CIBC 14th Annual Whistler Institutional Investor ConferenceJanuary 20, 2011

Brett GellnerChief Financial Officer

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 2009 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

2

Value proposition and strategy

Near and longer-term upside potential

Financial strength and capital allocation

3

Outline

AUSTRALIA

UNITED STATES

CANADA

18 MWHydro under development286 MW

Generation Facilities:

Coal-fired under construction

Coal-fired plants

Gas-fired plants

Hydro plants

Wind-powered plants

Geothermal

4,688 MW

1,843 MW

893 MW

1,064 MW

164 MW

Biomass 25 MW

Net generation in operation 8,677 MW

Canada’s largest publically traded wholesale power generator & marketer

Value proposition and strategy

Yield, upside potential, and steady disciplined growth

Low-to-moderate risk profile

Financial strength

Disciplined investment decisions

4

Acquired Vision Quest

Divested Mexico

Renegotiated Sarnia

Retired Wabamun

2008 2009 20102005

Constructed Genesee 3

2000

Transitioned to PRB coal

2006

Acquired CE Gen

2003

AcquiredCanadian

Hydro

2009

Acquired Centralia

2000

Constructed Keephills 3

2011

Strategy: The last 10 years

CoalGasRenewables

$20.96

$32.69

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011e

8,563 MW6,870 MW

Generation gross margin per MWh

produced

73%15%12%

54%

21%

24%

5

Diversified growth & optimization have driven a 55% increase in gross margins

Significantly increased renewable portfolio

0

500

1,000

1,500

2,000

2,500

2000 2005 2010 2011e

Hydro Wind Geothermal Biomass

Renewable Portfolio CapacityMW

Strategy: The last 10 years

6

Diversification and contracting drives growth

Funds from operations have grown despite lower market prices

7

$MM$/MWh

Funds From Operations vs.Weighted Average Price / Merchant MWh Produced

Next 10 years

Continue to drive productivity and lower costsSustain improved operational performance

Unit specific maintenance plans for pending 45 year proposalMaintain options around coal sitesFinalize Centralia transition planParticipate in CCS technology development

Information technology & strategic suppliers drive productivityPrepare transition from PPAs

Implement capital stock transition“Green Coal”

Drive the Base

Drive the Base

Reposition Coal

Reposition Coal

8

Near Term2011 - 2014

Long Term2014 - 2020

Green & DiversifyOur Portfolio

Green & DiversifyOur Portfolio

Deliver on 304 MW of announced growthMaintain development pipeline of over 1,405 MWContinue to target 200 – 300 MW growth / yr

Continue to build multiple options for the futureGas & hydro baseloadSecure natural gas supplyStrong acquisition potential

5%

10%

15%

20%

25%

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

$30

$40

$50

$60

$70

$80

$90

$100

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

Actual Forecast

Reserve Margins1

1% load growth

2% load growth

3% load growth

Alberta market

Positives

Alberta Economics: GDP growth to range from 2.1% - 5.5% annually for 2010 – 2020

Oil sands recovery driving load growth

2.5% demand growth per year for the next three years

Challenges

Over 800 MW of new supply in 2011

Weak natural gas prices expected to continue throughout 2011

1 Figures as of January 11, 2011

Alberta Power Prices1$/MWh

Actuals Current Market

+$1 / GJ = ~$8 - $10 / MWh

Forward prices remain soft due to low natural gas prices and capacity additions, long-term fundamentals remain strong, driven by oil sands recovery

9

2 Includes transmission; does not include assumptions around announced facilities, only facilities under construction

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

2007 2008 2009 2010 2011 2012 2013 2014

$0

$10

$20

$30

$40

$50

$60

$70

2006 2007 2008 2009 2010 2011 2012 2013 2014

PacNW market

Positives

Demand destruction slowing down; -1.8% for 2010 versus -3.2% last year

1.9% demand growth per year for the next three years due to expectations of a modest economic recovery

Challenges

Economic recovery losing momentum in recent months

Weak natural gas prices expected to continue throughout 2011

Continued growth in renewables expected over the next few years

+$1 / MMBtu = ~$7 - $9 / MWh

1 Figures as of January 11, 2011

10

Improvements in demand; forward price recovery driven by natural gas

Reserve Margins1

PacNW Power Prices1US$/MWh

Actuals Current Market

Actual Forecast1% load growth

2% load growth

3% load growth

0

500

1,000

1,500

2,000

2,500

3,000

3,500

2010 2011 2012 2013

Contracted To be contracted Open

0

500

1,000

1,500

2,000

2,500

3,000

3,500

2010 2011 2012 2013

Contracted To be contracted Open

$0

$50

$100

$150

$200

$250

1 2 3 4 5

Merchant Portfolio Contractedness Avg. Incremental EBITDA From Higher Prices (2011 – 2014)2

