operations: three core areas + global exploration. asia: song doc, northern fields gas and oil •...

Operations: three core areas + global exploration. . .

North America

North SeaSoutheast Asia

Growth through shale gas

Sustainable cash flowOil price leverage

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 Asia25%

Other4%

North America

40%

North Sea31%

Oil50%

Gas39%

Oil Linked Gas11%

SE AsiaNorth SeaConventional

Commodity Price US$/mmbtu

$4

$6

$9

Commodity Price US$ WTI

$40

$60

$90

Unconventional

2009 Production 2009 Commodity Exposure

April 2010 www.talisman-energy.com Page 1 of 31

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

% Undeveloped gas reserve bookings

Strategy drives lower F&D costs. . .

59

494645

30

Unconventional Gas PeersTalisman North America

Talisman total F&D Cost (C$/boe)(Excluding price revisions)

24

43

2009

2008

43% Reduction


. . .and longer reserve life

North America

North Sea

SE Asia

10

11

7

18

13

15

Typical Industry Unconventional 1P Range

15–20

1P

2P

Reserve Life Index 2009Years

2009 Year End 2P Reserves 2.3 Billion boe

Oil39%

Gas52%

ShaleGas9%

People and organizational changes

• Building the Senior Team− Five new EVP’s− New SVPs Shale and HSSE/OI, VP HR − New country managers in Malaysia and Papua New Guinea

• 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− NA shale


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, Non-core conventional, unconventional and midstream

• 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, over 290 wells drilled/planned• Marcellus 2009 Exit rate: 65 mmcfe/d• Montney Shale 2009 Exit rate: 15 mmcfe/d

• $3.4 Billion, including land

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

Kurdamir• Successful appraisals: 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 by year end 2009

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)Name

Talisman continues to look at opportunities to focus the portfolio, primarily North America conventional


Strong investment grade ratings. . .

0.0 x

0.5 x

1.0 x

1.5 x

2004 2009

Debt to Trailing Twelve Month Cash FlowRatio

0%

20%

40%

60%

2004 2009

Debt to Debt + EquityPercentage

$0

$1

$2

$3

$4

$5

$6

$7

$8

$9

$10

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

3.5x

4.0x

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

Average = 1.72x

Talisman

Debt to Trailing Twelve Month Cash Flow

Peer companies

Talisman

Available Liquidity

Average = $3.5 billion

C$ billion


New Growth - North American shale gas plays

Québec• Unproven play• 756,000 total net acres

Montney Shale• Proven and expanding play• 272,000 total net acres• 168,000 tier 1 net acres• 3,000 tier 1 drilling locations

Marcellus• Proven and expanding play• 512,000 net acres in NY• 218,000 tier 1 net acres in PA• 2,000 tier 1 PA drilling locations

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

The Marcellus Shale – large contiguous land base

Marcellus Development Metrics

Tier 1 Net Acres – PA 218,000

Net Acres – NY 512,000

Spacing (acres/well) 80

• Focus on PA – 2,000 potential tier 1 drilling locations

• Exit rates: 2009 – 65 mmcf/d; 2010 – 250-300 mmcf/d

• 2010 plan: drill 170 net wells, complete and tie-in 145

• D&C optimization ongoing

• Water management plans in place for 2010

• Majority of permitting in place for 2010

• Egress ramping up to 600 mmcf/d

Talisman Updates

Marcellus Shale FairwayTLM Shale AcreageMajor Pipelines

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


Talisman Updates

• Development of Farrell Creek and Greater Cypress in 2010

• Continue piloting in 2010

• 3,000 potential tier 1 drilling locations

• 2010 exit rate: 40 – 60 mmcf/d

• 2010 plan: drill 25 development wells, 10-15 pilot wells

• Excellent industry and stakeholder relationships

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

• Egress capacity of 320 mmcfe/d

Montney Shale - proven and expanding play

168,000Tier 1 Acreage

Montney ShaleKey Metrics

272,000Net Acres

80Spacing (acres/well)

Pilot & Development


• 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

ABBC

TLM Montney LandMontney ShaleMontney CoreMajor Pipelines

Talisman Updates

• Largest land position in most prospective shale fairway

• Proven we can systematically fracture Utica formation

• Actively building government and industry relationships

• Excellent proximity to premium markets

• Earning wells demonstrate opportunity

Proving Québec - extensive land position


4Horizontal Well Tests - 2010

6Gross Earning Wells drilled

Available on TQMSecured Egress Capacity

756,000Net 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)


