLE FORD – OPTIMIZING VALUE FROM LIQUIDS-RICH SHALE PLAY Materiality
Eagle Ford type curve mboe/d
• •
~60,000 net acres, majority held by production Doubled production over last 2 years
1.5 1.0
Cost Structure
0.5 0.0
•
Field opex of $4.70/boe
•
Continuous D&C cost improvement
0
5
10
15
20
25
30
35
40
Months
Well economics
Competitive Advantage
IP 30 day (boe/d)
800-1,400
•
Successful joint operations with Statoil
EUR (mboe)
•
Vastly improved operational performance and egress in place
D&C costs ($ million)
•
Infrastructure and egress in place
Drilling locations (net)
>300
•
60% liquids
IRR (% BT)
30-75
November 2014
NYSE: TLM | TSX: TLM
www.talisman-energy.com
400-950 7-8
Page 8
EAGLE FORD – FREE CASH FLOW FROM 2016 Sources and uses of cash*
Production
$ million
mboe/d
50
800 Capital
Gas
Cash flow*
Liquids
40
600 30
400 20
200
10
0
0
2013
2014
2015
2016
2017
2018
2013
2014
2015
2016
2017
2018
* Assumes COGEH price deck
November 2014
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Page 9
CHAUVIN – OVERVIEW R5
R1 W4
2014 asset summary T45
Production YTD (mboe/d) Production mix
TLM operated
Edgerton
2P reserves*
Husky
2P reserve life index (years)
Twin Butte
2014 guidance
Other pipeline Facility Truck terminal
95 >200,000
Land (net acres)
CNRL
TLM pipeline
Chauvin
11
(oil %)
36
(mmboe)
10
FY production (mboe/d)
~10
Capex ($ million)
~40 1
Rigs (average)
Total wells drilled (net) 40
T40
0
2012 Source: IHS public data
2013
2014(e)
* As at December 31, 2013
CHAUVIN – STABLE FREE CASH FLOW GENERATION Materiality
Chauvin type curves boe/d
•
~900 million boe original oil in place (net)
•
~350 undrilled locations
75
GP Lloyd
50 25
Cost Structure
0
•
High margin per barrel
•
~$150 million of annual free cash flow in 2014
0
Competitive Advantage • •
Leduc
Highly focused field operations, control key infrastructure Recovery factor upside with large OOIP
15
30
75
GP
Lloyd
Leduc
IP 30 day (boe/d)
30
65
60
EUR (mboe)
100
100
50
D&C costs ($ million)
1.5
1.1
0.8
20-30
65-75
>99
100
70
15
Drilling locations (net)
NYSE: TLM | TSX: TLM
60
Well economics
IRR (% BT)
November 2014
45
Months
www.talisman-energy.com
Page 10
CHAUVIN – LONG-TERM, LOW-RISK ATTRACTIVE CASH FLOW Production
Sources and uses of cash*
mboe/d
$ million
200
Capital
Cash flow*
150
9
100
6
50
3
0
Development/optimization
12
Base
0
2013
2014
2015
2016
2017
2018
2013
2014
2015
2016
2017
2018
* Assumes COGEH price deck
November 2014
NYSE: TLM | TSX: TLM
www.talisman-energy.com
Page 11
GREATER EDSON R25
R20
R15
R10
2014 asset summary
R5 W5
Production YTD (mboe/d)
T60
Wild River
38 171
Gas (mmcf/d)
Duvernay North
TLM operated
Edson
11
Liquids (mbbls/d)
~525,000
Land (net acres)
Whitecourt
T55
2P reserves* (mmboe)
172
2C Contingent resources* (mmboe)
382
BE** Prospective resources (mmboe)
715
Midstream pipeline
2P reserve life index (years)
Facility
2014 guidance
11 ~42
FY production (mboe/d)
Duvernay outline
T50
Edson
Alberta T45
Product mix (%) Gas NGLs
~75 ~25
Capex ($ million)
~200 ~3
Rigs (average)
Duvernay South Horizontal wells drilled (net)
Rocky Mountain House
T40
15 10 5 0 2012 * As at December 31, 2013
2013
2014 (e)
**BE – Best Estimate
LIQUIDS-RICH PRODUCTION AND STRATEGIC INFRASTRUCTURE • ~525,000 net prospective acres
Materiality
• Multiple prospective horizons: Dunvegan, Falher/Notikewan, Wilrich, Sundance, Spirit River
Cost Structure
• Continuous improvement in cost structure and full cycle costs
Competitive Advantage
November 2014
• Operated infrastructure (~2,700 km pipelines, 5 plants) • Commercial agreements access full value chaing • Long operating history
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Page 12
GREATER EDSON WELL ECONOMICS Edson type curves
Wild River type curves
mmcf/d
mmcf/d Dunvegan 8
Falher / Notikewin
6
Wilrich
-5%
4
8
Edson-Wilrich
6
Sundance-Spirit River
4 2
2
0
0 0
5
10
15
20
25
30
35
40
0
45
15
30
Months
Wild River well economics
Dunvegan
Falher / Notikewin
Wilrich
4.5
5.5
5.0
IP 30 day (mmcf/d)
2.8
2.9
2.8
EUR (bcf)
~65
~70
~65
5.8
5.8-6.3
5.8
60-70
>99
65-75
~50
~120
~120
D&C costs ($ million) Drilling locations (net)
*Assumes deep cut processing at Pembina Saturn Plant
Edson Wilrich 6.6
Edson well economics
EUR (bcf)
IRR (% BT)
60
Months
IP 30 day (mmcf/d) Liquids yield (bbls/mmcf)*
45
Liquids yield (bbls/mmcf)*
6.0
3.9
~25
~20
6.2
6.2
>99
70-80
~180
~160
D&C costs ($ million) IRR (%BT) Drilling locations (net)
Sundance Spirit River 5.3
*Assumes processing at Edson gas plant
GREATER EDSON – FREE CASH FLOW GROWTH Sources and uses of cash*
Production
$ million
mboe/d
400 Capital
60
Cash flow*
Gas
Liquids
50 300
40 200
30 20
100
10 0
0
2013
2014
2015
2016
2017
2018
2013
2014
2015
2016
2017
2018
* Assumes COGEH price deck
November 2014
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Page 13
DUVERNAY TLM land Exxon
Fox Creek
Encana Chevron Shell Leduc Reef Edge TLM drilled and completed TLM in progress Midstream pipeline TLM gas plant
Oil Liquids Gas
2014 asset summary Land (net acres)
~300,000 1.8
BE** Prospective resources* (billion boe)
