1

Credit Suisse Energy SummitFebruary 4, 2010

Brian BurdenChief Financial Officer

2

This presentation may contain forward-looking statements, including statements regarding the business and anticipated financial performance of TransAlta Corporation. All forward-looking statements are based on our beliefs and assumptions based on information available at the time the assumption was made. These statements are not guarantees of our future performance and are subject to a number of risks and uncertainties that may cause actual results to differ materially from those contemplated by the forward-looking statements. Some of the factors that could cause such differences include cost of fuels to produce electricity, legislative or regulatory developments, competition, global capital markets activity, changes in prevailing interest rates, currency exchange rates, inflation levels, unanticipated accounting or audit issues with respect to our financial statements or our internal control over financial reporting, plant availability, and general economic conditions in geographic areas where TransAlta Corporation operates. Given these uncertainties, the reader should not place undue reliance on this forward-looking information, which is given as of this date. The material assumptions in making these forward-looking statements are disclosed in our 2008 Annual Report to shareholders and other disclosure documents filed with securities regulators.

Unless otherwise specified, all dollar amounts are expressed in Canadian dollars.

Forward looking statements

3

Value Proposition & Strategy Markets & ContractingFinancial outlookGrowth strategyInvestment Highlights – 2010+

Outline

4

Wholesale generator & marketer in Western Canada and U.S.; renewable focus across Canada

Low to moderate risk profile

Low cost, predictable operations

Financial strength

Deep pipeline of low carbon growth opportunities

Environmental leadership

UNITED STATES

CANADA

AUSTRALIA

Sustainable & consistent shareholder value creation

271 MW

Generation Facilities:

Coal-fired under construction

Coal-fired plants

Gas-fired plants

Hydro plants

Wind-powered plants

Wind under construction

Geothermal

4,967 MW

1,843 MW

893 MW

883 MW

189 MW

164 MW

Biomass 25 MW

Net generation in operation 8,775 MW

Hydro under development 18 MW

A sound strategy

5

0

500

1,000

1,500

2,000

TA GLH.UN BAM.A EMA FTS IEF.UN TRP BPT.UN EP.UN

Executing on our strategy

Over $1.8 billion invested in

renewable energy in 2009

Renewable CapacityIn Canada(MW)1

1 Based on renewable generation in Canada only

Wind Hydro Biomass

Canada’s leading provider of renewable energy

Renewables will account for almost a quarter of TransAlta’s fleet in 2012

Coal57%Gas

21%

Renewables22%

Coal55%Gas

21%

Renewables24%

20122010

6

Executing on our strategy

2010 by the numbers

EBITDA growth generated from renewables should drive multiple expansion

Coal52%

Gas20%

Renewables28%

Coal53%

Gas25%

Renewables22%

2010 2012

89% contracted for 2010, leverage to power price recovery in key markets

Earnings growth – Return to low double digit earnings growth off of 2009

$850 - $950 million cash flow from operations

$300 - $400 million of free cash to be generated through to 2012

7

(2,000)-

2,0004,0006,0008,000

10,00012,00014,000

2007

2008

2009

2010

2011

2012

2013

0%2%4%6%8%10%12%14%16%

Additional Adjusted CapacityExisting Adjusted CapacityPeak Demand based Reserve MarginPeak Demand

MWsReserve Margin

Market outlook: Alberta

Forward prices are soft but longer-term fundamentals of the Alberta market remain strong; oil sands recovery will drive load growth

(CAD$/MWh)

Figures as of January 14, 2010

Reserve margins

Expect demand to grow at ~2% per year for the next three years

Power prices

Forward market driven off of soft natural gas pricesNatural gas prices likely to remain low out to 2011+ $1/GJ = ~ $8 / MWh

Actuals Current Market

$40$50$60$70$80$90

$100

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

8

15,00017,00019,00021,00023,00025,00027,00029,000

2007

2008

2009

2010

2011

2012

2013

2014

20%25%30%35%40%45%50%55%60%65%70%

Additional Adjusted CapacityExisting Adjusted CapacityAvg. Demand based Reserve MarginAverage Demand

Alberta reserve margins expanding as load remains flat; economic and oil sands recovery needed to drive load growth

MWsReserve Margin

Market outlook: PacNW

Reserve margins to increase in the short-term due to demand destruction; forward pricing continues to track natural gas prices

(USD$/MWh)

