INVESTOR DAY 2012 - TransAlta · Grow customer business to 500 MW in Alberta in 2013 and add...

INVESTOR DAY

2012

POWER INFRASTRUCTURE

This presentation contains 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 pricing in the market place, our inability to

contract Centralia as expected, a reduction in our Dividend Reinvestment Plan participation, our inability to achieve funds from

operations as expected, an increase in the cost of fuels to produce electricity, our inability to enter into long-term contracts due to

prevailing market conditions, our inability to complete growth projects as planned, legislative or regulatory developments, changes in

prevailing interest 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 November 28, 2012. The material assumptions in making these forward looking statements are addressed in our

third quarter report, our 2011 Annual Report to shareholders and in our most recent Annual Information Form along with other

disclosure documents filed with securities regulators.

Any "financial outlook" or "future oriented financial information" in this presentation, as defined by applicable securities legislation, is

provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers

are cautioned that reliance on such information may not be appropriate for other purposes.

Except to the extent required by law, we assume no obligation to publicly update or revise any forward looking statements, whether

as a result of new information, future events or otherwise. All forward looking statements in this presentation are expressly qualified

in their entirety by these cautionary statements. For information on our risks please refer to the Company’s Annual Information form

which has been filed on SEDAR and can be accessed at www.sedar.com.

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

This presentation may contain references to comparable earnings, comparable earnings per share, comparable EBITDA, funds from

operations, and funds from operations per share which are not defined under IFRS. Refer to the Non-IFRS financial measures

section of TransAlta’s third quarter 2012 MD&A for an explanation and, where applicable, reconciliations to net earnings attributable

to common shareholders and cash flow from operating activities. The presentation may also contain references to gross margin and

operating income, which are Additional IFRS measures. Please refer to the Additional IFRS measures section of the MD&A.

Forward looking statements

2

Overview Dawn Farrell

Operations Hugo Shaw

Marketing & Energy Trading Rob Schaefer

Growth

Canada gas Ken Stickland

Australia Aron Willis

M&A Brett Gellner

Financial Brett Gellner

Concluding remarks / Q & A Dawn Farrell

Today’s agenda

3

Dawn Farrell

President & CEO

4

Our vision

To be the most competitive low cost

power infrastructure

and energy marketer in our core markets

5

We are diversified and well

positioned to grow

5 fuel types; 3 key markets; significant growth

…and we have significant

knowledge in our Marketing and

Energy Trading organization

Generator

services

Information

Merchant

sales

Customers

Marketing

Our strategy and assets

Coal

4,940 MW

Gas

1,913 MW

Hydro

919 MW Wind

1,129 MW

Geothermal

164 MW

6

Secured cash flows are driven by our customers

1 MW have been adjusted to reflect actual capability and reflects 2013 contracted levels 2 STC = Short-term contracts; LTC = Long-term contracts

1

Megawatts (MW)

Contracts

,2

2

7

Operations Marketing and

Energy Trading

Growth

Business Model S

hare

d S

erv

ices

Financial Strategy

Operational excellence

in availability &

cost control

Dividend & Growth

8 – 10% TSR

People

Long-term customers

Generator services

Market information

Energy Trading

$ Capital to support

growth

$

$

8

TransAlta today What’s working:

Operational excellence:

Heritage assets in Alberta market are a significant source of future value for existing

shareholders

Asset planning has coal plants set up to run to end of life

Wind/Hydro fleet size represents strong value in portfolio

Gas portfolio strong and diversified enough to create competitive advantage for

growth

Growth:

Western Canada and Australia markets are sources of growth

Diversified approach to growth and focus on customers is uncovering a wide array of

opportunities

9

Areas of focus What we are improving:

Operational excellence: Focus company on funds from operations to maximize competitiveness

Alberta PPA’s: lengthen and better match cash / earnings to spending requirements

Re-organize to take advantage of I.T. and face into demographics and competitive pressures

Marketing & Energy Trading: Increasing hedge targets to reduce cash flow volatility

Significant value in focusing on customers in Alberta; growing commercial & industrial business

Re-aligning Energy Trading back to basics

Growth: Adding partners to increase opportunities for growth and reduce impact of greenfield projects on the

balance sheet in the 2013 – 2017 time period

Capital allocation: Implementing processes that support growth and operational excellence

10

Areas of focus What we are assessing:

Marketing & Energy Trading: The right size for our proprietary trading as markets evolve

Growth: How to attract customers into long-term contracts in Alberta

How to expand our Western US business

How to compete for renewable assets given competitiveness with cost of capital

Corporate: How to build a competitive Shared Services model across diverse assets, regions and

businesses

11

It’s all about execution…

Five planned major maintenance coal outages

completed; final planned outage on Sundance 5

almost complete

Long-term contract signed for Centralia

Reduced operating and capital costs

2012

Major Issues

Complete end of life major

maintenance plan for coal

Re-contract Centralia

Finalize the Sundance A and

Sundance 3 arbitrations

Manage environmental regulations

Increase competitiveness

2012

Accomplishments

Force majeure results validate our operating practices

Re-build of Sun A units in progress; will add future cash

Final Canadian GHG regulations provide added value for

TransAlta

Realigned organization to better deliver on strategy

12

…goals…

Top 5 player in PacNW by 2015

Grow Western U.S. Business

Leading behind-the-fence generator

in Western Australia

No. 1 generator & energy marketer

in Alberta 30% market position

Canada’s largest publicly traded

provider of renewable energy Add 100 – 200 MW per year

Add 1,500 MW

Double our size to 600 MW

Growth

Tracking: Sundance 7, MidAmerican

partnership

Not tracking: Seeking M&A

opportunities

Adding New Richmond but below

target

Tracking: Solomon

Stable generation OM&A

Consistent availability 89 – 90 %

Offset inflation

Lower major maintenance costs for

coal $30 million per outage in 2015

Safety IFR1 less than 1.0

Operational Better than target: 90.3%1 ytd

Exceeded: 5.5% lower ytd

2012 above yearly target;

