talisman - corporate presentation jan 2010

Operations: three core areas + global exploration. . .

North America

North SeaSoutheast Asia

Growth through Unconventional gas

Sustainable cash flowOil price leverage

Norway exploration

Self funding built in growth

-10%

0%

10%

20%

30%

40%

International Portfolio 10yr ROACE (%)North America 10yr ROACE (%)

. . .provides a balanced portfolio

-10%

0%

10%

20%

30%

40%

SE Asia21%

Other5%

North America

42%

North Sea32%

Oil52%

Gas36%

Oil Linked Gas12%

SE AsiaNorth SeaConventional

Commodity Price US$/mmbtu

$4

$6

$9

Commodity Price US$ WTI

$40

$60

$90

Unconventional

2008 Production 2008 Commodity Exposure

January 2010 www.talisman-energy.com Page 1 of 35

Robust strategy – a clear business strategy tounlock value

1Establish Long-term Profitable Growth• North America shale gas• Southeast Asia

2Reposition International Exploration Portfolio for Renewal• Support existing core areas• Build new production areas

3Focus Portfolio to Generate Cash for Re-investment• Maximize value from existing mature assets• Exit non-strategic areas

2008 % Undeveloped reserve bookings

Strategy drives lower F&D costs. . .

60

403833

18

Unconventional Gas PeersTalisman North America

Talisman 5 year historical F&D Cost (C$/boe)

10.9

20.323.5

20.2

SE Asia North Sea North America Total


. . .and longer reserve life

North America

North Sea

SE Asia

9

14

9

22

15

13

Typical Industry Unconventional 1P Range

15–20

1P

2P

Reserve Life Index 2008Years

2008 Year End 2P Reserves 2.5 Billion boe

Oil46%

Gas50%

UnconventionalGas4%

People and organizational changes

• Building the Senior Team

– Five new EVP’s

– New SVP Shale, VP’s HR and HSE

• Enhancing Functional Capacity

– HSE: New board committee, global standards, performance management

– Talent and career development

– New Long Term Incentive Plan

– Project management

• Organization to drive focus

– UK operations delivery

– NAO unconventional


Strategy scorecard – delivery

Exploration Key exploration wells: 27

Bid Rounds: Norway, others

Project Delivery

(First Production)

Norway: Rev, Yme

UK: Tweedsmuir Phase B, Affleck

SE Asia: Song Doc, Northern Fields Gas and Oil

• Rev, Yme (expected 2H10)

• Tweedsmuir ‘08, Affleck 3Q09

• Song Doc, Northern Fields Gas and Oil

Disposals North America: Lease 10, non-core assets

UK: Core and non-core assets

SE Asia: Australia

Other: Trinidad and Tobago

Exit: 35–45 mboe/d, $1.5–2.0 Billion

• Lease 10, Midstream, Non-core conventional and unconventional

• Netherlands, Beatrice, UK Core (on hold)

• Australia (on hold)

• Trinidad and Tobago, Denmark, Yme Dilution

38 mboe/d, $3.2 Billion to date

NA

Unconventional

Evaluate five unconventional plays and drill 240–290 wells

Capital: $2.5–$3.0 Billion

• Evaluated five plays, 270–290 wells drilled/planned

• $3.4 Billion, including land

• 25 wells drilled and two currently drilling• Discoveries: Kitan, Grevling, Huron, Godwin, Shaw,

Kurdamir• Successful appraisals: Hai Su Den, Situche

• Four blocks Colombia, Block 158 Peru, Blocks K-44, K-39 and K-9 KRG (Kurdistan), three Barents Sea blocks, Blocks 133 & 134 Vietnam, Andaman III Block Indonesia, Sabah blocks SB309/SB310 Malaysia, ten blocks PNG

2008 Promises. . . . . .delivered

Success in focusing the portfolio

$660NA Conventional

$300Midstream

$90Yme dilution

$380Trinidad and Tobago

$710Bakken

$595Netherlands

$3,170Total

$90Lease 10

$250Lac La Biche

$95Denmark

Sales price

($C Million)CompletionName

Focus the Portfolio Additional Levers

Talisman continues to look at opportunities to focus the portfolio

• Tunisia

• North America non-core


Strong investment grade ratings. . .

0.0 x

0.5 x

1.0 x

1.5 x

2004 2008 3Q2009

Debt to Trailing Twelve Month Cash FlowRatio

0%

20%

40%

60%

2004 2008 3Q2009

Debt to Debt + EquityPercentage

0.0 x

$0

$1

$2

$3

$4

$5

$6

$7

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

3.5x

. . .with low leverage relative to peers and good liquidity

Average = 1.96x

Talisman

Debt to Trailing Twelve Month Cash Flow

Peer companies

Talisman

Available Liquidity

Average = $3.3 Billion

C$ Billion

3Q 2009 Disclosure


North America growing a material position in thebest rocks. . .

Marcellus

Montney

Québec

Other

Outer Foothills

3,677

Gross Acresthousands

1,004

951

833

558

331

May 2008

2,657

May 2008

771

793

599

436

58

Net Acresthousands

132

48

31

49

3

1

OGIPNet tcfe

Marcellus9.8

Montney17.7

30

Contingent Resource

Net tcfe

Outer Foothills

2.3

2,5103,180

1,004

951

833

558

331

May 2008

124

Other 0.2

May 2009 Disclosure

. . .and is repositioning into the best rocks to ensurewe are the low cost producer

Plays where Talisman has material positions

0

2

4

6

8

10

12

FayettevilleMarcellusMontney

Haynesville(8–12 bcf/well)

WoodfordUtica

West TXBarnettMuskwa

Conventional

North America Strategic Shift

Other North American plays

Estimated North America gas supply costs

Supply cost

(US$/mmbtu NYMEX)

