11

TransAlta Corporation

Investor Presentation

April 2017

22

This presentation may include forward-looking statements or information (collectively referred to herein as “forward-looking statements”) within the meaning of applicable securities

legislation. All forward-looking statements are based on our beliefs as well as assumptions based on information available at the time the assumptions were made and on

management’s experience and perception of historical trends, current conditions, and expected future developments, as well as other factors deemed appropriate in the

circumstances. Forward-looking statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases such as “may”, “will”,

“believe”, “expect”, “anticipate”, “intend”, “plan”, “project”, “forecast”, “foresee”, “potential”, “enable”, “continue”, or other comparable terminology. These statements are not

guarantees of our future performance and are subject to risks, uncertainties, and other important factors that could cause our actual performance to be materially different from that

projected. In particular, this presentation contains forward-looking statements pertaining to our business strategy and goals, including our strategy and position to grow gas-fired and

renewable generation; the anticipated benefits of shifting to a capacity market structure; the repositioning of our capital structure by pursuing project-level debt; anticipated future

financial performance, including as it pertains to comparable earnings before interest, taxes, depreciation, and amortization (“EBITDA”), comparable funds from operations (“FFO”),

and comparable free cash flow; the timing and the completion and commissioning of projects under development, including the South Hedland power project and its associated costs

and benefits; the coal-to-gas conversions, including costs of any such conversions and the anticipated reduction in emissions; development of a pump-storage project at Brazeau,

including the anticipated benefits, total investment costs, location of developments, the increase to capacity and the timing of construction; access to low cost growth capital; ability to

realize growth opportunities, including brownfield solar and battery sites in Alberta in regard to future growth opportunities and targeted gas and renewable acquisitions in Australia,

the United States and Canada; ability to further hedge at prices higher than the current market in Alberta; estimated regulatory environment, including anticipated cost/tonne for

carbon emissions; ability to monetize the off-coal transition payment; the generation supply mix in Alberta by 2030; attributes of coal-to-gas conversions, including the anticipated

capital costs, investment life, reduction in emissions and operating costs; expectations related to future earnings and cash flow from operating and contracting activities;

expectations in respect of financial ratios and targets, including dividend payout ratio; the Corporation’s plans and strategies relating to repositioning its capital structure and

strengthening its balance sheet, including the allocation of debt between the Corporation and TransAlta Renewables Inc. as well as the debt reductions that are expected to occur;

the potential drop-down candidates from TransAlta Corporation to TransAlta Renewables Inc.; and the Corporation’s ownership level of TransAlta Renewables Inc.

Factors that may adversely impact our forward-looking statements include risks relating to: fluctuations in market prices and the availability of fuel supplies required to generate

electricity; our ability to contract our generation for prices that will provide expected returns; the regulatory and political environments in the jurisdictions in which we operate; adverse

regulatory developments, including unanticipated impacts on existing generation and coal-to-gas conversions; environmental requirements and changes in, or liabilities under, these

requirements; changes in general economic conditions including interest rates; operational risks involving our facilities, including unplanned outages at such facilities; disruptions in

the transmission and distribution of electricity; the effects of weather; disruptions in the source of fuels, water, or wind required to operate our facilities; natural or man-made

disasters; the threat of domestic terrorism and cyberattacks; equipment failure and our ability to carry out, or have completed, repairs in a cost-effective manner or timely manner;

commodity risk management; industry risk and competition; fluctuations in the value of foreign currencies and foreign political risks; the need for additional financing; structural

subordination of securities; counterparty credit risk; insurance coverage; our provision for income taxes; legal, regulatory, and contractual proceedings involving the Corporation;

outcomes of investigations and disputes; reliance on key personnel; labour relations matters; risks associated with development projects and acquisitions, including delays in the

construction of or increased costs associated with the South Hedland power project; and any market disruption, including any actions taken by the Balancing Pool as the buyer under

the power purchase arrangements. The foregoing risk factors, among others, are described in further detail in the Risk Management section of our Management Discussion and

Analysis and under the heading “Risk Factors” in our Annual Information Form. Readers are urged to consider these factors carefully in evaluating the forward-looking statements

and are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this document are made only as of the date hereof

and we do not undertake to publicly update these forward-looking statements to reflect new information, future events or otherwise, except as required by applicable laws. In light of

these risks, uncertainties, and assumptions, the forward-looking events might occur to a different extent or at a different time than we have described, or might not occur. We cannot

assure that projected results or events will be achieved.

