TransAlta Corporation. Investor Presentation January 2018

Transcription

1 TransAlta Corporation Investor Presentation January

2 Forward Looking Statements 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: our business strategy and goals, including TransAlta s strategic priorities; emerging industry trends, including assumptions pertaining to declining cost for renewables, abundant supply of low cost natural gas and increasing value of hydro-based power storage; ability to execute on life extension and growth opportunities, including Brazeau Pumped Storage and Bighorn facility expansion; expected $30 million to $50 million to be received annually in credits for TransAlta s existing renewable generation; increase in revenue from Alberta; ability to realize $15 to $20 million annually in green credits in Alberta; qualification for capacity payments in 2021; upside potential for post-ppa Alberta hydro; the implementation of Alberta s capacity market and the regulatory design of such capacity market; forecasted Alberta prices; cumulative life extension of the converted coal-to-gas units; emission reductions anticipated following conversion of coal-to-gas; reduction in fixed costs following conversion to gas; expectations regarding free cash flow ( FCF) of converted units; economic advantages expected to be realized of converted units, including cost and time to build; TransAlta s key growth strategies and opportunities; construction of gas pipeline, including the Tidewater natural gas pipeline, the volumes, cost and expected commercial operation date ( COD ) thereof; the Bighorn hydro expansion and Brazeau Pumped Hydro projects, including the size, cost and timing thereof; the system benefit arising from the Brazeau Pumped Hydro project; growth to be realized, including the Goonumbla solar farm in Australia, the Garden Plains and Cowley Ridge wind farms in Alberta and the Antelope Coulee Wind farm in Saskatchewan, including the capacity, in-service date and cost of each project; capital allocation in 2018 and 2020; future capital structure, including adjusted FFO to net debt in 2020; FCF outlook in 2018; the 2018 outlook, including comparable EBITDA, FFO and FCF ranges; the 2018 to post-2021 FCF outlook; and the relationship with TransAlta Renewables, including TransAlta s continued sponsorship of TransAlta Renewables and the ability of TransAlta renewables to compete for third party acquisitions and new opportunities. Factors that may adversely impact our forward-looking statements include risks relating to: legislative or regulatory developments, including as it pertains to the Alberta capacity market and Federal environmental legislation; changes in economic and competitive conditions; inability to secure natural gas supply and the construction of a natural gas pipeline on terms satisfactory to the Company; the introduction of disruptive sources of energy or capacity; changes in the price for natural gas; decreased demand for energy or capacity; availability of financing; fluctuations in market prices, including deviations of Alberta spot and Mid-C spot prices relative to stated assumptions; the availability of fuel supplies required to generate electricity, including the costs of natural gas within Alberta; changes to the relationship with, or ownership of, TransAlta Renewables; wind and hydro resources being less than long term average; reduction to the Canadian coal capacity factor; our ability to contract our generation for prices that will provide expected returns; risks associated with development projects and acquisitions, including permitting, labour and engineering risk associated with the coal to gas conversions; increased costs or delays in the construction or commissioning of pipelines to the converted units. 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 forwardlooking 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 presentation. 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. 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 at all. We cannot assure that projected results or events will be achieved. Certain financial information contained in this presentation, including Comparable EBITDA, FFO and 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 and the Securities and Exchange Commission on Unless otherwise specified, all dollar amounts are expressed in Canadian dollars. 2

3 Emerging Industry Trends De-carbonization Move away from coal Significant Growth in Renewables Growth in renewables as a source of low carbon generation Cost of renewables is declining Intermittent nature of renewables is shifting value from baseload to peaking resources Natural Gas Generation Growth Abundant supply of low cost natural gas will support dispatchable natural gas generation and coal to gas conversions Shift to Fast- Ramping Technologies Growing need for flexible, responsive generation Value of hydro-based power storage will increase Increasing recognition of the importance of reliability TransAlta well positioned to capitalize on emerging trends 3

4 TransAlta s Priorities Convert coal to gas Leverage our operating platform for value creation Build financial strength Continue to diversify and build customer relationships Grow free cash flow 4