Forward prices track natural gas movements+ $1 / MMBtu = ~ $7 / MWh

Reserve margins Power prices

Expect demand to grow at ~1% per year for the next three years

Actuals Current Market

Figures as of January 14, 2010

$30

$40

$50

$60

$70

$80

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

9

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2009 2010 2011 2012

Contracted Open

Alberta PPAs and long-term contracts provide solid base for stable earnings and support TransAlta’s low to moderate risk business strategy

Total MWs

Approx. target contracting level 90%

PPAs, long & medium-term contracts

PPAs, long and medium-term contracts account for

~70% of generationAverage contract life ~12 years

Merchant contracting strategy targets 25% / yr

Protecting the value of TransAlta’s generation and investment grade balance sheet

10

0

500

1,000

1,500

2,000

2,500

3,000

3,500

2009 2010 2011 2012

Contracted To be contracted Open

2009Contracts

2011 Contracts

2010 Contracts

2009 Contracts

2010 Contracts

2009 Contracts

2008Contracts

2008 Contracts

Merchant MWs

Approx. levels only

Merchant MWs

Merchant hedging strategy designed to minimize impacts of adverse market conditions while allowing for upside potential

Approximate target level - 90%

AB: $65 - 70PACNW: $60 - 65

AB: $65 - 70PACNW: $55 - 60

AB: $60 - 65PACNW: $55 - 60

Avg.Contract Price

AB: $50 - $55PACNW: $50 - 55

772012

AB: $45 - $50PACNW: $45 - 50

832011

AB: $45 - $50PACNW: $45 - 50

892010

Current Forward Price

(Jan 14, 2010)

~%Contracted

Year

Capacity adjustments

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$1,000

$200

$600

$450

$750

Dividends

Announced growthcapexSustaining capex

NCI

Available

$3,000 Cash flow fromoperations

2010 - 2012Capital Allocation Plan

Dividend

Provide shareholders sustainable dividend

growth

Share Buyback

Provide shareholders incremental return of

capital in absence of value-creating investment

opportunities

Growth Investment

Projects must deliver unlevered, free cash, after

tax IRR >10%

Portfolio Optimization

Divest or improve non-core and underperforming

assets

Sources of capital: ~$3.0 billion

Uses of capital : ~$3.0 billion

We remain disciplined in how we manage our balance sheet and allocate capital

Capital plan and funding

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35%

40%

45%

50%

55%

60%

2006 2007 2008 2009e

0%

5%

10%

15%

20%

25%

30%

35%

2006 2007 2008 2009e012345678

2006 2007 2008 2009e

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

Credit Lines Utilized Credit Lines Available

Execute our plan while maintaining long-term financial strength and stability

Range:4 - 5x

Cash flow to interest

Range:20 - 25%

Cash flow to debt

Financial strength

Range:55 - 60%

Debt to capital Committed credit lines

Sep. 30, 08 Sep. 30, 09

$B

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UNITED STATES

CANADA

Growth Strategy

Growth strategy has shifted to accelerate near-term investments in renewables and focus on multiple options for long-term sustainability

Wind

Hydro

Under Construction:6 Facilities

189 MW

18 MW

Net Capacity 478 MW

Coal 271 MW

Total Capital Spend: $1.5B

Wind

Advanced development: 12 Facilities

Hydro

Geothermal

417 MW

134 MW

87 MW

Net Capacity 638 MW

Total Capital Spend: $2.0B – $2.4B

Short-term2009 - 2013

Canadian Hydro acquisition accelerated growth of renewables Pan-Canadian approachShift focus to natural gas combined-cycleExecute LOI on Project PioneerAcquire CO2 offsets

Medium-term2014 - 2017Shift focus to natural gas combined-cycleManage lifecycle investmentsExpand run of river hydro investmentsCO2 offsets trading

Green coal with CCSRenewables in the PacNWPartner in storage hydro in Alberta

Long-term2018 - 2020+

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Key milestones aheadGovernment funding announced Q4/2009Industry partners include Alstom and Capital Power; others to be addedFEED study to be completed by the end of 2010

Advancing Canada’s first large-scale project to retrofit a power plant to capture and store 1M tonnes of CO2 by 2015

Environmental Leadership

Project PioneerLargest scale pilot in North AmericaFirst project in the world to have an integrated underground storage system Potential to remove 90% of CO2 from emission streamKeephills 3 selected