Tracking for 2013

Exceeded: 0.78 ytd

1 Adjusted for Centralia (YTD = As of Sept 30, 2012

2 Injury frequency rate

3. Cash flow per share

Consistent TSR growth

Consistent cash flow growth

Strong balance sheet

Financial

8 – 10% TSR annually

4 – 5% CFPS2 growth

Maintain investment grade

Not tracking: target unchanged

Not tracking: target unchanged

Tracking: focused on

improving

13

…and having a good plan

Strategic objectives

Deliver one greenfield project from MidAmerican

partnership

Add $40 - $60 million of EBITDA from growth

Return trading to $40 - $60 million in gross margin

Grow customer business to 500 MW in Alberta in

2013 and add long-term contracts to support Sun 7

Add new long-term contracts in Centralia

Short-term focus (2013)

Operational objectives

Achieve availability of 89 – 90%

Return sustaining capital to $350 million per year

run rate

Offset inflation on OM&A costs

Deliver Sundance A rebuild at $190 million

Commission New Richmond

Achieve safety IFR < 1

People and culture

Complete realignment of organization

Build Shared Services organization

Implement new compensation structure

Financial objectives

Achieve $800 – $900 million in FFO

Maintain dividend

Strengthen balance sheet

Continued access to multiple sources of capital

Maintain strong liquidity

14

Where are the risks?

Commodity prices Managing exposure to natural gas and power

prices in the 2014 – 2018 timeframe

Low construction productivity in Alberta Sundance A rebuild

Final GHG regulations GHG and other pollutants need to be aligned

to realize full value from new legislation

Alberta PPAs Lengthy arbitration timeframes

Economic uncertainty Slower growth for oil sands, and other mining

projects

15

Where are the opportunities?

Commodity prices Gas prices starting to show more strength and

additional calls for upside

Need for new generation supportive of longer-

term Alberta power prices

Additional opportunities as we continue to establish

our behind the fence generation expertise

Australia

MidAmerican partnership Significant synergies as two companies work

together to develop large scale opportunities

LNG Significant growth forecasted in the region

without enough power to fuel all the plans

Marketing Additional synergies between customers and

growth will uncover more opportunities

16

Our plan to 2021

Base EBITDA Solomon, Sun A, Centralia Future Growth Post PPA Value

2012 2013 2014 2015 2016 2017 2018 2019 2021

Solomon

Lower Sust.

Capex

Sun A Centralia Escalating price & volumes

Sun A

Post PPA Post PPA

1. Illustrative only, depicts adding EBITDA of $40 - $60M / year to achieve our targets

1

17

Driving shareholder value

TSR Target:

8 – 10% / yr

Financial strength

Dividend

Greenfield growth

Acquisitions

Optimized contracting

and leverage

Energy Trading

1st Quartile cost

performance


18

Hugo Shaw

EVP Operations

19

Topics covered

Generation operating model

Goals and results

Fleet update

Coal

Gas

Hydro

Wind

Construction update

Sustaining and growth capital estimates

20

Operating Model

Operational

excellence

Safety Asset plans

Regulatory

compliance

Defined roles &

accountabilities

Front line

communication

& technical

training

Plant

engineering

practices

Maintenance

strategy

Work

management

Management

of change

Planning &

execution

21

Stable generation OM&A

Consistent availability 89 – 90 %

Offset inflation

Lower major maintenance

costs for coal $30 million per outage

in 2015

1 Adjusted for Centralia (YTD = As of Sept 30, 2012)

2. Injury frequency rate

Safety IFR2 less than 1.0

Goals and results

Better than target:

90.3% YTD1

Better than target:

5.5% lower YTD

2012 above yearly

target; Tracking for

2013

Better than target:

0.78 YTD

22

Facility Capacity

Sundance 1,581 MW

Keephills 1 & 2 806 MW

Keephills 3 225 MW

Genesee 3 233 MW

Sheerness 195 MW

Centralia 1,340 MW

Capacity in operation 4,380 MW

Coal overview

Facility Name Capacity

Sundance A Rebuild 560 MW

Maintenance Strategy

Implement Operating Model and ensure 100%

adherence to all processes and standards

Maintain boilers to achieve availability and

production targets to end-of- life with 24-30

month major maintenance intervals

Schedule and plan all routine maintenance

work to increase proactive work

Increase monitoring of equipment conditions

and reliability

Improve major maintenance outage planning

and execution and reduce capital spend to 1st

quartile benchmark

23

24

2012 major maintenance work completed

Boiler economizer replacement

Low pressure turbine replacement

DCS installation – wire pulls

Keephills 1 & 2

Turbine retrofits and generator rotor replacements

Boiler repairs / pieces of work – over 12,000

DCS installation in Kps 2 – 6 kilometers of new cable

& 15,000 reconnections

Total labor hours – 850,000

Sundance 3

Turbine LP rotor replacement


Partial waterwall and economizer replacement

Main transformer replacement


Sundance 5

Turbine HP valve overhaul


Generator links replacement


1. Excludes work done at Sheerness, G3 and Centralia

Sundance and

Keephills

Boiler Leaks

Alberta coal unplanned outages Improved maintenance practices have reduced unplanned outage losses and increased availability

Sundance and

Keephills

Availability

NERC Average (Coal)

# of leaks

Availability

25

Alberta coal unplanned outages Canadian federal GHG emissions regulations

Plant MW Annual GWh1 45 Year Rule Final

Regulations

Years Increase Additional

GWh

(1)