Source: Tristone Capital Feb 2009


• Returns are stable and predictable

–Downside commodity price protection

• Long Life Assets

–Extended production profiles

–Materiality

• Material Growth

–Current portfolio has built in growth

–Large accessible YTF resources

• Competitively Positioned

–Well established relationships

–Staff in five countries

–Incumbent advantage

15 13

22

16

Total North America

North Sea SE Asia

10.9

20.323.5

20.2

4.5

17.5

7.0

9.7

SE Asia is a great place to do business

2P Reserve Life IndexYears

5 year F&D ($/boe)Excluding Price Revisions

OPEX ($/boe)2004–2008 Average

0

40

80

120

160

2002 2008 2013

Growth in SE Asia ca. 10% per annum over next 5 years

Oil

Gas

Rate (mboe/d)

CAPEX

($C Millions)767512331305235316269

(82) 5122361220195(82)Free Cash Flow

($C Millions)

• Kitan oil

• Corridor additional gas

• Northern Fields

• Tangguh Phase 1

• HSD/HST oil

• PM-3 IOR

Future projectsSE Asia production

16%

ca. 10%

Vietnam

• Nam Con Son gas

• Cuu Long

Indonesia

• Makassar Strait

• Tangguh Phase 2

• Andaman III Block

Malaysia

• Sabah Blocks

Papua New Guinea

• Lowland Gas Commercialization

• Song Doc


0

25

50

75

100

2005 2008 2009

0

10

20

30

40

UK provides a strong profitable base and leverageto high oil prices

0.0

0.5

1.0

1.5

2005 2008 2009

% ROACE

ROACE

Free Cash Flow(C$ Billion)

Netbacks and ROACEC$/boe

$55/bbl

$65/bbl

Forecast Performance

UK - resetting the cost base

C$/boe

10

15

20

25

30

2004 2005 2006 2007 2008

UK unit operating costs

3Q 2009YTD


Build New Production Area

Support Existing Production Area

VietnamMalaysia

Indonesia

KRG (Kurdistan)

Peru

Norway

Colombia

UK North Sea

Exploration – Building the Portfolio. . .

PNG

0%

50%

100%

2007 2008 2009E 2010E 2011Target

0

20

40

60

80

Exploration Capital Expenditures & Average Prospect Size

Percent of Capital Expenditures

. . .and Positioning for Renewal

2009-2013 Exploration targets:

• ca. 600 mmboe resource adds in 5 years

• Less than $5/boe Finding Cost

• ca. C$600MM capital budget per year

mmboe

Support Existing Production Area

Build New Production Area

Average prospect size (working interest resource estimate)


Priorities for 2010

1. Accelerate portfolio transition

2. Maintain focus on returns and profitability

3. Continue to build organizational capacity

Capital program C$5.2 Billion

• Fund from cash flow, asset sales, balance sheet strength

• Scalable up and down

• Includes $300 Million non-cash capital lease

2010 production approximately flat with 2009

• NA shale gas and SE Asia gains offset declines in NA conventional & UK, and impact of 2009 asset sales

• Marcellus shale: 250-300 mmcf/d 2010 exit rate, up from 65 mmcf/d yr end 2009

• Montney shale: 40-60 mmcf/d 2010 exit rate

• Growth expected from 2011

• NA shale gas emerging as growth driver

2010 Corporate Outlook

2010 Activity

North America

• Marcellus shale: drill 170 wells

• Montney shale: drill 35-40 wells (development/pilot)

• Quebec: continue piloting activity

• Non-core conventional asset dispositions

North Sea

• Auk North & South, Burghley, Yme development

• Infill drilling

SE Asia

• HSD/HST and Kitan development

• Malaysia infill drilling and platform upgrades

• PNG appraisal

International Exploration

• 10 new core area wells• Colombia (2), Peru (1), Kurdistan (2), Makassar Strait (2), PNG (3)


Capital expenditures increased in 2010 to support strategic transition

International Exploration

SE Asia

NA Conventional

Norway

UK

NA Unconventional

2008 2009E 2010E

Cash Capital Expenditure

C$ Billion

5.2

4.5

4.9

Other

Key milestones

Projects for sanction

•Burghley

•Kitan

Projects(First Production)

Key Exploration Wells

•Rev

•Northern Fields (oil)

•Affleck

•Huron

•Godwin

•Grevling

•Situche

•Kurdamir

•Shaw

•Yme

•Corridor additional gas sales

20102009

DivestmentsContinue non-core divestments

•Pasangkayu (2 wells)

•Runtusapa

•K-44 Well 3

•PNG Lowland (3 wells)

•Grevling Appraisal

•HSD and HST

UnconventionalMarcellus

Montney Core

Montney Shale

Quebec

•Six rig development - drilled 53 wells

•Drilled 21 wells

•Three pilot areas

•Commence horizontal pilots

•Drill 170 net wells

•Drill 25 horizontal development wells and 10-15 pilot wells

•Complete and test four horizontal pilot wells


Summary

• Strategy aimed at:– Reducing F&D North America shale gas– Extending Reserve Life SE Asia– Profitable growth Material exploration successes

• Operational progress being made in all areas– Improving execution in NAO – Project delivery in SE Asia (Northern Fields, Song Doc, Corridor)– Discoveries in Exploration (Kitan, Grevling, Huron, Godwin, Shaw, Kurdamir)– C$3.2 Billion from divestments

• Positioned for growth– 30 tcf contingent resources in NAO– SE Asia ca.10% over next 5 years– 2010 Capital budget at C$5.2 Billion but flexible up or down

• Strong balance sheet– Approximately C$4.8 Billion liquidity at end 3Q 2009– Debt to cash flow of 0.85x at end 3Q 2009

Appendix


2010 Hedging Program

January 11, 2010 Disclosure

• 240 mmcf/d @ ~C$6/C$7.50 (AECO)

• 100 mmcf/d @ ~US$5.50/US$6.50 (NYMEX)

• 22,000 bbls/d @ ~US$50/US$60

2H 2010• 25,000 bbls/d @ ~US$71/US$90

• 335 mmcf/d @ ~C$6/C$7.25 (AECO)• 28,000 bbls/d @ ~US$52/US$80

1H 201075,000 bbl/d in collars

North American GasOil

Our growing unconventional base provides a structural advantage to drive lower F&D costs