5 PRELIMINARY DRAFT FOR DISCUSSION PURPOSES ONLY, :08 PM TransAlta s Global Generation Portfolio 5

6 TransAlta Today 2016 CASH FLOW FROM GENERATION (1) Coal / Future CTG Solar AUSTRALIA Hydro Wind Hydro Gas Corporate Offices Wind / Solar 22% 6% 30% $830 mm Coal (2) BC AB ON QC NB 42% WA Gas MN MA WY Significant generator with 8,266 MW of capacity Diversified operations with over 65 facilities in three countries Highly contracted (75%) with upside to Alberta market 1 Comparable EBITDA less sustaining capital and excludes Energy Marketing and Corporate Segments 2 Excludes the $80 million adjustment to provisions in the fourth quarter of 2016 relating to our Keephills 1 outage in

7 Natural Gas OVERVIEW 100% of generation contracted 9 year weighted average contract life Total net capacity of 1,348MW 67% Canada and 33% Australia WESTERN CANADA AUSTRALIA EASTERN CANADA CUSTOMER FOCUS Sites designed and built to supply a customer need Excellent track record of extensions beyond original contract term $372 $390 - $410 Gas-fired Generation Assets $315 $334 $290 - $ E 2021E EBITDA ($ millions) Long-term stable cash flows 7

8 Wind and Solar OVERVIEW 71% of generation contracted with an average capacity weighted contract life of 13 years Total net capacity of 1,339MW Canada s largest generator of wind power Experienced developer and operator of wind in Alberta OPERATING MODEL Remote monitoring and operation of all sites optimizes site performance Extensive data enables optimization of operations Able to leverage our knowledge and customer relationships to develop new sites WESTERN CANADA WESTERN U.S. $179 $176 $195 $195 - $215 EASTERN CANADA Wind / Solar Assets $220 - $ E Contracted EBITDA ($ millions) Merchant EBITDA ($ millions) Highly contracted asset base with upside in Alberta 8

9 Hydro OVERVIEW Own and operate over 90% of Alberta s hydro Expecting approximately $25 million annually in green credits under new regulation WESTERN CANADA CANADA EASTERN CANADA Critical back-up for wind and solar Essential for market stability Immediate ramping Hydro Facilities LIFE EXTENSION AND GROWTH $225 - $275 Re-contracted Akolkolex for 30 years Optionality for extensions and upgrades New opportunities: Brazeau Pumped Storage Bighorn facility expansion $87 $73 $82 $65 - $ E EBITDA ($ millions) Unique, reliable and perpetual 9

10 CA and US Coal / Future CTG OVERVIEW Total net capacity of 4,373MW 3,033MW in Alberta and 1,340MW in US PPAs on Keephills 1 and 2 and Sheerness expire at end of 2020 in advance of the transition to the new capacity market STRATEGIC OBJECTIVES Optimize the value of the coal portfolio between 2018 to 2020 Convert 2,600 MW of the Alberta coal fleet to clean energy by 2022 Evaluate timing of conversions of jointly owned facilities Keephills 3, Genesee, and Sheerness OFF-COAL AGREEMENT Government of Alberta annual off-coal payments of $37.4 million totaling $524 million First payment received in Q3/17 Opportunity to monetize ($ million) $451 $456 $434 $395 - $415 Coal / Future CTG Facilities E EBITDA ($ millions) Approximately $200 million in FCF annually for an additional fifteen years beyond 2021 $300 - $350 10

11 PRELIMINARY DRAFT FOR DISCUSSION PURPOSES ONLY, :08 PM Clarity in Alberta s Power Market Transition 11

12 Regulatory Clarity Achieved Coal Phase Out Off-coal agreement and federal rules mean coal is phased out by 2029 in Canada Environmental Policies Initial carbon tax of $30/tCO2 effective January 1, 2018, potentially climbing to $50/tCO2 by 2022 Credits for electricity generation with emissions below 0.37 tco 2 per MWh Existing wind and hydro eligible Capacity Market Supports incumbent and new generation by providing value for capacity Capacity market design well advanced First auction in 2019 for capacity in 2021 Coal to Gas Plant life extended by 5 to 10 years past coal end of life TransAlta s cumulative fleet life extended by approximately 75 years adding over $1 billion of FCF Regulatory clarity supports investment strategy 12

13 Alberta Carbon Rules are a Positive Outcome for TransAlta EXISTING WIND AND HYDRO GENERATION Will receive credits for generation up to the performance standard under the OBA NEW GREEN CREDITS Eligible to use credits for up to 40% of carbon price obligations starting in 2018 Escalating by 5% per year to 60% by 2022 Credits will be used to offset the carbon costs for coal and converted gas units OBA SYSTEM Generators charged based on emissions above the performance standard Generators credited based on emissions below the performance standard Emissions above standard 0.37 tco 2 e/mwh Emissions below standard $30 to $50 million annually in credits for existing renewables 13