Sundance 1 280 2,085 2017 2019 2 4,170

Sundance 2 280 2,085 2018 2019 1 2,085

Sundance 3 368 2,740 2021 2026 5 13,701

Sundance 4 406 3,023 2022 2027 5 15,115

Sundance 5 406 3,023 2023 2028 5 15,115

Sundance 6 401 2,986 2025 2029 4 11,943

Keephills 1 406 3,023 2028 2029 1 3,023

Keephills 2 406 3,023 2029 2029 0 -

Sheerness 1 98 1,415 2031 2036 5 3,630

Sheerness 2 98 1,415 2035 2040 5 3,630

Genesee 3 225 1,675 2050 2055 5 8,377

Keephills 3 225 1,675 2056 2061 5 8,377

Total 43 89,166

¹ Based on 85% availability

Revised federal GHG regulations provide additional 43 years and approximately 89,000 GWh of production in TransAlta’s coal fleet

26

Gas overview

1. Units operated by CEGen

Facility Name Capacity

(MW)

Ownership

(%)

Net

ownership

(MW)

Technology

Poplar Creek 356 100 356 Alstom 11N2

Fort Saskatchewan 118 30 35 GE 7EA

Sarnia 506 100 506 Alstom 11N2

Mississauga 108 50 54 GE LM6000

Ottawa 68 50 34 GE LM6000

Windsor 68 50 34 GE LM6000

Centralia 248 100 248 GE LM6000

Power Resources1 212 50 106

Saranac1 240 37.5 90

Yuma1 50 50 25

Parkeston 110 50 55 GE LM6000

Southern Cross 245 100 245 GE LM6000

Solomon Power Station 125 100 125 GE LM6000/ Solar Titans

Capacity in operation 2,454 1,913

27

Gas major maintenance work

Implement Operating Model and ensure 100% adherence to all processes and standards

Optimize major maintenance schedule and scope based on equipment condition monitoring and predictive analysis, OEM recommendations, inspection results and engineering/technical standards

Schedule and plan all routine maintenance work to increase proactive work

Maintain fleet-wide critical spare parts inventory

Poplar Creek GT5 Major Major overhaul including replacement of

compressor and turbine rotor blades

Outage duration 8 days shorter than plan

Fort Saskatchewan Major Inspection and overhaul of gas and steam

turbine/generator; replacement of control

system

Outage duration 2 days shorter than plan

Mississauga GT Hot Section Replacement Replaced combustors and high pressure

turbine sections in both LM6000 units

Both completed in 4 days as scheduled

Sarnia Steam Turbine Overhaul First major overhaul of unit; upgraded controls

and protection systems installed

Outage duration 3 days longer than plan

2012 Outages Maintenance strategy

28

Turbine Inspection

interval & type

Inspection

interval & type

Inspection

interval & type

Inspection

interval & type

11N2 A B A C

6,000 hrs 12,000 hrs 18,000 hrs 24,000 hrs

LM6000 Hot Section Overhaul

25,000 hrs 50,000 hrs

7EA CI HGP Overhaul

10,000 hrs 24,000 hrs 48,000 hrs

11N2

A & B - Minor inspections; 3 - 4 day outage

C – Major overhaul; 25 - 32 day outage

LM6000

Hot section; 3 - 4 day outage

Overhaul – major overhaul 6 -7 day outage

7EA

CI –Combustor Inspection; 4 - 6 day outage

HGP – Hot Gas Path; 9 – 11 day outage

Overhaul – major overhaul 26 - 28 day outage for

7EA

Gas & Steam Turbine

major maintenance schedule

Inspection and major maintenance intervals

Legend

Alstom 11N2 C-Inspection

Unit disassembly Rotor removal Deblading

29

Gas fleet performance well above industry standards

Availability by gas turbine technology

NERC Average (Gas)

30

Hydro overview

Facility Capacity

Barrier 1 13 MW

Bearspaw 1 17 MW

Bighorn 1 & 2 120 MW

Brazeau 1 & 2 355 MW

Belly River 3 MW

Bone Creek 19 MW

Cascade 1 & 2 36 MW

Ghost 1 – 4 51 MW

Facility Capacity

Horseshoe 1 – 4 14 MW

Interlakes 1 5 MW

Kananaskis 1 - 3 19 MW

Pocaterra 1 15 MW

Rundle 1 & 2 50 MW

Spray 1 & 2 103 MW

Three Sisters 1 3 MW

Taylor Hydro 13 MW

Facility Capacity

Waterton 3 MW

St. Mary 2 MW

Upper Mamquam 25 MW

Pingston 45 MW

Akolkolex 10 MW

Ragged chute 7 MW

Misema 3 MW

Galetta 2 MW

Facility Capacity

Appleton 1 MW

Moose Rapids 1 MW

Skookumchuck 1 MW

Wailuku 10 MW

Total owned capacity in

operation

919 MW

31

Hydro life extension strategy

New control

systems New runners Generator rewinds

Refurbish our hydro fleet for another 50 years of operation

and add new capacity and production

32

Life extension progress

Bighorn condition

assessment

Spray 1 life extension 2013 - 2014 Constructability reviews

Schedule and cost estimates

Contracting

Turbine runner replacement, generator rewind,

control systems upgrades, balance of plant

refurbishment

Brazeau (2015) & Bighorn (2016) life

extension Detailed engineering

Constructability reviews

Schedule and cost estimates

Contracting

Turbine runner replacement, generator rewind,

control systems upgrades, balance of plant

refurbishment

2012

Pocaterra Penstock

replacement Spray detailed

engineering

Brazeau condition

assessment

2013 - 2016

33

Wind overview

Facility Capacity Ownership

(%)

Net

Ownership

(MW)

