2011 07 Corporate Presentation Web Handout

• Portfolio transition largely complete Outlook transformed

Exploration work in progress

• 5-10% growth into the future Sustainable due to shape of portfolio

Improving profitability as replacement costs reduce

Liquids options including GTL

• Exploration upside to come Key exploration drilling results to come over next 2 years

• Portfolio structured for positive free cash flow over time

• Focus on world class execution

Safe, profitable growth

North Americashale provides

long-term growth

Southeast Asiaself-funded built in

growth and exploration

Producing areas

Exploration areas

North Seastable production

generates free cash flow

Latin Americabuilding new core area –

acquisition, development, and exploration

European shale

Kurdistan

Talisman - three core production areas, plus high impact international exploration

July 2011 NYSE: TLM │TSX: TLM www.talisman-energy.com Page 1

Diversified portfolio – oil and gas mix

2P reserves

39%

11%

22%

28%

9%

45%

12%

34%

2010 production (417 mboe/d)

Liquids/gasGeography

2P reserves

39%

30%

27%

4%

28%

31%

36%

2010 production(417 mboe/d)

North America

Southeast Asia

North Sea

Other

Oil

Oil-linked gas

Shale gas

Gas

5%

Portfolio strategy

North America shale – Liquids and leading gas plays

Southeast Asia – ~8% growth from known projects, self-funded

Focus Areas – Southeast Asia and Latin America

Future Options – Kurdistan and Poland

BaseFree cash flow to invest

North America conventional – Flat for a decade at 80-90 mboe/d

North Sea – Flat production at 110-140 mboe/d until 2020

1

3 ExplorationRenewal of the firm

2 Growth5-10% sustainable growth


Outlook transformed –dispositions/acquisitions 2008-2011

12 mboe/dProduction

C$5.3 billionProceeds

75%Percentage gas

70 mboe/dProduction

North America

5Countries exited

International

Dispositions

360*Poland

300Norway

International

North America

400Kurdistan

9,000PNG

4,300Colombia

78Eagle Ford

210Montney

220Marcellus

Net acres(thousand)

Acquisitions and entries

*Acreage to be earned

0

2

4

6

8

2008-2010 dispositions – North America break-even

Gas price C$/mcf

Break-even range of

sold properties

Unconventional acquired properties

Retained conventional

Sold

Average


0

5

10

15

20

0

20,000

40,000

60,000

Accretive dispositions

ProductionC$/flowing boe

ReservesC$/boe

Disposals Talisman trading multiple

1P 2P

Reserve replacement costs$/boe

Increasing profitability and reserves growth

0

10

20

30

40

50

2009 2010

PDP

Total

Reserve replacement ratioPercentage (%)

2011-2015 target

0

50

100

150

200

2009 2010 2011-2015 target


Profitability – improving opex and recycle ratio

Unit operating costs C$/boe

12

13

14

201020092008

2.5x

2.0x

1.5x

1.0x

0.5x

0.0x2010

2.2x

2008

0.7x

1 year recycle ratio (normalized) Netback/replacement cost

Competitive position

ProductionPercentage (%)

Talisman

100

75

50

25

0 0

25

50

75

100

Talisman

Proved developed reservesPercentage (%)

Peeraverage

Peeraverage

18

27

36

Talisman

Netback C$/boe

PUD percentagePercentage (%)

30

45

60

75

Talisman

Peer average

Peeraverage

Oil & liquids

Oil-linked gas Oil-linked gas

Oil & liquids


0

50

100

150

200

250

300

0

10

20

30

40

50

60

87654321

Shale free cash flow turning point

Reinvestment ratio and decline curvePercentage (%)

Decline curve

Reinvestment ratio to maintain production

Years

Reinvestment ratio Decline curve

Free cash flow positive

5

4

3

2

1

0

Actual cash flow

Cash flow and capital

20122009 2010 2011

Analyst cash flow estimate

Capital

Cash flow and capital$ billion

Analyst mean cash flow estimate$3.8B $4.6B


Capital expenditure

Cash capital spend$ billion

3

2

1

02012

5

4

20112010

North America shale

North America conventional

North Sea

Southeast Asia

Exploration

Other (incl. Latin America)

Colombia

HST/HSD

Eagle Ford

Montney carry

Conventional liquids

Sustainable growth

5-10%

North Sea

North America conventional

North America shale

Southeast Asia

Latin America

Rest of world

20152014201320122011

Productionmboe/d


North America – leading shale portfolio

TLM land

Area of operation

Montney JV

Average working interest 50%

Development/pilot

Montney JV


Development/pilot

Eagle Ford

Average working interest ~40%

Development

Eagle Ford


Development

Marcellus


Development

Marcellus


Development

Quebec Utica


Pilot

Quebec Utica


Pilot

5.5

5.0

4.5

4.0

3.5

3.0

2.5

Industry full cycle break-even$/mcfe

Eag

le Fo

rd

Marcellu

s (dry g

as)

Mo

ntn

ey

Barn

ett

Fa

yetteville

Ho

rn R

iver

Ha

ynesville

Bo

ssier

Wo

od

ford

Source: Wood Mackenzie

North America – portfolio profile

0

25

50

75

100

201520112008

Liquids productionmboe/d

Discontinued operations Opportunity

Committed projects

0

25

50

75

100

0.0

2.5

5.0

7.5

10.0

201520112008

Shale production

Conventional production

Unit operating costs

Production and unit operating costsPercentage (%) $/boe


Shale running room

2010 contingent resourcetcfe

Note: 2010 excludes Quebec. Adjusted for Sasol JVs

(7)Produced/2P/sold/expiries

6Purchases/farm-ins/improved performance

46Closing

(10)Sasol JV

57Opening

Total: 46

Marcellus (NY)

Marcellus (PA)

Montney Farrell Creek/Cypress A JVs

Other Montney

Eagle Ford Montney Heritage

13

10

3 6

4

10

0 2,500

Eagle Ford

Other Montney

Montney FarrellCreek/Cypress A

JVs

Marcellus (PA)

Other Montney(Groundbirch)

Wells drilled to date Net drilling locations remaining

Net well locations

0

1

2

3

4

5

MontneyFarrell Creek

excluding carry

Eagle FordMarcellus

Talisman shale break-even

2011 remaining life of field break-even$/mmbtu

0

1

2

3

4

5

MontneyFarrell Creek

including carry

Eagle FordMarcellus

2015 remaining life of field break-even$/mmbtu

Note: Liquids value based on WTI $73

Range Range


Marcellus Shale – Pennsylvania

• ~$800 million capital program – 2011

• Average 2010 production 181 mmcf/d

• Expect average 2011 production 350-400 mmcf/d range

• Secured over 600 mmcf/d egress

• Full cycle break-even <$4.00/mmbtu

40-130OGIP/section (bcf)

