TransAlta Corporation. Investor Presentation August 2017

Transcription

1 TransAlta Corporation Investor Presentation August 207

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: 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 207 and post-202; source of funds regarding repayment of up-coming debt maturities; and our strategic objectives for 207, 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 suppot 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 and the Securities and Exchange Commission on 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. 2

3 Positioning TransAlta for Growth 60% of Total Cash Flows Are Gas / Wind / Solar on Long-term Contracts () 206 Cash Flow From Generation (2) 22% Gas Wind and Solar 42% 64% of Cash Flow From Generation driven by Gas, Wind, and Solar Natural gas / wind / solar portfolio is 87% contracted (3) on a weightedaverage capacity basis with a weighted average contract life of 0.5 years (3) Canada s largest generator of wind power New Alberta Market Structure Enhances Asset Value 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 Hydro Assets Represent 90% of Alberta s hydro capacity Substantial upside once Alberta PPAs expire in four years Increased reliability and flexibility Significant Growth Opportunities $0+ bn Alberta renewables build-out Australian and AB Renewable Opportunities MW Brazeau Pumped Storage Hydro Low Cost Growth Capital Through RNW 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 TransAlta has entered a new phase with substantial growth opportunities Based on cash flow from generation 2 Comparable EBITDA less sustaining capital and excludes Energy Marketing and Corporate Segments 3 Based on weighted average gross capacity 3

4 PRELIMINARY DRAFT FOR DISCUSSION PURPOSES ONLY, :04 PM TransAlta s Global Generation Portfolio 4

5 TransAlta At A Glance Exchanges TSX / NYSE MAP OF OPERATIONS Enterprise Value,2 $8.0B Coal / Future CTG Solar Market Cap. 2 $2.3B Hydro Gas Wind Corporate Offices 207 Comparable EBITDA (guidance) $,025 -,00 mm 207 Comparable FFO (guidance) $ mm 207 Comparable FCF (guidance) $ mm BC AB 206 Cash Flow From Generation (3) Hydro ON QC NB Wind / Solar 22% 6% 30% Coal (4) WA MN MA $830 mm WY 42% Gas Net Installed Capacity: 8,67MW Canadian Coal / Future CTG: 3,593MW U.S. Coal:,340MW Gas:,473MW Wind / Solar:,339MW Hydro: 926MW AUSTRALIA TransAlta is Canada s largest generator of wind power and the largest generator of renewable energy in Alberta Note: Comparable EBITDA, Comparable FFO, and Comparable FCF are not defined under IFRS. For furtherinformation on non-ifrs financial measures we use, see the section entitled Non-IFRS Measures contained in our Management Discussion and Analysis 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 June 30, Based on closing price on the Toronto Stock Exchange as of August 5, 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 206 relating to our Keephills outage in 203 5

6 206 Cash Flow Natural Gas OVERVIEW 00% of generation contracted 9 year weighted average contract life () Total net capacity of,473mw; 898MW in Canada and 575MW in Australia Approximately 85 90% of our portfolio is not exposed to natural gas price volatility Majority of contracts are capacity with passthrough arrangements for fuel Additional risk management through hedging activities RECENT GROWTH Commissioned South Hedland in July 207 Counterparties: State-owned utility Horizon Power (75%) and Fortescue Metals Group (25%) $80 mm of incremental annual EBITDA from $585 (2) million capital expenditure From Generation (4) WESTERN CANADA AUSTRALIA 42% Gas EASTERN CANADA Gas-fired Generation Assets ($ millions) EBITDA $35 $334 $372 Sustaining Capital (4) $63 $3 $26 Cash Flow From Generation (3) $252 $303 $346 Based on weighted average gross capacity 2 Total 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 rates 3 Comparable EBITDA less sustaining capital and excludes Energy Marketing and Corporate Segments 4 6 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