Kent Hills 150 83 124.5

Le Nordais 99 100 99

Melanchton 200 100 200

Wolfe Island 198 100 198

Ardenville 69 100 69

Blue Trail 66 100 66

Castle River 44 100 44

Cowley North 20 100 20

Facility Capacity Ownership

(%)

Net

Ownership

(MW)

Cowley Ridge 21 100 21

Macleod Flatts 3 100 3

McBride Lake 75 50 37.5

Sinott 7 100 7

Soderglen 71 50 35.5

Summerview 1 70 100 70

Summerview 2 66 100 66

New Richmond 68 100 68

Total capacity in operation 1,129 MW

34

80%

82%

84%

86%

88%

90%

92%

94%

96%

98%

100%

2009 2010 2011 2012e 2013e

Availability

Implement Operating Model and

ensure 100% adherence to all work

processes and standards

Schedule and plan all routine

maintenance work in low wind

seasons

Minimize equipment failure through

monitoring and predictive analysis by

TransAlta’s ODC (Operations

Diagnostic Center)

Monitor and dispatch crews through

central wind control center on 24 x 7

basis

Wind maintenance strategy and availability

Wind control centre

Maintenance strategy Availability

North American Benchmark by GL Garrad Hassan

35

0 ft

65 ft

161 ft

118 ft

Sundance units 1 & 2 update

70% of water wall rebuild costs are fixed

Variable costs includes incentives/penalties tied to

completion date and labour hours expended

Very experienced Alstom construction team from

U.S.

Senior TransAlta construction manager to manage

total project

Stats:

Project management:

1.4 million labour hours

248 boiler wall panels (8ft x 40ft)

15,000 tube welds

36

New Richmond – construction update

Progress

31 out of 33 concrete towers

12 turbines with nacelle

6 turbines pre-commissioned

8 cranes and average 200 workers/day on site

Work completed

22 kilometers of roads and

underground collector system

Substation completed

Schedule

End of Dec: Nacelle installation to be completed

Feb 2013: Blades and commissioning completion

Q1 2013: Achieve commercial operations

37

($M) 2012e 2013e 2014e 2015e

Sustaining $405 – 450 $295 – 335 $360 – 395 $340 – 375

Routine Capital $100 – 115 $90 – 100 $90 – 100 $85 – 95

Major Maintenance $265 – 285 $165 – 185 $220 – 240 $205 – 225

Mine Capital $40 – 50 $40 – 50 $50 – 55 $50 – 55

Other1 $50 – 70 $30 – 50 $30 – 50 $25 – 35

1 Includes repowering/life extension and productivity

Overall sustaining capital

Setting up for sustained long-term operational excellence

Average sustaining capital cost of $350 million per year between 2013 and 2015

38

($M)

Remaining

for 2012 2013 e

Total

Project Cost

Major Projects

(Sundance Units 1&2)

$25 - $45 $150 - $170 $190

New Richmond $70 - $115 $0 - $10 $205

Total major projects

and growth

$95 - $160 $150 - $180 $395

2013 Total major projects and growth

39

TSR Target:

8 – 10%/yr

Energy Trading

Operating model defined and being

implemented across fleet to drive

operational excellence

Safe work practices world class

Three year boiler reset completed –

availability targets being achieved in coal

fleet

Major maintenance costs for coal fleet

reduced in 2013 to average $35M per

coal unit outage; target to achieve $30

million by 2015

Gas and wind plant availability continue to

be in first quartile

Initiated refurbishment of hydro fleet to

extend life by additional 40 years

OM&A costs reduced by 5% in 2012; will

continue to offset inflation


Operational

excellence

1st Quartile cost

performance

Greenfield

growth

Optimized

Contracting and

Leverage

40

Rob Schaefer

EVP

Corporate Development

Source: NGX, Alberta Electric System Operator, Canaccord Genuity 41

Topics covered

Marketing and Energy Trading operating model

Market update

Alberta

Pacific Northwest

Marketing strategy

Alberta

Pacific Northwest

Energy Trading

42

People

Systems

Risk control

Compliance

Operating Model

Market Intelligence

Proprietary

Trading

Real time

Term trading

Analytics

Risk

management

Marketing &

Sales

Long-term

contracts

Alberta

PacNW

Generator

services

Merchant

bidding

Economic

dispatch

Dispatch

services

Hedging

43

Alberta

Desk

West

Desk

East Desk

Marketing and Energy Trading covers TransAlta’s core markets

44

2013 focus

Proprietary trading:

Back to basics

Deliver $40 - $60 million in gross margin

Marketing & sales:

Increase contracting for merchant assets

Add new long-term contracts in Centralia

Add new long-term contracts in Alberta

Grow commercial and industrial business

Secure new Alberta long-term contracts to support existing assets

and growth

Generator Services:

Increase hedge levels

Compliance and risk management

Maintain top compliance practices and processes

45

Alberta market

Monthly Alberta power and AECO gas prices $CAD/MWh $CAD/mmbtu

Weak relationship between natural gas and power prices

46

1Source: Canaccord Genuity

Data: NGX, Alberta Electric System Operator

Alberta forward market is a poor predictor of

future spot market settles

Forward prices tend to reflect spot fundamentals not future fundamentals

$/MWh

Average annual Alberta power prices compared to historical forward Alberta power prices