Key metrics

Net acres 223,000

Net well locations 1,850

Contingent resources (tcf) 6Pittsburgh

West Virginia

PennsylvaniaPennsylvania

TLM land

TLM focus area

Basin

Major pipelines

Marcellus Shale

Pennsylvania horizontal well type curvemmcf/d

6 bcf5 bcf4 bcf

0

1

2

3

4

5

6

7

0 100 200 300 400 500 600

Top 5 wells (first 400 days)

250 day average (57 wells)

350 day average (28 wells)

\

Key metrics 2009 20102011

assump-tions

Net new wells on-stream 22 99 ~100

Average production (mmcf/d)

29 181 350-400

Horizontal well metrics (TLM operated)

EUR per well (bcf) 3.0-7.5 ~5 ~5

30 day IP per well (mmcf/d) 2.1-5.5 ~5 ~4

6 bcf5 bcf4 bcf

• Continuing strong well performance

• Bias toward drilling longer wells


Shale learning curve – Marcellus example

1.2

0.8

0.4

0.0

-56%

20102008

Drill and construct

Complete

0

1

2

3

4

5

+67%

20102008

Marcellus EUR per wellbcfe

Marcellus total D&C capex per frac stage$ million/350 feet lateral

• Acreage in liquids rich window, largely evaluated, >50% held by production

• Ramp from 4 to 10 rigs 2011, manageable land expiries

• Full cycle break-even <$4.00/mmbtu

Eagle Ford Shale – JV

750Net well locations

Net acres 78,000

Contingent resource550 mmboe

(~50% liquids)

55-65Average production (mmcfe/d)

Horizontal well metrics (TLM operated)

Key metrics2011

assumptions

Net new wells on-stream ~25

EUR per well (mboe) 660

30 day IP per well (boe/d) 1,200

Mexico

Texas

Oil

Liquids

rich

Dry gas

Corpus Christi

San Antonio

Prospective fairway

JV landSM Energy acquisition landMajor pipelineSales pipeline


Montney Shale – proven and expanding play

• 2011 capital program ~$100 million

• Farrell Creek commercial development Accelerated value through strategic

partnership

• Long-life resource with multiple gas monetization options, including liquids

• Targeting full cycle break-even <$4/mmbtu

33Contingent resources (tcfe)

~450Average OGIP/section (bcf)

Key metrics

Net acres 211,000

Net well locations ~4,300

GreaterCypressGreaterCypress

FarrellCreek

FarrellCreek

Greater Groundbirch

Greater Groundbirch

BritishColumbia

Alberta

Fort St. John

GrandePrairie

TLM landBasinMajor pipelines

Talisman Sasol Montney Partnership

• Farrell Creek and Cypress A to be an integrated development area

• Sasol’s Cypress A funding commitment may be applied to Farrell Creek development

• Cypress A transaction closed June 2011

109,000

20.6

1,580

520

2,100

Total

57,00052,000Acreage (net acres)

20152011Start-up

11.29.4Contingent resource (tcfe)

Joint VentureFarrell Creek

CypressA

Transaction value (C$ million)

1,050 1,050

Cash (C$ million) 260 260

Funding commitment (C$ million)

790 790

Alberta

BritishColumbia

Talisman Sasol Montney

partnership

Talisman Sasol Montney

partnership

TLM landPartnership landBasinMajor pipeline


• 2011 capital program ~$800 million (gross)/~$100 million (net)

• Ramp from 4 rigs in 2010 to 10 in 2011

• Targeting full cycle break-even <$4.00/mmbtu

• Secured ~500 mmcf/d egress on Spectra system

Montney Shale – Farrell Creek & Cypress A Sasol JV

10.3Contingent resource (tcfe)

Net acres 55,000

Net well locations 1,700

Farrell Creek horizontal type curve

mmcfe/d

0

2

4

6

8

10

0 100 200 300

200 days average (5 wells)

5 Bcf7 Bcf9 Bcf

50-6026Average production (mmcf/d)

Farrell Creek horizontal well metrics (TLM operated)

Key metrics 20102011

assumptions

Net new wells on-stream 20 ~25

EUR per well (bcf) ~6 ~7

30 day IP per well (mmcf/d) ~6 ~6

2

4

6

8

50 60 70 80 90 100 110

Options for North American gas development

Pipeline favoured

GTL & LNG favoured

Nymex ($/mmbtu)

WTI ($/bbl)


Quebec Utica Shale

756,000Net acres

Key metrics

30 day IP (mmcfe/d)Horizontal wells

Vertical wells Test rate (mmcfe/d)

Average of vertical wells >0.6

St. Edouard 5.3

Wells 2-3 Under evaluation

CanadaUSA

Montreal

Trois-Rivières

Quebec

Storage FacilitySt. Edouard

Leclercville

Fortierville

Gentily

St. Gertrude

TLM landHorizontal wellVertical wellBasinMajor pipelineSales pipeline

• Quebec government announced an environmental review

• Lease expiry tenure of 12-15 years allows sufficient time to adapt to the regulatory environment

Conventional portfolio overview

AlbertaBritish Columbia

USA

ChauvinChauvin

ShaunavonShaunavon

MonkmanMonkman

OjayOjay

CardiumCardium

Wild RiverWild River

SundanceSundance

Edson HeritageEdson Heritage

TLM land

Conventional gas

Tight gas

Liquids rich gas

Oil

2,530957,000Total

30

1,000

150

400

950

Net well locations

326,000

90,000

87,000

260,000

194,000

Net acres

GasMonkman

Tight gas/

liquids rich gas

Wild River

Tight gasOjay (Nikanassin)

OilChauvin/Shaunavon

Oil/

liquids rich gas

Cardium oil and gas/Sundance

ProductArea


Conventional portfolio production

0

20

40

2012-2014 average

20112008-2010 average

Liquids

ProductionLiquids percentage (%)

Liquids opportunity

0

4

8

12

Conventional operating efficiencyPercentage (%) C$/boe

Operating efficiency

Talismanlifting costs

Benchmarklifting costs (Ziff)

*Ziff Energy Group data unavailable

0

25

50

75

100

2008 2009 2010*

Cardium – Sundance Medlodge

~400-700

~350-750

13

Sundance Medlodge

Average industry well metrics*

2011 assumptions

Key metrics Cardium Oil

Cardium Wet Gas

Net new wells on-stream

9 3

EUR per well (mboe) N/A ~500

30 day IP per well (boe/d)

