TransAlta Corporation (TSX:TA)

Investor Day 2019

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Sep 16, 2019

Good morning, everyone, and welcome to TransAlta's 2019 Investor Day here in Toronto. We're so happy to be here with you all. My name is Tiara Valentini for those that don't know me, and I am the Manager of Investor Relations here at TransAlta. I would like to inform you all that today's presentation will be webcast and recorded. I invite those listening along to view the supporting slides, which are now available on our website. An audio replay of the presentation will be available later along with the transcript. That will be posted on our website shortly thereafter as well. Before we start the presentation, I would like the audience in the room to take note of the following safety messages. There are 2 exits to this room, 1 at the front and one at the back. In the event that there is an emergency, kindly proceed to the exit nearest you and make your way to the corridor next to our meeting room. The emergency exit stairwell is located in this corridor next to the women's washroom. This stairwell will take you down to the ground floor on Pearl Street. From there, make your way to St. Andrew's Church, which is on the southwest corner of King Street and University Avenue. This is the Vantage Building designated muster point. I will now turn to our advisory on forward looking statements. As we begin our session, I would like you to note that this presentation includes a number of forward looking statements, which are based on a number of assumptions and subject to a number of risks and uncertainties, many of which are set forth on this slide behind me. I would encourage you to read it subsequently at your convenience. This presentation contains references to non IFRS measures. Such measures may not be comparable to similar measures presented by other entities. Information regarding these non IFRS measures can be found within this presentation and also within our annual and quarterly MD and A report. And so without further delay, I would like introduce Dawn Farrell, President and Chief Executive Officer of TransAlta, and welcome her to the podium. She will start us off with panel introductions and kick off our session with an overview of our agenda. Welcome, Dawn. Thanks, Kiara, and welcome, everyone, and thanks for all of you for coming out today. I am going to start with some introductions of the team and I'll walk through the agenda. I am going to do a brief overview of TransAlta for those of you that don't know us well. So for those of you that do, just bear with me, it won't take that long. And then I'll get into the meat of what we're here to talk about today, which is our strategy. So today, of course, we have John Pusanores with us. He's our Chief Operating Officer. His primary focus now at the company is to consolidate the business under a single team as it moves to a simpler operation. And of course, you'll hear about that today. Today, he's going to take you through our views of the market fundamentals in Alberta. He'll touch on Ontario and he'll also give you an overview of these existing operations and the work that they're doing there. Many of you know Brett Gellner. He's our Chief Development Officer. He's working on the projects for the future. And under his leadership, we've developed our coal to gas conversion strategy and we're pursuing a pipeline a solid pipeline of unique investment opportunities. He's joined by Wayne Collins. Wayne is our Executive Vice President of Generation. As some of you know Wayne as the brains behind our stronger performance at our Alberta coal fleet and he recently transitioned the Sundance units off their PPAs in Alberta very, very successfully. Now together, Brett and Wayne are going to take you through our plans for converting our Alberta coal fleet to gas by 2025 actually by the end of 2024 and the very beginning of 2025. Aaron Willis is our Senior Vice President of Growth. Some of you have seen him a while ago when he was in his role as our General Manager of Australia. So he's back now in Canada and he's focused on working with BREC to prospect, develop, buy, build and contract new generation plants here in Canada, in the United States and in Australia. He's going to walk you through our development pipeline, our focus for renewables growth and our plans for delivering some on-site cogeneration. And he'll also update you on the construction projects that we currently have underway. We and then of course, we have Todd Stack. He was appointed our Chief Financial Officer in May. And he's going to show you how we're going to finance our transition. Now I've worked with Todd for over 25 years now. He has extensive background in the industry, including engineering, development, treasury and most recently as our corporate controller. That makes him a fantastic partner as for ensuring that we can successfully finance the transition that we'll take you through. We are going to have a short break between Brett and Aaron and we'll have a Q and A at the end of the session. So, let's get started. So, I want to start with why invest in TransAlta. So, we're very, very excited to be here today to roll out the execution plan that underpins the strategy that we communicated to you in September or December of 2017. And on this first slide, you'll see that by the end of 2025, TransAlta's fleet will be 100% clean energy. You're also going to hear today that our execution plan is deep and it's well underway. And this is great news for you, our shareholders. Today, we're outlining our clean energy investment plan that has strong and lasting returns and it has significant upside potential. Our investment path enables us to continue to be a low cost and cornerstone player in the Alberta power market. And in addition, the way that we've designed this plan, we now have the financial capability to also grow our gas and renewables business. Our plan will be executed while keeping our balance sheet strong. And this is going to be done by using the funds we raised earlier this year and those that will be generated from the base business. We do have a strong culture, which is focused on execution. And today, you'll hear that we