SE Asia provides access to large-scale opportunities

Development

Malaysia: PM3 IOR

Vietnam: Cuu Long Basin Hai Su Den

Indonesia: Corridor Jambi Merang

Exploration

Development

ExplorationIndonesia

Papua New Guinea

Australia

PhilippinesThailandVietnam

Malaysia

Vietnam: Nam Con Son

Indonesia: Makassar Strait

PNG: onshore/offshore

Other: offshore Sabah, Aceh

0

40

80

120

160

2002 2009 2013

• PM-3 IOR

• HSD/HST oil

• Kitan oil

• Northern Fields oil

Growth in SE Asia ca. 8 - 10% per annum over next 4 years

Oil

Gas

Rate (mboe/d)

30

680CAPEX

($C Millions)767512331305235316269

(82) 5122361220195(82)Free Cash Flow

($C Millions)

• Corridor additional gas

• Northern Fields gas

• Jambi Merang

• PNG gas condensate

Future projectsSE Asia production

16%

ca. 8-10%

Vietnam

• Nam Con Son gas

• Cuu Long

Indonesia

• Makassar Strait

• Tangguh Phase 2

• Andaman III Block

Malaysia

• Sabah Blocks

Papua New Guinea

• Foreland Gas Commercialization


GSF Explorer

• Potential for giant fields in emerging new basin

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

• Two Pasangkayu wells planned in 2010

• Sageri well planned in 2011

• 9 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 in 2009

• Large gas/condensate prospects identified

• 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 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

• 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 2-4 tcf

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

• 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)

Exploration – Building the portfolio. . .

SE Asia

South America

NorthSea

KRG (Kurdistan)

European Shale Gas


2009-2013 Exploration targets:

• ca. 600-650 mmboe resource adds in 5 years

• Less than $5/boe Finding Cost

• ca. C$600-700 MM capital budget per year

0%

50%

100%

2007 2008 2009 2010E 2011E

0

20

40

60

80

Exploration Capital Expenditures & Average Prospect Size

Percent of Capital Expenditures

. . .and Positioning for Renewal

mmboe

Support Existing Production Area

Build New Production Area

Average prospect size (working interest resource estimate)

2010 2013

Foothills

Foreland

Heavy Oil

Exploration Drilling Timeline

Foothills (4 Blocks)

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

− Appraisal program in late 2010

• Captured significant land position in foothills

Foreland (5 Blocks)

• Two wells 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– 15 prospects and leads

• Successful appraisal at Situche Central in 2009

• Block 101 exploration well planned for 2010

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

• Option to enter Block 39 PSC in 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 2010

Talisman acreage

Block 39

Block 44Kurdamir-1

Kirkuk Field

Green Line

Sarqala-1

Block 9

Prospects


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, Burghley

• Corridor additional gas sales

20102009

DivestmentsContinue non-core divestments

• Pasangkayu (2 wells)

• Runtusapa

• K-44 Well 3

• PNG Lowland (3 wells)

• Grevling Appraisal

UnconventionalMarcellus

Montney Shale

Quebec

• Three to six rig development

− Drilled 53 wells

• Three pilot areas

• Commence horizontal pilots

• Six to ten rig development

− Drill 170 net wells

• Drill 25 horizontal development wells and 1 10-15 pilot wells

• Complete and test four horizontal pilot wells

Continuing successful execution

• Strategic Transition Continues− Accelerate portfolio transition− Maintain focus on returns and profitability− Geographic and commodity diversity retained

• Delivering on Promises− Production targets met− Improving F&D costs − Focused operating cost reduction in the North Sea

• New Strategy is working− NAO transition to shale− SE Asia growth underpinned− International exploration beginning to show results

• Strengthening Internal Capability− Organizational change− Improved functional capabilities

• Health, Safety and Environment• Drilling• Information Technology• Performance management• Capital management• Human Resources


Appendix

Priorities for 20101. 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 2H 2010• NA shale gas emerging as growth driver