Certain financial information contained in this presentation, including comparable FFO and comparable FCF, may not be standard measures defined under International Financial

Reporting Standards (“IFRS”) and may not be comparable to similar measures presented by other entities. These measures should not be considered in isolation or as a substitute

for measures prepared in accordance with IFRS. For further information on non-IFRS financial measures we use, see the section entitled “Non-IFRS Measures” contained in our

Management Discussion and Analysis, filed with Canadian securities regulators on www.sedar.com.

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

Forward Looking Statements

33

TransAlta’s Investment Merits

• Geographic: Over 8,600 MW’s of net generation capacity in Canada (75%) , U.S. (18%) and Australia (7%)

• Fuel: Over 70 facilities including wind, hydro, gas, co-generation, coal

• Supporting Stable EBITDA: 70% - 85% contracted generation over next four years

• Reliable: Average contract duration of approximately six years

• Liquidity: $1.7 billion at December 31, 2016

• Annual Cash Payments: From Alberta government for coal compensation total more than $500 million

• Renewables’ skill sets: Alberta’s largest generator with technical, financial, project management, and operating expertise.

• Access to low cost growth capital: Via TransAlta Renewables and internally generated cash.

44

Seizing Investment Opportunities in Targeted Markets

Region Opportunity

(MW’s)

Strategic Considerations

Alberta 5,000

• ~3,000MW’s of coal-to-gas conversions; extending life

of existing depreciated assets

• 600 – 900MW’s pump storage at Brazeau; grow site

capacity to between 955 – 1,255MW’s

• Brownfield wind farms shovel ready for upcoming

renewables bid

• Brownfield solar and battery sites ready for future

opportunities

Australia 5,000

• Wind/solar focus with sites in active development

• Offtake agreements

• Targeted gas and renewables acquisitions

Saskatchewan 1,500 • Wind and Solar sites being developed

Eastern

Canada1,000

• Ontario RFPs greenfield solar/ small hydro uprates

• Targeted gas and renewables acquisitions

U.S. 500• Renewables expansion at existing facilities

• Targeted gas and renewables acquisition

TransAlta’s Global

Generation Portfolio

66

TransAlta’s Generation Asset Overview

Coal: 4,931MW (~73% in Canada)

Wind/Solar: 1,384MW (~84% in Canada)

Gas: 1,323MW (~68% in Canada)

Hydro: 926MW (~100% in Canada)

TransAlta is Canada’s largest generator of wind power and the

largest generator of renewable energy in Alberta

77

Gas & Renewables Cash Flow Leading the Way

• Gas-fired and renewable assets were approximately 70% of total

Cash Flow From Generation(1)

in 2016 and approximately 11% higher

than in 2015.

• $3.3 billion of assets positioned in markets where public policy is

promoting clean power; Canada, Australia and the US

(1) Cash Flow From Generation = Comparable EBITDA (adjusted for the Keephills 1 force majeure provisions) less sustaining capital.