Carbon Capture and Storage

CO2 returned

Energy Input (oil/gas)

Energy Input (coal)

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Outlook for earnings and cash flow growth improving despite uncertainty given low commodity prices in core markets

Approximately 89% contracted for 2010 provides high degree of earnings protection

Majority of operations performing above industry benchmarks; strategies in place to address challenges at Alberta coal and drive base operating performance – Target 90% fleet availability for 2010

Financial strength, cash flow stability and investment grade ratios supported by high level of contracting and low risk business profile

Investment highlights - 2010 Outlook

Near-term value creation driven by productivity, cost control, and improved Alberta coal plant performance

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Strategic imperatives in place that under pin our plan for lower carbon sustainable value creation

Advancing on key strategies to reposition coal and green the portfolio with optionality• Carbon capture and storage: Project Pioneer • Growth in renewables; account for 24% of generation fleet by 2012

Higher portion of earnings coming from highly contracted renewable and natural gas portfolio should expand our multiple

Fuel diversity + geographic diversity + financial flexibility + balance sheet strength = low risk business model and sustainable value creation

Investment highlights 2010+

Long-term expansion of renewables and repositioning of coal will create sustainable value

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Appendix

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Earnings growth expected due to operational improvements and sustainable cost savings; outlook more positive with return of demand and higher natural gas prices

$2.50

$1.75

$1.25

2012

EPSEstimates

$1.00$35 - $45$45 - $55Low Case

$1.05$45 - $55$55 - $65Medium Case

$1.10$60 - $75$65 - $75High Case

2009

AB Prices$/MWh

PNW Prices$/MWh

Near-term earnings outlook

*Includes Canadian Hydro

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Performance goals

Increased due to increased generation gross margins and lower OM&A spend

$0.32$0.34>10%/yrComparable EPS Grow Earnings and Cash Flow

Annual Metrics

5.8X

23.6%

50.1%

Annual Metric

$194 MM

$7.78/MWh

Annual Metric

83.9%

Q3 2009

TBDAnnual Metric$230 - $2603-yr Avg. Sustaining Capex

Make Sustaining Capex Predictable

Maintained strong balance sheet, financial ratios and ample liquidity

7.2X

31.1%

48.1%

Min. of 4X

Min. 25%

Max. 55%

Cash Flow to InterestCash Flow to DebtDebt to Total Capital

Maintain InvestmentGrade Ratings

TBDAnnual Metrics>10%/yr>10%/yr>10%/yr

ROCETSRIRR

Deliver Long-termShareowner Value

$202 MM

$8.70/MWh

Annual Metric

86.0%

Q3 2008

Decreased due to unfavorable changes in working capital, partially offset by higher cash earnings

Decreased primarily due to targeted cost savings throughout the company and lower compensation costs

TBD

Decreased due to higher unplanned outages at Centralia Thermal and higher unplanned outages at Alberta Thermal

2009 Goals

$800 - 900 MMOperating Cash Flow

90 - 92%AvailabilityAchieve top decile operations

10%/yrInjury Frequency RateImprove Safety

Offset InflationOM&A/installed MWhEnhanceProductivity

Measures ReviewFinancial ratios

20

Comparable net earnings per share of $0.34 versus comparable earnings of $0.32 in Q3 2008

• Accelerated major maintenance program resulting in positive performance from the majority of Alberta coal units; higher availability at Keephills partially offset by unplanned outages Sundance

• New 16.5 year, long-term contract at Sarnia natural gas co-gen facility adds incremental economic value

• Lower OM&A driven by targeted cost savings across the organization

• Higher unplanned outages at Centralia Thermal Unit 1 and lower Energy Trading gross margins offset gains

• YTD comparable earnings of $0.49 versus $1.06 for same period in 2008; due to reduced earnings from hydro assets as a result of poor water conditions in Alberta, higher unplanned outages at Centralia Thermal and higher planned outages at Alberta coal plants

Cash flow from operations of $194 million compared to $202 million in Q3 2008• Decrease in cash flow due to lower improvement in working capital offsetting higher cash earnings

• YTD cash flow from operations $334 million compared to $610 million for same period in 2008 due to lower cash earnings, an extra $116 million PPA payment in 2008, and higher inventory balances in 2009

Increased results from Canadian Generation and OM&A savings partially offset by lower results from Centralia Thermal and Energy Trading

Q3 2009

21

$0.32

198

$62

-

-

1

-

$61

Q3 2008

$0.49

198

$97

-

(6)