14 Upside Potential for Alberta Wind Assets ALBERTA WIND REVENUE (1) Alberta market supports higher value Benefit from higher expected power price due to carbon costs and higher stronger fundamentals $15 to $20 million annually in green credits Will qualify for capacity payments in 2021 $60 $50 $40 $30 $20 Power Revenue ($ mm) Credits ($ mm) Capacity Revenue ($ mm) $10 $0 Today 2018 to 2020 Post 2021 Revenue from Alberta expected to increase over 90% going forward 1) Energy price in 2018 to 2020 assumed to be $65/MWh. Energy and capacity prices post 2021 assumed to be $40/MWh and $10/KW-month, respectively. Credits based on a $30 carbon tax in 2018 to 2020 and a $50 carbon tax post Generation assumed to be 1,000 GWh 14

15 $ millions Significant Upside Post-PPA for Alberta Hydro $300 $225 - $275 $250 $200 $150 $100 $50 $0 Historical EBITDA (5-yr average) Capacity Payment Received from BP¹ Obligations Paid to the BP¹ Future Capacity Payments Emissions Credits Future Proforma EBITDA Comparable hydro assets valued at 12x to 14x EBITDA 1 Balancing Pool 15

16 Development of Alberta s Capacity Market Supports Our Fleet Forward Auction Provides future revenue visibility and stability Equal Treatment All capacity resources permitted to participate TransAlta s entire generation fleet will be able to participate Downward Sloping Demand Curve Mitigates price volatility and supports capacity revenue during periods of oversupply REP Capacity Excluded Avoids negative impact on capacity price due to subsidized renewables TransAlta is well positioned to compete in a capacity market 16

17 TransAlta s Units are Required EXPECTED CAPACITY REQUIREMENTS (MW) Peak Demand 15% Reserve (1) (2) 13,966 1,822 14,441 1,884 15,216 1,985 Adjusted Capacity: 13,700 (3) (4) 12,144 12,557 13, E 2025E 2030E 1 Based on AESO s 2017 reference case 2 Assumes AESO sets a 15% reserve margin above peak demand for determining capacity requirements 3 Adjusted for outages, de-rates and anticipated capacity eligibility for thermal (95%), hydro (90%) and wind (15%) generation 4 Assumes interties are ineligible for capacity 17

18 Forecasted Alberta Prices in New Market Design CAPACITY PRICE FORECAST ($/KW-MONTH) $25 $20 $15 $10 LEI EDC $5 2021E 2022E 2023E 2024E 2025E 2026E 2027E 2028E 2029E 2030E 2031E ENERGY PRICE FORECAST ($/MWH) $55 $50 $45 $40 $35 LEI EDC $ E 2022E 2023E 2024E 2025E 2026E 2027E 2028E 2029E 2030E 2031E Capacity price will be an important driver of future revenue 18

19 PRELIMINARY DRAFT FOR DISCUSSION PURPOSES ONLY, :08 PM Transitioning our Coal Fleet 19

20 MW Converted CTG Conversions: Proven Technology Harding Street Unit 7 MW Converted 450MW Timeframe 2016 Fuel switching is an attractive and economical option for utilities that must maintain a certain generating capacity in their fleet [ ] Power Engineering Shawville Unit 3/4 376MW 2015/2016 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 5,000 4,000 Conversions (# Completed) ,000 Joliet Unit 7/8 1,326MW (1) ,000 1, Not a new concept - many North American examples of CTG conversion 1 Capacity for Unit 6 (290MW), Unit 7 (518MW), and Unit 8 (518MW). Units 7 and 8 are most similar to TransAlta s planned conversions 20

21 Key Driver of Conversion Life Extension TRANSALTA S COAL & CTG GENERATION CAPACITY (MW) 4,000 3,500 3,000 Cumulative fleet life extended by approximately 75 years 2,500 2,000 1,500 1, No Conversion Scenario Convert to Gas 21

22 Key Outcomes of Conversion Emissions Reduction EMISSIONS INTENSITY REDUCTION (%) 48% 60% (1) 98% 95% Carbon emissions are almost halved and particulate emissions are effectively eliminated for converted generation CO2 NOx SO2 Hg 1 NOx reduction ranges from 10% to 70% depending on unit specification. Certain units already generate low NOx emissions. 22

