investor presentation november 2017 - transalta€¦ · 6 natural gas overview 100% of generation...

11

TransAlta Corporation

Investor Presentation

November 2017

22

This presentation includes 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 available information 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”, “can”, “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 actual results or outcomes to be materially different from those set forth in the forward-looking statements. In

particular, this presentation contains forward-looking statements pertaining to: the new Alberta market structure, including hydro upside following expiry of the power purchase

arrangements; the coal-to-gas conversion; ability to participate in the Alberta and Saskatchewan renewable build-out, including Antelope Coulee, Garden Plains and Cowley Ridge

repower; impact of carbon pricing in Alberta; the development of the Goonumbla solar farm; the Brazeau pumped storage project, including the costs and timing thereof; the

monetization of the Alberta off-coal payments; the changes driving future opportunities within Alberta and TransAlta’s ability to realize on such opportunities; development of policies

to support coal to gas conversion; supply merit order in 2024; characteristics of coal-to-gas conversions relative to new combined cycle facility, including cost, heat rate and ramping;

supply of natural gas; impact of the Alberta market structure on coal to gas conversions; the anticipated benefits associated with converting from coal to gas generation; ability of

hydro assets to earn both energy and capacity revenue; anticipated benefits to be realized through our sponsorship and shareholdings in TransAlta Renewables; factors driving cash

flows in 2017 and post-2021; source of funds regarding repayment of up-coming debt maturities; and our strategic objectives for 2017, including as it pertains to Project Greenlight,

repositioning of the capital structure, realizing upon strategic growth.

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, natural gas, coal, wind, hydro and solar; 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, including the development of regulations pertaining to the capacity market in Alberta and the support of coal-to-gas conversion; disputes with

counterparties, including as it pertains to establishing commercial operation at South Hedland; 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; natural or man-made disasters; the threat of domestic terrorism and cyberattacks; lower than anticipated electricity

prices; equipment failure and our ability to carry out, or have completed, repairs, alterations or conversions 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; 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; increased costs or delays in the construction or commissioning of the Kent Hills wind expansion

project; adverse regulatory developments; and any market disruption or changes in market regulation, including changes relating to the implementation of a capacity market. Many of

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. Readers are cautioned not to place undue

reliance on forward-looking statements, which reflect the Corporation's expectations only as of the date of this news release. The purpose of the financial outlooks contained in this

presentation is to give the reader information about management's current expectations and plans and readers are cautioned that such information may not be appropriate for other

purposes.

Certain financial information contained in this presentation, including Comparable EBITDA, 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 “Reconciliation

of Non-IFRS Measures” contained in our most recently filed Management's Discussion and Analysis, filed with Canadian securities regulators on www.sedar.com and the Securities

and Exchange Commission on www.edgar.com.

Unless otherwise specified, all dollar amounts are expressed in Canadian dollars. References to “TransAlta” include TransAlta Corporation’s subsidiaries, including TransAlta

Renewables Inc., as applicable.

Forward Looking Statements

http://www.sedar.com/

http://www.edgar.com/

33

42%

22%Gas

Wind and Solar

$10+ bn

Alberta

renewables

build-out

600 – 900MW

Brazeau Pumped

Storage Hydro

Australian and

AB Renewable

Opportunities

Low Cost

Growth Capital

Through RNW

Positioning TransAlta for Growth

1Based on cash flow from generation2Comparable EBITDA less sustaining capital and excludes Energy Marketing and Corporate Segments

3Based on weighted average gross capacity

60% of Total

Cash Flows

Are Gas /

Wind / Solar

on Long-term

Contracts(1)

Significant

Growth

Opportunities

New Alberta

Market

Structure

Enhances

Asset Value

64% of Cash Flow From Generation driven by Gas, Wind, and Solar

Natural gas / wind / solar portfolio is 87% contracted(3) on a weighted-

average capacity basis with a weighted average contract life of 10.5 years(3)