10% Proved

reserves3.6 tcf

85%Contingentresource

30 tcf

2008 North American Year End Resources 2008 % Undeveloped Gas Reserve Bookings% PUD

60

4038

33

18

Unconventional Gas PeersTalisman North America

5%Probablereserves1.6 tcf


The Marcellus Shales – large contiguous land base

~ 200

80Spacing (acres/well)

2010 Secured Egress Capacity (mmcfe/d)

214,000Net Acres – PA

647,000Net Acres – NY*

Marcellus Development Metrics

• Focus on Pennsylvania

• Full scale development initiated

• D&C optimization ongoing

• Water management plans in place for 2010

• Majority of permitting in place for 2010

• Egress ramping up to 400 mmcf/d

Talisman Updates Industry Perspective

• Talisman top three in resource potential

• One of the top two shale plays in North America

•IRR: 10% - 35% ($4.50- $8.50 NYMEX)

•Breakeven gas price US$/mmbtu 3.50 – 4.50

• Total basin OGIP up to 500 tcf

Source: BMO January 2009, Tristone October 2008, Ross Smith Energy Group 2008, First Energy Capital Corp January 2009

* May 2009 Disclosure

Marcellus Shale FairwayTLM Shale AcreageMajor Pipelines

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

0 50 100 150 200 250 300

2 bcf 4 bcf 6 bcf

Marcellus Shales - demonstrating ability to execute

2.3 – 5.0

3.0 – 6.0

3.4 – 5.5

65

53

2009

Horizontal Well Metrics

6# Wells (Gross)

2008

2.0 – 3.0

2.5 – 3.5

6.5 – 7.5

5

30 Day IP per Well (mmcfe/d)

EUR per Well (bcfe)

D&C Cost per Well (US$ Million)

Exit Production Rate (mmcf/d)

Well Number

Operational Highlights

• 27 horizontal wells on stream (23 Op + 4 Non-Op) – on average exceeding 3.5 bcf type curve

• Current production of 65 mmcf/d (sales gas)

• 2010 program has commenced with six rigs

• 2010 target exit production rate of 250 - 300 mmcf/d

11

##

Days

Rate (mmcf/d)

Pennsylvania Horizontal Wells

1515


3.0

4.0

5.0

6.0

7.0

8.0

Stage Pad Drilling

Completions LogisticsInvert Drilling Fluid

• Lean operations

• Pad drilling and pre-set rigs

• Optimizing water management plan

• Supply management negotiations

Marcellus D&C Cost Reductions

Marcellus Shales – driving to top tier execution

FourthWell

LastWell

Supply Chain

D&C Cost (US$ Million) Key cost reduction levers

FirstWell

Data acquisition and well evaluation

Applied Drilling Learnings

Improved completion techniques

Hole stability management

Target

US$5.6US$7.5 US$4.3

Operational ImprovementsFacility Standardization

US$3.9

0.0

1.0

2.0

3.0

4.0

5.0

0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0

.

Well Number • Lean well delivery

• Drilling costs already below initial 2009 target

Marcellus Shales – driving to top tier execution

Completion Costs

(US$ Million) (US$ Million)

Drilling Costs

Drilling Performance – Cost vs. Depth(ft thousands)

$US Million

111919

##

4Q Target

Actuals

0

2

4

6

8

10

12

14

0.0

1.0

2.0

3.0

4.0

5.0

Wells Wells


Talisman Updates

• 21 horizontal wells drilled in Montney Core (2009)

• Shale wells tested with encouraging results

• Excellent industry and stakeholder relationships

• Incorporating learnings and technology to reduce costs and improve well efficiency

Montney - proven and expanding play

Montney ShaleMontney CoreKey Metrics

110-220

369,000*

Dev

320Secured Egress Capacity mmcfe/d

270,000Net Acres

80Spacing (acres/well)

Pilot

Industry Perspective

• Talisman top tier resource potential

• One of the largest economically viable resource plays in North America

•IRR: 10% - 66% (US$4.50 - $8.50 NYMEX )

•Breakeven gas price US$/mmbtu 3.50 – 4.50

• Total basin OGIP up to 600 tcf

Source: BMO January 2009, Tristone October 2008, Ross Smith Energy Group 2008, First Energy Capital Corp January 2009


0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

0 50 100 150 200 250 300 350 400 450


• Leading horizontal driller

• Significant strides in reducing costs; targeting <C$4/mcf breakeven

• 15 horizontal wells currently on stream – on average exceeding type curve

• Most recent five horizontal well test rates averaged 4.0 mmcf/d

Montney Core – development success

2.6

4.0

4.5

25

2009 Target

4.0

3.0 – 4.0

3.5 – 5.4

42

17

2009 YTD*

Horizontal Well Metrics

52# Wells (Gross)

2008

1.5 – 4.4

2.8 – 3.0

4.9 – 9.3

35

30 Day IP per Well (mmcfe/d)

EUR per Well (bcfe)

D&C Cost per Well (C$Million)

Production (mmcfe/d)

4 bcf Type Curve

3 bcf Type Curve

Days

Rate (mmcf/d)

Horizontal Well Production History

* 3Q 2009 Disclosure


0.0

1.0

2.0

3.0

4.0

5.0

Wells 1-5 Wells 6-10 Wells 11-15 Wells 16-20 Last Well

Montney Drilling Costs per Well

Montney Drilling Time per Well

Montney Core – top tier operational performance

0

25

50 Competitors

Talisman

Cost (C$ Million)

Days per Well

Wells 1-5 Wells 6-20 Last Well

22 wells

140 wells

50%

• Lean Well delivery driving top tier performance metrics

• Learning faster

• Developing faster

• 50% lower costs

0% 100%

Lean process is delivering significant opportunities to accelerate the well delivery and increase asset value

• Creating flow and eliminating waste across the business

• As much a cultural change as a business redesign

• Creating an engaged and motivated workforce

Current performance

Starting performance

Target

Lead time % Improvement

Tie-in

Complete

Drill

Construction

Land & License

Survey

Site selection 50% Cycle Time Improvement

Montney Well Delivery Cycle Time


Upper Montney

Lower Montney

Montney Shale pilot – early success

0

1

2

3

4

5

6

0 20 40 60


• Expect to move segments of the play to commercial development in 2010

• Initial test rates exceeding expectations

• Initial egress in place and processing strategy initiated

19Number of Wells Drilled in 2009 (Gross)