have all the major building blocks in place to be successful. So the leadership team at TransAlta is passionate about our investment strategy and believe this is a great time to be an equity holder in the business. So just for a few of you that don't know us, let me start by reminding you just briefly who we are. We are a leader in clean energy with a fierce commitment to a future. Our mission is to provide safe, low cost, reliable and clean energy. And most importantly, our employees have embraced innovation, safety and sustainability and they incorporate these values into all of their decisions and all of our decisions. Their determination to create a respectful workplace where personal integrity is the price of entry helps us to drive results that are both sustainable and lasting. Now today, we own and operate 71 facilities across 3 countries and 5 fuel technologies. Our marketing and trading group optimizes cash flows in markets where we have merchant supply and we generate electricity today using coal, natural gas, wind, water and the sun. And of course, by 2025, we will no longer be using coal as a primary feedstock. We do love the diversification of technology markets customers and the optionality of selling megawatts from our plants to both markets and customers. And by the end of 2021, our coal fleet will be well on its way to gas with only 32% of the fleet remaining on coal. As we roll off the remaining PPAs in Alberta at the end of 2020, the 62% of our megawatts in the Alberta market simply become more valuable. So today. Today, we'll be presenting our company in a very simple way, you can see where we are driving value. We operate 1 TransAlta with a single operating model for all our plants, trading, marketing and our shared services operation. We have a consolidated growth team with a consistent approach to development, acquisition and construction. And by focusing on our leadership, our leadership on driving value from each of our assets in each of our markets, we drive value for TransAlta shareholders. Now like others, we do have many companies and joint venture relationships underneath the TransAlta banner. The business arrangement that gets the most attention is TransAlta Renewables. Most of the projects that are in renewables were originally developed and built in TransAlta. And by selling these assets to renewables, we were able to create significant value for TransAlta shareholders. Having TransAlta Renewables as a financing vehicle for long term contracted gas and renewable projects allows us to attract additional sources of low cost capital. You know and we know that we always have questions from investors about the relationship between TransAlta and TransAlta Renewables and if there are benefits to having the 2 companies under a single operating model. And by the time you leave today, you'll be convinced that a single operating model is not only smart, but it's competitive. Moreover, we'll outline our newly announced dividend policy for TransAlta Corporation and we'll be presenting information regarding our capital allocation for TransAlta on a deconsolidated basis. And this will help our investors see how the dividends from TransAlta Renewables flow through to the capital allocation decisions at TransAlta. Since we last updated you in 2017, we've delivered on many fronts to support the execution of the strategy that we're presenting today. We are proud to say that we generated a record free cash flow of $367,000,000 in 20.18 and this was before the additional 100 and $57,000,000 of PPA termination proceeds that we received from the balancing pool. We also received an additional $58,000,000 in funds in August of this year after winning an arbitration for the recovery of the mining assets under those PPAs. Our Greenlight program has been a keystone of our transformation, driving innovation across the company and adding more than $70,000,000 of value to our bottom line. We are here today to put a final bow on our coal to gas transition. Our gas pipeline is now built and commissioned and it's putting us well ahead in that strategy. Today, we're going to show you how we've adapted our plan to take advantage of the decision to continue with an energy only market in Alberta. We did we also acquired 100 percent of Key Pals III, so that we now have maximum flexibility for timing our conversions. Today, Brett and Wayne will outline a clear plan and will provide estimates of EBITDA under various prices for our repowering strategy in Alberta. You'll see that we pivoted our strategy towards repowered combined cycle plants to account for the decision to stay with an energy only market in the Alberta power system. Our clean energy investment plan positions the Alberta business to be very competitive and it is a key driver of the value proposition that we are presenting here today. Now in terms of our renewables growth strategy, we have secured 3 additional wind farms in the U. S. And a new wind farm in Alberta. These projects come with quality counterparties and stable long term cash flows. And we do expect shortly to announce our 1st new small on-site cogeneration project and Aaron will show you how we're developing that business. On the capital front, we've reduced the TransAlta corporate debt by CAD323,000,000. Dollars We've improved our credit position and our balance sheet significantly. In addition, we secured 750,000,000 of capital from Brookfield in the form of a strategic relationship that has added expertise to our board and Brookfield as a cornerstone shareholder. This funding allows us to buy back up to 250,000,000 of shares, accelerate our coal to gas transition and achieve $1,200,000,000 in senior bonds by the end of 2020. And these are all extremely important pieces of our execution plan. So today you're going to see that we are positioned for the energy only market in Alberta. It's no secret that TransAlta's fleet is significant in the Alberta market. Our generation base is twice the size of the next largest player. The good news is that our fleet is diversified between thermal and renewables and that it's needed for reliability for the province. It's also no secret that our view was that a capacity market offered strong benefits to