Canada’s largest generator of wind power

Convert

Coal

Assets to

Gas

Hydro

Assets

Capacity

Market

Coal-to-Gas (“CTG”) Conversions

Low cost to convert

Extends asset life

Critical stand-by power to support

new renewables

Substantial reduction in capital and

operating costs

Increased reliability and flexibility

Hydro Assets

Represent 90% of Alberta’s hydro

capacity

Substantial upside once Alberta

PPAs expire in four years

TransAlta has entered a new phase with substantial growth opportunities

Alberta’s build-out is the largest single-market investment opportunity in

North America

As Alberta’s incumbent renewables developer – TransAlta is well-positioned

to participate in the 5,000 MW renewable build-out

Significant growth opportunities are already in the pipeline

2016 Cash Flow From Generation(2)

PRELIMINARY DRAFT – FOR DISCUSSION PURPOSES ONLY, 2017-10-31 3:23 PM

44

TransAlta’s Global Generation Portfolio

55

30%

42%

22%

6%

BC

WA

ON

WY

QC

NB

MN

AB

MA

TransAlta is Canada’s largest generator of wind power

and the largest generator of renewable energy in Alberta

TransAlta At A Glance

2016 Cash Flow From Generation(3)

Note: Comparable EBITDA, Comparable FFO, and Comparable FCF are not defined under IFRS. For further information on non-IFRS financial measures we use, see the section entitled “Non-IFRS Measures” contained in our Management Discussion and Analysis1 Enterprise value calculated as: market capitalization + consolidated total debt (book value) + preferred shares (book value) + non-controlling interests (book value) - cash and cash equivalents. Balance sheet data as at September 30, 20172 Based on closing price on the Toronto Stock Exchange as of October 30, 2017 3 Comparable EBITDA less sustaining capital and excludes Energy Marketing and Corporate Segments 4 Excludes the $80 million adjustment to provisions in the fourth quarter of 2016 relating to our Keephills 1 outage in 2013

MAP OF OPERATIONS

Coal / Future CTG

Hydro

Gas

AUSTRALIA

Exchanges TSX / NYSE

Enterprise Value1,2 $7.9B

Market Cap.2 $2.2B

2017 Comparable EBITDA (guidance) $1,025 - 1,100 mm

2017 Comparable FFO (guidance) $765 - 820 mm

2017 Comparable FCF (guidance) $270 - 310 mm

Net Installed Capacity: 8,671MW

Canadian Coal / Future CTG: 3,593MW

U.S. Coal: 1,340MW

Gas: 1,348MW

Wind / Solar: 1,339MW

Hydro: 926MW

Solar

Wind

Corporate Offices

$830 mm

Coal(4)

Gas

Wind / Solar

Hydro

66

Natural Gas

OVERVIEW

100% of generation contracted

9 year weighted average contract life(1)

Total net capacity of 1,348MW; 898MW in

Canada and 450MW in Australia

Approximately 85 – 90% of our portfolio is not

exposed to natural gas price volatility

Majority of contracts are capacity with pass-

through arrangements for fuel

Additional risk management through hedging activities

RECENT GROWTH

Commissioned South Hedland in July 2017

Counterparties: State-owned utility Horizon Power

(75%) and Fortescue Metals Group (25%)

$80 mm of incremental annual EBITDA from $585(2)

million capital expenditure($ millions) 2014 2015 2016

EBITDA $315 $334 $372

Sustaining Capital(4) $63 $31 $26

Cash Flow From

Generation(3) $252 $303 $346

1Based on weighted average gross capacity2Total estimated project spend is AUD$570 million. Total estimated project spend is stated in CAD$ and includes estimated capitalized interest costs and may change due to fluctuation in foreign exchange rates3Comparable EBITDA less sustaining capital and excludes Energy Marketing and Corporate Segments4“Sustaining Capital” primarily includes maintenance capex, routine capital (capital required to maintain our existing generating capacity), mine capital (capital related to mining equipment and land purchases), and finance leases

WESTERN

CANADA

EASTERN

CANADA

AUSTRALIA

Gas-fired Generation Assets

42% Gas

2016 C

ash

Flo

w

Fro

m G

en

era

tio

n(4

)