3Number of Pilot Areas in 2009

Metrics (Pilot)

Pilot Well Results

4 bcf Horizontal Type Curve

1 bcf Vertical Type Curve

Days

Rate (mmcf/d)

GR NeutronDensity

GasSaturationPorosity

Talisman Updates

• Largest land position in most prospective shale fairway

• Currently completing first horizontal well and drilling second

• Proven we can systematically fracture Utica formation

• Long term growth opportunity

• Actively building government and industry relationships

• Excellent proximity to premium markets

• Earning wells demonstrate opportunity

Proving Québec - extensive land position

Industry Perspective

3Planned Horizontal Wells - 2010

6Gross Earning Wells drilled

Available on TQMSecured Egress Capacity

771,000*Net Acres

Key Metrics

Acres following earning

Not testedSt Francois Du Lac #1

700Saint-Edouard / Questerre

Test Rate (mcfe/d)Earning Well / Partner Name

900

>400Saint-David / Questerre

Leclercville / Intragaz

>800Gentilly / Questerre

>300La Visitation / Questerre

Early Success (Vertical Wells)



Other North America Assets – historical results

0

500

1,000

1,500

2000 2008 3Q2009YTD

Dispositions

Conventional excl Dispositions

0

500

1,000

1,500

2,000

2000 2008 3Q2009YTD

Productionmmcfe/d C$ Million

Capital (excluding land)

• Optimize between value and free cash flow• Dispose of non-material assets to fund unconventional areas• Manage costs in low commodity price environment

Malaysia, PM-3: Northern Fields oil & gas production

Indonesia, Corridor: Full year West Java gas sales

Vietnam, Song Doc: On production

Vietnam, 15-2/01: Hai Su Den basement discovery & appraisal

Key SE Asia projects delivered

Growth Areas (5-9)#

1

Indonesia

Papua New Guinea

Australia

Philippines

ThailandVietnam

Malaysia

9

99

8

9

632

4

4

3

2

1


• Talisman 41.4% WI (Operator)

• C$1.6 Billion project (4 Platforms, FSO, 50 wells and 100+ km of subsea pipelines)

• Early Gas on production Q3 2008, Oil on production Q1 2009, Dry Gas Q2 2009

• Increasing PM 3 CAA gross liquid production to 45,000 bbl/d and gas production to 290 mmcf/d

• PM-3 working interest 2P reserves: 154 mmboe

Malaysia/Vietnam - PM-3 CAA Northern Fields demonstrating project capabilities

Oil

Gas

ProspectsFuture Platform

Producing Platform

Gas export to

Ca Mau, Vietnam

Gas export to Resak, Malaysia

Legend

Song Doc

Northern Fields Southern

Fields

PM-3

VietnamMalaysia

Vietnam - Song Doc DevelopmentLeveraging existing knowledge and infrastructure

• Talisman 30% WI (JOC Operator)

• C$110 Million project (wellhead platform and leased FPSO)

• First oil delivered on budget in November 2008

• Song Doc working interest 2P reserves: 5.4 mmboe

Oil

Gas

ProspectsFuture Platform

Producing Platform

Gas export to

Ca Mau, Vietnam

Gas export to Resak, Malaysia

Legend

Song Doc

Northern Fields

Southern Fields

PM-3

VietnamMalaysia


Duri

Corridor

Sumatra

Jakarta

Java

Singapore

Indonesia - CorridorLong life, low cost asset with significant upside. . .

• Talisman working interest 36% (ConocoPhillips Operator)

• Connection to multiple markets strengthens the ability to commercialize un-booked reserves

• Talisman working interest production 250 mmcf/d (full year 2008 West Java gas sales)

• Working Interest 2P reserves: 2.4 tcfe with additional P3 reserves of 660 bcfe

• 2P Reserve life: 23 years

. . .strong growth with good price realizations and netbacks

Corridor Gas Productionmmcf/d

0

100

200

300

5yr Average Corridor Netback Realization($/mcf)

19%

2002 2008 3Q 2009YTD

Realized Price

Netback

$8.73

$5.13

Opex

$2.79

$0.30

Royalties

$0.81


SE Asia provides access to large-scale opportunities and Talisman continues to build the portfolio

Projects delivered (1-4)

Malaysia: Built-in growth with IOR projects

Exploration: Makassar Strait and Offshore North Sumatra, Indonesia; Onshore and Offshore PNG; Offshore Sabah, Malaysia

Indonesia, Corridor: World-class asset with significant un-booked reserves

Vietnam, Nam Con Son Basin: Building new core exploration base

Vietnam Cuu Long Basin:Emerging core area

8

7

6

5

9

#

5

Indonesia

Papua New Guinea

Australia

Philippines

ThailandVietnam

Malaysia

9

99

8

9

632

7

Malaysia - PM-3 Improved Oil Recovery project leverages Talisman’s core strengths

• Development Optimization of the PM-3 CAA Southern Field’s main oil reservoirs

• Improve average oil recovery factor from 25% to 35% via re-completions, infill drilling and water injection

• Offsets natural field production decline

• Targeting 53 mmbbls 3P reserves and additional prospective resources

0

2

4

6

8

10

12

Rate (mboe/d)

PM-3 South incremental IOR Production

Typical reservoir cross section over 800 meters thick

2009 2010 2011 2012 2013

Phase 2

Phase 1


Vietnam - Block 15-2 HSD/HST Early Production Scheme (EPS) leverages in-house capabilities

• Talisman WI 60% (JOC Operator)

• HST (Hai Su Trang) clastic reservoir and HSD (Hai Su Den) basement reservoir is a phased development