~120 ~330

37090490Net well locations

35,00045,000114,000Net acres

Sundance Medlodge

Cardium Wet Gas

Cardium

Oil

• Evaluating resource potential

• Strong Talisman infrastructure position

• Light sweet crude and liquids rich gas

TLM land

Competitor land

Oil

Liquids rich gas

Gas

*Company reports, Accumap


Wild River

1,000

90,000Net acres

Net well locations

Wild River liquids yield

bbl/mmcf

0

25

50

75

Deep Cut PlantCurrent

38038028030 day IP per well(mboe/d)

450450250EUR per well (mboe)

Well metrics (TLM operated)

864Net new wells on-stream

2011 assump-

tions20102009Key MetricsTLM land

Wild River area

Gas pipeline

Deep cut plant

Southeast Asia – near-term growth projects

Australia

Indonesia

Malaysia

Vietnam

Papua New Guinea

Timor Leste

0 500 1,000 1,500Km

Jambi MerangJambi Merang

PM-3 CAA IORPM-3 CAA IORHST/HSDHST/HSD

OKOK

CorridorCorridor

KitanKitan

StanleyStanley


020152014201320122011201020092008

200

100

Near-term projects underpin production growth

729 593 559CAPEX

($ million)

731 644 769Cash flow

($ million)

Southeast Asia production mboe/d

Base

Development

~8%

Key development projects

• Corridor additional gas sales

• Jambi Merang

• PM-3 CAA IOR

• PM-3 CAA infill drilling

• HST/HSD

• Kitan

Indonesia South Sumatra core area

• Strategic core area

• 2P reserves of 369 mmboe

• Infrastructure in place

• Gas price underpinned by demand

• Demonstrated execution

Gas to Java

Gas toSingaporeGas to

Duri

SouthSumatra

TLM blockGas pipeline

OK BlockInfill wells

OK BlockInfill wells

CorridorInfill drilling

Dayung facilities upgradeSumpal expansion

LTROSuban Phases 2 & 3

CorridorInfill drilling

Dayung facilities upgradeSumpal expansion

LTROSuban Phases 2 & 3

Jambi Merang5 development wells

Facilities

Jambi Merang5 development wells

Facilities

Indonesia gas price trend$/mcf

0

2

4

6

20092008 201020062005 2007

Average domestic gas purchase


1Q 2011 price realization and netbacks$/mcf

Corridor – a major cash generator for Southeast Asia

• Largest gas producing property in Talisman’s portfolio

1 bcf/d (gross) sales gas

4.3 tcfe (gross) committed to gas contracts

1.2 tcfe (gross) waiting to be monetized

Further upside

Majority of production linked to oil price

• Technical unitization agreed in 2010 Allow further development opportunities

Potential for additional gas contracts

• 3 wells currently producing over 600 mmcf/d (gross)

• Latest new well capable of 160 mmcf/d (gross)

TLM Southeast Asia netback

$5.55

Opex/transportation

RoyaltiesRealized price

$9.41 $3.09

$0.76

Jambi Merang – a high quality acquisition

• Strategically located next to key infrastructure

• 2P reserves of 28 mmboe at cost of $8.15/boe

• Fast track development

• Leveraging premium domestic market

• Potential for significant upside

Production mboe/d

0

4

8

12

20152014201320122011

South Sumatra

Gas to Singapore and Duri

Gas to Java

Jambi MerangJambi Merang

TLM block

TLM non-focus block

Past well

Prospect/lead

Gas pipeline

Oil field

Gas field


0

10

20

30

40

50

20092008 201520112010

PM-3 CAA – stable production base with near-term growth

• Stable and reliable production base

• Substantial cash flow

• Further organic growth through incremental oil recovery projects

Base

Development

TLM block

Prospect/lead

Oil pipeline

Gas pipeline

Oil field

Gas field

Vietnam

Malaysia

PM-3 CAAPM-3 CAA

Song Doc

Production mboe/d

Vietnam Block 15-2 HST/HSD development

10,000 – 15,000Peak production (boe/d)

>30% at $75/bblIRR

Current plan

2013First oil

Sanction 2011 year-end

2P reserves (mmboe) 24

Hai Su Trang (HST)• Underpins development in

Block 15-2

• Clastic reservoir

• Initial development with 3 producers and 1 injector

Hai Su Den (HSD)• Re-sized with significant

capital reduction

• Fractured basement reservoir

• Initial development on Block B with completion of 2 existing wells

HSDHSD

HSTHST

TGTTGT

Gas to Bach Ho Field

FPSOFPSO

TLM blockMultiphase productionGas liftWater injectionGas exportOil field

Vietnam

15-2/01


PNG

Nam Con Son BasinNam Con Son Basin

Makassar StraitsMakassar Straits Papua New GuineaPapua New Guinea

SabahSabah

Australia

Indonesia

Malaysia

Vietnam

North Sumatra

JPDA

Arun LNG

East Indonesia

BontangLNG

Tangguh LNG

PNG LNG

0 500 1,000 1,500Km

TLM block

Major exploration option

Other exploration option

LNG facility

Long-term growth from high quality exploration portfolio

120

100

80

60

40

20

0

Expanding exploration footprint in the region

• Four-fold increase in footprint

• Substantial exploration position provides potential long-term growth Vietnam – Nam Con Son Basin Indonesia – Makassar Straits PNG – Foreland Basin

• Continued access to acreage via regular licensing rounds

• Talisman is the leading IOC with largest acreage position in Southeast Asia

Total land holdingsmillion acres (net)

0

10

20

201020092008

Indonesia

Vietnam

Malaysia

PNG

IOCs

NOCs

Talisman

Peer land holdings comparison – Southeast Asia*million acres (gross)

Source: Wood Mackenzie

*Includes China


Vietnam

Nam Con Son Basin

Cuu Lon Basin

Hai Su Trang

Hai Su Den

Lan Tray

15-2/01

Lan Do

Red Emperor

133/134133/134

135/136135/136

5.2/105.2/10

Ngoc ThachNgoc Thach

TLM block

Pending

Well

Discovery

Lead

Seismic

Oil field

Gas field

Vietnam – Nam Con Son

• Operated position established in underexplored eastern Nam Con Son Basin

• Planned seismic program in 2011 in preparation for 2012 drilling

Title from Walker for seismicNgoc ThachProspect

Ngoc ThachProspect

Target zone

Ngoc Thach

NT-4-1X Well path

NT-4-1X Well path

0 1 2Km

NW SE

South Makassar – large upside potential

• Major deep water gas potential

• Drilling Lempuk-1 exploration well in Sageri PSC in 2011

Lempuk-1 prospect

Lempuk-1Lempuk-1

South Makassar Basin

South Sageri

Sageri

South MandarSadang

Ruby FieldSultan(2009)