2,100
Drilling locations (net)
2014 guidance Wells (rig released in 2014)
7
Capex ($ million)
~135 1
Rigs (average)
Horizontal wells drilled (net) 9
Rimbey
6 3
Rocky Mountain House
0
2012
Source: IHS public data
* As at December 31, 2013
2013
2014 (e)
**BE – Best Estimate
A PREMIER SHALE PLAY
Materiality
Cost Structure
• ~300,000 net acres (prospective land) • 1.8 billion boe prospective resource (unrisked) • Near-term transition to pad drilling / multi-well completions expected to materially drive costs down • Significant improvement in drill times in 2014 • Leverage industry learnings as activity increases
Competitive Advantage
November 2014
• Contiguous with Talisman Greater Edson infrastructure which allows earlier production flow • Marcellus, Montney and Eagle Ford learnings transfer
NYSE: TLM | TSX: TLM
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Page 14
NORTH DUVERNAY – APPRAISED BY INDUSTRY ACTIVITY Shell 02/05-30 Yield ~525 bbls/mmcf 1,650M Lateral
Encana 06-06 Yield ~487 bbls/mmcf
Encana 06-09 Yield ~370 bbls/mmcf 21 stages
Chevron 02/01-36 Yield ~29 bbls/mmcf 6 stages 1,220M Lateral
Shell 03/13-33 Yield ~413-532 bbls/mmcf 2,250M Lateral
TLM 02/16-21 Yield 11.3 mmcf/d ~59 bbls/mmcf (24 hr test rate)
Waskahigan
TLM 01-18 Yield ~3 bbls/mmcf 3.2 mmcf/d (IP) 6 stages, 995M Lateral
Bigstone Encana 02/08-05 Yield ~350 bbls/mmcf 4 mmcf/d (IP) 1,850M Lateral
Shell 04-16 Yield ~405 bbls/mmcf 1,850M Lateral
TLM 15-7 & 02/15-7 Currently drilling 2 well pad
TLM 12-26 Yield ~14 bbls/mmcf 3.8 mmcf/d (IP) 7 stages, 1,012M Lateral
TLM 05-18 1,258M Lateral
Pine Creek
Celtic 13-36 Yield~94bbls/mmcf 7.1 mmcf/d (IP) 25 stages, 1,727M Lateral Trilogy 03-13 Yield ~72+ bbls/mmcf 5.2 mmcf/d (IP) 12 stages , 1,395M Lateral Trilogy 05-03 Yield ~68+ bbls/mmcf 16 stages, 1,1745M Lateral
TLM 04-09 Yield ~69 bbls/mmcf 1.4 mmcf/d (IP) 6 stages, 1,172M Lateral
Source: Various corporate presentations and public production data
Edson
Chevron 05-05 Yield ~117 bbls/mmcf 3.9 mmcf/d IP (7 day Test)
TLM Duvernay land Leduc Reef Edge Oil Gas Liquids New TLM well TLM well Competitor well Midstream pipeline Facility
>700 Net prospective locations Chevron 04-22 Yield ~105 bbls/mmcf 1.8 mmcf/d IP (7 day Test) IP represents 30 day initial production rate Yield represents separator yields
SOUTH DUVERNAY – LARGE CONTIGUOUS LIQUIDS-RICH LANDS Encana 03-06 Yield ~45 bbls/mmcf 3.7 mmcf/d (IP) 40 stages 2,084M Lateral
Encana 13-17 Yield ~190 bbls/mmcf 1.7 mmcf/d (IP) 10 stages 1,250M Lateral
TLM 06-09 1,258M Lateral
Willesden Green
Encana 11-05 Yield ~120 bbls/mmcf 1.6 mmcf/d (IP) 5 stages 518M Lateral
Encana 02-35 Yield ~148 bbls/mmcf 2,030M Lateral
TLM 03-06 Yield ~180 bbls/mmcf 1.1 mmcf/d+201 bbl/d liquid (restricted) 7 stages, 1,076M Lateral
TLM 16-15 (~1600 m lateral) Q4, 2014 completion
TLM 02/04-33 Yield ~285 bbls/mmcf 1.2 mmcf/d +343bbl/d liquid (restricted) 16 stages, 1,600M Lateral
Shell 04-21 Yield ~72 bbls/mmcf 3.5 mmcf/d (IP) 1600M Lateral
TLM 10-03 Yield ~875 bbls/mmcf 0.3 mmcf/d+262 bbl/d liquid 5 stages, 1,050M Lateral
TLM 03-28 Yield ~320 bbls/mmcf 1.4 mmcf/d+448bbl/d liquid restricted 14 stages, 1,615M Lateral
Ferrier
Source: Various corporate presentations and public production data
November 2014
NYSE: TLM | TSX: TLM
TLM 11-25 Yield 2.7 mmcf/d ~450 bbls/mmcf (24 hr test rate) TLM 13-07 Yield 1.9 mmcf/d ~315 bbls/mmcf (24 hr test rate)
www.talisman-energy.com
TLM Duvernay Land Leduc Reef Edge Oil Gas Liquids New TLM well TLM wells Competitor wells
100-1,000 bbls/mmcf
>1,400 Net prospective locations IP represents 30 day initial production rate Yields represent separator yields
Page 15
MAJOR PLAYER Duvernay top high graded* land holders Gross acres 450,000 400,000 350,000 300,000 250,000 200,000 150,000 100,000 50,000 0
A
B
Talisman
C
D
E
F
G
H
I
* >20 metres of net pay Source: BMO Capital Markets, April 2014
D&C COST CHALLENGE D&C costs $ million
20
19.0
• No vertical strat. test • Drilling time learning curve • Pad drilling efficiencies
3.5 15 4.5 11.0 10
• Multi-well completion efficiencies • Frac water sourcing and disposal efficiencies • Proppant and diversion optimization
5
0
2014 average cost
November 2014
Drilling
NYSE: TLM | TSX: TLM
Completions
www.talisman-energy.com
Target
Page 16
DUVERNAY – GROW SUBSTANTIAL PRODUCTION Sources and uses of cash**
Production**
$ million
mboe/d Capital
100
Cash flow*
Liquids
1,500
Gas
80 60
1,000 40 500
20 0
0
2013
2014
2015
2016
2017
2018
2019
2020
2013
2014
2015
2016
2017
2018
2019
2020
* Assumes COGEH price deck ** Assumes 100% working interest with 8 rig program
November 2014
Future
100 mboe/d
Value growth
Plateau
NYSE: TLM | TSX: TLM
www.talisman-energy.com
Page 17
TLM block Equion block
Akacias
Equion
COLOMBIA
CPE-6
COLOMBIA – PRODUCING AND POSITIONED FOR GROWTH
Materiality
• Self-funding growth with Equion providing cash flow to develop blocks CPO-9 & CPE-6 • Major resource extension at Akacias – 2.5 billion barrels discovered OOIP (gross) with upside
Cost Structure