customers and the system in a world that increasingly favors renewable generation. A key foundation of our strategy at the company is to ensure that Alberta power prices remain low and competitive. And this has been a value in the company since 1911. And it's also an important value for us to ensure that our investors achieve returns that match the risks of reinvesting in our fleet in our home market. The shift back to an energy only market required us to pivot our strategy. And because we now have all the building blocks in place, we were able to do that. A combination of the right carbon policy federally and provincially, our ability to build the Pioneer pipeline early, our ability to raise cash earlier this year and frankly, the engineering and operational challenge in our team enabled us to pivot our plan to allow us to continue supplying clean and competitive low cost energy to our home market. A large part of the lift in value that we expect is because we have a very clear and sensible plan to reinvest in assets in our home market. We have organic growth. Most of the elements of our plan are in our control and will emerge because we can take the lead. Now when Aaron profiles our growth strategy for new gas and renewables, you should walk away confident in our ability to find great projects with great returns. He'll show you a slide that will convince you that our growth plans are backed up by our track record. This slide here is further evidence that we have the track record to achieve our goal as a leader in clean energy in both gas and renewables developments by the end of 2025. It shows that since 2008, we've more than tripled our EBITDA in renewables. It is very difficult for Canadian investors to buy into a position in the quickly growing renewables market. There aren't a lot of investments here in Canada because of the high degree of public sector ownership of our utilities. Our ability to grow our portfolio of strong contracted gas and renewables investments makes us one of the few companies in Canada that can give investors a position in what is becoming a very, very exciting space. Now there's quite a few of these days over ESG metrics as investors really try to get under all the disclosures that are necessary to understand the true value and risk of cash flows in companies. Now sustainable development is not new to us. I've personally been working on this file since 1987. In 1990, 30 years ago, we were the 1st Canadian company to purchase carbon offsets and in 2000, we were an early adopter of wind technology. Today, we've amassed the largest wind fleet in Canada and we've achieved a lot of that growth over the past 15 years. As electricity technology has moved from hydro to coal to gas to wind to solar and it's now on its way to batteries and storage, there's always we've always been there and we've always had an offering to our customers. TransAlta has reported its sustainability measures since the early 90s. And 4 years ago, we chose to go to integrated reporting well ahead of all of our peers in the market. All of our ESG measures are verified by Ernst and Young and there's an array of measurements we track in our report. Not only do we track greenhouse gases and air emissions, but we also look at things and set goals around water use intensity, waste management and landfill usage. For today, we've presented just a few key measures, including the diversity of our management team and our Board, our greenhouse gas emissions and our safety performance. And we pride ourselves in our progressive plans and the results on all these fronts. And we do know from talking to investors that making progress on all of our goals is important. We also test our practices externally and are reporting against standards that are set by people outside of us. We look to the CDP, the task force on climate related financial disclosures and the Canadian Council for Aboriginal Business. And I can say that getting a B score with DDPE with our coal plants shows you just how much work we've done to create a very credible and strong set of ESG disclosures. The past 3 years for us have been about driving financial performance within a very strong ESG framework. Our key financial metric for performance is free cash flow and free cash per share. And those of you who know us know that to be the case. And this is the cash that really truly is left over to either repay debt, grow or return it to you, our shareholders. We've grown our free cash flow over the past 3 years and the market has rewarded us for for that growth as shown in the chart on the left. Okay. That's it for the overview. So why are we here? For all of you who are going, please stop. We know, we know. Today, you're going to hear from the team that we have a comprehensive plan that allows us to make some great investments, continue to return cash to shareholders, achieve our balance sheet goals and continue to generate strong cash from our base business. We've pivoted our Alberta investment plans towards repowered combined cycle plans to increase our competitiveness and generate cash in our home market. We have great prospects in gas and renewable space and we're the company to invest in if you want to be part of a market that is expanding and growing. And our priorities are simple. Our first priority is to invest between $600,000,000 $1,200,000,000 in our Alberta thermal fleet to set it up for the future. The second is to complete over $800,000,000 of construction projects that we have underway today on time and on budget. Our third is to grow our on-site and cogeneration business. 