Massalima

2011 3D seismic

TLM block

TLM JSA block

Well

Discovery

Prospect

3D seismic

Gas field


PNG – well positioned for significant resource capture

• Estimated 15-20 tcf (gross) unrisked prospective resource

• Access to 14 licenses covering >9 million net acres

• Aggregate 2-4 tcf (gross)

• Positioned to lead PNG foreland gas aggregation

• 3 main aggregation hubs

• Stanley success validates gas aggregation strategy

TLM block

Discovery

Well

Lead

Gas discovery

Stanley-2Stanley-2

Ubuntu-1Ubuntu-1

AiemaAiema

WeimangWeimang

AwapaAwapa

Stanley-4Stanley-4Elevala-2Elevala-2

Siphon-1Siphon-1

PNG – early success at Stanley

• Early condensate recovery scheme in Stanley

Early monetization

Sanction end of 2011

450 bcf gas and 10 mmbbls condensate contingent resources

• Drill 8-10 wells in 2011

• Strategic partnering

Strong interest

Value proposition increasing with each success

Access to monetization expertise

5

4

3

2

1

0Opportunities (contingent resources)

Further risked (prospective resources)

2011 drilling program

(prospective resources)

1Q 2011 discoveries

Stanley/Ubuntu (contingent resources)

Discoveries (contingent resources)

2011 risked drilling program

Stanley/Ubuntu

TLM

3rd party

Talisman blocks3rd party blocks

Resource additionstcf


Sabah exploration – potential to grow in Malaysia

• Multiple plays – shallow oil potential and deep HPHT gas/condensate potential

• Acquiring 2,600 km2 3D seismic in 2010-2011

• Drilling 2 wells in 2012

Oil target

Depositional model – deep and shallow potential

Miocene to Pliocene sedimentary sequence of offshore West Sabah, Malaysia

HPHT gascondensate target

Malaysia

SB 309SB 309

SB 310SB 310

TLM block

Lead

Proposed seismic

Oil field

Gas field

Malaysia

PNG

Vietnam

Indonesia

Southeast Asia – 2010-2012 exploration activity

Seismic Drilling

South Makassar

Bravo Romeo Lempuk SO-A

Nam Con Son

Blk 5.2 -Tach Anh 4

Blk 5.2 -Ngoc Thach

Foreland Foreland

Stanley-2

Ubuntu-1

Sabah

309 310

Siphon-1 Elevala-2

PNG 6 well program

Weimang-1

Stanley-4

Awapa-1 Aiema-1

Multi-well program

2010 20122011


0

50

100

150

200

110

2020

140

2005 2012201120102009200820072006

North Sea – 110-140 mboe/d through 2020

Productionmboe/d

Yme Auk South

Godwin

Dispositions

Continuing operations

Grevling

Beta

Grosbeak

Flyndre/Cawdor

redevelopment

MonArb Fulmarhub

North Sea operating efficiency

Claymore production Operating efficiencymboe/d Percentage (%)

0

5

10

15

20

25

0

25

50

75

100

1Q2011

20102009

Production

Operating efficiency

0

25

50

75

100

2010

69%

2009

68%

2008

66%

Operating efficiencyPercentage (%)

Medium-term target 80-90%


UK – cash flow and returns

-1.0

-0.5

0.0

0.5

1.0

1.5

2011-2014average

2008-2010average

Exploration

DevelopmentActual

Forecast performance($85/bbl)

Capital expenditure

Cash flow$ billion

0

15

30

2008-2010average

2011-2014average

Return on average capital employed*Percentage (%)

*Excludes extraordinary future tax liability charges


Actual

Production – sustained by a conveyor belt of projects

United Kingdom

Aberdeen

Flotta

UK

Norw

ay

Flotta hubBurghley

Flotta hubBurghley

MonArb hubCayley,

Godwin, Shaw

MonArb hubCayley,

Godwin, Shaw

Fulmar hubAuk North, Auk South,

Flyndre/Cawdor

Fulmar hubAuk North, Auk South,

Flyndre/Cawdor

First oil November 2010 Auk North

First oil October 2010 Burghley

Delivered in 2010

2013First oil

362P reserves (mmboe)

Auk South redevelopment

2014-2016First oil

41-88 (2P undeveloped-3P)

Reserve range(mmboe)

MonArb area redevelopment

2012Project sanction

6-8 (2P undeveloped-3P)

Reserve range(mmboe)

Flyndre/Cawdor


MonArb hub – production growth through tie-backs

Base enhancement• Montrose 7 infill wells

• Maximized recovery

• Field life extended

Development• Godwin 2012

• Cayley 2015

• Shaw 2015

Exploration• Vigne

• Seagull and North Seagull

ShawShaw

CayleyCayley

GodwinGodwinArbroathArbroath

MontroseMontrose

VigneVigne

SeagullSeagull

North SeagullNorth Seagull

AberdeenAberdeenAberdeen

2011-2013 exploration well

Discovery

Prospect

Oil field

Fulmar hub – opportunity rich

Base enhancement• Clyde 4 infill wells



Development• Auk North on-stream 2010

• Auk South redevelopment 2013

• Flyndre/Cawdor 2014

Exploration• Appleton

• Area prospectivity

No

rway

AukNorthAuk

NorthClydeClyde

Flyndre/Cawdor

Flyndre/Cawdor

2011-2013 exploration well

Discovery

Prospect

Oil field

AppletonAppleton

AberdeenAberdeenAberdeen

Auk SouthAuk South


Norway – cash flow and returns

1.0

0.5

0.0

-0.5

-1.02011-2014

average2008-2010

average

Capital expenditure

Exploration

Development


Actual

Cash flow and capital$ billion

0

5

10

2011-2014average

2008-2010average

Return on average capital employedPercentage (%)

Actual


Varg hub – efficient development maximizes value

FPSO

NorwayUK

GrevlingGrevling

WildcatWildcat

RevRev

IsbjørnIsbjørn

VargVarg

Future infill locationProspectOil fieldGas field

Base enhancement• 4-8 infill wells

• Field extension with 1 well

• Gas production via Rev



Development• Grevling tie-back

• Discovery of 37-50-122 mmboe (gross contingent resources)

• Oil tested from 3 formations

Exploration• Isbjørn

• Wildcat


Yme – first oil by end of fourth-quarter

Project near completion• Subsea equipment installed• Drilling complete• Topsides ready for installation• First oil 4Q 2011• 2P reserves – 44 mmboe