23 $ millions Key Outcomes of Conversions Reduced Fixed Costs $45 $40 $35 $30 Less complex operations lead to significant cost reductions $25 $20 $15 $10 $5 $0 Convertible Coal Converted Gas Fixed OM&A Sustaining Capital Pipeline Tolls Fixed OM&A and sustaining capital costs are reduced 1 Average annual fixed costs for a 400 MW unit by approximately 15% 23

24 Key Outcomes of Conversion Competitive Variable Costs $50 $45 $40 $35 $30 $25 $20 $15 $10 $5 $30 PER TONNE CARBON COSTS ($/MWh) $50 PER TONNE CARBON COSTS ($/MWh) $0 Coal Converted Coal Converted Fuel Carbon Other Cost of carbon drives competitive advantage Note: Converted unit based on natural gas price of $2.50/GJ. Other category includes costs associated with the removal of mercury, and costs associated with reducing NOX, SOx, and particulates. Transmission costs are excluded in all scenarios. 24

25 Key Outcomes of Conversions FCF Generation CUMULATIVE FCF OVER LIFE OF ASSETS ($ MILLION) $3,000 $2,500 $2,000 $1,500 Conversion expected to generate over $1 billion in additional FCF given expected federal regulations Convert to Gas $1,000 $500 Stay on Coal $- Expected FCF growth of over $1 billion with conversion Assumes $30 carbon tax and $8/KW-month capacity price 25

26 Sensitivity of FCF to Capacity Prices EST. AVERAGE ANNUAL FCF UNDER CAPACITY MARKET ($ MM) $400 $350 $30/tonne $300 $250 $200 $150 $ Average $50 - $7.00 $8.00 $9.00 $10.00 $11.00 $12.00 $13.00 Capacity Price ($/KW-month) FCF of converted units is expected to be in-line with historical 26

27 Substantial Economic Advantages Compared to New Build Conversions will be able to enter the market faster, at lower capital cost and with substantially less risk than new CCGT CTG Conversion New Combined Cycle Facility Build Cost (2,700 MW) $300 million $4.5 billion Time to Build 60 days 4 5 years Ramping Slower Faster Carbon Tax Higher Lower Illustrative Heat Rate 9.5x - 11x 7x Conversions will supply customers with low priced, reliable power 27

28 PRELIMINARY DRAFT FOR DISCUSSION PURPOSES ONLY, :08 PM Strongly Positioned For The Future 28

29 TransAlta s Growth Strategy De-carbonize Leverage Existing Sites Leverage Scale and Operational Expertise for Acquisitions Focus on Greenfield & Brownfield Take Some Merchant Risk Expand into New Regions Expand Direct Customer Business Partner 29

30 TransAlta s Growth Strategy Key Actions Strategy Actions De-carbonize Fleet Leverage Existing Sites Leverage Scale and Operational Expertise Focus on Greenfield & Brownfield Take Some Merchant Risk Expand into New Regions Expand Direct Customer Business Partner Convert coal to gas Expand in hydro/wind/solar/efficient gas Expand existing Alberta hydro sites (e.g. Brazeau) Future repowering of existing wind sites Add new natural gas at existing coal sites Integrate new assets without adding significant overhead/admin costs In-sourcing of operations and maintenance Leverage experience and competitive advantage in new builds Less competitive - higher returns Leverage Energy Trading & Marketing expertise and knowledge Opportunities with some merchant risk attract fewer competitors and generate higher returns Expand into other regions of U.S. and Eastern Australia Behind-the-fence generation PPAs with non-traditional counterparties (e.g. technology/telecom companies) Create value by combining strengths of other parties Potential to partner with financial players, OEMs, and customers 30

31 Growth Opportunity Set Alberta natural gas pipeline Potential for 500+ MW of renewables in Alberta and Sask. Behind the fence gas generation in Alberta, BC and Ontario Solar development in Australia and U.S. Significant acquisition opportunities in U.S., Canada, Australia Conversion of 2,500-3,000 MW of coal to gas Potential for 4,000 MW of renewable in Alberta Brazeau energy storage project, Bighorn expansion, Dunvegan Repowering of existing wind sites in U.S. and Canada Acquisitions Replacement of 3,000 MW of converted CTG in Alberta with greenfield natural gas fired generation and storage Greenfield solar and wind in U.S. Acquisitions TransAlta/TransAlta Renewables well positioned to continue to grow 31

