INVESTOR DAY 2012 POWER INFRASTRUCTURE
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
Operational excellence
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
Boiler repairs / pieces of work – over 6,000
Partial waterwall and economizer replacement
Main transformer replacement
Total labor hours – 515,000
Sundance 5
Turbine HP valve overhaul
Boiler repairs / pieces of work – over 6,000
Generator links replacement
Total labor hours – 250,000
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
Driving shareholder value
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
Driving shareholder value
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
Optimized contracting
and leverage
Energy Trading
1st Quartile Cost
performance
Operational excellence
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
Driving shareholder value
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
Driving shareholder value
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
Optimized contracting
and leverage
Energy Trading
1st Quartile cost
performance
Operational excellence
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
Driving shareholder value
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
Optimized contracting
and leverage
Energy Trading
1st Quartile cost
performance
Operational excellence
81
Brett Gellner
Chief Financial Officer
Financial
Topics covered
Financial objectives
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
Financial objectives
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
Represents FFO starting point of $900M
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
Represents FFO starting point of $800M
Represents FFO starting point of $900M
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
Driving shareholder value
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
Alberta Sundance 8 Up to 400 Gas-fired $620 - $720
Alberta Sundance 9 Up to 400 Gas-fired $640 - $740
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