investor presentation april 2017 - transalta...analysis and under the heading “riskfactors ......
TRANSCRIPT
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.