• Equion – efficient operations and cost management • Ocensa capacity, the lowest cost and most reliable route of crude export in Colombia
Competitive Advantage
November 2014
• Strong Ecopetrol partnership • Ocensa 63,000 bbls/d transportation capacity, ability to manage growth and market excess capacity
NYSE: TLM | TSX: TLM
www.talisman-energy.com
Page 18
EQUION – WELL RUN, EFFICIENT SOURCE OF CASH Production
Floreňa
mboe/d 20 Pauto Piedemonte
10
Recetor Cupiagua Norte Cusiana
0 ’13
’14
’15
’16
’17
’18
Piedemonte Expansion
Equion block Oil field Gas condensate
~$220 million
~$100 million
Cash flow from operations in 2013
Free cash flow in 2013
CPO-9 – AKACIAS AND ADDITIONAL PROSPECTS RESULTING IN SUBSTANTIAL UPSIDE Chichimene Akacias
~53mbbls/d
Apiay Block ~22mbbls/d
Nueva Esperanza p
discovered OOIP current best estimate Akacias extension (gross)
Castilla Yaguarundi
2.5 billion bbls
~113mbbls/d
Tayra
Substantial additional exploration potential Note: 2013 annualized production numbers based on ANH public data
CPO-9 block Producing oil field Prospect/Lead Akacias commercial area Potential larger accumulation
November 2014
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Page 19
AKACIAS – DEVELOPMENT UNDERWAY CPO-9
Akacias Production
AE-2 AK-20
AK-19
mboe/d (TLM net)
Akacias AK-18 AK-11
40
AK-1 AK-9
Upside
AK-10 AK-16
30
AK-17
AE-1
Akacias
AK-15
Chichimene
20 Cubarral block Commercial area
10
Drilled well
Nueva Esperanza-1 2H 2014 Drill
Producing wells LTT
Humadea - 1974 Chevron well
Prospects
0 Nueva Esperanza Sur-1 2H 2014 Drill
kms 0
2
4
6
8
’13
10
’14
’15
’16
’17
’18
•
O&G regulator (ANH) is supportive of Field Development Plan as submitted, obtaining environmental permit for full development the last hurdle to start of development activity
•
First phase expected over two years (following receipt of environmental permit) −
Drill 50 development wells
−
Build 50,000 bbls/d (gross) central processing facility
CPO-9 – AKACIAS EVOLUTION THROUGH APPRAISAL AE-2 Untested
AE-1
Ak-20
Untested
LTT
Ak-17 LTT
Ak-16 LTT
Ak-11 LTT
Ak-15
Ak-10
LTT
LTT
Ak-19
Ak-18
LTT
Ak-1 LTT
LTT
Declaration of “Commerciality”** December 2013 – tested pay to base Ak-15 - 1.3 billion bbls OOIP* On LTT at ~450 bbls/d & 48% water cut Current Best Estimate – logged pay to base AE-1 – 2.5 billion bbls OOIP* Max lowest known oil – logged pay to base AE-2 – 3.2 billion bbls OOIP* OOIP Range
* Heavy oil (gross) ** See advisories Note: Ak-9 highly deviated well not on schematic
High
Best
Low
3,200 mmbbls
2,500 mmbbls
1,300 mmbbls
Oil water contact not yet encountered. Stratigraphic wells (AE-1 & AE-2) granted approval to be flow tested by regulator, expect testing to occur mid-2015.
November 2014
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Page 20
CPO-9 – AKACIAS: POTENTIAL FOR A MUCH LARGER ACCUMULATION Top Reservoir Elevation ft
• Humadea well drilled in the ‘70’s proved heavy oil in the Nueva Esperanza Sur structure
Akacias Commercial Area
Nueva Esperanza
• Targeting oil in the up dip structural trend to the SW
Humadea Well
• 4 well exploration program underway Nueva Esperanza Sur
– Nueva Esperanza reached TD in October, logging and testing on going – Nueva Esperanza Sur expected to spud 1H 2015
Yaguarundi
Tayra
ASIA-PACIFIC – DELIVERY, CASH FLOW AND GROWTH
Materiality
• 2P reserves of 520 million boe • ~$1.2 billion of cash flow, ~50% of Talisman’s 2014 guidance • ~140,000 boe/d production target 2014, at netback of ~$35/boe
Cost Structure
• Top quartile HSE performance with improving operational uptime • Premium pricing and growing margins • Consistent and reliable project execution
Competitive Advantage
November 2014
• Identified further organic and inorganic potential • Consistent track record underpin relationships • Strategic fit
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Page 21
ASIA-PACIFIC – SUBSTANTIAL CASH FLOW AND GROWING Sources and uses of cash* $ million 2,000 Capital
~140,000 boe/d 2014 production target
1,500
>10% CAGR
1,000
Cash flow
Cash flow**
500
0
2013
2014
2015
2016
2017
2018
* Including Algeria ** Assumes COGEH price deck
TRACK RECORD OF DELIVERY Production mboe/d 180 160
Vietnam
Other
Malaysia
Indonesia
18% CAGR over 20 years
140 120 100 80 60
May, 1993 Entry into Indonesia
1994 Acquired interests in Corridor & OK Block
1998 Corridor Gas Project commissioned
August, 2001 Acquired block PM-3 CAA, Malaysia
September, 2003 PM-3 CAA project, producing over 19 mboe/d in Q4
October, 2005 Acquired interests in Southeast Sumatra, ONWJ & Australia
2010 Acquired Jambi Merang PSC
April, 2011 Jambi Merang first gas
October, 2011 First oil from Kitan
May 2013 December, First oil 2012 from Awarded HST/HSD Kinabalu PSC
July 2013 Red Emperor acquisition
11% CAGR last 10 years
40 20 0
1993
November 2014
1998
NYSE: TLM | TSX: TLM
2003
2008
www.talisman-energy.com
2013
Page 22
DOMESTIC DEMAND DRIVING GAS PRICE INCREASES Asia-Pacific gas supply demand balance*
Domestic gas prices
bcf/d
$/mcf Confirmed domestic supply
14
20
2005
12% p.a.