47

Price required to attract new generation1

¹

AESO estimate that prices in the range of $55-$125 / MW

are required to attract new combined cycle generation

48

Pacific Northwest; upside at Centralia as power

prices come off their lows

Centralia 2013 – 2016 average annual gross

margin

0

50

100

150

200

35 40 45 50

$110 - $115

$140 - $145

$170 - $175

$M

Market price $USD/MWh

$80 - $85

$USD/MWh $USD/mmbtu

2008 2010 2008 2009 2011 2012

Power is highly correlated to gas with the

exception of Q2

49

Alberta marketing

Approach customized for each market segment

55% Large industrial

and oil sands

Customized offers

~25 targeted

customers

2 to 10+ year term

22% Commercial & small

industrial

Standard offers

1000 targeted customers

2 to 10 year term

17% Retail

Fixed price sales by

auction

6% Losses

Retail

Commercial and

small industrial

Large industrial

and oil sands

Losses

50

Building our customer base to drive stable revenues

Strong market

relationships

Low cost, diverse

portfolio provides

competitive advantages

Trading capability

provides tools to offer

flexibility to customers

Alberta contracting targets MW

1,900 MW

added

600 MW

added

Positioning for growth and PPA roll-off

Competitive Advantages

Actuals

51

Strategy for contracting Centralia

Focused on adding more contracts 2013 – 2020 through a combination of

Participation in Request for Proposals (RFPs)

Capturing opportunities to hedge when market prices are supportive

Centralia contracting targets 2013 - 2025

MW

T Total capacity Hedged

52

Contracted position

Hedge targets increased to support revenue certainty

2013 Contracted Prices

AB $55 - $60 / MWh

PACNW $40 - $45 / MWh

MW Total portfolio contractedness1

82% 77% 75% 75%

With the Puget Sound

Energy contract our base

portfolio is now 75%

contracted

Targeting higher

contracting levels and

longer-term contracts

1Capacity adjusted volumes 53

Refocus on strengths – trading around assets and lower risk proprietary

opportunities

Expect to see gross margins consistent with history of $40 to $60M per

year

Trading operation

$M

54


Optimized

Contracting

and Leverage

Marketing & Energy Trading plays

an important role in capturing

market value for TransAlta’s

merchant fleet

Driving for more contracts to

ensure revenue stability

Refocusing proprietary trading on

core strengths to deliver tighter

gross margin expectations

55

TSR Target:

8 – 10%/yr


and leverage

Energy Trading

1st Quartile Cost

performance


Ken Stickland

Chief Business

Development Officer

56

Topics covered

Growth in our markets

Canada

- Immediate and long-term opportunities

Alberta

- Market drivers

- Oil sands potential demand

British Columbia

- Market drivers

- Potential LNG demand

TransAlta’s growth strategy

Strategy behind partnerships

MidAmerican

Update on Sundance 7

57

Canadian power demand is estimated to grow by ~1.6% per year over the next decade

Western Canadian growth is the strongest

Immediate term, largest opportunity in three areas:

Oil sands

Alberta grid additions

British Columbia LNG

Medium term, opportunity across Canada in the renewable space for targeted

acquisitions and greenfield developments

Significant opportunity for growth

58

Alberta market drivers

1AESO Long Term Adequacy Metrics November 2012

Steady load growth across the province

Two decades of ~3% annual load growth

with AESO forecasting similar growth

rate going forward

200 to 400+ MW of new capacity

needed each year in addition to

retirements

4,000 – 5,000 MW required by

2022

Reserve margins projected to decline

unless new capacity is added above

current projects being constructed

Significant demand emerging in the oil

sands is creating an opportunity to

supply power 24 x 7

Alberta Interconnected Electric System (AIES)

Reserve Margin, 2000 - 20171

Declining reserve margins

Historic Forecast

59

Alberta potential power demand – oil sands

Project Status Estimated Load

(MW)

Projects in Operation 1,265

Projects Under Construction 419

Projects with Regulatory Approval 1,218

Projects Under Regulatory Review 1,260

Projects Announced / Disclosed 718

Total 4,880

1Source: Oil Sands Developers Group 2Source: The Conference Board of Canada 3Source: The Conference Board of Canada

Oil sands projects1 Investment in generation capacity in

Canada 2010 – 20303

$B

$122 $74

$B

$56

$18 $10

$162

$118

Over $350 billion of investment in oil

sands by 20352

60

Peak demand growth2

MW

Peak demand3(MW) Excluding initial LNG load

Peak demand4(MW) Including initial LNG load

Average peak demand is forecasted to grow at a rate of ~3% per year through 2020

largely driven by increase in industrial demand

BC Hydro is currently working under an extension to the Integrated Resource Plan,

which identifies a short-term peak capacity gap from 2015 – 2020

The only capacity resources that can be available to meet this gap are new natural

gas generation plants

Several companies are currently working to establish LNG export facilities, creating

a potential investment of approximately $20 billion in BC

Residential

Commercial

Industrial

Total

energy

requirements

2011 - 2016 1.9% 2.3% 6.9% 4.0%

2011 - 2022 2.0% 2.1% 5.4% 3.3%

Energy growth rates per year1

British Columbia market drivers

Peak demand

expected to

increase by

approximately

5,000 MW

1,2BC Hydro 2012 Integrated Resource Plan 3,4Peak demand for 2011 is weather normalized

61

British Columbia market drivers

Potential for 5-10 BCF / day of LNG projects in the next

decade

Electric powered compressors leads to lower emissions

(GHG and NOx)

With electric powered compressors, potential power

demand ranges from 2,000 to 4,000 MW in the 2018 –

2025 period with potential to increase

British Columbia LNG – an opportunity to rival the oil sands:

LNG in Kitimat and Prince Rupert

If LNG projects proceed, the Horn River provides a

regional supply of abundant gas reserves. Up to

700MW of additional power may be needed to electrify

the Horn River region of BC to extract the gas reserves

Horn River

Prince Rupert

Horn River

Kitimat

62

Why partner?

Enhances our ability to pursue

more and larger projects

Diversifies investment risk in any

one project

Reduces development and

construction risk

Adds financial strength

Leverages skill sets and

expertise of both parties

Why MidAmerican?