1

-

$102

YTD Q3’09

199198Weighted average common shares outstanding in the period

$0.34

$66

-

-

-

-

$66

Q3 2009

$210Earnings on a comparable basis

-Settlement of commercial issue, net of tax

8Change in life of Centralia parts, net of tax

$1.06Earnings on a comparable basis per share

65Writedown of Mexican investment, net of tax

(4)Sale of assets at Centralia, net of tax

$141Net earnings

YTD Q3’08

Results ($M)

Comparable earnings

Q3 2009

22

33,439

84.4

$0.87

$334

$0.52

$0.49

$102

$97

$219

$1,107

$2,007

YTD Q3’09

12,357

86.0

$0.27

$202

$0.31

$0.32

$61

$62

$124

$398

$791

Q3 2008

36,235

85.7

$0.81

$610

$0.71

$1.06

$141

$210

$406

$1,207

$2,302

YTD Q3’08

11,610

83.9

$0.29

$194

$0.34

$0.34

$66

$66

$120

$380

$666

Q3 2009

Availability (%)

Comparable earnings per share

Basic and diluted earnings per share

Comparable earnings

Operating income

Production (GWh)

Cash dividends declared per share

Cash flow from operating activities

Net Earnings

Gross margin

Revenue

Results ($M)

Q3 2009

23

Net earnings

$102$66Net earnings, 2009105Other

97-Decrease in equity loss

29(5)(Increase) decrease in income tax expense

1112Decrease in non-controlling interest

(3)

(3)

17

(14)

(8)

4

$61

Q3 2009

(1)

(34)

(51)

(44)

13

(69)

$141

YTD Q3’09

Mark-to-market movements - Generation

Decrease in COD gross margins

Decrease (increase) in operations, maintenance, and admin costsIncrease in depreciation expense

Increase in net interest expense

Increase (decrease) in Generation gross margins

Net earnings, 2008

Q3 2009

24

$(196)

-

(8)

-

(19)

(40)

(169)

(294)

$334

YTD Q3’09

$20

(1)

-

-

(1)

(25)

(58)

(97)

$202

Q3 2008

2-Cash flows from equity investments

$(33)

-

(116)

(3)

(69)

(163)

(294)

$610

YTD Q3’08

-Timing of contractually scheduled payments

$12Free cash flow (deficiency)

-Other income

(1)Non-recourse debt repayments

(7)Distribution to subsidiaries’ non-controlling interest

(58)Dividends on common shares

(116)Sustaining capital expenditures

Add (Deduct):

$194Cash flow from operating activities

Q3 2009($M)

Free Cash Flow

25

$0.66$0.82

$1.16$1.31

$1.46

$0.97

$1.40

$0.25

$0.50

$0.75

$1.00

$1.25

$1.50

$1.75

2004 2005 2006 2007 2008 2009e 2010e

Earnings and cash flow profile

Medium and long-term contracts underpin earnings and cash flow expectations

Long Term >5yrs

Medium Term 3-5yrs

Short Term <3yrs

Open

TransAlta Contracts

$0$200$400$600$800

$1,000$1,200$1,400

2005 2006 2007 2008 2009e 2010-2012e

Cash flow from operations

$620 $675*$778*

$922*

$650

$550

$5/mmbtu

$7/mmbtu

$9/mmbtu

$M

Analyst Consensus Estimate

Comparable earnings per share

$MNormalized Year: $850 - $950M

Sustaining Capex

Dividend

Free cash flow$300 - $400M

Free Cash

Cash Flow

$0

$200

$400

$600

$800

$1,000

2010*Adjusted for the timing of PPA revenues

$300 - $400MFree Cash

2010

26

$0

$200

$400

$600

$800

$1,000

2010 2011 2012 2013 2014 2015 2016 2017 2018 Thereafater

CDN MTN's US MTN's

1

Minimal debt refinancing over the short-term provides ample financial flexibility

CAD $M

1) Based on Dec. 31, 2009 FX rate of $1.0525 CAD/ US

1 1

1

Debt profile supports balance sheet

27

$130 - 140

$40 - 50

$5 - 10

$100 - 115

$275 - 315

2010e

$115 - 125

$20 - 25

$35 - 45

$40 - 45

$130 - 150

$340 - 390

2009e

Centralia Fuel Blend

$150 - 170$155 - 175Major Maintenance

$40 - 50$35 - 40Mine

$5 -10$5 -10Productivity

$115 - 130

$310 - 360

2012e

$115 - 130

$310 - 355

2011e

Routine

Sustaining

($M)