$0

$100

$200

$300

$400

$500

$600

$700

$800

$900

2014 2015 2016

$ m

illio

ns

Cash Flow From Generation

Renewables & Gas Coal Total Generation

(1)(1)

11%

increase

10%

increase

88

Contracted Generation Portfolio Supports Stable EBITDA

Stable cashflows underpinned by contract and hedging strategy

Alberta• Highly hedged through 2017

• Market volatility allow opportunity to

further hedge at prices higher than the

current market

Pacific Northwest• Puget Sound Energy and other long-term

contracts provide base of between

~280MW and 380MW

• Additional shorter-term hedges managed

dynamically to capture market volatility

Merchant exposure in Alberta and the

Pacific NW

2017 Hedge prices

AB ~$45 - $50/MWh

PacNW ~$45 - $50/MWh

2018 Hedge prices

AB ~$45 - $50/MWh

PacNW ~$45 - $50/MWh

Total portfolio contractedness(1)

MW85% 73% 70% 69%

(1) As of Dec. 31, 2016

0

1,000

2,000

3,000

4,000

5,000

6,000

2017 2018 2019 2020

PPAs Long-term contract

Short-term contract /Hedges

Open Merchant

99

Key Growth Drivers in Australian Power Markets

Plant Net

MW’s

Counterpart

Fortescue River Gas

Pipeline

- n/a

South Hedland(1) 150 Horizon Power, Fortescue

Metals Group

Solomon 125 Fortescue Metals Group

Parkeston 55 Newmont Power Pty

Southern Cross 245 BHP Billiton Nickel West

• 2015 Federal Renewable Energy Target (RET) legislation creates a

driver for new transmission connected to solar and wind projects.

• Recent transmission stability issues in Southern Australia triggering a

review of the need for distributed peak power.

Aging coal fleet in Eastern Australia provides opportunity for alternate fuel

sources to replace these assets

(1) South Hedland is expected to be commissioned mid-2017

1010

South Hedland Power Station

150 MW Combined Cycle Gas Power Station in Western Australia

• $585 million project(1)

has been funded without increasing TA debt

• Expected to generate ~$80 million of EBITDA on an annualized basis

• Commissioning expected on budget in mid-2017

(1) Total estimated project spend is AUD$570 million. Total estimated project spend is stated in CAD$ and includes estimated capital interest costs and may

change due to fluctuation in foreign exchange rates.

Seizing Opportunities in Alberta and

Canada’s Transition to an Off-Coal

and Carbon Tax Regime

1212

Rules at the federal and provincial levels are under

discussion and costs/tonne are currently estimated to be:

• Federal: $50/Tonne by 2022

• Alberta: $30/Tonne starting in 2018

Transitioning Off Carbon.. Removing an Uneconomic Input

“Threading the needle on carbon exposure means transitioning out of carbon

sooner rather than later to avoid being subjected to an increasing cost

environment.” Dawn Farrell, CEO TransAlta Corporation

Pricing carbon is the new reality, it will become the largest

sole input cost to power generation driven by policies of

the Federal and Provincial governments.

1313

Required to eliminate coal emissions by 2030.

Will receive annual off-coal transition payments from

Alberta government starting in 2017.

1

2

TransAlta’s Off-Coal Transition Agenda in Alberta

TransAlta’s Response to the Changing Environment

• Working with stakeholders to create new capacity

market

• Converting coal-fired plants to gas-fired

• Development of Brazeau pump storage solution

• Bidding in the AESO REP auctions

1414

Implementing the Climate Leadership Plan

• 14 annual cash payments of $37.4 million totaling $542 million

• Payments expected to occur in third quarter each year until 2030.

• Opportunity to monetize contracted cash flow stream

(~$400 – $420 million)

• Compensation will be recognized as ‘net other operating income/

(loss)’

• Depreciation expense increases by approximately $60 million due

to reductions in useful lives for the Alberta coal assets

Off-Coal Transition Payments Agreement

1515

Implementing the Climate Leadership Plan

Creating a new Capacity Market

Executing coal-to-gas conversions to extend useful

lives of coal facilities

Supporting Renewable Electricity

• Fair treatment of existing renewable generation including the

value of renewable energy credits on existing generation

1

2

Memorandum of Understanding

Tangible Cooperation and Collaboration with

the Alberta Government in terms of:

3

1616

Alberta’s Climate Leadership Plan

CLP Requires

• Retirement of 6,200MW of baseload coal-fired generation by 2030

= ~40% of current installed capacity

• Installation of 5,000MW of intermittent renewable electricity by 2030

= ~2,000MW of reliable generation

Changing the Supply Mix

Issues: Energy-Only Markets

• System reliability risk; renewables

require backup support (lower reserve

margins)

• Depressed price distorts signal for

new firm generation investment

Solution: Capacity Market

• System reliability is maintained

• Provides appropriate price

signals to support new firm

generation investment

1717

Energy Only vs. Capacity Markets

Energy/AS

Energy-Only Market

Capacity Energy/AS

Capacity Market

• Energy market revenues recover

marginal costs

• Capacity market revenues recover

fixed operating & capital costs and

provide for return

• All costs and return of capital

must be recovered from

energy prices in the power

market

1818

Capacity Market – A Stable Investment Environment

TransAlta is well positioned to compete in a capacity market

with highly depreciated coal units that will be converted to gas-

fired generation

Allows existing and new dispatchable generation to compete

for capacity

Provides price and cash flow certainty, resulting in access to

lower cost of capital

Government has committed that non-dispatchable existing

renewables will not be economically harmed

1

2

3

4

TransAlta advocates for, and supports, a Capacity Market

1919

• Biggest market change in two decades.

• Timelines are aggressive; need to align with the first coal retirements.

• Schedule risk has been identified by the AESO

Capacity Market Transition Timeline

2017 2018 2019 2020 2021

Implementation

First Procurement

First Delivery

Schedule risk

Design

Legend:

2020

• What is the best capacity contract term (e.g. 1 year, up

to 7 years)?

• Resource eligibility – should demand participation and

renewables be allowed?

• Will subsidization of renewables distort price formation?

• Requirement to participate – will it be “must offer”?

• How will capacity costs be charged to consumers?

• How will consumers hedge?

Alberta’s Capacity Market Transition - Unknowns

Key Market Design Considerations

2121

TransAlta’s Coal Fleet – Leveraging Critical Mass

• ~3,000MW of coal-fired installed capacity eligible for coal-to-gas conversion;

representing ~50% of total coal capacity in Alberta

• Majority of TransAlta’s coal units are highly depreciated – providing for low-cost

capacity in Capacity Market

• Federal regulations provide opportunity for conversions; proposed standard of

550 t/GWh is under review

PlantMW

(Net)

Annual

GWh1 CommissionedRetirement Under

Exiting Rules2

Retirement Under

Federal Gas Regulation

Sundance 3 368 2,740 1976 2026 2036

Sundance 4 406 3,023 1977 2027 2037

Sundance 5 406 3,023 1978 2028 2028

Sundance 6 401 2,986 1980 2029 2038

Keephills 1 & 2 790 6,046 1984 2029 2040

Sheerness 1(3) 98 708 1986 2030 2045

Sheerness 2(3) 98 707 1990 2030 2045

Genesee 3 233 1,675 2005 2030 2045

Keephills 3 232 1,675 2011 2030 2045

1Based on 85% availability 2Sundance & Keephills 1 and 2 retirement dates are based on existing Federal coal legislation; remaining coal units are based on CLP date of 20303Sheerness 1 and 2 capacity based on 25% ownership interest

2222

Coal-to-Gas Conversion Attributes vs. Coal Generation

Lower Operating

Cost

• 40-50% lower operating & sustaining capital

• 65% lower carbon costs

Conversion &

Life Extension

Competitive

Capital Costs

• ~60 days required to convert coal burners to gas

• Potential to add 15 years to Alberta coal fleet

• Utilizes existing capital, sites and transmission

• $125 - $150/KW cost for burner conversion

Flexibility• Similar ramping and lower minimum stable

requirements

Reduced

Emissions

• 40% reduction in CO2 & up to 70% reduction in NOx

• 100% reduction in Mercury and SOx

Critical path items include:

Securing fuel supply and regulatory approval for gas pipeline

Technology &

Innovation

• Supports market implementation and development of

renewable generation

2323

Coal-to-Gas Conversion – A Comparative Analysis

Coal-to-Gas

Conversion

Reciprocating

Engine

New CCGT

Facility

Cost (per KW) $125 to $150 $1,300 to $1,400 $1,500 - $1,700

Carbon Tax Higher Lower Lower

Capacity Baseload/Mid-merit Peaking Baseload

Ramping Slower Faster Faster

Time to Build 60 days 2.5 to 3.5 years 4 to 5 years

Unit Size ~400 MW 10 to 20 MW 400 to 800 MW

Investment

Commitment

15 years 30 years 30 years

Coal-to-Gas conversions provide:

higher returns, at lower cost, over a shorter project life with

less regulatory risk.

2424

Plant Owner Conversion Details

Harding Street

Station

Indianapolis

Power & Light

2015/16 650MW (Units 5/6/7)

Commissioned: 1958 – 1973

Clinch River American Electric

Power

2016 476MW (Units 1/2)

Commissioned: 1958

Big Sandy American Electric

Power

2016 268MW (1 Unit)

Commissioned: 1963

Shawville NRG 2015/16 626MW (4 Units)

Commissioned: 1954 – 1960

Big Cajun NRG 2015 580MW (1 Unit)

Commissioned: 1982

Examples of Executed Coal-to-Gas Conversions

The conversion of coal units to gas-fired generation has been taking

place in the United States for a number of years.

2525

Brazeau Investment Supports System Reliability

600 to 900 MW pumped storage expansion

Increases Brazeau’s capacity to 955 -

1,255 MW.

Low cost alternative to greenfield build out

Investment of ~$1.8 billion to ~$2.5 billion

Targeting 2021 commencement of construction,

subject to long-term contract

1

2

3

Brazeau4

5

Large battery storage to support adoption of renewables

Current Capacity of

Brazeau is 355MW

2626

Brazeau Hydro – Looking Forward

1

New Dam

New Turbines1

2

2

Brownfield Expansion Utilizes existing site and infrastructure

Reliability Provides system support as wind build-out occurs

Flexibility Fast ramping

Sustainability Perpetual assets – existing hydro fleet is 100 yrs. old

2727

Brazeau Hydro – Our Action Plan

2017 2018 2019 2020 2021 2022 2023 2024 2025

Environmental Studies

Regulatory Applications

Engineering

Procurement

Construction

COD

Stakeholder Engagement

Secure Contract

Securing long-term contract with AESO is a key stage gate

2828

Leveraging TransAlta’s Operating Advantage in Alberta

History of developing and operating renewables facilities has lead to:

• Strong understanding of wind resources and hydrology

• Long-standing land owner and stakeholder relationships aid future

development plans

• Trusted developer and supporter of community enhancement projects

(TransAlta Tri Leisure Centre)

300MW’s of development ready wind sites in Alberta

• Advanced stages of development available for near-term AESO REP

• Near existing transmission and infrastructure

1

2

Financial Strategy

3030

0

50

100

150

200

250

300

350

400

450

500

2013 2014 2015 2016 2017 2018-2020

Comparable FCF Growth

Sufficient FCF to Fund Growth and Strengthen B/S

$280 to $315 million of Comparable FCF(1)

between 2013 and 2016$M

Outlook

Range

Target

(1) Comparable Free Cash Flow includes dividend payments on preferred shares but not dividend payments on common shares.

(2) Allocation between debt and growth shown for illustrative purposes only.

Expect capacity market to deliver similar FCF as current PPA

Growth(2)

Debt(2)

3131

Upcoming Debt Maturities

(1) Debt related to RNW.

(2) Includes USD$20 million of debt related to RNW.