Builds on existing successful

relationship at CEGen

Similar risk and return expectations

Extensive natural-gas fired

generation operating and

construction experience

Financial strength

Partnering for growth

63

Progressing with transmission interconnection process

Progress update

Turbine selection: Mitsubishi

Site location: Sundance site

Permitting Activities: 2014

COD: 2017 / 2018

Must be 75% contracted

Sun 7

Location Alberta

Fuel type Gas fired

generation

Size Up to 800 MW

Total project

cost

$1.2 - $1.4 B

Unlevered after

tax IRR

8% to 10%

Gas reserves update

Continue to target equity ownership of gas production

Targeting 50% of estimated Sundance 7 gas demand

Current market remains favorable for TransAlta

Sundance 7

64

TSR Target:

8 – 10%/yr

Energy Trading


Operational

excellence

1st Quartile cost

performance

Greenfield

growth

Optimized

contracting and

leverage

Well established presence in markets

with strong fundamentals

Extensive market knowledge and

relationships

Proven track record of providing

reliable low-cost power including

behind-the-fence

Partnership with MidAmerican

Competitive advantages

65

Aron Willis

Country Manager

Australia

66

Topics covered

Overview of business

Solomon acquisition

Western Australia resources profile

Growth strategy

67

Iron Ore

Gold

Gold

Nickel

Established in Western Australia in the

early 1990’s

Completed commissioning of our first

power station in 1996

Completed the purchased of WMC

Resources power generation assets in

1999

Specialists in safe, reliable supply of

power to remote mining operations

Overview

Our business Our customers

68

Overview

Our assets

6 power stations

480 MW installed capacity; 425 MW net to TA

Gas turbine and diesel reciprocating engine

technologies

Over 500km of transmission and distribution

infrastructure

Centralized remote control of all facilities

(125 MW)

(112 MW)

(110 MW)

(59 MW)

(37 MW)

(37 MW)

69

Solomon acquisition

$318 million acquisition of Solomon Power Project

(125 MW) to supply Electricity to Fortescue Metals

Group

16-year Power Purchase Agreement with Fortescue;

guaranteed value for 21 years either through a 5

year extension or sale of plant back to Fortescue

Escalating capacity payment adds $40 million in pre-

financing cash flow; payments not tied to production

volumes

Accretive to earnings and free cash flow per share

with low double digit after tax IRR

Flow through of fuel, O&M and maintenance capital

costs

Fits strategically with growth strategy for Western

Australia and provides opportunity for future growth

70

Western Australia

$110.9 billion in mineral and petroleum

exports in calendar year 2011

WA minerals and energy output

accounts for 61% of Australia’s total

exports

116,000 people employed in the mining

and resources sector in the state

Economic engine

Still growing…

$160 billion in mining/resource projects

either committed or under construction

Further $150 billion planned or possible

Iron Ore and LNG dominate the growth

space

Gross State Product growth is forecast

at 4-5% near term

Western Australia Mineral and Petroleum Exports 2011 Total value A$110.9 billion Source: 2011 WA Mineral and Petroleum Statistics Digest – Dept of Mines and

Petroleum

Western Australia Merchandise Exports by Country Total value A$121.2 billion Source: 2011 WA Mineral and Petroleum Statistics Digest – Dept of Mines and

Petroleum

71

Our Assets

Demand growth – minerals and energy

Significant growth is forecast

Current installed capacity of

approximately 9 GW On-Grid ~6 GW

Off-Grid ~3 GW

Energy requirements for new

mining projects and expansions

driving a 58% increase in

consumption to 2018

Compound annual growth rate for

the state from 2012 to 2023

forecast at 5.6%

7.0% minerals and energy

1.8% other industries

Remote location of projects means

95% of the growth will be satisfied

through self-generation

Source: 2012 State Growth Outlook – Chamber of Minerals and Energy

72

Our Assets

Demand growth – by region

Source: 2012 State Growth Outlook – Chamber of Minerals and Energy

Three main target regions

Pilbara: Major mining (hematite iron ore) and LNG investment, possibly new transmission

MidWest: Magnetite Iron Ore creates high electricity demand, large port expansion and some

new transmission

Goldfields: Gold and nickel, potential to aggregate smaller players and grow with current

customers

73

Growth strategy

Double our size to 600 MW MW

Target Solomon

Maintain our position as the leading behind-the-fence generator in Western Australia

74


1st Quartile cost

performance

Competitive Advantages

15 years experience in Australia

Operated throughout business

cycles

Deep technical expertise

Proven track record of reliability

Strong customer and stakeholder

relationships

TSR Target:

8 – 10%/yr

Acquisitions

Greenfield growth


and leverage

Energy Trading

1st Quartile cost

performance


75

Brett Gellner

Chief Financial Officer

M&A

Year Asset/ Company Region Fuel $M¹

1999/2002 Southern Cross W. Australia Natural

Gas/Diesel

$195

2000 Centralia U.S. Coal US$585

2000/2002 Vision Quest Alberta Wind $70

2003 CE Gen U.S. Geo/Gas US$710

2009 CanHydro Canada Wind/Hydro $1,700

2011 Taylor hydro Alberta Hydro Not disclosed

2012 Solomon W. Australia Natural

Gas/Diesel

US$320

Acquisitions have been, and will continue to be, an

important part of our growth strategy

¹ Rounded to nearest $5 million

Over $3.5 billion in acquisitions

77

M&A Market: Observations

Low interest rates and surplus capital resulting in low returns for high quality, highly

contracted assets

Non-strategic funds focused on cash equity returns versus “all-in” and accounting

returns

Tax structures/partnerships and leverage used to enhance equity returns

Select corporates using yield entities and partnerships to be competitive

Non-strategics have less appetite for acquisitions/projects with significant

development/construction risk

Market paying significantly less for early stage development compared to 5 – 10 years

ago

Financing for earlier staged companies a challenge

78

Key criteria

Category Criteria

Geographic regions Canada, Western U.S., Western Australia

Fuel types Gas, Wind, Hydro, Geo

Non-generation Assets Transmission & pipes if connected to

generation

Contracts > 10 years, or cost of service

Counterparties Established with investment grade ratings

or targeting investment grade

Fuel price/supply Flow-through

If not, higher returns required

Cost inflation Escalating PPAs or flow-through

Capital costs Flow-through

If not, higher returns required

Hurdles 8% + unlevered, after tax

Accretion Free Cash Flow per share

79

5,300 MW

3,200 MW

2,800 MW

Over 11,000 MW of existing wind generation

Significant wind opportunities in Western U.S.