4th, we have a team focused on building a pipeline of renewables and cogeneration projects in the U. S, projects that will grow R and W, utilize this debt capacity and further and deliver further dividends back to TransAlta shareholders. Finally, we will do all of this while running a strong base business that generates the cash to fund the growth, keep our debt inside a 3 times debt to EBITDA ratio and allow us to continue to pay and to start to grow our dividend. Todd is going to show you in his section how we can do all of this together in our comprehensive plan. Today, we are announcing that we are ready to deploy between $1,400,000,000 over the next 5 years in gas and renewables. It is the right bet. It's at the right time and it's for the right market. It's the capital that achieves our goal of becoming a competitive gas and renewables company by the end of 2025 and it has strong returns. By the end of 2021, we will have deployed over $800,000,000 to contracted renewables projects and small cogeneration projects that we'll announce soon. By the end of 2023, we'll have our simple boiler conversions and one of our repowered combined cycle conversions complete. And by the end of 2024, we'll have a second repowered combined cycle unit completed or an additional boiler conversion finished depending on what we see as are the market conditions. You'll hear from the team today that we're ready to go. We have many of the pieces lined up and in place and ready to deploy. Finally, you'll see that our pivot towards a more competitive strategy in an energy only market will make us the most competitive generator in Alberta. You'll hear from Todd that our plan is funded. You'll see that a strong balance sheet underpins our plan and we have contingencies built in, in the event that conditions change. Todd will show you that he'll tether the investment strategy to a strong balance sheet and a dividend policy that allows investors to benefit as we move through the plan. And the plan continues to allow us to invest in ourselves by using up to $250,000,000 in share repurchase over the next 3 years. He'll also show you how cash at R and W is being used to increase returns for TransAlta shareholders. Today, the dividend from R and W is being reinvested in Alberta at high returns. Tomorrow, the free cash flow generated from Alberta will support the growth in additional contracted renewables and will potentially grow your dividend. So listen, I wouldn't be a Canadian CEO if I weren't complaining about the value of the company relative to its benefits. However, I am not going to complain. What I'm going to do is tell you that the coal plant transition to gas as our coal plants transition to gas, the company simply becomes more valuable. Although Alberta is a merchant market, it is small, it's fairly closed and we have a key portfolio of assets. The new policies for converted units in Canada allow us to extend the lives of those assets. Our Alberta portfolio is diverse, which helps us stabilize cash flows from our Alberta business. And finally, although ZEP PPAs created more stable cash flows, they were set in 2,000 based on cost of service models and they were set at a very low level. As the PPAs roll off post 2020, we move to market pricing, which will give us sufficient cash for returns to investors and for reinvestment in reliable supply. And you're going to see today that the expected pricing in the Alberta market potentially lifts the value of your company. From this chart, you can see the market is in valuing our cash flows and Todd will take you through this math in his section. As we're on our way to deliver our clean energy investment plan, we think there's an excellent opportunity here for an attractive investment given our current valuations. So why is that? It's because we have a very competitive Alberta business and we've developed a fantastic reinvestment strategy in Alberta that continues will continue to create cash for a long time forward. And as you know, everything globally is moving towards electricity and electrification. Electricity is going to supply the energy demands of the world and the requirements for the future. Alberta is one of the only markets in Canada where you can have an investment in electricity. And we're an important player in electricity and power and we've put together what I think is a fantastic reinvestment program for the company. More importantly, we are well ahead in the renewable space. Everything is pointing towards massive investment in renewables globally. Here in Canada, your opportunities are limited. Electricity investment is primarily owned by the Crown Corporations. We are going to see a massive shift towards renewables and batteries here in Canada and elsewhere. And if you invest in TransAlta, you'll get to be part of that important shift in how electricity is produced for customers worldwide. Finally, today we announced a very disciplined capital allocation strategy. You know that over the next 3 years, we are going to continue to return capital to shareholders through the share buyback of up to $250,000,000 But at the same time, when we look at the ongoing cash that we are going to generate through this investment plan, we can see our way through to both investing in this plan and paying you as we go, which is where our dividend policy comes in today. We are very excited to have been able to land a whole package here today to talk to you about, so you can see where all the elements of the capital allocation strategy are and how they all fit together. I would say it's the most disciplined in the industry because we don't just look at some ratio. We in fact, what we do is we look at the need for cash, for debt repayment, for dividends, for preferred share dividends, for sustaining capital and of course as well for the excess cash that we have left over to reinvest in your company and grow it. So with that, I think just kind of ending up. Most of all, you only really invest in a company because you invest in the team. We have over 175 years of combined experience and a top team of people who are diverse in their views, believe me, diverse in their capabilities, their skills and their knowledge. We have created an environment of innovation where work ethic and creativity stand side by side so that we can lead into the future. As a team, we have the courage to make the changes that are required to ensure the company is competitive and we're good at seeking disadvantages hierarchy by networking the organization around the projects that will matter most to adding value to your holdings. So with that, I'm going to turn the podium over to John to talk about the Alberta market. Thank you, Don, and good morning, everyone. My name is John Koussienhoris, and I'm the Chief Operating Officer of the company. And I'm very pleased to be with you all this morning. I'll be