Demand
2013
Supply demand gap
12 15
10
9 bcf/d 8
10
16% p.a.
9% p.a. 13% p.a.
6 5
4 2 0 2010
0
2012
2014
2016
2018
2020
2022
2024
Vietnam
2026
* Includes Singapore, Malaysia, Vietnam and Indonesia
Singapore
Malaysia
Indonesia
Source: Wood Mackenzie
ASIA-PACIFIC – FREE CASH FLOW AND SUSTAINABLE GROWTH
Corridor
PM3CAA
HST/HSD
Foundation
November 2014
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• Red Emperor
• Sabah
• Kinabalu
• Sakakemang
• Jambi Phase 2
• Nam Con Son
• Tangguh Train 3
• Business Development
Developing
www.talisman-energy.com
Future
Page 23
CORRIDOR – GROWTH AND SUSTAINABILITY Production (net)*
>$370 million Free cash flow per annum net
mboe/d 80 70 60 50 40 30
2013
2014
2015
• ~1.1bcf/d gross sales
Sources and uses of cash*
• Production growth over the mid-term
600
2016
2017
2018
$ million
• Infill drilling – potential to support expansion of 80 to 150 mmcf/d*
Capital
Cash flow**
400 200 0
2013 *Talisman
2014
2015
2016
2017
2018
** Assumes COGEH price deck
internal estimate
CORRIDOR – PREMIUM PRICING, EXCEPTIONAL NETBACKS 2013 Realized Revenue by Pricing Mechanism
Evolution of domestic gas price re-negotiations $/mmbtu
Fixed Price Gas $5.67/mcf
23%
14 12 10 8 6 4 2 0
Headroom for domestic price increase
2007
8% Liquids $87.40/boe
2008
2009
2010
2011
2012
2013
2014
YTD 2014 Corridor field price realization and netback chart $/mcf
3.27
69% Oil Linked Gas $15.12/mcf
0.83 9.81 5.71
Realized price
November 2014
NYSE: TLM | TSX: TLM
Royalties
www.talisman-energy.com
Opex/trans.
Netback
Page 24
OPERATOR OF CHOICE AT PM-3 CAA YTD 2014 Realized Prices
$112
$7.30
per bbl
per mcf
Production outlook mboe/d 40 30 20 10 0
2013
• Maintain production with infill drilling and well interventions • Step out drilling of stratigraphic oil and gas play • Major facilities investment to support extension and growth
2014
2015
2016
2017
2018
Sources and uses of cash* $ million Capital
400
Cash flow*
200
0
2013
2014
2015
2016
2015
2016
2017
2018
* Assumes COGEH price deck
HST/HSD – EXCELLENT PROJECT EXECUTION, EXCEPTIONAL NETBACKS Production
$78 per boe YTD 2014 netback
mboe/d 15 10 5 0
• Achieved early payout of Petro Vietnam carry in 3Q, net production reduced • Early production history suggests potential upside • Utilizing additional capacity at FPSO increases value • Operating efficiency averaging 98%
2013
2014
NYSE: TLM | TSX: TLM
2018
Sources and uses of cash* $ million 300
Capital
Cash flow*
200 100 0
2013
2014
* Assumes COGEH price deck
November 2014
2017
2015
www.talisman-energy.com
2016
2017
2018
Page 25
KINABALU – INCREMENTAL PRODUCTION Production outlook mboe/d 20
10
0
2013
2014
2015
2016
2017
2018
Sources and use of cash*
• 1st expired PSC to be granted to an Independent • Improving operational efficiency, Q3 >95% • Production records achieved as operator
$ million 200
Capital
Cash flow*
150 100 50 0
2013
2014
2015
2016
2017
2018
* Assumes COGEH price deck
RED EMPEROR – RESOURCE WITH SIGNIFICANT UPSIDE Red Proposed Emperor2014 extension Drilling
• 67 million boe of gross 2C contingent resources in Red Emperor field • Red Emperor extension – 2 wells to be drilled in 2014
Red Emperor
Red Emperor proposed activity Block136
2013 Acquire
November 2014
NYSE: TLM | TSX: TLM
2014 Appraise
2015 Define Dev. Sanction
www.talisman-energy.com
2016
2017 Develop
Page 26
SAKAKEMANG – SIGNIFICANT POTENTIAL IN “OUR” BACK YARD To Singapore and Duri
• Strategically positioned farm-in within a proven petroleum province
Jambi Merang
• Synergy with Corridor and Jambi Merang
Sakakemang TLM block Forest Lake
Sakakemang Oil field Gas field
• Exceptional access to markets and infrastructure
Oil pipeline Jessup
Corridor
Gas pipeline
Sakakemang proposed activity
2014
2015
Seismic and G&G studies
2016 Expl. well
2017
POD application
Development
ALGERIA – FREE CASH FLOW & PERTAMINA RELATIONSHIP TLM block Other block Oil fields
Production mboe/d 15
Ourhoud
10 5
Greater MLN
0
2013
EMK
2014
2015
2016
2017
2018
Sources and uses of cash* $ million 150
Capital
Cashflow*
100
~$100 million
50
Free cash flow per annum net
0
2013
2014
2015
2016
2017
2018
* Assumes COGEH price deck
November 2014
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www.talisman-energy.com
Page 27
November 2014
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www.talisman-energy.com
Page 28
NORTH SEA BUSINESS OVERVIEW • Drive value from late life assets while continuing to pursue divestments/dilutions
Montrose Area Redevelopment (MAR)
– – – –
Montrose
Restore reliability and efficiency Execute major projects Optimize abandonment costs & schedule Divest/dilute
• UK
Cayley Arbroath
–
MAR project complete in 2016, peak production impact in 2017/2018 Claymore Compression Upgrade will deliver >80% Operating Efficiency
–
Shaw
Godwin
• Norway –
Yme flotel on station in September, decommissioning of topsides have begun Yme MOPU to be removed summer 2015 Yme redevelopment concept under evaluation
– –
IMPROVING PERFORMANCE AND RELIABILITY Claymore Area • Turnarounds at Claymore & Piper Q2/Q3 2014 Flotta Terminal
Piper
Claymore Scapa
Highlander
Tartan
Saltire
Chanter
• Claymore & Piper well work-overs planned for Q4 2014
Galley
Duart
• Claymore Compression Upgrade commissioning Q1 2015, will increase operational efficiency
Tweedsmuir
Petronella
Montrose/Arborath (MonArb Redevelopment)
Bleoholm & Buchan • Buchan turnaround complete in Q3 & Bleoholm continues Q3/Q4 2014
Hannay Blake
Montrose
• Partner alignment reached on Ross & Blake to secure the Bleoholm vessel until 2019
Ross Buchan
Cayley (future)
Brechin
Shaw (future) To Forties
Greater Fulmar Area Cawdor (future)
Halley
To Norpipe
Fulmar
Flyndre (future) Affleck
Auk North
Clyde Auk
Orion
To Janice
Wood
Arbroath
Bleoholm
November 2014
• Jacket for Montrose BLP installation completed
To Forties
Arkwright Godwin (future)