32 Alberta Pipeline Strategy NATURAL GAS PIPELINE REQUIREMENTS Sundance and Keephills can consume up to 175 MMcf/d through fuel blending; up to 700 MMcf/d once converted Existing pipelines can provide only limited amount of gas today Two or more pipelines will be secured in order to minimize the risk of any supply disruptions and to provide diversified access to natural gas in Western Canada TIDEWATER NATURAL GAS PIPELINE Entered into Letter of Intent with Tidewater to construct a 120 km pipeline from their Brazeau River Complex to TransAlta s generating facilities Initial volumes of 130 MMcf/d with the potential to expand to 340 MMcf/d Cost of ~$150 million, and expected COD in early 2020 PROPOSED PIPELINE MAP PROVIDES ACCESS TO TIDEWATER STORAGE FACILITIES TransAlta has the option to invest in up to 50% of the pipeline Aligns both companies interests; provides low cost access to natural gas transportation and future flexibility Ownership builds on TransAlta s ownership of natural gas pipeline infrastructure in Australia 32

33 Brazeau Energy Storage SIGNIFICANT VALUE Edmonton Unique one-of-a-kind pumped storage hydro project Up to a 900 MW/5,000 MWh Water Flow Brazeau Reservoir Brazeau Canal Water Flow Brazeau Gorge Brazeau Dam 355MW Investment of $2.5 billion Significant economic and employment benefits Abraham Lake Big Horn 1&2 120MW Water Flow Rocky Mountain House Targeting 2025/2026 operating date Requires long-term contract Ft. McMurray Grande Prairie Bonnyville Hinton Edmonton Camrose Wetaskiwin Red Deer Calgary Drumheller Medicine Hat 100 km Lethbridge 60 mi 33

34 Brazeau Pumped Hydro Significant System Benefits Fast Ramping Load Following Brazeau Pumped Hydro Storage Avoided Curtailment Wind Firming Voltage and Inertia Support Supports Transition to Clean Energy and a Low Cost, Reliable Electricity System 34

35 TransAlta s Brazeau Pumped Hydro Opportunity Proposed pumped hydro Existing power house Leverages existing infrastructure 35

36 Brazeau: Significant Work Completed and Underway Engaged Owner s Engineer, providing Class 5 Estimate Conducted initial geotechnical work Started engagement with First Nations Started environmental field studies Engaged with Governments, Communities, Unions, Regulators and NGOs 36

37 Bighorn Hydro Expansion Expand existing Bighorn from 120 MW to 240 MW Two additional turbines and intake structure Preliminary engineering work completed, identifying no significant issues Utilizes existing infrastructure Capable of providing energy, capacity and ancillary services Preliminary cost estimate of $360 million Brazeau Reservoir Water Flow Brazeau Gorge Edmonton Water Flow Brazeau Canal Brazeau Dam 355MW Bighorn 1&2 120MW Water Flow Rocky Mountain House Abraham Lake 37

38 Australian Growth Goonumbla Solar Farm AUSTRALIA Location Capacity Proposed In-Service Date Capital Costs Other Details 350km North-West of Sydney in New South Wales 70MW 2019 $140 mm 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 Perth Goonumbla Sydney TransAlta continues to build on already its significant Australian presence 38

39 Canadian Wind Projects Garden Plains Wind Location 30 km north of Hanna, Alberta Capacity 130MW Proposed In-Service Date Future Alberta REP calls or third party contracting Capital Costs $260 mm Other Details Wind resource data dating back to 2009 Partnerships with landowners since 2011 Location Antelope Coulee Wind 35 km southwest of Swift Current, Saskatchewan Capacity Up to 200MW Location Capacity Cowley Ridge Wind Repower Northwest of Pincher Creek, Alberta 20MW Edmonton Proposed In-Service Date Capital Costs Other Details April 2021 $400 mm Wind resource data dating back to 2008 Proposed In-Service Date Capital Costs Other Details Future Alberta REP calls or third party contracting $40 mm Site of original Cowley Ridge Wind Farm which was built in 1993 and dismantled in 2016 Long-term understanding of wind resource Hanna Calgary Swift Current Pincher Creek Saskatoon Regina Alberta wind projects remain candidates for future REP procurements or third party contracting; Antelope Coulee prepared for up-coming Saskatchewan RFP. 39