providing you with an overview of key market fundamentals that impact our business as well as a general overview of our operations. Market fundamentals, particularly in Alberta have been in flux for a number of years, but things have fundamentally changed recently, we believe for the better. We have market structure certainty now. We believe that we're going to have carbon pricing certainty shortly. And we believe that supply and demand fundamentals will drive pricing and supply additions in the years to come. We also believe that the evolution of the market is highly constructive for our company given the scope and scale of our fleet and its competitiveness in terms of its overall low variable cost and heat rate, the fact that it's needed to meet the load requirements of the problem of the province, sorry, and our ability to repurpose and reposition our coal fired fleet to a gas fired fleet to be even more competitive than it presently is at a capital cost that's a fraction of newbuild. In terms of structure, it may have taken us a while to get here, but we now have certainty of market design with the government of Alberta's retention of the energy only construct. And we're happy with the retention of the structure, which is pretty unique. Compared with most power markets, the Alberta market is relatively pure with relatively light regulatory intervention. Our experience with the market is that outcomes are dependent on demand and supply with both operating costs and over time, a return of and on capital being bid into and being embedded in market prices. We expect this to continue and expect the regulatory construct to permit that to be the case in order to ensure that reliability is maintained in the province. Being a low marginal cost generator is critical today and will continue to be critical in the future to competitiveness generally, which is something that we're very much focused on. Our fleet is very well positioned to compete in the market with its blend of 0 cost wind and hydro, which as Don showed you in one of our earlier slides are really one of the largest fleets of those types in the province. And with competitive and essential thermal generation, which is shifting to low cost gas. We also expect that Alberta will continue with a constructive carbon pricing framework, broadly along the lines of what we currently have with approximately a $30 per CO2 tonne price and credits for our existing wind and hydro generation in the province. You will see today that these changes broadly support our strategy for our Alberta business, which emphasizes coal to gas investments and the development of boiler conversions and gas repowered combined cycle facilities. Over time, we've had supportive and we believe appropriate pricing in Alberta with the average price in that $57 per megawatt hour range over the past 18 years. And that would be a little bit higher, probably closer to the $60 range if you take away 2016 2017. Those were unusual years due to the role that the balancing pool played in the termination of the historic power purchase arrangements and with the short run marginal cost bidding that it was doing during that time period, which is atypical in terms of what we've seen over time. Year to date, the price has been just over $57 per megawatt hour and the balance of the forward price is just a bit over $60 a megawatt hour. You can also see that the forward curves for 2020 2021 are suggesting prices in the $56 to $59 per megawatt hour range respectively. The slide also shows EDC Associates forecast for the province. EDC is based in Alberta, understands the market well and is generally considered to be the leading independent forecaster in the jurisdiction. Its forecast also suggests supportive prices being well into the $60 to $80 range, providing strong margins for our Alberta based generating fleet and supporting our planned investments in our thermal fleet. Brett and Wayne are going to be talking further about this shortly. Underpinning the price forecast has been the historic and expected ongoing load growth in the province, which has averaged about 1.5% per year since 2,009 and which is being forecasted to grow by up to 1700 megawatts by 2025. Load growth last year, and I'm talking about growth peak over peak, was approximately 3.3% and we had a further 0.4% growth quarter over quarter in the Q1 of this year, notwithstanding the relatively weak overall economic picture for Alberta. This too is lending support to power prices in the province and shows that a level of incremental supply additions should be able to be absorbed by the market. As the largest incumbent player in the province with the most diversified generating fleet, this is again supportive of our gas conversion and repowering strategy. Although as you'll see throughout our presentation, our strategy isn't really focused on load growth and doesn't require prices that are significantly higher than the levels that we're accustomed to seeing in the marketplace. Our coal to gas repowering and conversion strategy is very much oriented towards replacing megawatts that we currently have in the market, extending the life of our facilities and reducing our operating costs even further. And on that last point, we remain driven by our desire to reduce our per megawatt hour cost of generation. The 2 largest input costs for that are really carbon emissions and fuel. Brett will be speaking about the CO2 emissions reductions that we're focused on and the impact that carbon price has on that and the carbon price savings that we're targeting. But as you can see in the slide here, there is a very large supply of natural gas in Alberta, which has resulted in an associated reduction in the price of gas over the last 15 years or so. That too is also highly supportive of our gas focused strategy and will help us be an even lower cost generator in the province. And this is really highlighted in the next slide where we're showing you what our expected marginal fuel costs and carbon costs will be over time. And this will be critical in the energy only market, which will be very much focused on marginal cost in order to be competitive. The blue bar on the left indicates our fleet wide weighted average price of