$MM

1Based on a 10% ROCE, $1,500 – $3,000 per KW and a 30 year depreciation2 Relative to a base of $50/MWh in Alberta and $35/MWh in the PacNW

$75$60

$70$55

$65$50

$60$45

$55$40

AlbertaPacNW

Significant upside to price plus growth in the medium-term

11

Merchant MWs

Hedging strategy provides leverage to power price recovery

Alberta1: $60 - $65 $65 - $70 $65 - $70 $60 - $65PacNW1: $50 - $55 $55 - $60 $55 - $60 $45 - $50

20102011

2012 2013

90% target Capacity adjustments

Contracted To be contracted Open

At a 10% ROCE, 200 MW growth can add another

$40 - $80 million in additional EBITDA1

Merchant MWs

Significant upside potential

$-

$250

$500

$750

$1,000

$1,250

$1,500

$1,750

$60 $70 $80 $90 $100 $110 $120

Est.EBIT $MM

Estimated Incremental EBITDA in 2021$750 - $1,250 M 2

$750$1,000

$1,250

Alberta Power Prices 2021 ($/MWh)

2 Includes Sundance units 3 – 6, Keephills, Sheerness, and Alberta Hydro facilities

12

End of PPAs will provide significant EBITDA upside as production reverts back to TransAlta

1 Minimum power prices required for new NGCC facility

1

1 Excludes upside from incremental growth, replacement opportunities and higher prices between 2010 and 20212 Based on 45 year coal-life; and includes Sundance units 2 – 6, Keephills, Sheerness, and Alberta Hydro

Excellent long-term potential from PPA facilities

13

$-

$2,500

2010 20212010 2021

TA Base1

Value

Post PPA Value

$MM Potential EBITDA

Price

($/MWh)$60

$120

Upside

$2.1 B

$8.5 B

Cumulative Potential Upside from PPA Expiry(2018 – 2029)1,2

Investment Opportunities (TransAlta Fleet Only)

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031

TransAlta coal Replacement opportunity TA AB Portfolio growth

TransAlta AB Portfolio Growth

Replacement Opportunity*

TransAlta Coal

MW

Opportunity

1 Based on 45 year coal-life and $1,800 - $2,800 per KW

5,400 MW at Market Prices

$10 - $15 BInvestment Opportunity1

14

Canada’s 45 year plan provides significant future investment opportunities in Alberta alone

Captures the benefit of our significant tax pools and attractive tax treatment of renewablesAdds back non-cash accounting charges (e.g. dep`n) which can vary between companiesLong-term cash flow analysis captures the significant value from PPA expiry and reinvestment opportunities

$-$100$200$300$400$500$600$700$800$900

2005 2006 2007 2008 2009 2010e*

Net Earnings FFO

FFO Significantly Higher Than Earnings

$MM

1 Based on analyst consensus estimate for net earnings

Cash flow / funds from operations

2010e1

15

Cash flow accounts for tax pool benefits, adds back non-cash accounting charges, and captures future value of PPA expiry

0.0

0.5

1.0

1.5

2.0

2.5

3.0

2006 2007 2008 2009 2010e$0

$100$200$300$400$500$600$700$800$900

$1,000

2006 2007 2008 2009 2010e

Strong near-term cash flows

Expecting $800 - $900 M in funds from operations for 2011

Dividend Coverage2.0 – 2.5x$MM

Funds from Operations

Sustaining capex Free cash flow Dividends

$800 - $900 M FFO range

16

Capital allocation plan

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

2011 - 2013

Funds from operationsSustaining capexDividendsDRASPNCITotal

Balance sheet enhancement Growth

17

$ 2.8$ (1.3)$ (0.8)$ 0.2$ (0.2)$ 0.7

($B)

Appendix

18

Performance goals

Annual Metrics

4.6X

21.2%

56.7%

Annual Metric

$230 MM

$0.17

$7.51/MWh

Annual Metric

91.0%

Q3 2010

Annual Metrics

5.8X

23.6%

50.1%

Annual Metric

$194 MM

$0.34

$7.78/MWh

Annual Metric

83.9%

Q3 2009

Decreased due to low pricing in core markets, lower Energy Trading gross margins, slightly higher OM&A costs in the quarter