77

Wind / Solar

OVERVIEW



Total net capacity of 1,339MW

Canada’s largest generators of wind power

Experienced developer and operator of wind in

Alberta

GROWTH OPPORTUNITIES

Near-term opportunities for Alberta’s and

Saskatchewan's renewables procurement

Antelope Coulee (up to 200MW) - $400 million

Garden Plains (130MW) - $260 million

Cowley Ridge Repower (20MW) - $40 million

Longer-term opportunities as Alberta moves

toward adding 5,000MW renewable capacity by

2030

Existing Alberta merchant wind assets will benefit

from higher price ($15-20/MWh) caused by

provincial carbon pricing in 2018

Australian Solar projects

Goonumbla Solar Farm (70MW) - $140 million

($ millions) 2014 2015 2016

EBITDA $179 $176 $195

Sustaining Capital $12 $13 $12

Cash Flow From

Generation$167 $163 $183

WESTERN

CANADA

EASTERN

CANADA

WESTERN

U.S.

Wind / Solar Assets

42%

22%

Gas

Wind and Solar

2016 C

ash

Flo

w

Fro

m G

en

era

tio

n

1Based on weighted average gross capacity

88

Hydro

OVERVIEW



Total net capacity of 926MW

Own and operate over 90% of Alberta’s hydro

(834MW)

Ancillary services essential for market stability


Alberta PPAs historically priced below market

value – expect significant upside potential post-

expiry

Ability to store water allows for increased upside

Brazeau pumped storage hydro project

600 to 900MW at existing hydro site

$1.8 - $2.5 billion in estimated growth capital

Fast-ramping nature supports system reliability

as Alberta build-out of intermittent wind occurs

Targeting start of construction by 2020/2021

Planned COD by 2025(2)

($ millions) 2014 2015 2016

EBITDA $87 $73 $82


Cash Flow From


42%

22% 6%

Gas

Wind and Solar

Hydro

1Based on weighted average gross capacity2Subject to securing a long-term contract with the AESO

2016 C

ash

Flo

w

Fro

m G

en

era

tio

n

WESTERN

CANADA

EASTERN

CANADA

CANADA

Hydro Facilities

99

US Coal

OVERVIEW

28% of capacity contracted with Puget Sound

Energy which expires in 2025

Centralia facility total net capacity of 1,340MW

Two 670MW units currently scheduled for retirement

as coal facilities in 2020 and 2025

Merchant generation sold in US PacNW market

Flexibility to optimize returns

Ability to settle contract with power from other sources

(vs. operating) when favorable to do so

Attractive rail transportation agreement in-place

Coal is sourced from three suppliers in the Powder

River Basin


Potential for CTG conversions and solar farm

($ millions) 2014 2015 2016

EBITDA $62 $63 $41


Cash Flow From


WASHINGTON

Centralia Facility

42%

22% 6%

3%

Gas

Wind and Solar

Hydro

U.S. Coal

2016 C

ash

Flo

w

Fro

m G

en

era

tio

n

1010

Canadian Coal / Future CTG

OVERVIEW

Total net capacity of 3,593MW

22% of Alberta’s total capacity, supplying

approximately 30% of Alberta’s energy

49% of generation contracted after the

termination of Sundance PPAs

PPAs on Keephills 1 and 2 and Sheerness expire

at end of 2020 in advance of the transition to the

new capacity market


~3,000MW of capacity eligible for conversion at a

cost of less than 10% of new CCGT builds

Optimal solution to back-up Alberta’s intermittent wind

build out from a policy and economic perspective

Conversions will materially extend economic life of

units

Early conversions will drive significant reductions in

sustaining capex and operating costs

OFF-COAL AGREEMENT

Government of Alberta annual off-coal payments

of $37.4 million totaling $524 million

First payment received in Q3/17

Opportunity to monetize ($300-350 million)

($ millions) 2014 2015 2016

EBITDA(1) $389 $393 $393


Cash Flow From


1Excluding adjustment to provisions relating mostly to prior years (e.g., force majeure events such as the Keephills 1 outage in 2013)