Topsides in Stavanger ready for installation

0

20

40

Production from startupQuarterly mboe/d

Acquisitions – build new strategic core areas

• Strategy is to sustain production at 30-50 mboe/d

• 2 deals in 2010 sustain production

• Builds 2 new core areas

• Exploration portfolio renewal in a resource rich area

• Beta appraisal well tested 10 mboe/d 0

60

120

Resources (mmboe)

Riskedprospectiveexploration

Discoveries(2C)

Stavanger

Norway

Beta

Appraisalwell (2010)Outsider

Explorationwell (2011/2012)

Grosbeak

Appraisalwell (2011)

TLM blockWellDiscoveryProspect/lead

Discoveryupside(C3)


International Exploration portfolio – focused by region

Latin AmericaGrow new oil

production business

Latin AmericaGrow new oil

production business

North SeaSustain production

North SeaSustain production

Southeast AsiaSustain long-term growth

through exploration

Southeast AsiaSustain long-term growth

through exploration

KurdistanKurdistan

European shaleEuropean shale

Core regions

Future options

International Exploration – portfolio transition

• Focus• Deepen• Exit non-core• Access

international shale

Early success

• Colombia

• PNG – gas

2012 explorationtests• Vietnam – Nam

Con Son

• Malaysia – Sabah

• Peru – Marañon2011 explorationtests• Kurdistan

• Indonesia – South Makassar

• Poland shale

Screening for portfolio renewal

• International unconventional

• Deep water oil

Renew

(2011 )

Build

(2009-2010)

Test

(2010-2013)


25 20 15 10 5

250 200 150 100 50

252015105

25020015010050

Focused exploration portfolio

Trinidad

Netherlands

Tunisia

Denmark

Qatar

Poland

Alaska

Kurdistan

North Sea

Latin America

Southeast Asia

2007 2011

Exited

Future options

Land position (millions of net acres)

Average prospect size (mmboe)

Diverse exploration portfolio with material potential

• Liquids represent nearly 50% of Talisman prospective resources

Prospective resources, 2010 year-endBillion boe (unrisked)

Southeast Asia5 bboe

Future options 2 bboe

Latin America 2 bboe

Liquids and gas splitHydrocarbon phase

North Sea

1 bboe

Liquids Gas

• Total unrisked prospective resources of portfolio over 10 billion boe

North Sea

Southeast Asia Latin America

Future options


2,0142,0132011 2012

2012

2011-2012 high impact exploration drilling

Future options

Southeast Asia

Latin America

North Sea

Poland – SzczawnoKurdistan – K9

Indonesia – South Sageri

2011

Kurdistan – Topkhana, Kurdamir-2

Poland – Gdansk W., Braniewo S.

Vietnam – 5.2 Tach Ahn, 5.2 Ngoc Thach

Malaysia – Sabah – 2 wells

PNG – multi-well program

PNG – 6 wells

Indonesia – Lempuk

Colombia – Offshore – Mapalé-1, Mapalé-2

Colombia – Heavy oil – up to 12 wells

Peru – Situche Norte

Colombia – Hurón 2 and 3 appraisal wells

Colombia – Heavy oil – up to 12 wells

UK – Seagull North, Seagull appraisal

Norway – Skalle, Grosbeak, Peking Duck, OutsiderNorway – Isbjørn, Beta NE, Frode, Veslemøy

Latin America

• Large acreage position in 20 blocks

• Oil prone Llanos and Putumayo basins

• Huron discovery in Foothills in 2009

• Akacias discovery in Heavy Oil trend in 2010

• Minimum of 10 exploration/appraisal wells planned for 2011

Colombia

• Large acreage position in seven blocks

• Oil prone Marañon basin

• Under-explored petroleum basin

• Successfully appraised the Situche Central discovery in 2009

• Exploration seismic and drilling activities in 2011-2012

Peru

PutumayoBasin

Colombia

Rubiales

LlanosBasin

Situche

MarañonBasin

Peru

Chiriguaro

Hurón

Heavy oil

Heavy oil

TLM block

Oil/gas discovery

Discovery

Basin


Emerging exploration success – Colombia

153Offshore Caribbean

4,681Llanos/Putumayo heavy oil

548Llanos Foothills/Foreland

Net acres (thousand)

Basin

1. Llanos Foothills light oil/gas condensate

2. Llanos Basin/Putumayo heavy oil

3. Offshore Caribbean gas

Talisman now positioned in 3 plays

Venezuela

BrazilEcuador

Colombia

Atlantic Ocean

PacificOcean

Llanos

Putumayo

Guajira

Mag

dal

ena

CatatumboSinoSan Jacinto

FoothillsFoothills

Heavy oilHeavy oil

TLM block

MagdalenaFan

MagdalenaFan

Llanos and Putumayo Basins – heavy oil trend showing great potential

Ecuador

Tumaco

CAG 5

PUT 9

CAG 6 PutumayoBasin

Colombia

CPE 8CPO 12

CPO 9

Rubiales Field

LlanosBasin

CPE 6

Putumayo Basin3 licenses awarded

2010

Putumayo Basin3 licenses awarded

2010

TLM block

Export terminal

Oil pipeline

Gas pipeline

Akacias-12010

Akacias-12010

2010-2011seismic

acquisition

2010-2011seismic

acquisition

Guairuro strat wells2010-2011

Guairuro strat wells2010-2011


2010 acquisition of BP Colombia (Ecopetrol 51%, TLM 49%)

• Company renamed Equión Energia in January 2011 at closing

• 4 producing fields in Llanos Foothills

• 12-15 mboe/d (65% liquids) from February 2011 net to Talisman

• Interest in strategic infrastructure and export oil pipeline (OCENSA/ODC)

• 2 operated offshore Caribbean exploration licenses

CaribbeanSea

RC-4

RC-5

TLM block

Equión block

Discovery

Prospect

Oil pipeline

Gas pipeline

Oil field

Gas condensate field

FloreñaFloreña

Hurón

CupiaguaNorte

CupiaguaNorte

PautoSur

PautoSur

CusianaCusiana

2010 heavy oil discovery – Akacias CPO 9

• Significant discovery at Akacias, downdip of Chichimene Field

• Discovery tested at 1,250 b/d heavy oil

• 2011-2012 program 3D seismic Humadea exploration well 4 Akacias appraisal wells