$400$520

$700

$167

$400 $400

$296

$0

$200

$400

$600

$800

$1,000

$1,200

2017 2018 2019 2020 2021-2040

USD CAD

Upcoming Debt Maturities

($ millions)

1

2

$360M of non-recourse debt raised in 2016 will be used to settle 2017

maturities

3232

Finance & Treasury Overview

Area of Focus Execution

Liquidity• Average liquidity of $1.3B since 2014; liquidity of ~$1.7B at

December 31, 2016 including cash of $305 million

Area of Focus Execution

Financial Ratios • Ratios expected to improve once South Hedland is operational

Ratio 2013 2014 2015 2016 Target

Comparable FFO before Interest to Adjusted Interest 3.7 3.8 3.8 3.8 4 – 5x

Adjusted FFO to Adjusted Net Debt 15.2 16.9 15.2 17.0 20 – 25%

Adjusted Net Debt to Comparable EBITDA 4.6 4.2 5.0 3.8 3 – 3.5

(1) Reduction in Available Liquidity due to reduction in US bilateral credit facility from $300 million to $200 million.

Outlook and Priorities

3434

Executing on our 2016 Priorities

Secured a mutually beneficial coal transition

arrangement with the Alberta Government

Continued to reposition our capital structure

Continued to grow TransAlta Renewables Inc.

Continued to focus on delivering strong operational,

safety and financial performance

3535

Executing on 2016 Financial Goals

$9

90

$1

,06

5

$1

,10

0

$-

$200

$400

$600

$800

$1,000

$1,200

Low 2016 High

Comparable EBITDA

$7

55

$7

63

$8

35

$-

$200

$400

$600

$800

$1,000

Low 2016 High

Comparable FFO

$2

50

$2

99

$3

00

$-

$100

$200

$300

$400

Low 2016 High

87

%

89

%

89

%

80%

85%

90%

Low 2016 High

Comparable FCF CAD Coal Availability

(1) Includes $80 million provision adjustment related to the Keephills 1 force majeure.

(1)

3636

2017 Priorities – Positioning for Competition

Work collaboratively with the Government of Alberta

• Advance our investment in Brazeau by securing long-term contract

• Contribute to the design of a new capacity market

• Establish terms and conditions to convert coal plants to gas

Commission South Hedland

Grow renewables through RFP’s in Saskatchewan, Alberta and Australia

Execute our financing strategy to further strengthen the balance sheet

Continue to lead in safety and environment performance while delivering

against our 2017 financial targets

1

2

3

4

5

3737

2017 Outlook Ranges ($M)Comparable EBITDA $1,025 $1,135

Comparable Funds from Operations $765 $855

Sustaining Capital (260) (280)

Pfd Share/Other Distributions (205) (210)

Comparable Free Cash Flow $300 $365

Comparable Free Cash Flow Per Share $1.04 $1.27

Annual Dividend $0.16 $0.16

Dividend Payout Ratio 15% 13%

2017 Outlook

Range of Key AssumptionsPower Prices

Alberta Spot ($/MWH) $ 24 - $ 30

Alberta Contracted ($/Mwh) $ 45 - $ 50

Mid-C Spot (US$/MwH) $ 23 - $ 28

Mid-C Contracted (US$/MWh) $ 45 - $ 50

Other

Canadian Coal Availability 86% - 88%

Hydro / Wind Resource Long term average

3838

Executing Our Strategic Objectives2016 2017

Operational

Excellence

• Reduced OM&A costs by $20 million

year over year through improved

mine planning and mine

methodologies, reduced equipment

requirements and optimized

contractor usage.

• Continued focus on delivering

strong operational, safety and

financial performance.

Increase

Financial

Flexibility

• Entered into an off-coal agreement

with the Government of Alberta for

~$524 million over the next 14 years.

• Raised ~$360 million of project debt

and increased liquidity to ~$1.7 billion

at year end.

• Met 2016 guidance for comparable

EBITDA(1)

, FFO and FCF; at the high

end of FCF outlook range.

• Reposition our capital

structure by pursuing $700 to

$900 million of project-level

debt over the next 18 months.