ALBERTA

Canadian Coal / Future

CTG Facilities

42%

22% 6%

3%

27% Gas

Wind and Solar

Hydro

U.S. Coal

Canadian Coal

2016 C

ash

Flo

w

Fro

m G

en

era

tio

n


1111

Alberta’s Power Market Transition:

A Multi-Billion Dollar Opportunity

1212

Summary of Changes Alberta Market Implications

Coal

Generation

Phase Out

Requirement to eliminate coal emissions by 2030

Replacing 6,200MW of baseload coal

with 5,000MW of intermittent

renewables

Significant requirement for back-up

CTG conversions most economical

(less than 10% of new CCGT capex)

and best fit with government policy

Sizable investment opportunity with

build out of renewables, supported by

subsidies

Significant

Renewable

Procurement5,000MW of additional renewable capacity by 2030

AB Government providing contracts to support renewables development

Transition

From Energy

to Capacity

Market Implementation in 2018/2019

First procurement in 2019-2021

CTG units expected to set capacity

price below cost of new CCGT

Carbon

Pricing

Currently estimated carbon pricing estimates

Energy market pricing expected to

increase to account for carbon pricing

Increases competitiveness of CTG vs.

coal

Significant Changes Driving Alberta Opportunity

Alberta is transitioning away from coal through ambitious renewables goals

$50/Tonne

by 2022

$30/Tonne

starting in 2018(3)

Energy/AS Capacity Energy/AS(2) (2)

1For illustrative purposes only. Simple addition of +5,000MW of renewables capacity from current (does not factor in retirements or additions beyond 5,000MW target) 2“AS” refers to Ancillary Services 3Currently expected to be $30 per tonne for everything over performance threshold

2,773 MW

7,773 MW

Current 2030

(1)

6,200MW

0MW

Current 2030

1313

Summary of Alberta Opportunity Timing

2017 2018 2019 2020 2021 2022 2023+

400MW Renewables Procurement

(First Round)

400MW Target COD

(First Round)

Ren

ew

ab

les P

roc

ure

me

nt

Co

al-

to-G

as

Off-Coal Payments

New

Ma

rke

t S

tru

ctu

re

Capacity Market Expected

Conversion of Sundance Units 3 to 6 and Keephills Units

1 and 2

Sundance Unit 1 Retired

Sundance Unit 2 Mothballed

Federal Gas Emissions Regulation

Clarity Expected

1414

Required Coal

Retirements

Targeted

Renewable

Capacity

Implied Thermal or

Pump Storage Hydro

Required

Capacity 6,200MW 5,000MW

Assumed

Capacity Factor95%(1) 37.5%(1)

Capacity Factor

Adjusted5,890MW 1,875MW 4,015MW

Estimated

Opportunity of

Renewables

Build(2)

Renewables Buildout Will Require Back-up Generation

1Midpoint of TransAlta’s expectations for 35-40% capacity factors based on current technology2Assuming $2 mm per MW of wind, $0.1375 mm per MW for coal-to-gas and $1.60 mm per new MW of combined cycle

Approx. 4,000MW of new back-up generation or CTG conversions required by 2030

$10B

“We can see that those who invest in

renewables and then also have competitive

capacity to back them up will be among the

most competitive electricity generators.”

– Dawn Farrell, TransAlta CEO

(Apr-17)

“The key to a smooth transition will be allowing

about half of Alberta’s 18 coal-fired plants to be

converted to natural gas by changing out the

burners in existing boilers.”

– Globe & Mail, citing Terry Boston (Nov-16)

$6.4Bnew

combined

cycle

$0.6B coal-to-

gas vs.