Akacias-1

Humadea

View from North

ChichimeneField

ChichimeneField

Akacias-1Akacias-1

Castilla

Chichimene

Humadea-1Humadea-1

TLM block

Ecopetrol block

Exploration & appraisal well

Oil discovery

Prospect/lead

3D seismic

Oil field

Fault


Heavy oil discoveries in Colombia – CPE 6

• 2010 5 stratigraphic wells

Encountered oil in 4 of 5 stratigraphic wells with net pay of up to 30 feet

• 2011 program

Complete 6th stratigraphic well

Convert to exploration and production licence

Acquire 330 km2 3D seismic

Initiate further program of stratigraphic wells

GuairuroGuairuro

CPO 12

RubialesField

CPE 6

ODLODL

Quifa

Heavy oil trend

Area of pay

TLM block

Stratigraphic well

3D proposed seismic

Oil pipeline

Oil field

Colombia – pipeline capacity expanding with new supply

South/Central Llanos export capacityHeavy oil trend to Monterrey capacity

460 mboe/d330 mboe/d

1,100 mboe/d 730 mboe/d

2010 2013E

Apiay-Porvenir390 mboe/d

ODL340 mboe/d

OBC450 mboe/d

OCENSA/ODC660 mboe/d

2013E pipeline capacity

ODL170 mboe/dApiay-Porvenir

160 mboe/d

OCENSA/ODC 460 mboe/d

2010 pipeline capacity

COVEÑAS

MONTERREY

Caño Limón -Coveñas

COVEÑAS

MONTERREY


• Successfully appraised in 2009 and tested in 2010

• Demonstrated 1,100 ft oil column

• Appraisal well tested 5,200 bbls/d

• Light oil 37˚ API

• 80 km from Norperuano pipeline

Situche Central

• Situche Norte and Sureste structures identified

• Further upside in deeper reservoirs

• Exploration well in Situche Norte planned late 2011

Situche Complex

Peru - Situche Complex, Block 64

SitucheSureste

SitucheNorte

SitucheCentral

Planned

Planned TLM block

2011-2012 well

Discovery

Prospect/lead

3D seismic

2010 2011 2012

Offshore

CPE 8

Northern

CPE 6

CPO 9

Heavy oil

Niscota

Putumayo

CPO 12

Peru

Piedemonte

Foothills

Colombia

Base project expansion

Mapalé-1

Hurón-2 appraisal

Akacias discovery

Akacias 4 appraisals

Humadea expl.

Stratigraphic Stratigraphic

Stratigraphic

Stratigraphic

Situche Norte

Blocks 123/129

Situche Norte

Seismic acquisition Drilling program

Latin America exploration and development 2010-2012

Mapalé-2

Hurón-3 appraisal

Situche Sureste

Blocks 123/129


Future options – Kurdistan

• Significant discovery in 2009

• Proven gas condensate accumulation with indications of underlying oil leg

• Major oil and gas condensate potential

• Drilling Topkhana, Kurdamir-2 and K9 in 2011-2012Kurdamir

K44

KurdistanKurdistan

IranIran

Kirkuk

Taqtaq

Jambor

K39Topkhana

K9Baranan

IraqIraq

TLM block

Well

Gas condensate discovery

Prospect

Oil field

Gas field

Poland

2,300

Montney

1,400

Marcellus

250

Future options – Poland shale

• Seismic program currently underway

• 3 well program to commence in 3Q 2011

• Leveraging North American unconventional shale expertise

Shale thickness comparisonFeet

Empire StateBuilding

TLM block

Well

Shale fairway

Poland

Gdansk W.Gdansk W.

Braniewo S.Braniewo S.

SzczawnoSzczawno

CN Tower

1,250

1,815


Appendix

Balance sheet – strengthened through transition period

2.6

4.4

0

2

4

6

8

10

12

14

16

January 1, 2008

December 31, 2010

Dividends and other

Operating cash flow

Capital expenditure*

DisposalsLand and acquisitions

Net debtC$ billion

Strategic exploration

Eagle Ford

Colombia

Marcellus & Montney

*Excludes strategic land acquisitions


5.0

2.5

0.01Q 2011200920082007

Balance sheet

Significant liquidity – December 31, 2010$ billion

0Talisman

10

8

6

4

2

Peer companies

Average = $3.6 billion

Corporate debt$ billion

Net debt

Cash

0

4

8

12

Talisman

Balance sheet – leverage in line with peers

Debt to average daily production – Dec 31, 2010$ thousand/boe

0

20

Talisman

10

30Peer companies

Average = $15.1

Debt to PD reserves – Dec 31, 2010$/boe

Average = $5.78

Peer companies


Balance sheet – no near-term maturities

1,225

300

600

700

400375

50

0

250

500

750

1,000

1,250

Post 2034

2027202120152011

Debt maturity schedule$ million

150

0

25

50

75

100

20122H 20112Q 2011

Oil hedging update

Unhedged

$90 puts

$82-$94 collars

$81-$93 collars

Economic exposure to oil productionPercentage (%)

Unhedged

$90-$148collars

Unhedged

Collars

Puts

Unhedged


0

100

200

300

400

10 year production at 2010 rate

Sustainable base

0

200

400

600

10 year productionat 2010 rate

P21P

~1,000Wild River

~400Chauvin/ Shaunavon

~950Cardium/Sundance

~150Ojay (Nikanassin)

WellsProjects

MonArb

Yme

Infill drilling

Auk South

Projects

North America conventional reservesmmboe

North Sea reservesmmboe

*Feasibility studySource: Sasol

1980s 1990s 2000s 2010s

100 bbl/d 2,500 bbl/d 16,000 bbl/d 24,000 bbl/d

Sasolburg Qatar Nigeria

Canada*

Capacity of GTL reactors increasing

Enhanced performance through increased volumetric conversion efficiency

Oryx GTL plant


Talisman Key Historical Data

2010 2009 2008 2007 2006 2005Daily production, before royalties

Oil & liquids (mbbl/d) 189 211 224 241 262 250 Natural gas (mmcf/d) 1,367 1,283 1,247 1,265 1,342 1,319 Barrels of oil equivalent (mboe/d) 417 425 432 452 485 470

Daily production, after royaltiesOil & liquids (mbbl/d) 160 181 187 203 220 216 Natural gas (mmcf/d) 1,161 1,088 992 1,017 1,091 1,043 Barrels of oil equivalent (mboe/d) 353 362 352 373 402 390

Proved reserves, before royaltiesOil & liquids (mmbbl) 510 532 545 749 767 736 Natural gas (bcf) 5,237 5,273 5,338 5,464 5,403 5,417 Barrels of oil equivalent (mmboe) 1,383 1,411 1,434 1,660 1,667 1,639

Drilling activity (gross wells)North America - Oil & liquids 65 5 138 128 194 171 North America - Natural gas 243 154 286 288 496 495 North America Total 308 159 424 416 690 666 North America - Drilling success (%) 100 98 100 98 98 97