0%

35%

Current 2020 Target

RPS Levels and Targets - California

0%

30%

Current 2020Target

2025Target

RPS Levels and Targets - Oregon

0%

20%

Current 2020 Target

RPS Levels and Targets - Washington State

Western

U.S.

80


Proven track record of reliable, low

cost power

Access to multiple sources of

capital

Market knowledge

Development & construction risk

Economies of scale & potential for

synergies

Tax advantages

Competitive advantages

TSR Target:

8 – 10%/yr

Acquisitions

Greenfield growth


and leverage

Energy Trading

1st Quartile cost

performance


81

Brett Gellner

Chief Financial Officer

Financial

Topics covered


2013 Cash flow outlook

Dividend coverage

Dividend reinvestment programs

Credit metrics

Overall valuation

83

Objectives

Drive shareholder value

Maintain financial strength &

flexibility

Targets

TSR = 8 – 10% / yr

Dividend yield plus cash flow per share growth

Add $40 - $60 million of EBITDA per year, on

average

Investment grade credit ratings

Access to multiple sources of capital

Strong liquidity

Reduce risk

Continue to diversify and increase scale with

new assets

Add highly contracted assets

Hedge / contract existing assets

Achieve 1st quartile cost performance


84

Proven track record of adding EBITDA

Genesee 3

Canadian Hydro

5 greenfield wind farms

Sarnia contract

Coal uprates

Bone Creek Hydro

Keephills 3

Coal uprates

Solomon acquisition

New Richmond wind farm

Cost reductions

Growth and other initiatives have more than offset reduction from lower power prices

in the Pacific Northwest and closure/sale of assets

$M Approx. $50 - $60 million of

EBITDA added per year

since 2005

85

Coal

55%

Renewables

24%

Gas

21%

Coal

62%

Renewables

15%

Gas

23%

Reducing risk and enhancing value through diversification

TA: 7,963 MW

2008 TA: 9,065 MW

2012

86

Equity

Asset monetization

Internally generated cash

Preferred shares

Debt

(Corp & Project Finance)

Public & Private partnerships

(New and existing assets)

Reduction in OM&A and capital costs

Significant increase post PPA

Upside to rise in power prices

MidAmerican partnership on gas and geothermal

Interest from private and public entities for

potential partnerships

Recent examples: Meridian

US$400 million 10 year bond

Consider project financing with partners

$780 million raised to-date, receiving 50% equity treatment

Potential for $200 - $300 million more against existing assets

New assets could support more

$300 million raised for Solomon, New Richmond, and debt

reduction

~70% participation rate in Dividend Reinvestment Program

Access to multiple sources of capital to fund growth

87

2013 Outlook

$ millions

Funds from operations1 $800 - $900

Trading gross margin² $40 - $60

Sustaining capex3 $295 - $335

Availability

Cdn Coal

Gas

Wind

90 – 91%

~93%

~96%

Hydro production 2,100 GWh

Wind production – East 1,690 GWh

Wind production – West 1,260 GWh

Alberta power prices $55 - $65 / MWh

MidC power prices $30 - $35 / MWh

¹ Includes Sundance A capacity payments 2. In line with historical performance 3 Excludes Sundance A repair costs

Every $5/MWh change in either market equates to ~$30 million change in EBITDA

88

2013 Estimated excess cash flow and

dividend coverage

Significant excess cash flow available for debt retirement and/or growth

(including funding of Sundance A)

¹ Dividend Reinvestment Programs (DRP) 2 Free Cash Flow (FCF) defined as Funds from Operations (FFO) less sustaining capital less preferred share dividends less other distributions

Excludes DRP¹ proceeds

2013 Excess Cash Flow 2013 Dividend Coverage (% of FCF2)

$M

Free cash flow more than enough to cover dividends

89

Financing growth projects1

$ millions

Capital cost $1,300

Debt financing2 ($910 - $650)

Equity required $390 - $650

Partners’ interest ($195 - $325)

TA’s equity requirements $195 - $325

Years to construct 3

Equity required per year $65 - $108

Internally generated cash3 $90 - $190

Equity cash requirements very manageable for large scale,

greenfield combined cycle gas plant

¹ Illustrative only.

2. Dependent on contract in terms of term, economics and credit worthiness of counterparty

3. Based on chart from previous page using $800 - $900 million in funds from operations

90

Medium-term upside potential from Sundance A

Sundance A expected to generate cumulative incremental EBITDA in the range of

$120 to $280 million in the 2018-2019 timeframe once the PPA expires

1 Free Cash Flow (FCF) defined as Funds from Operations (FFO) less sustaining capital less preferred share dividends less other distributions.

Dividend coverage assumes no change to current FFO, current common and preferred share dividend amounts.

The dividend coverage shown post PPA assumes no additional assets added or divested

Annual incremental EBITDA is available for 2018 and 2019 only as Sun A is scheduled to shut-down at end of 2019 under new Federal Government GHG

legislation.