1515

Current Policies Supportive of CTG Conversions

Policy and consumer pricing concerns supportive of CTG conversions

Pricing carbon is the new reality

CTG conversions provide 40%

immediate reduction in emissions

compared to status quo

Better positioned for further federal

or provincial carbon pricing changes

Public Policy Favors

Clean Energy

CTG

Conversions

CTG are most economic back up to

support intermittent renewables

It will mitigate increasing electricity

costs

Subsidies for renewables build out

borne by consumer through carbon

taxes

Conversions Support

Lower Electricity Prices

1616

Hydro / Wind

CCGT

CCGT

Cogen

Cogen

CTG

CTG

Coal

Coal

Simple Cycle

Simple Cycle

Other

Other

CTG Well-Placed in the Merit Order

1For illustrative purposes only2Assumes CTG conversions occur for Sundance Units 3-6 and Keephills 1-2, 1,600MW of renewables generation is placed in-service (400MW per year for 4 years), and coal-fired retirements expected pre-2024 occur as scheduled3Management view of $50 carbon pricing and $3/GJ gas price scenario 4Intertie import capacity into AB: BC-735MW, Sask – 150MW, MATL – 300MW not factored into illustrative merit order

CTG expected to be competitive under future supply mix

Today(1) Illustrative 2024(1,2,3,4)

ILLUSTRATIVE MERIT ORDER

Hydro / Wind

CCGT

CCGT

Cogen

Cogen

Coal

Coal

Simple Cycle

Simple Cycle

Other

Other

Assuming wind

and hydro at full

capacity

Assuming wind

and hydro not

dispatching

Assuming wind

and hydro at full

capacity

Assuming wind

and hydro not

dispatching

Avg. Demand:

9,989MW

Peak Demand

12,763MWPeak Demand

11,500MW

Avg. Demand:

9,000MW

Short-Term Demand: Average system load in 2016 down less than 1% from 2014 levels

Long-Term Demand: Forecasted 1.5% annual load growth would require an additional 3,000MW by

2030 beyond transition related 9,000MW

Su

pp

ly (

MW

)

Su

pp

ly (

MW

)

Supply Scenarios Supply Scenarios

Simple Cycle

1717

Substantial Economic Advantage For CTG Conversions vs. CCGT

• CTG conversions will be able to enter the market faster, at lower capital cost

and with substantially less risk than new CCGT

Build Cost (per KW)

Carbon Tax

Ramping

Time to Build

CTG Conversion

$125 – $150

Higher

Slower

60 days

New Combined Cycle Facility

$1,500 – $1,700

Lower

Faster

4 – 5 years

CTG build cost (less than 10% of new CCGT) and timing advantages

significantly outweigh other operating characteristic disadvantages

Illustrative Heat Rate 11x 7x

1818Source: Alberta Energy Regulator, National Energy Board1Graph represents all Canadian production, but approximately 97% of production driven by BC, AB, and SK

Abundance of natural gas supply expected to keep Alberta prices

among lowest in the world into foreseeable future

Abundance of Affordable Natural Gas to Supply CTG

Material excess supply

Opportunity for long-term supply

contracts at today’s low pricing

Strong production growth

Focused on liquids (natural gas

viewed by-product)

Market access to United States

challenged

Alberta gas “backed out” by

Marcellus & Utica economics

Producers looking for solutions that

maximize netbacks and price

certainty for their natural gas as they

pursue liquids

--

$1

$2

$3

$4

$5

$6

--

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

20.0

2010 2012 2014 2016 2018 2020 2022 2024 2026

Natu

ral G

as P

rice ($

/GJ)

Can

ad

ian

Natu

ral

Gas P

rod

ucti

on

(b

cf/

d)

Western Canadian Production AECO C$/GJ (RHS) Nymex $C/GJ (RHS)

Lack of local Western

Canadian demand and

export options driving a

fundamental disconnect

between AB and US Markets,

putting long term downward

pressure on AB gas price

Historical Forecast

(1)

Increase of ~12% in

production by 2026

1919

New Market Structure Supports CTG Conversions

Energy

Market

Capacity

Market

KEY MARKET PRINCIPLES WHAT IT MEANS FOR THE MARKET

Energy price clears based on marginal cost

of marginal producer

CTG and/or coal likely to be marginal

producer most of the time between 2021 –

2025 (see slide 16)

Energy market expected to respond to

changes in natural gas and carbon prices

Margin with CTG units are better than coal

margin under most scenarios (gas

price/carbon taxes)