2010 Corporate Outlook


2010 Activity

North America• Marcellus shale: drill 170 net wells

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

• Quebec: continue piloting activity

• Non-core conventional asset dispositions

North Sea• Auk North & South, Burghley, Yme development

• Infill drilling

SE Asia• Kitan development

• Malaysia infill drilling and platform upgrades

• PNG appraisal

• Jambi Merang development

• Evaluation of HST/HSD early production scheme

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 2009 2010E

Cash Capital Expenditure

C$ Billion

5.2

4.3

4.9

Other


Hedging Program

February 26, 2010 Disclosure

1H 2010

• 335 mmcf/d @ ~C$6/C$7.25 (AECO)2010

75,000 bbl/d in collars

• 28,000 bbls/d @ ~US$52/US$80

• 25,000 bbls/d @ ~US$71/US$90

• 22,000 bbls/d @ ~US$50/US$602011

• 95 mmcf/d @ ~US$6/US$6.50 (NYMEX)

2H 2010

• 240 mmcf/d @ ~C$6/C$7.50 (AECO)

• 95 mmcf/d @ ~US$6/US$7 (NYMEX)

North American GasOil

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 2009April 2010 www.talisman-energy.com Page 17 of 31

0

1

2

3

4

5

6

7

0 50 100 150 200 250 300 350 400 450

Days

Top 5 Wells

200 Day Average (11 Wells)

First Well

2 Bcf

3.5 Bcf

5 Bcf

Marcellus Shale - demonstrating ability to execute

2.3 – 5.0

3.0 – 6.0

3.4 – 5.5

65

53

2009

3.0

3.5

3.8

250 - 300

214

2010Target

Horizontal Well Metrics

4# Wells Drilled (Gross)

2008

2.5

3.3

6.5

5

30 Day IP per Well (mmcfe/d)

EUR per Well (bcfe)

D&C Cost per Well (US$ Million)

Exit Production Rate (mmcf/d)

• 27 horizontal wells on stream (23 Op + 4 Non-Op)

• 2010 program has commenced with six rigs, plan to exit with 10 rigs

Rate (mmcf/d)

Pennsylvania Horizontal Wells

Operational Highlights

• Lean operations

• Pad drilling and pre-set rigs

• Optimizing water management plan

• Supply management negotiations

• Last five wells in 2009: D&C Costs = ~ $4 million

Marcellus Shale – driving to top tier execution

3.0

4.0

5.0

6.0

7.0

8.0

D&C Cost ReductionsD&C Cost (US$ MM)

First Well

0

2

4

6

8

10

12Most Recent

Well

Middle Well

0.5 1.0 1.5 2.0 2.5 3.0 3.5

Drilling Performance – Cost vs. Depth(ft thousands)

US$ MM

Key cost reduction levers

Fourth Well Last WellFirst Well Target

US$5.6US$7.5 US$4.3 US$3.8

Stage Pad DrillingCompletions Logistics

Invert Drilling Fluid

Supply Chain

Data acquisition and well evaluation

Applied Drilling LearningsImproved completion techniques

Hole stability management

Operational ImprovementsFacility Standardization


Upper Montney

Lower Montney

Montney Shale – early success

GR NeutronDensity

GasSaturationPorosity

Operational Highlights

• Target 5 bcf EUR and 4.5 mmcf/d IP per well

• Moved two pilot areas into development for 2010

• Piloting three areas in 2010

• Drill first multilaterals in 2010

Metrics 20092010

Target

Number of Wells Drilled (Gross) 19 35 - 40

Exit Product Rate (mmcfe/d) 15 40 - 60

Number of Pilot Areas 3 3

• 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

1513

18

15

Total North America

North Sea SE Asia

5.0

7.9

21.1

11.5

SE Asia is a great place to do business

2P Reserve Life IndexYears

OPEX ($/boe)2005–2009 Average


• 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 Q3 2009

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

• PM-3 CAA working interest 2P reserves: 161 mmboe

Malaysia/Vietnam - PM-3 CAA 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

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 310 mmcf/d in 2009

• Working Interest 2P reserves: 2.3 tcfe with additional P3 reserves of 860 bcfe

• 2P Reserve life: 18 years


. . .strong growth with good price realizations and netbacks

Corridor Gas Productionmmcf/d

0

50

100

150

200

250

300

350

5yr Average Corridor Netback Realization($/mcf)

19%

2002 2009 Realized Price

Netback

$8.61

$5.03

Opex

$2.73

Royalties

$0.84

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

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

• 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 facility upgrade

• Offsets natural field production decline and provides access to new reserves

• Targeting 53 mmboe 3P reserves and additional prospective resources


Indonesia – Jambi MerangSignificant near term production

• Talisman working interest 25% (joint operator with Pertamina)

• Two gas condensate discoveries (Pulau Gading & Sungai Kenawang)