• Early Production system to focus on HSD (Block B) and HST development

• Sanction 1H 2010 targeting 52 mmboe 2P reserves

• First oil in 2012 with peak production around 35,000 boe/d

• Estimated Capital spend approx. $1.0 Billion

production

Block 15-2/01 JOCHSD

Gas Export HST

Legend

EPS Platform

Future Platform

Oligocene Clastic Reservoir

Basement Reservoir

Future Development area

Early development

NorthSpill point: -4050 m

HST-1X & ST HSD-2X & ST

10 km

Schematic

3P

1P

2P

Block BBlock A Block C

Block D Block E

• Large basement structure: 62km2

• Appraisal and exploration drilling will define the next phases of development

• Additional exploration opportunities have been identified

HSD/HST basement structure appraisal

Clastic sectio

nG

ranitic

basem

ent

South

HSD-4XHSD-3X

HSD-1XHSD-5X


UK in context – projected resources 25 Billion boe with Talisman’s hubs strategically placed in Central North Sea

Central North Sea

Flotta Hub

50

14

6

33

1422

MonArb Hub

Fulmar Hub

2008 Production

mboe/d

2P Reserve Life Index

Years

North Sea projected 25 Billion boe remaining resources

NorthernNorth Sea

West of Shetland

Irish Sea

Southern North Sea

19%

14%51%

13%3%

FulmarHub

MonArb Hub

Flotta Hub

Central North Sea

NorthernNorth Sea

West of Shetland

Irish Sea

SouthernNorth Sea

25Billion

boe

Source: Oil & Gas UK March 2009, DECC

Auk North Target Area

Auk South Target Area

Auk South Redevelopment• Auk rejuvenation to access

29 mmboe 2P reserves

• Field life extension

• Drill 9 wells and 3 re-completes

• New integrated drilling deck, living quarters, and power from Fulmar

Schedule

• Project sanction 4Q 2008

• First oil 2012

• Peak production 11 mboe/d

Auk South redevelopment / Auk North development

FulmarHub

NorthernNorth Sea

S th

CentralNorth Sea

Auk North Development

• 2P 17 mmboe reserves

• Drill and complete 3 subsea horizontal producers (in progress) Install subsea manifold, pipelines and riser (2010 / 2011)

• Install topsides reception facilities on Fulmar (2010 / 2011)

Schedule

• Project Sanction: October 2008

• First Oil: 2011

• Peak production 10 mboe/d

AukDrained Area


Fulmar Hub

Auk

Clyde

Fulmar

Orion

Halley

Norw

ay

Affleck

Central North Sea Exploration focus drives expansion of strategic hubs

86

42

112

FulmarMonArb2008 year end reserves and resources

(mmboe)

272Unrisked prospective resource

40P3 reserves

722P reserves

Arbroath

Montrose

Arkwright

Wood

Brechin

Exploration2 wells drilled(1H 2009)

Exploration1 well (2010)Fulmar

Hub

MonArb Hub

Flotta Hub

Aberdeen

Flotta

Montrose / Arbroath Hub

FiddichGodwin

Cawdor

Flyndre

Cayley

Shaw

Talisman Recent Discoveries

Export Pipelines

Talisman Fields

Discoveries/Prospects/Leads

Storage tank – installed

Drilling – on track

Subsea installation – mid ‘09

First Oil – 2H 2010

Topside in construction yard

Topside in construction yard

Yme redevelopment project


Exploration success at Grevling and entry into Barents

Near Term

• Grevling discovery (15/12-21)

• Tested oil from 3 formations

• Evaluating development options

• Norwegian Petroleum Directorate estimates 40-130 mmboe recoverable reserves

Long Term

• Entry into Barents Sea through 20th Round award and acreage swap (1Q 2009)

• Access to large prospects to replenish Norway exploration inventory

• Veslemoy – 1 commitment well planned in 2012

Varg

Grevling

Norway

PL490 – 10%PL491 – 20%

Feb ’09 Strategic entry

Talisman acreage

PL531 (Veslemoy)20th Round Award

(25% equity)

PL490 – 10%PL491 – 20%

Feb ’09 Strategic entry

Goliat

Snøhvit

Build NewProduction

Area

• Explore in regions where Talisman has existing production

• Support current production and generate near-term cash flow for reinvestment

• Conduct exploration programs in regions with significant undiscovered resource potential

• Successful efforts will result in new core operating areas

SupportExisting

ProductionArea

Global Exploration - A two-pronged approach to renew the resource base

Colombia: Huron-1

North Sea: Ocean Princess


2009 2013

Foothills

Foreland

Heavy Oil

Exploration Drilling Timeline

Foothills (Niscota, Mundo Nuevo, Tangara, Block 9)

• Exploration success in the Niscota block (Huron-1)

• Captured significant land position in foothills

Foreland (5 Blocks)

• Drilled first prospect in 2009 with next planned for 2010

Heavy Oil (Block 6, 8)

• Extensive land position

• Seismic acquisition underway

Colombia

Talisman acreage

Block 8

Block 6

Block 9

Block 12

Foothills Blocks

Niscota

Foreland Blocks

Huron-1

Cusiana

Rubiales

Situche Central Appraisal

• Under-explored petroleum basin with material prospectivity

• Working interest in 5 blocks– Over 9 Million gross acres– 18 prospects and leads

• Existing infrastructure near Block 64 with spare capacity

• Situche Complex appraisal program underway

• Block 101 3D seismic acquisition commenced in August 2009

Talisman acreageBlock 64

Block 101

Block 134

Block 158

SitucheCentral

Block 103

Peru

Situche Central Appraisal


Block 39 Seismic Acquisition

KRG (Kurdistan) region of northern Iraq

• 40% working interest in Block 44

• Sarqala-1 drilled with oil & gas indications; currently suspended

• Kurdamir-1 spudded in May 2009

– Significant gas condensate discovery

• Decision to enter Block 39 PSC in 2Q 2010

– Potential 60% earned interest in Block 39

• 2D seismic acquisition completed on Block 39 in 2009

• Acquired operatorship in Block 9 (55% earned interest) and will commence 2D seismic acquisition in 2Q 2010