International - Oil & liquids 57 59 73 73 65 51 International - Natural gas 11 12 37 11 18 5 International Total 68 71 110 84 83 56 International - Drilling success (%) 85 86 89 79 83 81

Net undeveloped land (thousands of acres) North America 6,940 9,145 9,786 9,559 7,837 5,588 International 29,673 26,208 16,443 12,948 11,048 13,484 Total 36,613 35,353 26,229 22,507 18,884 19,072


Talisman Key Historical Data

2010 2009 2008 2007 2006 2005Ratios and Key Indicators (C$ millions, except per share)

Cash flow 3,058 3,961 6,163 4,327 4,748 4,672 Net Income 648 437 3,519 2,078 2,005 1,561 Per Common Share

Cash flow 3.00 3.90 6.06 4.19 4.35 4.23 Net Income 0.64 0.43 3.46 2.01 1.84 1.41

Exploration & development spending 3,953 4,245 5,106 4,449 4,578 3,179 Acquisitions 1,562 438 452 317 204 3,170 Dispositions 2,347 2,772 442 1,477 872 22

Average Royalty Rate (%) 16 15 18 17 17 17 Unit operating costs (C$/boe) 12.80 12.91 13.57 12.14 9.98 8.41 Unit DD&A (C$/boe) 15.21 17.36 16.44 14.74 12.22 10.88

Balance Sheet Info (C$ millions)Property, plant & equipment * 18,804 16,431 18,540 16,363 16,655 13,806 Total assets 24,193 23,618 24,275 21,420 21,481 18,354 Long-term debt (including current portion) 4,181 3,780 3,961 4,862 4,560 4,263 Shareholders' equity 10,479 11,111 11,150 7,963 7,307 5,729

Share information, adjusted to reflect stock splitsAverage common shares outstanding (millions) 1,018 1,019 1,019 1,019 1,064 1,099 TSX trading info

Average daily trading volume (thousands) 5,042 4,066 3,727 2,951 3,254 3,143 High (C$) 22.32 20.17 24.92 22.67 24.84 20.83 Low (C$) 15.71 9.92 8.28 16.90 16.12 10.50 Close (C$) 22.12 19.69 12.18 18.39 19.80 20.53

NYSE trading infoAverage daily trading volume (thousands) 3,120 3,998 4,248 2,115 2,139 1,384 High (US$) 22.43 19.51 25.71 22.08 21.62 18.08 Low (US$) 14.70 7.97 6.42 15.04 14.21 8.36 Close (US$) 22.19 18.64 9.99 18.52 16.99 17.63

Commodity InformationWTI (average US$/bbl) 79.53 61.79 99.65 72.31 66.25 56.70 NYMEX gas (average US$/mmbtu) 4.39 4.05 8.95 6.92 7.26 8.55 US$/C$ exchange rate (year end) 1.01 0.96 0.82 1.01 0.86 0.86

Realized product pricing, before hedging activitiesOil & liquids (C$/bbl) 80.52 67.36 96.43 75.00 69.82 62.78 Natural gas (C$/mcf) 5.76 5.29 9.01 6.99 7.20 8.30

Please note: These figures are all prior to reporting under IFRS and US currency transition which commenced January 1, 2011.

* 2009 restated for continuing operations.