• Flotel on station at Montrose for redevelopment work • Godwin well completed drilling in August, production expected to start 2Q 2015 • Project complete in 2016, peak production impact in 2017/2018
• Fulmar & Auk turnarounds Q3/Q4 2014
Platform
• Flyndre/Cawdor: Engineering on-going, early structural work for brownfield modifications at Clyde started, tie-ins in 2016/17
Subsea Tie-Back
• Strong Fulmar operational efficiency in recent months
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FPSO Vessel Operated/Non-Operated
Page 29
TALISMAN UK JOINT VENTURE PORTFOLIO MANAGEMENT Core
Late Life
Primary value driver: Increase production • Improve deliverability ‒ Production efficiency
Life Extension
Decommissioning
Primary value driver: Reduce costs
Primary value driver: Reduce costs
• Optimize operations to safely reduce costs
• Prepare for decommissioning
• Opportunistic project investment
• Asset examples: Saltire
‒ Project execution
‒ Extend field life where appropriate by TLM or other parties
• Extract additional well defined, low-risk resources •
• Reduce operating costs
‒ Optimize phasing
Asset examples: Bleoholm
• Assets: Claymore, Monarb, Piper
Currently defining asset strategies and creating two distinct business divisions to align with categorization
KURDAMIR / TOPKHANA CROSS SECTION T-1
T-2 Topkhana
• •
T-1 (drilled before K-2 & K-3) was not tested in the oil leg GOC 1882m in Topkhana extrapolated from K-2 and K-3 DST results
Topkhana OGC 1882mss
K-1
K-3
K-2
Kurdamir
Kurdamir OGC 1840mss
2C ODT: 2049 mss 3C ODT: 2229 mss
2C gas and condensate
3C oil
2C oil
DST oligocene intervals
Progressing approval of the Kurdamir Field Development Plan with the Kurdistan Regional Government and block Partner Note: 1C represented by 2C shading, but assumes different recovery factor
November 2014
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www.talisman-energy.com
Page 30
TALISMAN TRANSITION 2012-2014
TALISMAN TRANSITION 2012-2014 STRATEGIC PRIORITIES • Live within our means
1
− Reduced capital $4 billion to ~$3 billion − Maintain debt-to-cash flow 1.5-2x
• Focus our capital program
2
− Liquids production from core up 25%, cash flow from core up 60% − Working through legacy commitments
• Improve operational performance and reduce our full-cycle costs
3
− G&A reduced 20% last 2 years − 25% reduction in drill cycle times in Eagle Ford and Marcellus
• Unlock the net asset value of our portfolio
4
November 2014
− ~$2 billion dispositions completed, targeting future $2 billion + − Exploring range of broader strategic options
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Page 31
TALISMAN TRANSITION 2012-2014 DISCIPLINED & FOCUSED CAPITAL ALLOCATION 20% reduction in capital expenditure
70% of capital directed to core regions
$ billion
Percentage (%)
56% reduction of non-core exploration & appraisal $ million
4.0
500
75
20%
56%
>70%
400
in core 3.5
70 300
200
3.0
65 100
0.0
0
0 2012
2013
2014E
2012
2013
2012
2014E
2013
2014E
TALISMAN TRANSITION 2012-2014 LIQUIDS AND CASH FLOW FROM CORE AREAS 25% liquids growth from core areas
60% cash flow growth from core areas
mbbls/d
$ million 650
120 +18%
115
600
+50%
550
110
500 105 450 100 400 95 350 0
0 1Q’13
2Q’13
3Q’13 4Q’13 1Q’14
2Q’14
3Q’14
1Q’13
2Q’13
3Q’13
4Q’13
1Q’14
2Q’14
3Q’14
* Includes corp. costs
November 2014
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Page 32
SAFE AND EFFECTIVE EXECUTION Total reportable injuries frequency
Drilling cycle time (spud to release)
Per million exposure hours
Days Eagle Ford
50
4
Marcellus 40 3 30 2 20 1 10
0
0
2011
2012
2013
2011
2012
2013
SIMPLIFIED STRUCTURE AND LOWER COST G&A reduction $ million
Reduced management layer by
500
25%
490 480
20%
470 460 450 440 430
Reduced executive team by
420
45%
410 400 0 2012
November 2014
2013
2014E
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Page 33
STRONG & FLEXIBLE CAPITAL STRUCTURE Gross debt $ billion
Gross debt/CF
8
3.0
$3.2B bank facilities
• Targeting 1.5-2.0x debt:cash flow
2.5 2.0
• Capacity for small acquisitions within core regions
1.5
• Investment grade
6 $4.4B term debt
4
1.0
2 0.5 0.0
0 1H’12
2H’12
1H’13
Gross debt/cash flow
2H’13
Gross debt
1H’14
3Q’14
Targeted gross debt/cash flow
PORTFOLIO MANAGEMENT • Delivered against disposition targets
Dispositions 2011
Montney cash
2012
Coal Asset
2013
• Targeting ~$2 billion additional dispositions next 12-18 months
UK
WCSB
Montney
Ocensa
2014/15
Target
0
November 2014
– $6.6 billion dispositions (including carries) since 2011 – Exited 7 non-core positions
Montney carry
500
1,000
1,500
2,000
2,500
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Page 34
TALISMAN KEY HISTORICAL DATA Q3-2014
2013
2012
2011
Daily production, before royalties Oil & liquids (mbbsl/d) Natural gas (mmcf/d) Barrels of oil equivalent (mboe/d)
2010
135 1,310 353
132 1,451 373
162 1,582 426
178 1,491 426
189 1,367 417
211 1,283 425
224 1,247 432
241 1,265 452
Daily production, after royalties Oil & liquids (mbbsl/d) Natural gas (mmcf/d) Barrels of oil equivalent (mboe/d)
102 1,041 275
97 1,163 291
131 1,292 347
146 1,233 351
160 1,161 353
181 1,088 362
187 992 352
203 1,017 373
--- COGEH --Proved reserves, before royalties Oil & liquids (mmbbl) Natural gas (bcf) Barrels of oil equivalent (mmboe) Net undeveloped land (thousands of acres) North America International Total
2009
2008
2007
--- SEC ---
209 4,785 1,006
311 4,679 1,091
518 5,818 1,488
510 5,237 1,383
532 5,273 1,411
545 5,338 1,434
749 5,464 1,660
4,950 19,637 24,587
5,281 23,006 28,287
5,795 27,522 33,317
6,940 29,673 36,613
9,145 26,208 35,353
9,786 16,443 26,229
9,559 12,948 22,507
Note: Reserves and acreage data for 2011 and prior years reported in accordance with US Standards (SEC). Data for 2012-2013 reported in accordance with COGEH rules. Refer to Talisman's Annual Information Form and Annual Report for additional disclosures.