generation based on the current composition of our fleet, including our wind and hydro assets. As we convert our coal fleet to gas and introduce 2 gas repowered units, we expect our weighted average marginal cost per megawatt hour to fall by about 35% pretty dramatically to approximately $15 per megawatt hour, which will clearly support our competitiveness in the province. The other point that I'd like you all to take away today is that our generating fleet is needed in the province and is absolutely critical to the provinces load being met with a required level of reliability. Using the Alberta Electric System operators own long range adequacy metrics, the slide shows the ongoing importance of existing coal and eventually gas fired supply in meeting the needs of Alberta. The chart on the left is a little busy, but shows in the blue line the peak demand expected by the ISO over the next 2 years. If you remove the dark green and I think on one of the slides, well, I guess it is pink, I thought it was looking a bit brown yesterday at the top of the chart, which represent the capacity available from intermittent wind generation in the intertie. The importance of existing installed coal, gas and hydro in meeting the needs of the province is pretty clear. The chart on the right, which is also based on the ISO's long term adequacy metrics, points out that there are currently very real expectations of tight supply periods in the province in the near term. The supply cushion represented shows the difference between firm supply and by firm, we exclude intermittent or uncertain win in the intertie supply and expected daily peak demand over the course of the next few years. And it highlights the potential for supply deficits for extended periods of time during the forecasted period. In fact, the chart and it's probably a bit hard to see it, actually shows that the supply cushion is actually negative for extended periods of time, which are the lower dips that you see there, when only the most reliable generation available in the province is considered from a supply perspective. The key takeaway I think is that our Keypills and Sundance units are required to meet the needs of the province, which as you all know is characterized by a very high and consistent industrial load level with relatively limited fluctuation. That's 24 hours a day, 7 days a week, 3 65 days a year. In fact, when we've canvassed a variety of jurisdictions in the world, we haven't been able to identify another market that is as dependent on or as from a demand perspective as focused or comprised of industrial and commercial load as Alberta is. Our retail market is actually relatively small given our relatively small population base in the province. I also want to highlight the importance of ancillary services in the context of our fleet. Ancillary services ensure that the interconnected electric system in the province is operated in a manner that gives a satisfactory level of service with acceptable levels of voltage and frequency. Significant volumes of ancillary services are procured each year by the ISO and we supply almost 50% of this important segment through our hydro fleet and we do it in a manner that permits us to conserve and manage our water position throughout the year. And we're able to achieve pretty good pricing, about 60% of the flat energy pricing in the province for that service that we provide. I'll be speaking a little bit more to you all about how our hydro fleet generates its cash flow shortly. Finally, I like to just have just a quick word on the situation here in Ontario where we have a pretty significant fleet. We're a significant generator. We actually have a bit over 1,000 megawatts of installed capacity in the jurisdiction. We are expecting the eventual implementation of a capacity market here and at least some level of carbon pricing in the province based on the federal government's output based pricing system. However, given the contracted nature of our assets in the jurisdiction, we're presently largely insulated from any near term impacts from the changes that might occur in the market, largely because of the current contracts as I mentioned and the change in law provisions that exist in them. So moving on now to our operations. In terms of an operations overview, the key messages are that our generating fleet is highly diversified both by fuel type and geography with considerable contractedness, upside from merchant generation, particularly in Alberta and with an ongoing focus on low cost generation. We've definitely seen an improvement in our fleet's financial and operating performance encompassing a variety of key aspects from safety to availability to the variable cost of production, all of which is something that we're really proud of. We've also unified our entire generating fleet under a single coordinated leadership team along with our trading, asset optimization, commercial team and our shared services group. In terms of our operating model, we're really focused on being a leader in safe, low cost generation with a focus on really 4 major elements. The first is simplification. And by simplification, we mean leadership consolidation, a focus on reduced OM and A, particularly as we continue our journey to converting our coal fired generation to gas fired generation, a focus on the development of a multi skilled and flexible workforce, a focus on centralized and remote operations, which is really one of our core competencies. Our wind and hydro fleets as well as much of our Australian gas business is all run-in a remote and simplified manner. And finally, we have a key focus on the introduction of new acquisitions that we have in an efficient and simplified way. Secondly, we've really concentrated on a fleet wide approach to asset optimization, particularly with the focus on the merchant portfolio in Alberta. And that includes a focus on fuel and carbon cost reductions, the use of data analytics to help us make better decisions in a more predictive way for the business. Those of you I think that were able to attend our Investor Day sessions this past July would have seen firsthand some of the work that the team is doing by leveraging data analytics to make more informed and accurate and frankly faster decisions in operating and dispatching for our hydro and our wind assets. 