7 206 Cash Flow From Generation Wind / Solar OVERVIEW 7% of generation contracted 3 year weighted average contract life () WESTERN CANADA Total net capacity of,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 (30MW) - $260 million Cowley Ridge Repower (20MW) - $40 million WESTERN U.S. 42% EASTERN CANADA Wind / Solar Assets Gas Wind and Solar Longer-term opportunities as Alberta moves toward adding 5,000MW renewable capacity by 2030 Existing Alberta merchant wind assets will benefit from higher price ($5-20/MWh) caused by provincial carbon pricing in 208 Australian Solar projects Goonumbla Solar Farm (80MW) - $60 million Based on weighted average gross capacity ($ millions) EBITDA $79 $76 $95 Sustaining Capital $2 $3 $2 Cash Flow From Generation 22% $67 $63 $83 7

8 206 Cash Flow From Generation Hydro OVERVIEW 96% of generation contracted 4 year weighted average contract life () Total net capacity of 926MW Own and operate over 90% of Alberta s hydro (834MW) Ancillary services essential for market stability GROWTH OPPORTUNITIES WESTERN CANADA CANADA EASTERN CANADA Alberta PPAs historically priced below market value expect significant upside potential postexpiry Ability to store water allows for increased upside Brazeau pumped storage hydro project 600 to 900MW at existing hydro site $.8 - $2.5 billion in estimated growth capital Fast-ramping nature supports system reliability as Alberta build-out of intermittent wind occurs Targeting start of construction by 2020/202 Planned COD by 2025 (2) 6% 22% 42% Hydro Facilities Gas Wind and Solar Hydro ($ millions) EBITDA $87 $73 $82 Sustaining Capital $36 $7 $29 Cash Flow From Generation $5 $56 $53 Based on weighted average gross capacity 2 Subject to securing a long-term contract with the AESO 8

9 206 Cash Flow From Generation US Coal OVERVIEW 28% of capacity contracted with Puget Sound Energy which expires in 2025 Centralia facility total net capacity of,340mw Two 670MW units currently scheduled for retirement as coal facilities in 2020 and 2025 WASHINGTON 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 Centralia Facility Coal is sourced from three suppliers in the Powder River Basin 42% Gas Wind and Solar GROWTH OPPORTUNITIES Potential for CTG conversions 3% 6% 22% Hydro U.S. Coal ($ millions) EBITDA $62 $63 $4 Sustaining Capital $2 $5 $7 Cash Flow From Generation $50 $48 $24 9

10 206 Cash Flow From Generation Canadian Coal / Future CTG OVERVIEW Total net capacity of 3,593MW 22% of Alberta s total capacity, supplying approximately 30% of Alberta s energy 76% of generation contracted ALBERTA PPA s expire at end of 2020 in advance of the transition to the new capacity market GROWTH OPPORTUNITIES ~3,000MW of capacity eligible for conversion at a cost of less than 0% 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 $524 million Opportunity to monetize ($ million) ($ millions) EBITDA () $389 $393 $393 Sustaining Capital $2 $83 $69 Cash Flow From Generation Canadian Coal / Future CTG Facilities 27% Gas 42% Wind and Solar Hydro 3% 6% 22% U.S. Coal Canadian Coal $78 $20 $224 Excluding adjustment to provisions relating mostly to prior years (e.g., force majeure events such as the Keephills outage in 203) 0

11 PRELIMINARY DRAFT FOR DISCUSSION PURPOSES ONLY, :04 PM Alberta s Power Market Transition: A Multi-Billion Dollar Opportunity

12 Significant Changes Driving Alberta Opportunity Coal Generation Phase Out Significant Renewable Procurement Summary of Changes 6,200MW Current 2030 Requirement to eliminate coal emissions by ,773 MW 0MW 7,773 MW Current ,000MW of additional renewable capacity by 2030 AB Government providing contracts to support renewables development () Alberta Market Implications Replacing 6,200MW of baseload coal with 5,000MW of intermittent renewables Significant requirement for back-up CTG conversions most economical (less than 0% of new CCGT capex) and best fit with government policy Sizable investment opportunity with build out of renewables, supported by subsidies Transition From Energy to Capacity (2) (2) Energy/AS Capacity Energy/AS Market Implementation in 208/209 First procurement in CTG units expected to set capacity price below cost of new CCGT Carbon Pricing $30/Tonne starting in 208 (3) $50/Tonne by 2022 Currently estimated carbon pricing estimates Energy market pricing expected to increase to account for carbon pricing Increases competitiveness of CTG vs. coal Alberta is transitioning away from coal through ambitious renewables goals For 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 3 Currently expected to be $30 per tonne for everything over performance threshold 2