TALISMAN KEY HISTORICAL DATA --- CAD$ ---
--- US$ --2013
1
2012
507 425 0.49 0.41
2,196 (1,175)
3,022 132
3,434 776
2.13 (1.15)
2.95 0.12
755 102
2,885 111 736
23 17.03 16.59
1
Ratios and Key Indicators ($ millions, except per share) Cash flow Net Income (loss) Per Common Share Cash flow Net Income (loss) Exploration & development expenditure Acquisitions Dispositions Average Royalty Rate (%) Unit operating costs ($/boe) Unit DD&A ($/boe) Balance Sheet Info ($ millions)1 Property, plant & equipment2 Exploration and evaluation assets Total assets Long-term debt (including current portion) Shareholders' equity Share information, adjusted to reflect stock splits Average common shares outstanding (millions) TSX trading info Average daily trading volume (thousands) High (C$) Low (C$) Close (C$) NYSE trading info Average daily trading volume (thousands) High (US$) Low (US$) Close (US$) Commodity Information WTI (average US$/bbl) NYMEX gas (average US$/mmbtu) US$/C$ exchange rate (period end) Realized product pricing, before hedging activities Oil & liquids ($/bbl) Natural gas ($/mcf)
1
2
2
2009
2008
2,954 945
3,961 437
6,163 3,519
4,327 2,078
3.36 0.76
2.90 0.93
3.90 0.43
6.06 3.46
4.19 2.01
3,511 160 2,313
4,142 1,319 569
3,473 1,530 2,273
4,245 438 2,774
5,106 452 442
4,449 317 1,477
26 15.21 17.40
21 15.83 16.09
19 14.17 12.55
16 12.44 11.76
15 12.91 17.28
18 13.57 16.44
17 12.14 14.74
9,654 3,133 18,765 4,695 9,034
9,752 3,165 19,161 5,239 8,555
13,005 3,516 21,858 4,442 9,910
15,909 3,954 24,226 4,895 10,018
13,266 3,442 22,094 4,204 9,195
16,431 23,618 3,780 11,111
16,322 24,275 3,961 11,150
16,363 21,420 4,862 7,963
1,033
1,030
1,025
1,023
1,018
1,015
1,017
1,032
4,877 11.99 9.69 8.57
2,574 13.83 10.68 12.35
6,105 14.70 9.71 11.25
5,258 24.82 11.34 12.98
5,042 22.32 15.71 22.12
4,988 20.17 9.92 19.69
5,486 25.40 8.28 12.18
4,280 22.67 16.90 18.39
6,340 11.22 8.57 8.65
4,888 13.38 10.34 11.65
5,008 15.21 9.46 11.33
4,003 25.21 10.75 12.75
3,125 22.43 14.70 22.19
3,947 19.51 7.97 18.64
6,164 25.71 6.42 9.99
3,074 22.08 15.04 18.52
97.97 3.67 0.94
94.22 2.80 1.00
95.13 4.07 0.98
79.53 4.39 1.01
61.79 4.05 0.96
99.65 8.95 0.82
72.31 6.92 1.01
104.82 5.01
107.04 5.92
67.36 5.29
96.43 9.01
75.00 6.99
Q3-2014
97.49 5.69
2011
2010
78.19 5.59
2007
Please note: The financial information prior to January 1, 2010 was prepared in accordance with CGAAP, then applicable to publically accountable enterprises. These dollar amounts are in C$. The financial information after January 1, 2010 is presented in accordance with IFRS. Both IFRS and CGAAP may differ from US GAAP. These dollar amounts are in US$. 1
2
All figures include results from Talisman Sinopec Energy UK Ltd and Equion Energia Ltd, with the exception of Balance Sheet information; 2012 numbers have not been restated to reflect equity accounting Restated for operations classified as discontinued in 2010
ADVISORIES Forward-Looking Information This presentation contains information that constitutes “forward-looking information” or “forwardlooking statements” (collectively “forward-looking information”) within the meaning of applicable securities legislation. This forward-looking information includes, among others, statements regarding: business strategy, priorities and plans; expected production – company-wide, regionally and by product-type; expected cash flow and cash flow growth by product-type, region and asset; expected free cash flow by region and asset; projected gas and LNG supply and demand and associated consequences in Southeast Asia; expected LNG project unit costs and break-even costs; expected spending by type, region and asset; expected capacity increase at Jambi Merang; expected exploration and development steps and timeline at Sakakemang, Kinabalu, Sabah, Red Emperor, Akacias and CPE-6; planned drilling activity in Asia Pacific, Colombia, Kurdistan and North America; expected project sanction at Red Emperor; expected first oil at the Foreña plant; expected removal of the Yme MOPU; expected stages and completion of the MAR project; expected turnarounds at Bleoholm, Fulmar and Auk, expected timing and benefits of the Claymore Compression Upgrade; expected timing of the Eagle Ford becoming FCF positive; expected drilling costs, completion costs and drill cycle times in the North American assets; expected D&C costs and drilling cycle times in North America expected liquids recovery at the Pembina Saturn deep-cut facility; expected dispositions, timing and value of such dispositions; expected G&A reductions; and other expectations, beliefs, plans, goals, objectives, assumptions, information and statements about possible future events, conditions, results of operations or performance. The company priorities and goals disclosed in this presentation are objectives only and their achievement cannot be guaranteed. The factors or assumptions on which the forward-looking information is based include: assumptions inherent in current guidance; projected capital investment levels; the flexibility of capital spending plans and the associated sources of funding; the successful and timely implementation of capital projects; the continuation of tax, royalty and regulatory regimes; ability to obtain regulatory and partner approval; commodity price and cost assumptions; and other risks and uncertainties described in the filings made by the Company with securities regulatory authorities. The Company believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct. While Talisman reviews short-term market conditions, forward-looking information for longer term future periods assumes escalating commodity prices. Closing of any transactions will be subject to receipt of all necessary regulatory approvals and completion of definitive agreements. 