CTG requires low capital investment ($50

million per unit + life extension costs)

Cash flow from existing assets could be

maintained with a capacity price in the $8 –

$10/KW-month range(1)

New CCGT requires large upfront capital

costs (est. $600-700 mm for 400MW)

New CCGT likely requires high confidence

that capacity price will be at a minimum of

$12 - $14/KW-month for many years(1)

CTG conversions will require much lower capacity payments than new CCGT Note: Illustrative calculation of required capacity prices for CTG = Capacity revenue required (cash flow target, fixed OM&A, sustaining capital and return of and on conversion capital) / 12 months / committed capacity 1Assumming $50 carbon taxes and $3/GJ gas price

2020

Timeframe

“Fuel switching is an attractive and

economical option for utilities that must

maintain a certain generating capacity in

their fleet […]”

– Power Engineering

“A number of coal plants nationwide have

converted to natural gas, a move that

uses much of the same infrastructure but

involves different economics, less

pollution […]”

– Midwest Energy News

NORTH AMERICAN

CTG CONVERSIONS

MW

Converted

Not a new concept - many North American examples of CTG conversion

CTG Conversions: Proven Technology

Harding Street

Unit 72016450MW

Joliet

Unit 7/820161,326MW(1)

Shawville

Unit 3/4 2015/2016376MW

2 2 510

2618

-

1,000

2,000

3,000

4,000

5,000

2011 2012 2013 2014 2015 2016M

W C

on

vert

ed

Conversions

(# Completed)

1Capacity for Unit 6 (290MW), Unit 7 (518MW), and Unit 8 (518MW). Units 7 and 8 are most similar to TransAlta’s planned conversions

2121

Factors Driving Early CTG Conversion

Early conversion provides TransAlta with superior asset flexibility,

reduced risk, and enhanced capital efficiency

Early Conversion Benefits

Expected

Timing2021-2023

Expected Near-Term

Carbon Costs~70% savings upon conversion

Operating Expenses and

Sustaining Capital

Significant savings upon conversion driven by lower fixed operating expenses and

sustaining capital expenditures (including avoidance of Clean Air Strategic

Alliance (CASA) compliance capital expenditures)

Operating

Flexibility

Faster CTG ramp-up, ability to turn unneeded plants “off” and avoid unnecessary

operating expenses will drive improved capacity market competitiveness

Reliability ImprovementsImproved reliability critical in a capacity market with performance obligations

CTG expected to operate more reliably than coal units

Gas Pricing Benefit from currently low natural gas pricing environment

Policy

Implications

Political and social influence trending to less carbon, CTG better positioned for

potential increases in carbon pricing

2222

CTG and Market Redesign Support Coal Cash Flows

CTG expected to replace and potentially improve existing PPA cash flow

2014

High

Flat

$178 mm

$210 mm

$224 mm

CASH FLOW FROM GENERATION(CANADIAN COAL VS. CTG)

2015 2016 CTG

CTG conversions expected to replace and

potentially improve cash flow from existing

Canadian Coal

Alberta PPAs currently earning capacity-

equivalent price of approximately $10-12/KW-

month and negative implied energy margins(1)

CTG conversion expected to result in significantly

lower operating costs and sustaining capital

going-forward

Approximately $8-10/KW-month required to

maintain cash flow under a capacity market

construct assuming no margin earned in energy

markets(1)

1Illustrative calculation of required capacity prices for CTG = Capacity revenue required (Cash flow target, fixed OM&A, sustaining capital and return of and on conversion capital) / 12 months / committed capacity