13 Renewables Procurement Coal-to-Gas New Market Structure Summary of Alberta Opportunity Timing Federal Gas Emissions Regulation Clarity Expected Capacity Market Expected Off-Coal Payments Sundance Unit Retired Sundance Unit 2 Mothballed Conversion of Sundance Units 3 to 6 and Keephills Units and 2 400MW Renewables Procurement (First Round) 400MW Target COD (First Round) 3

14 Renewables Buildout Will Require Back-up Generation Required Coal Retirements Targeted Renewable Capacity Implied Thermal or Pump Storage Hydro Required Capacity 6,200MW 5,000MW Assumed Capacity Factor Capacity Factor Adjusted 95% () 37.5% () 5,890MW,875MW 4,05MW 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-7) Estimated Opportunity of Renewables Build (2) $0B $0.6B coal-togas vs. $6.4B new combined cycle The key to a smooth transition will be allowing about half of Alberta s 8 coal-fired plants to be converted to natural gas by changing out the burners in existing boilers. Globe & Mail, citing Terry Boston (Nov-6) Approx. 4,000MW of new back-up generation or CTG conversions required by 2030 Midpoint of TransAlta s expectations for 35-40% capacity factors based on current technology 2 Assuming $2 mm per MW of wind, $0.375 mm per MW for coal-to-gas and $.60 mm per new MW of combined cycle 4

15 Current Policies Supportive of CTG Conversions Public Policy Favors Clean Energy Conversions Support Lower Electricity Prices 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 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 Policy and consumer pricing concerns supportive of CTG conversions 5

16 Supply (MW) Supply (MW) CTG Well-Placed in the Merit Order ILLUSTRATIVE MERIT ORDER Today () Illustrative 2024 (,2,3,4) Assuming wind and hydro at full capacity Other Simple Cycle Coal Peak Demand,500MW Avg. Demand: 9,000MW Assuming wind and hydro not dispatching Other Simple Cycle Coal Assuming wind and hydro at full capacity Other Simple Cycle Coal CTG Cogen Peak Demand 2,763MW Avg. Demand: 9,989MW Assuming wind and hydro not dispatching Other Simple Cycle Coal Cogen CCGT CTG CCGT Cogen Cogen Hydro / Wind CCGT Hydro / Wind CCGT Supply Scenarios Supply Scenarios Short-Term Demand: Average system load in 206 down less than % from 204 levels Long-Term Demand: Forecasted.5% annual load growth would require an additional 3,000MW by 2030 beyond transition related 9,000MW CTG expected to be competitive under future supply mix For illustrative purposes only 2 Assumes CTG conversions occur for Sundance Units 3-6 and Keephills -2,,600MW of renewables generation is placed in-service (400MW per year for 4 years), and coal-fired retirements expected pre-2024 occur as scheduled 3 Management view of $50 carbon pricing and $3/GJ gas price scenario 4 Intertie import capacity into AB: BC-735MW, Sask 50MW, MATL 300MW not factored into illustrative merit order 6

17 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 CTG Conversion New Combined Cycle Facility Build Cost (per KW) $25 $50 $,500 $,700 Time to Build 60 days 4 5 years Ramping Slower Faster Carbon Tax Higher Lower Illustrative Heat Rate x 7x CTG build cost (less than 0% of new CCGT) and timing advantages significantly outweigh other operating characteristic disadvantages 7

18 Canadian Natural Gas Production (bcf/d) Abundance of Affordable Natural Gas to Supply CTG Western Canadian Production () AECO C$/GJ (RHS) Nymex $C/GJ (RHS) Historical Forecast Increase of ~2% in production by 2026 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 $6 $5 $4 $3 $2 $ Natural Gas Price ($/GJ) 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 Abundance of natural gas supply expected to keep Alberta prices among lowest in the world into foreseeable future Source: Alberta Energy Regulator, National Energy Board Graph represents all Canadian production, but approximately 97% of production driven by BC, AB, and SK 8