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 the forward-looking information contained in this presentation. The material risk factors include, but are not limited to: the risks of the oil and gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas; risks and uncertainties involving geology of oil and gas deposits; risks associated with project management, project delays and/or cost overruns; uncertainty related to securing sufficient egress and access to markets; 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, including decommissioning liabilities; risks related to strategic and capital allocation decisions, including 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, interest rates and tax or royalty rates; the outcome and effects of any future acquisitions and dispositions; health, safety, security and environmental risks, including risks related to the possibility of major accidents; environmental regulatory and compliance risks, including with respect to greenhouse gases and hydraulic fracturing; uncertainties as to access to capital, including the availability and cost of credit and other financing, and changes in capital markets; risks in conducting foreign operations (for example,
civil, political and fiscal instability and corruption); risks related to the attraction, retention and development of personnel; changes in general economic and business conditions; the possibility that government policies, regulations or laws may change or governmental approvals may be delayed or withheld; and results of the Company's risk mitigation strategies, including insurance and any hedging activities. The foregoing list of risk factors is not exhaustive. Additional information on these and other factors which could affect the Company’s operations or financial results or strategy are included in Talisman’s most recent Annual Information Form. In addition, information is available in the Company’s other reports on file with Canadian securities regulatory authorities and the United States Securities and Exchange Commission. Forward-looking information is based on the estimates and opinions of the Company’s management at the time the information is presented. The Company assumes no obligation to update forward-looking information should circumstances or management’s estimates or opinions change, except as required by law. Unless the context indicates otherwise, references to ‘‘Talisman’’ or the ‘‘Company’’ include the direct or indirect subsidiaries of Talisman Energy Inc., partnership interests held by Talisman Energy Inc. and its subsidiaries and Talisman’s equity interests in Equion Energıa Limited (‘‘Equion’’) and Talisman Sinopec Energy UK Limited (‘‘TSEUK’’). Such use of ‘‘Talisman’’ or the ‘‘Company’’ to refer to these other legal entities, partnership interests and equity interests does not constitute a waiver by Talisman Energy Inc. or such entities or partnerships of their separate legal status, for any purpose. In this presentation, Talisman uses the term “unlocking value” to describe the realization of the value of an asset within Talisman’s portfolio that, prior to its full or partial disposition, was not valued at its full market value, as reflected in Talisman’s share price and enterprise value. By monetizing the asset through a disposition or joint-venture, the Company is able to attribute a market value to the asset that can quantifiably be reflected in Talisman’s share price and enterprise value.As used in the context of the Company’s Colombian assets, long-term testing indicates continuous well production going to market at the most recent weekly average. A permit for long term testing is required for a well to produce oil until the permit for full field development has been granted. Use of the word “commerciality” in this presentation does not imply that the full development of the field has been booked as reserves. The term “commerciality” is used in this presentation as it is used in the Block CPO-9 license and Block CPE-6 license (each a “License”). A declaration of commerciality is a written declaration by the licensees to the state regulator that declares the licensees’ unconditional decision to proceed with commercial exploration of a discovery. Upon filing a declaration of commerciality, a discovery becomes a commercial field under the terms of the License. Oil and Gas Information Reserves National Instrument 51-101 ("NI 51-101") of the Canadian Securities Administrators imposes oil and gas disclosure standards for Canadian public companies engaged in oil and gas activities. An exemption granted to Talisman also permits it to disclose internally evaluated reserves data. Any reserves data contained in this presentation reflect Talisman’s estimates of its reserves. While Talisman annually obtains an independent audit of a portion of its proved and probable reserves, no independent qualified reserves evaluator or auditor was involved in the preparation of the reserves data disclosed in this presentation. In this presentation, Talisman makes reference to proved and probable reserves in the Marcellus, Eagle Ford, Chauvin and Edson areas. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. The reserves life index (“RLI”) for proved plus probable reserves in Marcellus, Greater Edson, the Eagle Ford and Chauvin was calculated by dividing the year-end 2013 proved plus probable reserves by the 2014 production guidance for these assets. Net Present Value The 2013 2P reserves value of the Company’s Americas and Asia-Pacific regions reflects the after-tax net present value, discounted at 10%. The after-tax net present value of the Company’s 2P reserves in its core regions reflects the tax burden on the properties on a standalone basis. It does not consider the business entity level tax situation, or tax planning. It does not provide an estimate of the value of that level of the business entity, which may be significantly different.