• Talisman working interest production ramping up to 11,000 boe/d over three years starting in 2011

• Working interest 2P reserves up to 28 mmboe

• Strategically located near major pipelines and adjacent to Corridor South Sumatra

Corridor

Talisman acreage

Discoveries

0 30 60 90 120 Km

Sungai KenawangPulau Gading

Gas to Singapore

Gas toDuri

Gas toJava

Geragai Facility

Jambi Merang

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 (central fault Block B only) and HST development

• Sanction late 2010 or 2011 targeting an initial 30 – 40 mmboe 2P reserves

• First oil in late 2012 or 2013 with peak production around 25,000 - 30,000 boe/d (gross)

• Obtain HSD production history to assess reservoir potential before any further development activity

production

Block 15-2/01 JOCHSD

Gas Export HST

Legend

EPS Platform

Oligocene Clastic Reservoir

Basement Reservoir

Potential Future Development area


0

25

50

75

100

2005 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 2009

% ROACE

ROACE

Free Cash Flow(C$ Billion)

Netbacks and ROACEC$/boe

Despite low commodity prices in 2009, UK remained a Free Cash Flow generator

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

Central North Sea

Flotta Hub

46

11

7

13

24

MonArb Hub

Fulmar Hub

2009Production

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

37


• 2P 21 mmboe reserves

• Successfully completed two subsea horizontal producers in 2009

• Drill and complete third subsea horizontal, 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

Auk North Target Area

Auk South Target Area

Auk South Redevelopment• Auk rejuvenation to access

36 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

Auk North Development

AukDrained Area

FulmarHub

NorthernNorth Sea

S th

CentralNorth Sea

Fulmar Hub

Auk

Clyde

Fulmar

Orion

Halley

Norw

ay

Affleck

Central North Sea Exploration focus drives expansion of strategic hubs

199

40

112

FulmarMonArb2009 year end reserves and resources

(mmboe)

218Unrisked prospective resource

43P3 reserves

882P reserves

Arbroath

Montrose

Arkwright

Wood

Brechin

Exploration2 wells drilled(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

• Appraisal well planned for 2010

• 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


Key Historical Data2009 2008 2007 2006 2005

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

Daily production, after royaltiesOil & liquids (mbbl/d) 181 187 203 217 213 Natural gas (mmcf/d) 1,088 992 1,017 1,091 1,043 Barrels of oil equivalent (mboe/d) 352 373 402 390

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

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

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

Net undeveloped land (thousands of acres)North America 9,145 9,786 9,559 18,886 5,588 International 26,208 16,443 12,948 85 13,484 Total 35,353 26,229 22,507 18,971 19,072


Key Historical Data2009 2008 2007 2006 2005

Ratios and Key Indicators (C$ millions, except per share)Cash flow 3,961 6,163 4,327 4,748 4,672 Net Income 437 3,519 2,078 2,005 1,561 Per Common Share

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

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

Average Royalty Rate (%) 15 18 17 17 17 Unit operating costs (C$/boe) 12.91 13.57 12.14 9.98 8.41 Unit DD&A (C$/boe) 17.36 16.44 14.74 12.22 10.88 Return on capital employed (%) 4 27 18 19 19

Balance Sheet Info (C$ millions)Property, plant & equipment 18,914 18,540 16,363 16,655 13,806 Total assets 23,618 24,275 21,420 21,481 18,354 Long-term debt (including current portion) 3,780 3,961 4,862 4,560 4,263 Shareholders' equity 11,111 11,150 7,963 7,307 5,729

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

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

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

Commodity InformationWTI (average US$/bbl) 61.79 99.65 72.31 66.25 56.70 NYMEX gas (average US$/mmbtu) 4.05 8.95 6.92 7.26 8.55 US$/C$ exchange rate (year end) 0.9555 0.8166 1.0120 0.8581 0.8577

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

2007 and 2008 have been restated for operations classified as discontinued in 2009.Notes: Return on capital employed = Net income plus tax effected interest / (average shareholders' equity + average net debt)


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 looking information includes, among others, statements regarding:

business strategy, priorities and plans; expected first production; planned and potential dispositions; planned drilling, development, redevelopment, piloting, sanctioning, appraisals, upgrades, egress and exploration; estimated supply and finding costs; planned production and production growth, incremental production and future projects; asset life, costs and returns; planned capital expenditures and program; planned prospective resource additions and expected prospect size; planned reduction of F&D and extension of reserves life; planned profitable growth; planned hedging programs; targeted drilling and completions costs; targeted EUR and IP; increases in operational efficiencies; reserves life and remaining resources; improved average oil recovery factors; forecasted cash flow; planned seismic acquisitions; and planned 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 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.