19 New Market Structure Supports CTG Conversions KEY MARKET PRINCIPLES WHAT IT MEANS FOR THE MARKET Energy Market Energy price clears based on marginal cost of marginal producer Energy market expected to respond to changes in natural gas and carbon prices CTG and/or coal likely to be marginal producer most of the time between (see slide 6) Margin with CTG units are better than coal margin under most scenarios (gas price/carbon taxes) Capacity Market CTG requires low capital investment ($50 million per unit + life extension costs) New CCGT requires large upfront capital costs (est. $ mm for 400MW) Cash flow from existing assets could be maintained with a capacity price in the $8 $0/KW-month range () New CCGT likely requires high confidence that capacity price will be at a minimum of $2 - $4/KW-month for many years () 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) / 2 months / committed capacity Assumming $50 carbon taxes and $3/GJ gas price 9

20 MW Converted CTG Conversions: Proven Technology Harding Street Unit 7 MW Converted 450MW Timeframe 206 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 205/206 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 7/8,326MW () 206 2,000, Not a new concept - many North American examples of CTG conversion Capacity for Unit 6 (290MW), Unit 7 (58MW), and Unit 8 (58MW). Units 7 and 8 are most similar to TransAlta s planned conversions 20

21 Factors Driving Early CTG Conversion Early Conversion Benefits Expected Timing Expected Near-Term Carbon Costs Operating Expenses and Sustaining Capital Operating Flexibility ~70% savings upon conversion 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) Faster CTG ramp-up, ability to turn unneeded plants off and avoid unnecessary operating expenses will drive improved capacity market competitiveness Policy Implications Political and social influence trending to less carbon, CTG better positioned for potential increases in carbon pricing Reliability Improvements Improved 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 Early conversion provides TransAlta with superior asset flexibility, reduced risk, and enhanced capital efficiency 2

22 CTG and Market Redesign Support Coal Cash Flows CASH FLOW FROM GENERATION (CANADIAN COAL VS. CTG) High $78 mm 204 $224 mm $20 mm Flat CTG CTG conversions expected to replace and potentially improve cash flow from existing Canadian Coal Alberta PPAs currently earning capacityequivalent price of approximately $0-2/KWmonth and negative implied energy margins () CTG conversion expected to result in significantly lower operating costs and sustaining capital going-forward Approximately $8-0/KW-month required to maintain cash flow under a capacity market construct assuming no margin earned in energy markets () CTG expected to replace and potentially improve existing PPA cash flow 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) / 2 months / committed capacity 22

23 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 $77 mm EBITDA 5-Yr average with PPA $49/MWh 5-year Average AB Power Price $62 mm EBITDA 5-Yr illustrative average without the PPA Potential for significant increase to cash flows in new market construct once current Alberta Hydro PPA expires 23

24 PRELIMINARY DRAFT FOR DISCUSSION PURPOSES ONLY, :04 PM Strongly Positioned For The Future 24

25 Positioned to Seize Opportunities in Targeted Markets Opportunity Capacity Capital Expenditures Expected COD Goonumbla Solar Farm 80MW $60 mm Mid-208 Medium-Term Alberta Wind Projects 50MW $300 mm December 209 CTG Conversions 2,37MW $50 mm/unit Saskatchewan Wind 200MW $400 mm 2020 CTG Conversions 662MW $50 mm/unit TBD Longer-Term Brazeau Pump Storage MW $.8 - $2.5B 2025 Other Alberta Renewables 4,600MW of potential $0B of potential Contracted projects can be funded with 60-80% leverage $0.8 to $.0 billion of equity investment Represents investment extending to 2025 ( equity requirements not material given project level debt) Potential for $3B to $4B of contracted growth opportunities over the next 5-0 years 25

26 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 80MW mid-208 $60 mm Site is permitted under the New South Wales Major Project Planning Development process Engaged Tier EPC contractor to undertake construction and operation and maintenance Currently securing offtake agreements Perth Goonumbla Sydney TransAlta continues to build on already its significant Australian presence 26