>10%/yrComparable EPS Grow Earnings and Cash Flow

TBD$295 - $340Sustaining CapexMake Sustaining Capex Predictable

Maintained strong balance sheet, financial ratios and ample liquidity

4 - 5X

20 - 25%

55 - 60%

Cash Flow to InterestCash Flow to DebtDebt to Invested Capital

Maintain InvestmentGrade Ratings

TBD

>10%/yr>10%/yr>10%/yr

Comparable ROCETSRIRR

Deliver Long-termShareowner Value

Higher operating cash flow due to favorable changes in working capital

Decreased year-over-year due to less major maintenance activities in 2010 and increased capacity

TBD

Increased availability due to lower planned and unplanned outages at our Sundance plant, lower planned outages at our Mississauga and Windsor facilities, and lower unplanned outages at Centralia

2010 Goals

$850 – 950* MMOperating Cash Flow

90%AvailabilityAchieve top decile operations

1.0 by 2015Injury Frequency RateImprove Safety

Offset InflationOM&A/installed MWhEnhanceProductivity

Measures ReviewFinancial ratios

*Estimate revised to $800 - $900 million

Performance Goals

19

$(196)$74$12$107Free cash flow (deficiency)

$1.69$2.28$0.98$1.05Cash flow from operating activities per share

$595$664$241$233EBITDA

$463$558$178$184Funds from operations

12,742

91.0

$0.29

$230

$0.17

$0.17

$38

$38

$98

$380

$700

Q3 2010

11,610

83.9

$0.29

$194

$0.34

$0.34

$66

$66

$120

$380

$666

Q3 2009

33,439

84.4

$0.87

$334

$0.52

$0.49

$102

$97

$219

$1,107

$2,007

YTD2009

35,857

88.1

$0.87

$502

$0.71

$0.57

$156

$126

$287

$1,137

$2,008

YTD2010

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 2010 - Highlights

20

(6)---Settlement of commercial issue, net of tax

$0.34

198

$66

-

-

$66

Q3 2009

$0.17

220

$38

-

-

$38

Q3 2010

1-Change in life of Centralia parts, net of tax

$0.49

198

$97

-

$102

YTD2009

220Weighted average common shares outstanding in the period

$0.57

$126

(30)

$156

YTD2010

Earnings on a comparable basis

Earnings on a comparable basis per share

Income tax recovery related to the resolution of certain outstanding tax matters

Net earnings

Results ($M)

Comparable earnings

Q3 2010

21

Net earnings

$38

(2)

12

(5)

(13)

(15)

(5)

(4)

4

$66

Q3 2010

$156Net earnings, 2010

(12)Other

15Decrease in income tax expense / increase in income tax recovery

7(Increase) decrease in non-controlling interest

(28)

(2)

44

(20)

50

$102

YTD 2010

Decrease in Energy Trading gross margins

(Increase) decrease in OM&A costs

Increase in depreciation expense

Increase in net interest expense

Increase in Generation gross margins

Net earnings, 2009

Q3 2010

22

$12

-

(1)

(7)

(58)

(116)

$194

Q32009

$74

-

(13)

(44)

(169)

(202)

$502

YTD2010

$(196)

(8)

(19)

(40)

(169)

(294)

$334

YTD2009

$107Free cash flow (deficiency)

-Other income

-Non-recourse debt repayments

(15)Distribution to subsidiaries’ non-controlling interests

(49)Cash dividends paid on common shares

(59)Sustaining capital expenditures

Add (Deduct):

$230Cash flow from operating activities

Q32010($M)

Free cash flow

23

$0

$200

$400

$600

$800

$1,000

2010 2011 2012 2013 2014 2015 2016 2017 2018 ThereafterCDN MTN's US MTN's

(CDN $M)

1 Based on Sept. 30, 2010 FX rate of $1.03 CAD/US

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

Debt profile

24

1

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

Credit Lines Utilized Credit Lines Available

35%

40%

45%

50%

55%

60%

2006 2007 2008 2009 Q32010

0%5%

10%15%20%25%30%35%

2006 2007 2008 2009 Q32010

012345678

2006 2007 2008 2009 Q32010

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

Range:4 - 5x

Cash flow to interest

Range:55 - 60%

Debt to capital

Range:20 - 25%

Cash flow to debt

Committed credit lines

Sept. 30, 2009 Sept. 30, 2010

$B

Maintaining investment grade ratios

25

Other

$30 - 50$20 - 30

$55 - 80$5 - 10$10 - 20

Repowering / Life ExtensionProductivity

$35 -45

$190 - 210

$115 - 130

$340 - 385

2013e

$40 - 50

$280 - 300

$115 - 130

$435 - 480

2012e

$25 - 30Mine Capital

$210 - 230Major Maintenance

$120 - 135

$355 - 395

2011e

Routine Capital

Sustaining

($M)