Talisman acreage

Block 39

Block 44Kurdamir-1

Kirkuk Field

Green Line

Sarqala-1

Block 9

Prospects

GSF Explorer

• Potential for giant fields

• 3D seismic acquisition completed on Pasangkayu and 2D on Sageri

• Two Pasangkayu wells in 2010

• First Sageri well (south of Exxon Sultan 1 – hydrocarbons present) to begin drilling in Q4 2010

• 11 prospects and leads

Indonesia – Makassar Straits

JSA: Joint Study AreaPSC: Production Sharing Contract

Talisman JSA

Talisman acreage

Sageri PSC

Sulawesi

Kalimantan

Makassar Strait

Sultan 1

Pasangkayu PSC


Indonesia – North Sumatra

Andaman III Seismic

• Awarded block Q3 2009

• Large gas/condensate prospects

• Close to infrastructure

− Arun LNG facility has significant excess capacity

• 3D seismic planned for 2010

• Exploration well planned for 2012

0 25 50 75 100Kms

Andaman III

Indonesia(Sumatra)

Arun LNG Plant

Talisman acreage

Malaysia – Sabah

• Awarded two PSC contracts with working interest of 70%

• Over 13,000 square kilometres of highly prospective shallow water acreage

• Designated operator in both blocks

• 3D seismic program planned for 2011

• Exploration drilling currently planned for 2012

0 25 50 75 100Kms

SB309

SB310

Malaysia

Murphy/Shell Fields: > 1100 MMBO rec.

Talisman acreage

Prospects and leads

Kinabalu Field:240 MMBO rec.

CoPi/Petronas Fields: > 6 Tcf rec.

Samarang Field:450 MMBO rec.


Vietnam - building an acreage position in the prolific Nam Con Son Basin

Talisman acreage

Block 15/2-01

Block 133

Block 134

Nam Con Son Basin

Cuu Long Basin

Hai Su Den

Bach Ho

Cuu Long Basin

• Continuing to appraise Hai Su Den

Nam Con Son Basin

• Talisman WI 38% (operator) farm-in Blocks 133/134 – added 3.3 Million gross acres

• Large gas potential allows Talisman to pursue gas-to-power strategy

• Proven hydrocarbon system in Nam Con Son blocks - Talisman prospective resource up to 2 tcf

Papua New Guinea

PNG Foreland Basin

• Gas aggregation strategy targeting 3-5 Tcf•

• Additional ten blocks acquired in 2009 - total 15 Million gross acres

• One offshore and six onshore discoveries

• Acquire approx. 1,000 km of 2D seismic and commence exploration and appraisal drilling in 2010

• Evaluate early condensate production scheme in 2010

0 60 120 180 240Kms

Talisman acreage

HighlandArea

Papua New Guinea

Pandora Gas Field Planned

LNG Plant

Lowland Area(ForelandBasin)


Key Historical Data2004 2005 2006 2007 2008

Daily production, before royaltiesCrude oil & liquids (mbbl/d) 228 250 262 241 224 Natural gas (mmcf/d) 1,259 1,319 1,342 1,265 1,246 Barrels of oil equivalent (mboe/d) 438 470 485 452 432

Daily production, after royaltiesCrude oil & liquids (mbbl/d) 193 213 217 203 187 Natural gas (mmcf/d) 1,014 1,043 1,091 1,017 992 Barrels of oil equivalent (mboe/d) 365 390 402 373 352

Proved reserves, before royaltiesCrude oil & liquids (mmbbl) 618 736 767 749 545 Natural gas (bcf) 5,223 5,417 5,403 5,464 5,338 Barrels of oil equivalent (mmboe) 1,362 1,488 1,639 1,667 1,434

Drilling activity, net wellsNorth America - Crude oil & liquids 137 171 194 128 91 North America - Natural gas 444 495 496 288 189 North America Total 581 666 690 416 280 North America - Drilling success (%) 94 97 98 98 100

International - Crude oil & liquids 57 51 65 73 18 International - Natural gas 3 5 18 11 9 International Total 60 56 83 84 27 International - Drilling success (%) 77 81 84 79 73

Net undeveloped land (thousands of acres)North America 5,508 5,588 7,923 9,559 9,786 International 8,808 13,484 11,048 12,948 16,443 Total 14,316 19,072 18,971 22,507 26,229


Key Historical Data2004 2005 2006 2007 2008

Ratios and Key Indicators (C$ millions, except per share)Cash flow 2,916 4,672 4,748 4,327 6,163 Net Income 654 1,561 2,005 2,078 3,519 Per Common Share

Cash flow 2.54 4.23 4.35 4.19 6.07 Net Income 0.57 1.41 1.84 2.01 3.47

Exploration & development spending 2,538 3,179 4,578 4,445 4,971 Acquisitions 330 3,170 204 317 452 Dispositions 888 22 872 1,473 100

Average Royalty Rate (%) 16 17 17 17 18 Unit operating costs ($C/boe) 7.26 8.41 9.98 12.14 13.57 Unit DD&A ($C/boe) 10.29 10.88 12.04 14.90 16.41 Return on capital employed (%) 11 19 19 18

Note: Return on capital employed = Net income plus tax effected interest / (average shareholders' equity + average debt)

Balance Sheet Info (C$ millions)Property, plant & equipment 10,101 13,806 17,278 17,763 19,487 Total assets 12,408 18,354 21,481 21,443 24,275 Long-term debt 2,457 4,263 4,560 4,862 3,961 Shareholders' equity 4,831 5,729 7,307 7,963 11,150

Share information, adjusted to reflect stock splitsCommon shares outstanding (millions) 1,125 1,099 1,064 1,019 1,015 TSX trading info

Average daily trading volume (thousands) 2,862 3,143 3,254 2,951 3,727 High (C$) 11.70 20.83 24.84 22.67 24.92 Low (C$) 7.89 10.50 16.12 16.90 8.28 Close (C$) 10.78 20.53 19.80 18.39 12.18

NYSE trading infoAverage daily trading volume (thousands) 744 1,384 2,139 2,115 4,248 High (US$) 9.55 18.08 21.62 22.08 25.71 Low (US$) 5.88 8.36 14.21 15.04 6.42 Close (US$) 8.99 17.63 16.99 18.52 9.99