2323

Hydro EBITDA Expected to Increase Post-PPA

Under new Alberta market construct hydro will have ability to earn both energy

and capacity revenue

Storage hydro will be able to bid higher assumed capacity than run-of-river

Potential to unlock significantly higher EBITDA under reasonable power price

environments

+$30/MWh energy prices could result in material EBITDA uplift from those

recently achieved under Alberta PPA

Potential for significant increase to cash flows in new

market construct once current Alberta Hydro PPA expires

$162 mmEBITDA

5-Yr illustrative

average without

the PPA

$77 mmEBITDA

5-Yr average

with PPA

$49/MWh

5-year Average

AB Power Price


2424

Strongly Positioned For The Future

2525

Positioned to Seize Opportunities in Targeted Markets

Potential for $3B to $4B of contracted

growth opportunities over the next 5-10 years

OpportunityCapital

Expenditures

Expected

CODCapacity

Longer-Term

Medium-Term

$1.8 - $2.5B 2025600 – 900MWBrazeau Pump Storage

CTG Conversions $50 mm/unit TBD662MW

$10Bof potential

2020 - 20304,600MWof potential

Other Alberta

Renewables

2019$140 mm70MWGoonumbla Solar Farm

Alberta Wind Projects December 2019$300 mm150MW

CTG Conversions 2021 - 2023$50 mm/unit2,371MW

Contracted projects can be funded with 60-80% leverage

$0.8 to $1.0 billion of equity investment

Represents investment extending to 2025 (2017-2019 equity requirements not material given project level debt)

Saskatchewan Wind $400 mm 2020200MW

2626

Australian Growth

TransAlta continues to build on already its significant Australian presence

Perth

Sydney

AUSTRALIA

Goonumbla

Goonumbla Solar Farm

Location350km North-West of Sydney in New South

Wales

Capacity 70MW

Proposed

In-Service

Date

2019

Capital

Costs$140 mm

Other Details

Site is permitted under the New South

Wales Major Project Planning

Development process

Engaged Tier 1 EPC contractor to

undertake construction and operation

and maintenance

Interconnection agreements are in place

Currently securing offtake agreements

2727

Garden Plains and Cowley Ridge Repower submitted to up-coming Alberta procurement;

Antelope Coulee prepared for up-coming Saskatchewan RFP.

Canadian Wind Projects

Edmonton

Calgary

Saskatoon

Regina

Hanna

Pincher Creek

Swift Current

Garden Plains Wind

Location30 km north of Hanna, Alberta

Capacity 130MW

Proposed

In-Service DateDecember 2019

Capital Costs $260 mm

Other Details Wind resource data dating back

to 2009

Partnerships with landowners

since 2011

Antelope Coulee Wind

Location 35 km southwest of Swift

Current, Saskatchewan

Capacity Up to 200MW

Proposed

In-Service DateApril 2021


Other Details Wind resource data dating back

to 2008

Cowley Ridge Wind Repower

Location Northwest of Pincher Creek,

Alberta

Capacity 20MW

Proposed

In-Service DateDecember 2019


Other Details Site of original Cowley Ridge

Wind Farm which was built in

1993 and dismantled in 2016

Long-term understanding of

wind resource

2828

Brazeau Investment Supports System Reliability

600 – 900MWpumped storage project

$1.8 – 2.5Binvestment

Brownfield Advantageexisting infrastructure

(upper reservoir, transmission,

reduced cost of project)

2020 / 2021start of construction upon receipt of a

long-term AESO contract

Fast-ramping nature

Supports System

Reliabilityas wind build-out occurs

955 – 1,255MWnew capacity of Brazeau

post-completion

Expected to reach COD in 2025 - large storage best

positioned to support build of 5,000MW of intermittent renewables

1 New Turbines

2 New Dam

1 2

1Subject to securing a long-term contract with the AESO

Developing Brazeau pump storage solution to support

adoption of renewables in Alberta

Currently engaging in discussions with the Government of

Alberta in pursuit of a long-term contract

Environmental studies currently underway

Expected commercial operation date in 2025(1)

2929

Enhancing Growth Through Sponsored Vehicle

Return uplift by developing assets in TA then crystalizing value through RNW

1Net generating capacity2Including Class B shares

COMMENTARY ADVANTAGE FOR TRANSALTA

Attractive portfolio of highly contracted

renewables and gas-fired assets (2,440MW

capacity)(1)