Estimated incremental annual

EBITDA Post Sun A PPA $M

Post Sundance A PPA

Common dividends as % of FCF1

Represents FFO starting point of $800M


91

Longer-term upside potential from Alberta PPA plants

Expiry of the Alberta Coal and Hydro PPAs is expected to provide significant EBITDA

and dividend coverage upside

2021 Post PPA

1 Free Cash Flow (FCF) defined as Funds from Operations (FFO) less sustaining capital less preferred share dividends less other distributions

Dividend coverage assumes no change to current FFO, current common and preferred share dividend amounts.

The dividend coverage shown post PPA assumes no additional assets added or divested

Annual incremental EBITDA shown will decline over time as the Alberta PPA plants retire based on the new Federal Government GHG Regulations

Cumulative potential upside

(2021 – 2030)

$4.4 - $8.4 billion

Estimated incremental annual

EBITDA Post 2020 $M Common dividends as % of FCF1



92

Dividend reinvestment programs: key features

Standard Program Premium Program

Investors receive additional

shares of TA instead of cash

dividend

Investors receive cash,

which is funded by new

shares issued to the market

Widely used program in

Canada

~8 – 10 companies use the

program

Shares received based on

discount (currently 3%)

Investor receives 2% cash

premium

Participation rate typically in

the range of 30 – 40%

Participation rate typically in

the range of 30 – 40%

Participation rate consistent with other companies with both programs

Current participation rate of ~70% bringing in ~$200 mm of equity per year

93

Dividend reinvestment programs:

key advantages & disadvantages

Advantages Disadvantages

Lower cost than raising equity through

capital markets

Dilutive to shareholders if used solely

for debt retirement

Short-term debt reduction provides

some interest savings benefit to offset

dilution

Target cash flow per share growth

rates more difficult to achieve with

added dilution

Can provide steady flow of equity to

match cash requirements for

greenfield projects

Neutral to accretive to free cash flow

per share for projects generating 8%+

ROCE

Can be scaled back quickly and easily

if there is no good use for proceeds

94

Credit metrics

Cash flow to debt Cash flow to interest

Prefs treated at 50/50 debt/equity Prefs treated at 100% equity

1. LTM – Last 12 months adjusted for one-time payment associated with Sundance 1 & 2 decision 95

Actions taken to enhance balance sheet and risk profile

Issued preferred and common share equity

Implemented premium DRIP program

Termed out US$400 million of debt at lowest rate in recent company history

Exited lower performing and non-core assets

Entered into long-term contract at Centralia

Reduced operating and administration costs

Continue to diversify through adding long-term, contracted assets

96

Trading levels ($M / installed capacity)

On a per megawatt (MW) basis, TransAlta is trading well below most other

power generation companies in Canada

97


TSR Target:

8 – 10%/yr

Financial strength

Dividend

Financial strategy remains unchanged

Focused on delivering cash flow to

fund dividend and growth, and

maintain investment grade ratings

Significant cash flow upside from

Alberta PPAs starting in 2018

Operational

excellence

1st Quartile

cost

performance

Energy

Trading

Optimized

contracting

and leverage

Acquisitions

Greenfield

growth

98

Appendix

99

Bond Maturity Profile

- - - - - - - -

400

- - - -

200

120 27

-

177

400

- -

-

- -

251 300

-

500

-

520

-

- -

-

- -

300

0

200

400

600

800

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025-2040

USD Debt CAD Debt

1 Excluding drawn credit facilities of $1,309 million and amortizing debt of $38 million at September 30, 2012 2 USD debt is presented at an exchange rate of $1 U.S. = $1 CAD

CAD $M

100

2013 Estimated excess cash flow and dividend coverage

Significant excess cash flow available for debt retirement and/or growth

(including funding of Sundance A)

FFO Scenario 750$ 800$ 850$ 900$ 950$

Sustaining Capex (mid point) (315)$ (315)$ (315)$ (315)$ (315)$

Pfd share dividends and other distributions (90)$ (90)$ (90)$ (90)$ (90)$

Free cash flow before common dividends 345$ 395$ 445$ 495$ 545$

Common share dividends (305)$ (305)$ (305)$ (305)$ (305)$

Net Cash Flow before Dividend Reinvestment Plan (DRP) 40$ 90$ 140$ 190$ 240$

DRP at approximately 70% participation 215$ 215$ 215$ 215$ 215$

Net Cash Flow after DRP for Debt Repayment/Growth 255$ 305$ 355$ 405$ 455$

Common Share Dividend Payout

Without DRP 88% 77% 69% 62% 56%

With DRP at a 70% participation rate 26% 23% 20% 18% 17%

2013 Estimated Cash Flow/Dividend Coverage Sensitivity Analysis

1 Based on 262 million shares outstanding to account for DRP (numbers rounded)

1

Free cash flow more than enough to cover dividends

1

1

101

Advanced development pipeline

102

LOCATION PROJECT

NET

CAPACITY FUEL TYPE

TransAlta

CAPEX RANGE

MW $ MM

Alberta Oil sands cogeneration Up to 150 Gas-fired $300 - $325

Alberta Sundance 7 Up to 400 Gas-fired $600 - $700



British Columbia Combined cycle facility Up to 400 Gas-fired $700 - $800

Oregon Wind project 150 Wind $275 - $300

California Black Rock 1-2 117 Geothermal $500 - $600

California Black Rock 5-6 117 Geothermal $500 - $600

TOTAL MW : 2,134 $4.1 B - $4.8 B

2021 - 2022

Projects in advanced development

TARGET

COMMERCIAL

OPERATION DATE

2016 - 2017

2017 - 2018

2020 - 2021

2019 - 2020

2021 - 2022

2018 - 2019

2015 - 2016

INVESTOR DAY 2012 - TransAlta · Grow customer business to 500 MW in Alberta in 2013 and add...

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