Advisories Forward-Looking Information This presentation contains information that constitutes “forward-looking information” or “forward-looking statements” (collectively “forward-looking information”) within the meaning of applicable securities legislation. This forward-looking information includes, among others, statements regarding: business strategy, priorities and plans; planned and potential acquisitions; planned drilling, development, redevelopment, piloting, sanctioning, appraisals, upgrades, egress and exploration; potential drilling locations; expected ROACE; number of rigs; estimated planned production and production growth, incremental production and future projects; expected production by region and resource type; net acreage to be acquired on the closing of an acquisition from SM Energy Company; remaining life of field break even; expected liquids exposure; asset life, costs and returns; planned capital expenditures and program; expected timing of the international exploration portfolio transition; expected pipeline capacity in Colombia; expected net production resulting from the acquisition of BP Colombia; the exploration and development plans for Latin America and Southeast Asia; the 2011 plans for Akacias CPO 9 and CPE 6 in Colombia; expected prospective resource and land additions; expected shale free cash flow turning point, expected break-even costs; targeted number of wells onstream; expected development dates of Flyndre/Cawdor, Godwin, Shaw and Cayley; expected reduction to unit operating expenses; expected timing of first production and expected production from startup; expected redevelopment of Auk South; percentage of liquids production and growth; expected sustainability of production in the North Sea; remaining reserves; increases in operational efficiencies; target UK operating efficiency; expected reserves replacement costs and replacement ratio; expected extensions to field life; forecasted cash flow; expected reinvestment ratio and decline curve; planned seismic acquisition; potential cost savings; expected liquids yield of Deep Cut Plant; expected facilities improvement activities; and other expectations, beliefs, plans, goals, objectives, assumptions, information and statements about possible future events, conditions, results of operations or performance. The forward-looking information included in this presentation is based on Talisman’s 2011 capital program. Talisman has set its 2011 capital expenditure plans assuming: (1) Talisman’s production in 2011 will be 5-10% greater than 2010, excluding the BP Colombia acquisition; (2) a WTI oil price US$75/bbl; and (3) a NYMEX natural gas price of approximately US$4/mmbtu. Talisman now believes that base production growth will be closer to 5% in 2011 excluding the BP Colombia acquisition. Information regarding business plans generally assumes that the extraction of crude oil, natural gas and natural gas liquids remains economic. Forward-looking information for periods past 2011 assumes escalating commodity prices. The Eagle Ford Shale net acres include SM Energy Company acreage to be acquired on the closing of that transaction. Closing of any transactions will be subject to customary conditions including 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, market demand and unpredictable facilities outages; risks and uncertainties involving geology of oil and gas deposits; uncertainty related to securing sufficient egress and markets to meet shale gas production; the uncertainty of reserves and resources estimates, reserves life and underlying reservoir risk; the uncertainty of estimates and projections relating to production, costs and expenses; the impact of the economy on the ability of the counterparties to the Company’s commodity price derivative contracts to meet their obligations under the contracts; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; fluctuations in oil and gas prices, foreign currency exchange rates and interest rates; the outcome and effects of any future acquisitions and dispositions; health, safety and environmental risks; uncertainties as to the availability and cost of financing and changes in capital markets; risks in conducting foreign operations (for example, political and fiscal instability or the possibility of civil unrest or military action); changes in general economic and business conditions; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; and results of the Company’s risk mitigation strategies, including insurance and 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. 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. Talisman has obtained an exemption from Canadian securities regulatory authorities to permit it to provide certain disclosures in accordance with the US disclosure standards, in addition to the disclosure mandated by NI 51-101, in order to provide for comparability of oil and gas disclosure with that provided by US and other international issuers. Accordingly, the reserves data and certain other oil and gas information included in this presentation are disclosed in accordance with US disclosure standards. Information on the differences between the US requirements and NI 51-101 requirements is set forth under the heading “Note Regarding Reserves Data and Other Oil and Gas Information” in Talisman’s most recent Annual Information Form. A separate exemption granted to Talisman also permits it to disclose internally evaluated reserves data. Any reserves and resources data contained in this presentation reflects Talisman’s estimates of its reserves and resources. 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 and resources data disclosed in this presentation. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. In this presentation, Talisman discloses reserves replacement costs (for ease of reference, referred to as “replacement costs” in this advisory). Replacement costs are used by the Company to determine the cost of reserves additions in a particular time period. Talisman’s reported replacement costs may not be comparable to similarly titled measures used by other companies. Replacement costs may not reflect full cycle replacement costs. Replacement costs’ predictive and comparable value is limited for the aforementioned reasons. Replacement costs are calculated by dividing exploration and development capital spending (including discontinued operations, but excluding midstream) by proved reserve additions. Further information regarding replacement costs which is required by NI 51-101 can be found on Talisman's website at www.talisman-energy.com. The reserves replacement ratio was calculated by dividing the sum of yearly changes (additions, discoveries and non-price revisions) to estimated proved oil and gas reserves by the Company's production for that year. The Company uses reserves replacement ratios as an indictor of the Company's ability to replenish annual production volumes and grow its reserves. It should be noted that reserves replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely, based on the extent and timing of new discoveries, project sanctioning and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not include cost, value or timing of future production of new reserves, it cannot be used as a measure of value creation. Production and Reserves Volumes Unless otherwise stated, production volumes and reserves estimates are stated on a Company interest basis prior to the deduction of royalties and similar payments, except for the Corridor well production volumes, which are stated on a gross basis, as that term is defined below. 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, OGIP and EUR as at April 30, 2011. Where not otherwise indicated, the contingent and prospective resources included in this presentation are 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 are; lack of gas sales contract; additional testing; production and performance appraisal activities; 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. 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 chance 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. The reference to "prospect" on slide 57 of this presentation refers to unrisked prospective resources. “Risked prospective resource” means geologically risked. OGIP is defined as original gas in place and is that quantity of gas that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of gas that is estimated, as of a given date, to be contained in known accumulations, prior to production. All OGIP estimates in this presentation are discovered. There is no certainty that it will be commercially viable to produce any portion of the resources. Estimated ultimate recovery (EUR) is a term commonly used in the oil and gas industry. EUR is an estimate of the quantity of oil and gas that is potentially recoverable. There is no certainty that it will be commercially viable to produce any portion of the EUR amount that is contained herein. 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. Forecasted Cash Flow: This presentation also contains discussions of anticipated cash flow. 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; anticipated cash payments made by the Company upon surrender of outstanding stock options using the cash payment feature, which in turn is dependent on the trading level of the Company’s common shares and the number of stock options surrendered or exercised; and the anticipated amount of cash income tax and petroleum revenue tax. The amount of taxes and cash payments made upon surrender of existing stock options 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.


Netbacks Talisman also discloses netbacks for the Company and Southeast Asia in this presentation. Netbacks per boe are calculated by deducting from the sales price associated royalties, operating and transportation costs. US Dollars and IFRS Dollar amounts are presented in US dollars, except where otherwise indicated. Financial information prior to January 1, 2011 was prepared in accordance with Canadian generally accepted accounting principles (CGAAP) then applicable to publically accountable enterprises. The financial information for 2011 is presented in accordance with International Financial Reporting Standards (IFRS). Both IFRS and CGAAP may differ from generally accepted accounting principles in the US. See the notes to Talisman’s Annual Consolidated Financial Statements for the significant differences between CGAAP and U.S. generally accepted accounting principles. 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, net debt, ROACE and capital expenditure including exploration expensed. These terms are not defined by IFRS. Consequently, these are referred to as non-GAAP measures. Talisman’s reported results of free cash flow, cash flow, net debt, ROACE and capital expenditure including exploration expensed 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 represents net income before exploration costs, DD&A, impairment, deferred taxes and other non-cash expenses. Cash flow is used by the Company to assess operating results between years and between peer companies using different accounting policies. Cash flow should not be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net income as determined in accordance with IFRS as an indicator of the Company’s performance or liquidity.

Net Debt is calculated by adjusting the Company’s long term debt per the financial statements for bank indebtedness, cash and cash equivalents. The Company uses this information to assess its true debt position and eliminate the impact of timing differences. ROACE (return on average capital employed) is used to measure returns realized by the Company on capital employed and is calculated for each region by dividing normalized after-tax income by average capital employed. ROACE represents total assets, less current and long-term liabilities, but excluding both long-term debt and the current portion of long term debt, all components being the average between opening and closing balance sheets. Capital expenditure including exploration expensed is calculated by adjusting the capital expenditure per the financial statements for exploration costs that were expensed as incurred. Reserves and Resources Estimates NAO: Shale: 2009: 1P 109 mmboe; 2P 203 mmboe

Shale: 2010: 1P 309 mmboe; 2P 479 mmboe Southeast Asia: Block 15-2 HSD/HST: 1P 0 mmboe; 2P 24 mmboe

South Sumatra Core: 1P 283 mmboe; 2P 369 mmboe Corridor Committed Gas Contracts 1P 4.3 tcfe Corridor Yet to be Monetized P2 1.2 tcfe Jambi Merang: 1P 19 mmboe; 2P 28 mmboe PNG Aggregate (gross): detail resource split shown Slide 42

UK and Norway: Auk South Redevelopment: 1P 30 mmboe; 2P 36 mmboe

Flyndre/Cawdor: 1P 0 mmboe; 2P 6 mmboe; 3P 8 mmboe MonArb Redevelopment : 1P 8 mmboe; 2P 61 mmboe; 3P 92 mmboe Yme: 1P 28 mmboe; 2P 44 mmboe Grosbeak and Beta: 1C 8 mmboe; 2C 32 mmboe; 3C 54 mmboe Grevling Development: 1C 37 mmboe; 2C 50 mmboe; 3C 122 mmboe (100% working interest)


Notes

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Documents

2011 07 Corporate Presentation Web Handout