CORPORATE PRESENTATION

CORPORATE PRESENTATION November 2014 TALISMAN OVERVIEW TALISMAN – TWO CORE REGIONS OVERVIEW Americas Asia-Pacific Core: Asia-Pacific • Self-sustai...
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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

NYSE: TLM | TSX: TLM

www.talisman-energy.com

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

NYSE: TLM | TSX: TLM

www.talisman-energy.com

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

NYSE: TLM | TSX: TLM

www.talisman-energy.com

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

www.talisman-energy.com

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

NYSE: TLM | TSX: TLM

www.talisman-energy.com

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

NYSE: TLM | TSX: TLM

www.talisman-energy.com

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

NYSE: TLM | TSX: TLM

• 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

NYSE: TLM | TSX: TLM

www.talisman-energy.com

Page 27

November 2014

NYSE: TLM | TSX: TLM

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

NYSE: TLM | TSX: TLM

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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www.talisman-energy.com

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

NYSE: TLM | TSX: TLM

www.talisman-energy.com

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

NYSE: TLM | TSX: TLM

www.talisman-energy.com

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

NYSE: TLM | TSX: TLM

www.talisman-energy.com

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