Sustaining capex spend declines in 2010 due to lower major maintenance and levels out in 2011 and beyond

Sustaining capital

28

325 - 350*

$65 - 75

$0 - 5

$65 - 70

Natural Gas and

Renewables

1,775 - 1,850

$125 - 135

$60 - 65

$65 - 70

Coal

2,100 - 2,200GWh lost

$190 - 210Total$60 - 70Expensed

$130 - 140

Total

Capitalized

($M)

2010 Major maintenance plan

* Natural gas fleet only

Major maintenance

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Delivering on growth and creating long-term shareholder value

12054

66

MW

$195$140 – 155Total

$115 1---$85 - 90Blue Trail

-

2012e

$80 2

Total

-

2010e

-

2011e

$55-65

2009e

Sun 5 uprate

Completed

47846

69

225

66

18

54

MW

$100$80 - 85$15 - 20Kent Hills expansion

$71 3$40 - 45$25 - 30Bone Creek

$123 4$15 - 25$80 - 90Summerview II

$988 5$20 - 30$225 - 245$235 - 255Keephills 3

$135 $95 - 105$25 - 35Ardenville

$68$20 - 30$25 - 35$5 - 15$10 - 20KI & K2 uprates

$20 - 30

2012e

$1.5B

Total

$460 - 520

2010e

$45 - 65

2011e

$375 - 430

2009e

Total

In Progress

Growth capital

1. Blue Trail capital spend prior to 2009 was $25M2. Sun 5 uprate capital spend prior to 2009 was $17M3. Bone Creek capital spend prior to 2009 was $8M; total spend increased from $57M to $71M4. Summerview II capital spend prior to 2008 was $25M 5. Keephills 3 capital spend prior to 2009 was $496M

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Advanced development1

Over 600 MW of renewable energy in advanced development for TransAlta’s 2010 - 2013 pipeline

* TransAlta’s ownership** Based on initial estimates of Canadian Hydro

1) Includes Canadian Hydro

LOCATION PROJECT CAPACITY FUEL TYPE RESOURCE & TURBINE CAPEX RANGE PPA / MW SITE CONTROL Applied Secured SECURED $ MM LTC

Saskatchewan ANEDC 175 Wind TBD $420 - $470 PPA/LTCNew Brunswick NB - 1 54 Wind $100 - $155 PPA/LTCNew Brunswick NB - 2 54 Wind $100 - $155 PPA/LTCCalifornia Black Rock 1-3 87* Geothermal In Progress $450 - $500 PPA/LTCAlberta Dunvegan** 100 Hydro $500-$600 MerchantBritish Columbia Clemina Creek** 11 Hydro $30-$40 PPA/LTCBritish Columbia Serpentine Creek** 10 Hydro $30-$40 PPA/LTCBritish Columbia English Creek** 5 Hydro $10-$20 PPA/LTCOntario Royal Road** 18 Wind $35-$45 PPA/LTCOntario Yellow Falls** 8* Hydro $30-$40 PPA/LTCQuebec New Richmond** 66 Wind $180-$200 PPA/LTCQuebec St. Valentin** 50 Wind $150-$170 PPA/LTC

TOTAL MW : 638 TOTAL COST: $2.0 B - $2.4 B2012

Projects in Advanced DevelopmentTARGET

COMMERCIALOPERATION DATE

2012

ENVIRONMENTAL AND PERMITS

20122013/14

2012

2012

TBD

TBD

2013/14

TBD

20102010/11

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Macro issues impacting our industry

Having flexibility and options will create value given environmental, regulatory and technological uncertainties

Timing Wait for U.S. system to be determined Likely protracted process into 2010-11

Canada U.S.

StringencyAbsolute-based cap & trade with auctioningThermal fuel flexibility likely

Environmental protection under PPAs

Technology and efficiency for fossil plants, incl. CCS

Staged capital stock transition to cleaner sources

Timely offset acquisitions

Potential for EPA regulation with tough rule-based, prescriptive measuresSpecial consideration for coalWashington state executive order to reduce GHG emissions by ~50% by 2025

Commercial arrangements to manage merchant exposure

Fuel shifting at Centralia

Focus on geothermal growth

Response planning