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 SEC.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.

The completion of any contemplated acquisition or disposition 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 acquisition or disposition.


AdvisoriesOil and Gas Information

ReservesNational 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 disclosure in accordance with the US disclosure requirements, in order to provide for comparability of oil and gas disclosure with that provided by US and other international issuers. Accordingly, some of the reserves data and other oil and gas information included in this Presentation are disclosed in accordance with US disclosure requirements. Such information, as well as the information that Talisman discloses in the future in reliance on the exemption, may differ from the corresponding information prepared in accordance with NI 51-101 standards.

The primary differences between the current US requirements and the NI 51-101 requirements are that (i) SEC rules require disclosure only of proved reserves, whereas NI 51-101 requires disclosure of proved and probable reserves; (ii) SEC rules require reserves to be cash flow positive on an undiscounted basis, whereas NI 51-101 requires reserves to show a hurdle rate of return; and (iii) SEC rules require that reserves and the associated future net revenue be estimated using historic average annual prices, whereas NI 51-101 requires disclosure of reserves and the associated future net revenue using forecast prices.

The 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.

Talisman defines “Tier 1” acreage as top quality acreage with an expected full cycle breakeven of approximately $4/mcf.

ResourcesIn this presentation, Talisman also discloses prospective resources as at December 31, 2009. Talisman also discloses prospective undiscovered resource additions. Where not otherwise indicated, the prospective resources included in this presentation are best estimates.

Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Talisman’s prospective resources in the Nam Con Son Basin are partially risked for chance of discovery, but have not been risked for chance of development. If a discovery is made, there is no certainty that it will be developed or, if it is developed, there is no certainty as to the timing of such development. Where not otherwise indicated, references to “resource adds” in this presentation refer to unrisked prospective resources.

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


Advisories Reserves life indexTalisman discloses reserves life index (“RLI”) for each of North America, the North Sea and Southeast Asia. 1P RLI for 2009 is calculated by dividing the 2009 year end proved reserves at SEC historic average annual prices by the Company’s 2009 gross production. 2P RLI for 2009 is calculated by dividing the 2009 year end proved plus probable reserves at SEC historic average annual prices by the Company’s 2009 gross production.

F&DIn this presentation, Talisman discloses year over year finding and development costs per boe (“F&D”) for 2008 and 2009 for the Company. The annual F&D costs for the Company, for the last 3 years, and historic 3 year average, are as follows: 2009 - $24.30, 2008 - $42.87, 2007- $33.69, 3 year average - $32.38. 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 non-price related 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. 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. 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, and Corridor in this presentation. Netbacks per boe are calculated 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, the financial information is set out in accordance with Canadian GAAP which may differ from U.S. GAAP. See the notes to Talisman’s Annual Consolidated Financial Statements for the significant differences between Canadian and U.S. GAAP.

Non-GAAP Financial MeasuresIncluded in this presentation are references to financial measures used in the oil and gas industry such as free cash flow and ROACE. These terms are not defined by GAAP in either Canada or the U.S. Consequently, these are referred to as non-GAAP measures. Talisman’s reported results of free cash flow and ROACE may not be comparable to similarly titled measures reported by other companies. The presentation discloses free cash flow for the UK and Southeast Asia reporting segments. Free cash flow is used by management to measure the underlying cash generating ability of these segments. Free cash flow for the UK and South East Asia (UK- $359 million; SE Asia - $ 30 million) represents net income before exploration costs, DD&A, future taxes and other non-cash expenses (UK - $1,038 million; SE Asia - $709 million), less capital expenditures before acquisitions (UK - $679 million; SE Asia - $ 680 million).

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:Corridor: 1P 1.7 tcfe, 2P 2.3 tcfe, 3P 3.2 tcfePM-3 IOR: 1P 7.3 mmboe, 2P 32 mmboe, 3P 53.2 mmboe

UK and Norway:Monarb Hub: 1P 18 mmboe, 2P 88 mmboe, 3P 131 mmboeFulmar Hub: 1P 73 mmboe, 2P 112 mmboe, 3P 152 mmboe


operations: three core areas + global exploration. asia: song doc, northern fields gas and oil •...

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