• Repayment of maturing debt

in 2017 with existing liquidity.

• Target FCF of $400 million by

2018 to 2020.

Strategic

Growth

• Plan to participate in the 2017 Alberta

RFP for renewables.

• Conversion of coal plants to gas.

• Announced Brazeau pump storage

hydro project development.

• Longer-term, prepare to

capitalize on opportunities in

renewable generation.

• Continue to seek a long-term

contract for our Brazeau

project with the Government

of Alberta.

(1) Excluding adjustment to provisions relating mostly to prior years.

4040

Leveraging TransAlta Renewables Inc.

TransAlta Corporation and TransAlta Renewables are strategically aligned

TransAlta Renewables

TransAlta Public

~60-80% ~20-40%

• TransAlta is the largest

shareholder of TransAlta

Renewables Inc. and will

maintain ~60-80% ownership

• Unlocks the value of long-life

contracted assets on attractive

terms

• Provides access to lower cost

funding

• Strong currency to support

accretive acquisition of third party

assets

4141

TransAlta Renewables (TSX:RNW)

• Provides stable, consistent returns through the ownership of highly

contracted power generation and other infrastructure assets

Enterprise Value¹ $4.8 Billion

Market Cap.2

$3.7 Billion

2017 Comparable EBITDA (guidance) $425 - $450 million

2017 Comparable CAFD (guidance) $235 - $260 million

Dividend Yield 6.0%

Net Generating Capacity (incl. South Hedland) 2,441 MW

TransAlta Corporation’s Ownership 64%

¹ Does not include capital required to complete South Hedland Project2 Based on closing price as of March 1, 2017 and including Class B shares

Wind Hydro Gas Fired Gas Pipeline

4242

Significant Drop-Down Inventory

Potential Drop-Down Candidates from TransAlta Corporation

Gas Fired

Generation

• ~400 MW in Alberta & Ontario including:

• 244 MW Poplar Creek facility in AB

• ~150 MW from 4 facilities through TA Cogen

• ~$140M EBITDA

Alberta Hydro

• ~800 MW from 13 units in Alberta, representing

90% of Alberta’s hydro

• ~$60 - $120M EBITDA

Other

Renewables

• 20 MW wind facility in ON

• 50 MW wind facility in Minnesota

• 21 MW solar facilities in

Massachusetts

Appendix

4444

Financial Performance by Business Segment

Business

Segment

2011 2012 2013 2014 2015(1) 2016

(1)

Comparable EBITDA ($M)

Canadian Coal $273 $373 $311 $389 $393 $393

U.S. Coal $211 $148 $67 $65 $67 $41

Gas $275 $312 $332 $312 $330 $372

Wind and Solar $163 $151 $181 $179 $176 $195

Hydro $105 $127 $148 $87 $73 $82

Energy Marketing $101 ($13) $58 $75 $37 $52

Corporate ($84) ($83) ($74) ($71) ($72) ($70)

Comp. EBITDA ($M) $1,044 $1,016 $1,023 $1,036 $1,004 $1,065

Comp. FFO ($M) $812 $788 $729 $762 $740 $763

(1) Canadian Coal is normalized for provision adjustments including $80 million and $59 million in 2016 and 2015, respectively.

4545

Australia – 20 Years of Investment Experience

0

100

200

300

400

500

600

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

$200

19

97

19

98

19

99

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

20

14

20

15

20

16

20

17

Net

Cap

acit

y (

MW

)

Au

str

alian

Rev

en

ue (

CA

D$ m

illio

ns)

December 2002

Added remaining 15% ownership in

Southern CrossJanuary 2006

Gas turbine commissioned at

Southern Cross

September 2015

Solomon facility, acquired from Fortescue in

2012, commissioned.

Mid-2017

150 MW South Hedland facility expected to

on-line

Original Investment

Parkeston (55 MW net to TransAlta).

January 1999

TransAlta acquired a 85% interest in

Southern Cross; cash consideration of $187

million.