Current dividend yield of 6.8%

Majority shareholder (64% own.)(2) in $3.5B

market cap(3) entity

Provides stable and predictable dividends to

TransAlta

Low leverage (24% net debt / EV)(4) after

strong potential for growth

Significant acquisition capacity (both third-

party acquisitions and drop-downs)

Market premium multiple for assets with

strong, stable cash flows

10.6x EV/EBITDA (2017)

Access to competitive cost of capital

9.7% AFFO Yield (2017)

Ability to compete for third party acquisitions

and new opportunities

Ability to align risk/return profile with

appropriate entity

Provides natural home for new renewables

investments

Strong Balance

Sheet

Premium for

Strong, Stable

Cash Flows

Significant

Source of Value

3Based on October 30, 2017 closing share price ($13.81)4Net debt based on $4.6B EV and $3.5B market cap.


3030

Outlook and Priorities

3131

Tangible Factors Driving Cash Flow Growth

Targeting in excess of $400 million of Free Cash Flow for 2018 - 2020

$250 mm(1)

$270 mm

$310 mm

$400 mm

2016 2017

Outlook

South Hedland

(Partial Year)

MSA Settlement

Off-Coal Payment

Lower Margin on

Alberta Coal

Coal Supply Constraints

South Hedland

(Full Year)

Project Greenlight

Interest Expense

Higher Margin on

Alberta Renewables

Mississauga and

Poplar Creek

Sundance Units 1 & 2

Solomon PPA termination

Hydro Upside

Brazeau

Wind RFP in Alberta

Other LT Growth

$440 mm

1Includes MSA settlement payment, productivity capital, and Lakeswind tax equity

3232

$500

$700

$400 $400

$296

2018 2019 2020 2021-2040

USD CAD

1

Proactively Addressing Up-coming Debt Maturities

1Debt maturities as at October 15, 2017

Maturities to be settled

with non-recourse

debt / FCF / Alberta PPA

compensation / potential

off-coal monetization

RE

DU

CIN

G

LE

VE

RA

GE

AC

TIV

ELY

MA

NA

GIN

G M

AT

UR

ITIE

S

4.3x 4.1x 3.8x 3.6x 3.6x 3.6x3.0x

17%18% 17%

18% 18%19%

5%

10%

15%

20%

25%

30%

0

2

4

6

8

10

Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Target

Adj. Net Debt to Comp. EBITDA Adj. FFO to Adj. Net Debt Target

3.5x

20%

25%

3333

2016 2017

Work

Collaboratively

with

Government

MOU to work collaboratively to advance the objectives

of the Alberta Climate Leadership Plan:

CTG conversions

Support for renewables

Opportunity under a capacity market

Work with Alberta Government to secure a long-term

contract for Brazeau

Contribute to the design of a new capacity market

Establish terms and conditions for CTG conversion

Operational

Excellence

Reduced OM&A costs by $20 million y-o-y through

improved mine planning and methodologies, reduced

equipment requirements and optimized contractor

usage

Continue to lead on delivering strong operational, safety

and financial performance

Accelerate “Project GreenLight”

Increase

Financial

Flexibility

Entered into off-coal agreement with Government of

Alberta for $524 million over 14 years

Raised $360 million of project debt and increased

liquidity to $1.7 billion as at December 31, 2016

Met 2016 guidance for comparable EBITDA(1), FFO

and FCF; at the high end of FCF outlook range

$260 million project financing on our Kent Hills wind project

Comparable FCF of $270 to $310 million in 2017 and target

Comparable FCF of $400 to $440 mm by 2018 - 2020

Execute strategy to continue strengthening balance sheet

for next phase of growth plans

Strategic

Growth

Prepare for 2017 Alberta renewables procurement

Analyze CTG conversion potential

Announced Brazeau project development

Continued to grow RNW through drop-downs and

South Hedland completion

Grow renewables through procurements in Alberta,

Saskatchewan and Australia

Take steps to secure CTG conversion gas supply

Continue to advance Brazeau development

Executing Our Strategic Objectives

1Excluding adjustment to provisions relating mostly to prior years

investor presentation november 2017 - transalta€¦ · 6 natural gas overview 100% of generation...

Documents