40 Well Positioned to Grow Proven track record with significant opportunities being evaluated Competitive advantages beyond cost of capital Brownfield expansions leveraging existing infrastructure provide unique growth opportunity Continue to utilize TransAlta Renewables for long-term contracted opportunities Remain Focused and Disciplined 40

41 PRELIMINARY DRAFT FOR DISCUSSION PURPOSES ONLY, :08 PM Outlook and Financial Summary 41

42 Capital Allocation to 2020 SOURCES & USES ($ BILLION) $0.4 Existing Liquidity $0.2 Drop down to RNW Bond Repayment $1.4 $0.3 Off-Coal Monetization Amortizing Debt $0.3 $1.2 FCF including payment for Alberta PPA termination Dividend $0.1 Growth $0.3 Uses Sources Capital plan supports the transition to clean energy 42

43 Capital Structure On Solid Ground Debt metrics above target range post 2021 allow for excess FCF to be allocated to growth ADJUSTED FFO TO NET DEBT 30% 25% 20% 15% 15% 17% Current capital plan would result in FFO / Net Debt of ~30% 20% Target range of 20-25% 10% 5% 0% E 2020E Flexibility to fund additional growth over the next three years 43

44 Free Cash Flow Outlook FREE CASH FLOW BUILD-UP ($ MILLION) $600 $500 $400 Int. Exp. Reduction Off-Coal Pmt / MSA Solomon Sundance A Sundance B/C Termination Payment Optimization Sundance B/C $300 $256 Greenlight & Other South Hedland Coal Cost $275 - $350 $200 $100 $ E 44

45 2018 Outlook 2018 Outlook Ranges ($ million) Low High Comparable EBITDA $950 $1,050 Funds from Operations $725 $800 Sustaining Capital (215) (235) Free Cash Flow $275 $350 Free Cash Flow Including PPA Termination Payment $475 $550 Free Cash Flow Per Share $0.96 $1.22 Annual Dividend $0.16 $0.16 Dividend Payout Ratio 17% 13% Range of Key Assumptions Alberta Spot ($/MWh) $50 - $60 Alberta Contracted ($/MWh) $35 - $40 Mid-C Spot (US$/MWh) $20 - $25 Mid-C Contracted (US$/MWh) $47 - $53 Canadian Coal Capacity Factor 65% - 75% Hydro / Wind Resource Long term average 45

46 Free Cash Flow Outlook FREE CASH FLOW BUILD-UP ($ MILLION) $600 $525 - $575 $500 $400 $300 $200 Sundance B/C Termination Payment $275 - $350 $375 - $425 Full Year of Greenlight Interest Reductions Optimization Full Coal Cost Reductions Mississauga Poplar Creek Hydro Upside $100 $0 2018E 2019 to 2020 Post

47 Enhancing Growth Through Sponsored Vehicle COMMENTARY ADVANTAGE FOR TRANSALTA Significant Source of Value Attractive portfolio of highly contracted renewables and gas-fired assets Current dividend yield 7% Majority shareholder - 64% Provides stable and predictable dividends to TransAlta Strong Balance Sheet Low leverage offers strong potential for growth Significant acquisition capacity (both third-party acquisitions and drop-downs) Premium for Strong, Stable Cash Flows Market premium multiple for assets with strong, stable cash flows 10.4x EV/EBITDA Access to competitive cost of capital 10%% AFFO Yield 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 47

48 Why Invest in TransAlta Diversified portfolio in Alberta creates short-term value Significant value creation from coal to gas conversions Strong long term cash flows from diversified portfolio Improving balance sheet Growth opportunities unique to TransAlta 48

49 Value of Coal Not Being Recognized TA RNW TA-Excluding RNW TA Upside $0.9 $1.5 $3.4 Value attributable to existing coal plants in current share price Implies Coal at 6x to 8x EBITDA $3.3 $0.9 PPA Termination payment Renewables and gas not held at RNW Coal Monetization $0.2 $0.2 $0.6 $0.4 $2.2 Hydro (3) $2.2 TA Equity TA Debt, net of cash (1) (2) Preferred Shares NCI RNW Equity RNW Debt Remaining Value Coal Plant Correct valuation for the coal and CTG would increase the share price by $5 to $8 per share Priced as of November 27, Balance sheet items reflect Q values. 1 TA Debt, net of cash includes termination proceeds from Solomon. 2 includes the market value of TransAlta Renewables and BV of TA Cogen. 3 Hydro valued at $2.6 million per MW 49