Commodity InformationWTI (average US$/bbl) 41.40 56.70 66.25 72.31 99.65 NYMEX gas (Average US$/mmbtu) 6.09 8.55 7.26 6.92 8.95 US$/C$ exchange rate (year end) 0.8308 0.8577 0.8581 1.0120 0.8166

Realized product pricing, before hedging activities & after transportation costs (gross basis)Crude oil & liquids ($C/bbl) 46.57 61.92 68.75 73.78 96.43 Natural gas ($C/mcf) 6.02 8.03 6.95 6.73 9.01


AdvisoriesForward-Looking InformationThis 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 lookinginformation includes, among others, statements regarding: business strategy and plans; expected first production; planned and potential dispositions; planned drilling, development, redevelopment, sanctioning, and exploration; targeted drilling and completions costs; planned production growth, incremental production and future projects; forecasted free cash flow and netbacks; planned capital expenditures and program; planned prospective resource additions and expected prospect size; planned reduction of F&D and extension of reserves life; targeted EUR and IP; planned increases in operational efficiencies; planned seismic acquisitions; planned hedging programs; 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 2010 capital program as announced on January 11, 2010. Talisman has set its 2010 capital expenditure plans assuming: (1) Talisman’s production in 2010 will be broadly the same as 2009 at around 425,000 boe/d, excluding any sales in North America during the year; (2) a US $60/bbl WTI oil price for 2010; and (3) a US $3.50/mmbtu NYMEX natural gas price for 2010. Production estimates are subject to the timing of development activities and include the anticipated completion of planned dispositions. The completion of any contemplated disposition is contingent on various factors including market conditions, the ability of the Company to negotiate acceptable terms of sale and receipt of any required approvals of such dispositions.

Undue reliance should not be placed on forward-looking information. Forward-looking information is based on currentexpectations, estimates and projections that involve a number of risks which could cause actual results to vary and in some instances to differ materially from those anticipated by Talisman and described in this presentation. The material risk factors include, but are not limited to: operational risks in exploring for, developing and producing crude oil and natural gas, market demand and unpredictable facilities outages; risks and uncertainties involving geology of oil and gas deposits; theuncertainty of reserves and resources estimates, reserves life and underlying reservoir risk; the uncertainty of estimates and projections relating to production, costs and expenses; the impact of the economy and credit crisis on the ability of the counterparties to the Company’s commodity price derivative contracts to meet their obligations under the contracts; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; fluctuations in oil and gas prices, foreign currency exchange rates and interest rates; the outcome and effects of any future acquisitions and dispositions; health, safety and environmental risks; uncertainties as to the availability and cost of financing and changes in capital markets; risks in conducting foreign operations; changes in general economic and business conditions; uncertainties as to the availability and cost of financing and changes in capital markets; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; and results of the Company’s risk mitigation strategies, including insurance and hedging activities. The foregoing list of risk factors is not exhaustive. Forward-looking information is based on the estimates and opinions of the Company’s management at the time the statements are made. The Company assumes no obligation to update forward-looking statements should circumstances or management’s estimates or opinions change, except as required by law.

Oil and Gas InformationReservesCanadian securities regulatory authorities have granted Talisman an exemption which permits Talisman to provide certain disclosure in accordance with U.S. disclosure requirements. In Talisman’s Annual Information Form dated March 9, 2009, the Company discloses 2008 year end proved reserves in accordance with US disclosure requirements and also voluntarily discloses 2008 year end proved, probable and proved plus probable reserves in accordance with Canadian disclosure standards under National Instrument 51-101 ("NI 51-101"). This presentation includes 2008 year end reserves determined in accordance with NI 51-101 which are based on forecast prices. Information on the differences between the U.S. requirements and the NI 51-101 requirements is set forth under the heading “Note Regarding Reserves Data and Other Oil and Gas Information” in Talisman’s Annual Information Form. The exemption granted to Talisman also permits it to disclose internally evaluated reserves data. While Talisman annually obtains an independent audit of a portion of its reserves, no independent qualified reserves evaluator or auditor was involved in the preparation of Talisman’s reserves data disclosed in this presentation.

ResourcesIn this presentation, Talisman also discloses contingent resources, prospective resources and OGIP as at December 31,2008. Talisman also discloses prospective undiscovered resource additions. Where not otherwise indicated, the contingent and prospective resources included in this presentation are best estimates. Information on the high and low estimates can be found at the end of these advisories.


AdvisoriesContingent resources are defined as those quantities of petroleum estimated, as of a given date, to be potentiallyrecoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. In North America, the contingencies that prevent the resources from being classified as reserves are: additional testing, production and performance appraisal activities; demonstration of economic viability; facilities and egress; access to equipment and services; frac technology; commodity prices and regulatory approvals. In this presentation, Talisman’s disclosures of contingent resources are stated as best case estimates. A best case estimate lies in between a high case estimate and a low case estimate. 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 fromundiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Talisman’s prospective resources in the Nam Con Son Basin are partially risked for chance of discovery, but have not been risked for chance of development. If a discovery is made, there is no certainty that it will be developed or, if it is developed, there is no certainty as to the timing of such development. Where not otherwise indicated, references to “resource adds” in this presentation refer to unrisked prospective resources.

OGIP is defined as original gas in place and is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of gas that is estimated, as of a given date, to be contained in known accumulations, prior to production. All OGIP estimates in this presentation are discovered with the exception of the OGIP estimate for Quebec which is undiscovered. There is no certainty that any portion of the Quebec resources will be discovered. A recovery project cannot be defined for this volume of undiscovered original gas in place at this time. There is no certainty that it will be commercially viable to produce any portion of the resources.

Gross ProductionWhere not otherwise indicated, production volumes are stated on a gross basis, which means they are stated prior to thededuction of royalties and similar payments. In the U.S., net production volumes are reported after the deduction of these amounts. U.S. readers may refer to the table headed “Continuity of Proved Net Reserves” in Talisman’s Annual Information Form dated March 9, 2009 for a statement of Talisman’s net production volumes.