Talisman’s financial statements and MD&A should be consulted for information at the level of the business entity. Production and Reserves Volumes Unless otherwise stated, production volumes, acreage and reserves estimates are stated on a Company interest basis prior to the deduction of royalties and similar payments. In the US, net production volumes and reserve estimates are reported after the deduction of these amounts. US readers may refer to the table headed “Continuity of Net Proved Reserves” in Talisman’s most recent Annual Information Form for a statement of Talisman’s net production volumes and reserves. The use of the word “gross” in this presentation means a 100% interest prior to the deduction of royalties and similar payments. Resources, In-place Estimates and EURs In this presentation, Talisman also discloses contingent resources, prospective resources, OOIP and EUR as at May 6, 2014 (effective December 31, 2013). Where not otherwise indicated, in this presentation, the contingent resources provided are 2C and the prospective resources are unrisked best estimates. 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. The contingencies that prevent the resources from being classified as reserves may be one or more of: lack of gas sales contract; additional testing; production and performance appraisal activities; development time frame too far in the future; demonstration of economic viability; facilities and egress; access to equipment and services; hydraulic fracturing technology; commodity prices and regulatory approvals. There is no certainty that it will be commercially viable to produce any portion of the resources. In addition to these contingencies and uncertainties the development of commerciality of resources is also subject to a number of risk factors, as discussed more fully above.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. Unrisked prospective resources are not risked for change of development or chance of discovery. 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. Estimated ultimate recovery (EUR) is a term commonly used in the oil and gas industry. EUR is an estimate, on a given date, of the quantity of oil and gas that is potentially recoverable, plus those quantities already produced. There is no certainty that it will be commercially viable to produce any portion of the EUR amount that is contained herein. OOIP is defined as oil originally in place and is that quantity of oil that is estimated to exist originally in naturally occurring accumulations. It is the total quantity of oil that is estimated, as of a given date, to be contained in known accumulations, prior to production. OOIP estimates may contain all resource classifications, both discovered and undiscovered. 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. Non-Core Assets In this presentation, all references to “core” and “non-core” assets and properties align with the company’s current public disclosure regarding its assets and properties.
BOE Conversion Throughout this presentation, barrels of oil equivalent (boe) are calculated at a conversion rate of six thousand cubic feet (mcf) of natural gas for one barrel of oil (bbl). This presentation also includes references to mcf equivalents (mcfes) which are calculated at a conversion rate of one barrel of oil to six thousand cubic feet of gas. Boes and Mcfes may be misleading, particularly if used in isolation. A boe conversion ratio of 6mcf:1bbl and an mcfe conversion ratio of 1bbl:6mcf are based on an energy equivalence conversion method primarily applicable at the burner tip and do not represent a value equivalency at the well head.In this presentation, unless otherwise stated, mcf refers to natural gas and bbls refers to oil, except with respect to properties and assets in North America, where bbls refers to oil plus condensate. Netbacks Talisman also discloses netbacks 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 National Instrument 51-101 which is relevant to the company for comparative purposes. The source of the information was various corporate presentations and public production data. The company cannot confirm that any of this analogous information was prepared by a qualified reserves evaluator or that it was prepared in accordance with the COGEH Handbook. US Dollars and IFRS Dollar amounts are presented in US dollars, except where otherwise indicated. Financial information is presented in accordance with International Financial Reporting Standards (IFRS). IFRS may differ from generally accepted accounting principles in the US. Forecasted Cash Flow and Forecasted Free Cash Flow This presentation also contains discussions of anticipated cash flow and anticipated free cash flow both on an aggregate and per share basis. The material assumptions used in determining estimates of cash flow are: the anticipated production volumes; estimates of realized sales prices, which are in turn driven by benchmark prices, quality differentials and the impact of exchange rates; estimated royalty rates; estimated operating expenses; estimated transportation expenses; estimated general and administrative expenses; estimated interest expense, including the level of capitalized interest; and the anticipated amount of cash income tax and petroleum revenue tax. Pricing assumptions are consistent with those disclosed in the Company’s most recent Annual Information Form. The amount of taxes and cash payments made upon surrender of existing stock options and vesting of RSUs is inherently difficult to predict. Anticipated production volumes are, in turn, based on the midpoint of the estimated production range and do not reflect the impact of any potential asset dispositions or acquisitions. The completion of any contemplated asset acquisitions or dispositions is contingent on various factors including favourable market conditions, the ability of the Company to negotiate acceptable terms of sale and receipt of any required approvals for such acquisitions or dispositions. In addition to the assumptions that underpin forecasted cash flow, forecasted free cash flow also includes assumptions around capital investments and financing activities. Non-GAAP Financial Measures Included in this presentation are references to financial measures used in the oil and gas industry such as free cash flow, cash flow, Internal Rate of Return (IRR) capital expenditure and net debt. These terms are not defined by IFRS. Consequently, these are referred to as nonGAAP measures. Talisman’s reported results of such measures may not be comparable to similarly titled measures reported by other companies. Free Cash Flow is used by management to assess the amount of funds available for reinvestment or to reduce debt levels or return to shareholders. Free cash flow is the net of cash provided by operating, investing and financing activities before the repayment or issuance of long-term debt. Cash flow, as commonly used in the oil and gas industry, represents net income before exploration costs, DD&A, deferred taxes
and other non-cash expenses, including Talisman's share of cash flow from equity-accounted entities. 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 IFRS as an indicator of the company's performance or liquidity. Cash flow per share is cash flow divided by the average number of common shares outstanding during the period. Diluted cash flow per share is cash flow divided by the diluted number of common shares outstanding, as reported in the consolidated financial statements. Internal Rate of Return (or "IRR) is a rate of return used by management for capital budgeting purposes to measure and compare the profitability of investments. It is the discount rate at which the present value of all future cash flow is equal to the initial investment. Capital spending (or “capex”) is calculated by adjusting the capital expenditure per the financial statements for exploration costs that were expensed as incurred and adding Talisman's share of joint ventures. Exploration capex is the combined total of exploration expenditures capitalized as part of the exploration and evaluations assets in the Consolidated Balance Sheet plus the exploration expenses on a before-tax basis from the Consolidated Statement of Income. Development capex is the costs incurred in the development and producing phase and recorded as part of property, plant and equipment in the consolidated financial statements.Net debt is calculated by adjusting the company's long-term debt per the consolidated financial statements for bank indebtedness, cash and cash equivalents from subsidiaries and joint ventures. The Company uses this information to assess its true debt position and eliminate the impact of timing differences..
INVESTOR RELATIONS CONTACTS: Paul Smith Executive Vice President, Finance and Chief Financial Officer (403) 237.1434
ANALYST & INVESTOR RELATIONS INQUIRIES: Lyle McLeod Vice President, Investor Relations (403) 237.1020
GENERAL & MEDIA INQUIRIES: Brent Anderson Manager, External Relations (403) 237.1912
TALISMAN ENERGY INC. Suite 2000, 888 - 3rd Street S.W. Calgary, AB T2P 5C5 Phone: (403) 237.1234 Fax: (403) 237.1902 Email:
[email protected] Website: www.talisman-energy.com