3rd, we're also focused on the full implementation of our shared services model, which really isn't something we spend a lot of time talking to you about and which I'm going to spend just a moment on. We're centralizing the provision of all common essential services for our generating business under a senior, under a single leadership and one that is coordinated with our generating fleet. And the kinds of services that we're focusing on are things like IT, supply chain, ops services such as compliance and engineering and a number of the HR functions that we have. And as I mentioned, it'll be all one leadership team, no duplication and it'll be orient towards just providing those services that the generating fleet requires. And finally, we're going to continue to focus on the discipline that we've been able to develop by relentlessly focusing on our Project Greenlight methodology. And the 2 key areas that we have for Project Greenlight are really focusing on generating that bottom up innovation that our employees are developing and by enhancing our organizational health, which in our mind is really trying to improve the way that we actually do things. I can't even begin to stress the importance of this transformation on our company. And again, I think that those of you that were able to attend our investor tours in the summertime and spend time interacting with our employees would have gotten a firsthand feel for the impact that Project Greenlight has had on the company. And the way that it's had an impact on the way that we do things by empowering individuals to pursue any idea that they have to improve our business in a disciplined way. And I'll give you some examples of that as I talk specifically about our various operations. So one of our greatest assets and strengths is the diversity of our fuel types, geography and cash flows. Our coal to gas and gas repowering assets in Alberta have provided us with a very attractive investment opportunity in a healthy market in which we have a leadership position, which and Wayne and Brett will be walking you through that shortly. Our wind generation platform, which is amongst the largest in Canada and amongst the largest in North America, I think when you look at the size of the platform from a North American perspective, it's one of the top 15 platforms in the continent. It's a key part of our transition to becoming a leading clean power company. And it's in the process of seeing pretty significant growth with 4 projects under construction, which will increase the size of the fleet by about 30%. The strong contracted cash flows from our diversified gas fleet benefit our business, stabilize our cash flows while we service the needs of our largely industrial customers. And finally, we have our unique set of irreplaceable hydro assets in Alberta, some of which continue to operate very, very well and outstanding that they're over 100 years old. They continue to provide us with a unique competitive advantage in that jurisdiction, which is really difficult for anyone to replicate. The positioning of our legacy coal assets has changed markedly in the last few years with the unique gas repowering opportunity that they represent. They represent approximately 20% of Alberta's generation and we believe they will continue to provide much needed low cost and reliable capacity for years to come. By the end of 2020, the PPAs governing the fleet will expire, which will finally result in full operating and dispatch control reverting back to TransAlta for the units. Our planned coal to gas repowering investments will dramatically extend the life of the assets, reduce their operating costs and generate strong cash flows and excellent returns for our shareholders. And I'd like to just give you a sense on just a couple of the initiatives that working on from a Project Greenlight perspective on the fleet. One of them is in our Centralia plant and facilities down in Washington State, where the team there has really been focused on the chemistry of coal blending and is managed through the work that they do to actually source cheaper supplies, but supplies of coal that they can blend properly to ensure that just the combustion and the fuel that we have in the unit operates as efficiently as it can be at the lowest possible cost that it can be. That's an ongoing piece of work that they do. And in Alberta, for example, at Alberta Thermal, we've been using artificial intelligence now to actually optimize as best as we can the boilers that we have, both in terms of the emissions that they have and the fuel that they generate, again, creating significant cost savings for the company and improving their reliability on a go forward basis. Our hydro assets are unique. They're perpetual in nature and they provide a critical advantage for our company. We own and operate over 90% of the hydro generation in Alberta. We have additional hydro facilities in British Columbia and Ontario. As I mentioned to you earlier, they provide both ancillary services and energy to the market and expect to receive green credits under Alberta's new carbon pricing scheme, which we believe will increase their value further. Most importantly, the hydro PPA that we have with the balancing pool in Alberta will expire at the end of 2020, which we expect will result in a significant increase in our cash flows from those facilities in 2021 beyond. And again, I just want to give you a Project Greenlight example on our hydro fleet. Over the catalyst of the last year or so, the team has been really, really focused hard on developing a water forecasting and weather forecasting tool that they've been able to implement. And some of the people would have seen that in the summertime. This has really improved our ability to actually forecast water foreclosed and more precisely measure our reservoir levels, which we think conservatively has resulted in our cash flow improving by $3,000,000 to $4,000,000 this year alone. So that was a tremendous piece of work the team did over the course of the last 12 months. Our Alberta hydro assets are in a pricing premium, broadly in that 20% range