Sustaining capital

26

2011 - 2013 Sustaining capital plan1

1 Based on IFRS

630 - 640

$75 - 80

Natural Gas and Renewables

1,850 – 1,860

$135 - 150

Coal

2,480 – 2,500GWh lost

$210 - 230

Total

Capitalized

($M)

2011 Major maintenance plan1

Major maintenance

27

1 Based on IFRS

Tracking

Merchant

Q4 20124

15%+

$68 MM

46 MW (23 MW each)

Efficiency Uprates

Alberta

Keephills 1 and 2 Uprates

Tracking

Merchant

Q4 2012

15%+

$27 MM

15 MW

Efficiency Uprate

Alberta

Sundance 3 Uprate

10%+10%+Unlevered after tax IRR

AlbertaBritish ColumbiaLocation

Tracking

Merchant

Q2 2011

$988 MM 3

225 MW 1

Supercritical Coal

Keephills 3

Tracking

LTC

Q1 2011

$48 MM 2

18 MW

Hydro

Bone Creek

On time / On budget

Contract Status

Commercial Operations Date

Total Project Cost

Size

Type

Projects

1 450 MW gross size2 Bone Creek’s capital spend prior to the acquisition was $23 MM which does not form part of our total project cost3 Keephills 3 capital spend increased from $888 MM to $988 MM and its COD was revised from Q1 2011 to Q2 20114 Keephills unit 1 uprate has been moved to 2012

Executing on our growth strategy

28

TransAlta’s growth investments deliver long-term sustainable cash flow and earnings growth

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

Quebec New Richmond** 66 Wind $180 - $210 PPA/LTCQuebec St. Valentin** 50 Wind $150 - $180 PPA/LTCSaskatchewan Mistahay Utin 175 Wind TBD $450 - $500 PPA/LTCSaskatchewan Willow Bunch** 175 Wind TBD $450 - $500 PPA/LTCCalifornia Black Rock 1-3 87* Geothermal In Progress $400 - $500 PPA/LTCAlberta Sundance 7 700 Gas-fired TBD TBD $1,000 - $1,500 MerchantAlberta Dunvegan** 100 Hydro $500 - $700 MerchantBritish Columbia Clemina Creek** 11 Hydro $30 - $40 PPA/LTCBritish Columbia Serpentine Creek** 10 Hydro $30 - $40 PPA/LTCBritish Columbia English Creek** 5 Hydro $12 - $20 PPA/LTCOntario Royal Road** 18 Wind $35 - $45 PPA/LTCOntario Yellow Falls** 8* Hydro $30 - $45 PPA/LTC

TOTAL MW : 1,405 TOTAL COST: $3.3 B - $4.3 B

TBD

TBDTBD

2012

20132013/14

TBDTBD

TBD

Projects in Advanced DevelopmentTARGET

COMMERCIALOPERATION DATE

ENVIRONMENTAL AND PERMITS

2015

2013

2012

Advanced development pipeline

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

29

$1353$105 - 11569Ardenville

$1002$80 - 8554Kent Hills 2

$353$195 - 215189

$1181$10 - 1566Summerview 2

MW 2012e Total2010 2011eCompleted

$686$20 – 30$25 - 35$5 - 1546KI & K2 uprates

$27$10 - 20$10 - 15$0 - 515Sun 3 uprate

304

225

18

MW

$484$50 - 55Bone Creek

$9885$20 - 30$225 - 245Keephills 3

$30 - 50

2012e

$1.1B

Total

$280 - 320

2010e

$55 - 80

2011e

Total

In Progress

1 Sunmmerview 2 capital spend prior to 2010 was $106 M2 Kent Hills 2 capital spend prior to 2010 was $18 M3 Ardenville capital spend prior to 2010 was $27 M4 Bone Creek capital spend prior to the acquisition was $23M which does not form part of our total project cost. Spend prior to 2010 was $4 M.5 Keephills 3 capital spend prior to 2010 was $707M6 K1 & K2 uprates spend prior to 2010 was $2 M

Growth capital outlook2011 - 2012

30

All projects tracking on time and on budget