27 Canadian Wind Projects Garden Plains Wind Location 30 km north of Hanna, Alberta Capacity 30MW Proposed In-Service Date December 209 Capital Costs $260 mm Other Details Wind resource data dating back to 2009 Partnerships with landowners since 20 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 202 $400 mm Wind resource data dating back to 2008 Proposed In-Service Date Capital Costs Other Details December 209 $40 mm Site of original Cowley Ridge Wind Farm which was built in 993 and dismantled in 206 Long-term understanding of wind resource Hanna Calgary Swift Current Pincher Creek Saskatoon Regina Garden Plains and Cowley Ridge Repower submitted to up-coming Alberta procurement; Antelope Coulee prepared for up-coming Saskatchewan RFP. 27

28 Brazeau Investment Supports System Reliability 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 () New Turbines 2 New Dam MW pumped storage project $.8 2.5B investment Brownfield Advantage existing infrastructure (upper reservoir, transmission, reduced cost of project) 2020 / 202 start of construction upon receipt of a long-term AESO contract Fast-ramping nature Supports System Reliability as wind build-out occurs 955,255MW new capacity of Brazeau post-completion Expected to reach COD in large storage best positioned to support build of 5,000MW of intermittent renewables Subject to securing a long-term contract with the AESO 28

29 Enhancing Growth Through Sponsored Vehicle COMMENTARY ADVANTAGE FOR TRANSALTA Significant Source of Value Attractive portfolio of highly contracted renewables and gas-fired assets (2,440MW capacity) () Current dividend yield of 6.6% with recent ~7% increase in dividend post the commissioning of South Heldand Majority shareholder (64% own.) (2) in $3.6B market cap (3) entity Provides stable and predictable dividends to TransAlta Strong Balance Sheet Low leverage (22% net debt / EV) (4) after strong potential for growth Significant acquisition capacity (both thirdparty acquisitions and drop-downs) Premium for Strong, Stable Cash Flows Market premium multiple for assets with strong, stable cash flows 0.5x EV/EBITDA (207) Access to competitive cost of capital 9.4% AFFO Yield (207) 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 Return uplift by developing assets in TA then crystalizing value through RNW Net generating capacity 2 Including Class B shares 3 Based on August 5, 207 closing share price ($4.25) and including Class B shares 4 Net debt based on $4.6B EV and $3.6B market cap. 29

30 PRELIMINARY DRAFT FOR DISCUSSION PURPOSES ONLY, :04 PM Outlook and Priorities 30

31 Tangible Factors Driving Cash Flow Growth $440 mm $400 mm Hydro Upside $30 mm $250 mm () $270 mm 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 & 2 Brazeau Wind RFP in Alberta Other LT Growth Outlook Targeting in excess of $400 million of Free Cash Flow for Includes MSA settlement payment, productivity capital, and Lakeswind tax equity 3

32 ACTIVELY MANAGING MATURITIES REDUCING LEVERAGE Proactively Addressing Up-coming Debt Maturities Adj. Net Debt to Comp. EBITDA Adj. FFO to Adj. Net Debt 25% 20% 6.5% 7.6% 7.0% 8.2% 8.2% 4.3x 4.x 3.8x 3.6x 3.6x 3.5x 3.0x Q2 206 Q3 206 Q4 206 Q 207 Q2 207 Target 25% 20% 5% 0% 5% Maturities to be settled with non-recourse debt / FCF / Solomon proceeds / potential offcoal monetization USD CAD $296 $67 2 $520 $400 $400 $ Debt related to RNW 2 Includes USD$20 million of debt related to RNW 32

33 Executing Our Strategic Objectives 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 4 years Raised $360 million of project debt and increased liquidity to $.7 billion as at December 3, 206 Met 206 guidance for comparable EBITDA (), FFO and FCF; at the high end of FCF outlook range Reposition capital structure through $700 to $900 million of project-level debt over next 2 months Comparable FCF of $270 to $30 million in 207 and target Comparable FCF of $400 to $440 mm by Execute strategy to continue strengthening balance sheet for next phase of growth plans Strategic Growth Prepare for 207 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 Excluding adjustment to provisions relating mostly to prior years 33