Boe/Mcfe conversionThroughout this presentation, barrels of oil equivalent (boe) is calculated at a conversion rate of six thousand cubic feet (mcf) of natural gas for one barrel of oil and is based on an energy equivalence conversion method. This presentation also includes references to mcf equivalent (mcfe) which are calculated at a conversion of rate of one barrel of oil to six thousand cubic feet of gas (1 bbl:6 mcf). Boes and mcfes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl and an mcfe conversion ratio of 1 bbl:6 mcf are based on an energy equivalence conversion method primarily applicable at the burner tip and do not represent a value equivalency at the wellhead.

Reserves life indexTalisman discloses reserves life index (“RLI”) for each of the Company, North America, the North Sea and Southeast Asia. 1P RLI for 2008 is calculated by dividing the 2008 year end proved reserves at forecast prices by the Company’s 2008 gross production. 2P RLI for 2008 is calculated by dividing the 2008 year end proved plus probable reserves at forecast prices by the Company’s 2008 gross production.

F&DIn this presentation, Talisman discloses historic 5 year average finding and development costs per boe (“F&D”) for each of the Company, North America, North Sea and Southeast Asia. The annual F&D costs for the Company and each area by year, for the last 3 years included in the 5 year average are as follows: Company: 2008-$42.83, 2007- $25.85, 2006-$21.70; North America: 2008-$34.39, 2007-$22.62, 2006-$22.96; North Sea: 2008-$38.81, 2007-$28.77, 2006-$18.47; Southeast Asia: 2008-$166.03, 2007-$20.11, 2006-$124.77. Historic F&D is calculated by dividing the total costs incurred in oil and gas activities (excluding acquisition costs) by the gross proved reserves additions which include additions and revisions of gross proved reserves. Gross proved reserves include proved developed and proved undeveloped reserves and represent Talisman’s working interest. Various factors impact both historic reserve additions including: successful wells, improved recovery, new sales contracts and revisions to the economic parameters of a field as a result of changes in commodity prices, development costs or operating costs. All 2008 F&D numbers exclude the impact of price revisions on reserves resulting from SEC year end prices in 2008. F&D is used by the Company to determine the cost of reserves additions in a period. Talisman’s reported F&D may not be comparable to similarity titled measures used by other companies. It should be noted that F&D is a measure that has limitations. As an annual measure, the ratio is limited because it may vary widely, based on the extent and timing of new discoveries, project sanctioning and capital expenditures. The Company uses a 5


Advisoriesyear average F&D measure to reduce the inherent variability of an annual F&D measure, which may better represent the underlying trend in F&D. F&D may not reflect full cycle finding and development costs. The predictive and comparative value of F&D is limited for the aforementioned reasons.

NetbacksTalisman also discloses netbacks for the UK, North America and Corridor in this presentation. Netbacks per boe arecalculated by deducting from the sales price associated royalties, operating and transportation costs.

Analogous InformationThroughout this presentation, Talisman discloses analogous information as defined by NI 51-101 which is relevant to the Company for comparative purposes. The Company cannot confirm that the analogous information was prepared by a qualified reserves evaluator nor that it was prepared in accordance with the COGEH Handbook.

Canadian Dollars and GAAPDollar amounts are presented in Canadian dollars, except where otherwise indicated. Unless otherwise indicated, thefinancial information is set out in accordance with Canadian GAAP which may differ from U.S. GAAP. See the notes to Talisman’s Annual Consolidated Financial Statements for the significant differences between Canadian and U.S. GAAP.

Non-GAAP Financial MeasuresIncluded in this presentation are references to financial measures used in the oil and gas industry such as cash flow, freecash flow and ROACE. These terms are not defined by GAAP in either Canada or the U.S. Consequently, these are referred to as non-GAAP measures. Talisman’s reported results of cash flow, free cash flow and ROACE may not be comparable to similarly titled measures reported by other companies. Cash flow represents net income before exploration costs, DD&A, future taxes and other non-cash expenses. Cash flow is used by the Company to assess operating results between years and between peer companies using different accounting policies. Cash flow should not be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net income as determined in accordance with Canadian GAAP as an indicator of the Company’s performance or liquidity. A reconciliation of cashprovided by operating activities to cash flow for the years ended December 31 2008, 2007 and 2006 is located at page 46 of the Company’s 2008 Annual Report Summary located at www.talisman-energy.com. The presentation also discloses free cash flow for the UK and Southeast Asia reporting segments, which represents cash flow less capital expenditures, excluding acquisitions. Free cash flow is used by management to measure the underlying cash generating ability of these segments. ROACE (return on average capital employed) is used to measure returns realized by the Company on capital employed and is calculated for each region by dividing normalized after-tax income by average capital employed.

Reserves EstimatesSE Asia:PM-3 CAA: 1P 89mmboe, 2P 154mmboeSong Doc: 1P 2.7mmboe, 2P 5.4mmboeCorridor: 1P 1.73 tcfe, 2P 2.4 tcfe, P3 660 bcfePM-3 IOR: 1P 0 mmboe, 2P 15 mmboe, 3P, 53 mmboeCorridor New Contracts: 1P 15mmboe, 2P 41mmboeHSD/HST: 1P 0mmboe, 2P 52mmboe (not yet sanctioned)UK and Norway:Auk South: 1P 23mmboe, 2P 29mmboeAuk North Target Area: 1P 13mmboe, 2P 17mmboeAuk South Target Area: 1P 23mmboe, 2P 29mmboeMonarb Hub: 1P 23mmboe, 2P 72mmboe, P3 40mmboeFulmar Hub: 1P 83mmboe, 2P 112mmboe, P3 42mmboeAuk South: 1P 23mmboe, 2P 29mmboeAuk North: 1P 13mmboe, 2P 17mmboeBurghley: 1P 2mmboe, 2P 3mmboeAffleck: 1P 4mmboe, 2P 9mmboeYme: 1P 28mmboe, 2P 43mmboe


Notes

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talisman - corporate presentation jan 2010

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