as compared to the flat Alberta energy price as a result of the manner in which we manage the facilities and their water supply, which is a pretty precious resource for us, given that the system doesn't have a lot of storage. We run the facilities at times when prices are higher due to a tightness in the supply in the market. So taking 2018 as an example, while the average price in the market was in that $50 per megawatt hour range, we were able to secure an average price of $59 per megawatt hour for our wind fleet from the energy that we generated there. And as I mentioned earlier, our Alberta hydro assets also provide about 50% of the ancillary services requirements in the province. Things like regulating reserves, spinning reserves, supplemental reserves and standby services. And they're paid about 60% of the flat market price in the province for those services, which often don't require us to flow any or significant water to actually earn them. Sales of ancillary services roughly provide about half of the cash flow that we get from the fleet. Now some of you may have seen this slide before. It provides a visual illustration of the EBITDA earned by our hydro fleet, both prior to and following the impact of the power purchase arrangement that we have with the balance in pool, which as I said, was going to expire at the end of next year. I'm going to spend a little bit of time on this. And before getting into the numbers, I thought what I would do is just give you a brief overview of the mechanics of the arrangement so you can follow along. Now our hydro fleet generates energy and ancillary services which are sold at market prices. And our company has full operating and dispatching control over the fleet. In that way, it's very different than our PPAs over our coal fleet. However, the PPA, which impacts the bulk of our hydro fleet in Alberta, is settled separately and it's done in a financial manner and there's really 3 major flows of cash that exist under that arrangement. The first one is that TransAlta receives an annual capacity payment from the balancing pool And in return, we provide them with 2 payments. The first one is an annual energy payment that we give them, which is based on the notional quantity, a prescribed notional quantity of annual energy generation. And the second one is an annual ancillary services payment, which we provide, which similarly is based on a prescribed notional quantity of ancillary services that we generate. So turning to the bridge on the chart, which summarizes 2018 actual monetary flows for the hydro fleet. You'll see that we earned about $90,000,000 from energy sales, a further $104,000,000 from ancillary services sales in the year and we repaid $56,000,000 from the balancing pool in terms of the PPA through the capacity payment that they provide. And that payment will disappear at the end of the PPA. But we expect that we're going to be able to make up a bunch of that lost cash flow through increased power prices and also through the carbon credits that we expect to receive for the fleet. Finally, TransAlta earned another $41,000,000 on its hydro fleet from the non PPA hydro assets that we have, our transmission, which is part of the segment that in the way that we report it and also from other hydro services that we provide like water management services and Blackstar capabilities. And that's a pretty stable cash flow year over year. The cost of our hydro operations in 2018 was $1,000,000 And when you deduct it from the revenue streams that are outlined on the chart that I just went through would give you pro form a EBITDA for the hydro businesses roughly in that $240,000,000 $244,000,000 range, which we believe is within the range of what we would normally expect the business to provide following the expiry of the PPA. And I'll talk a little bit more about that in the next slide. However, in 2018, under the terms of the PPA, we paid the balancing pool $135,000,000 in the form of that annual energy and ancillary services payment that I was talking about earlier. And typically that payment is equaled or broadly approximated 100% of the energy revenue that we've received and about 50% of the ancillary services revenue that the business would have received. And that would have led to the reported number, which was $109,000,000 in the year. That payment, that $135,000,000 payment will go at the end of the PPA at the end of 2020. In this chart, we presented a range of post PPA EBITDA outcomes from the hydro fleet after removing all of the impacts of the PPA and over a range of Alberta flat prices ranging from $50 to $70 At these prices, we expect our hydro business to generate an EBITDA in the range of $200,000,000 to about $250,000,000 which roughly translate to an EBITDA lift of about $18,000,000 to $20,000,000 for every $5 per megawatt hour increase in the price is roughly what it translates to. Turning to our wind and solar fleet. We have over 1300 megawatts of capacity. Actually in 21 facilities, the additional facilities actually are solar in Massachusetts and our wind is located in Alberta, Ontario, Quebec, New Brunswick, Wyoming and Minnesota. And we're currently developing 4 projects again in a diverse set of locations, which will increase the size of the fleet by almost 400 megawatts. The fleet is highly contracted with an average capacity weighted contract life of about 11 years and it provides us with predictable and growing cash flow of around $250,000,000 a year. We're the largest wind generator in Canada and have one of the largest platforms in North America. We have extensive in house experience in wind farm development, which Aaron is going to be speaking to you about a bit later. And we have a very strong operating model in our wind operations, highly developed remote operations and monitoring, very experienced maintenance program and team and significant data analytics and optimization capabilities. And our wind fleet 2 is really focused on green light initiative and examples. And these typically come from our employees. One of them that we've been working on is we've developed a new weather forecasting model, which helps us in the way that we operate the wind farms during the wintertime, avoiding icing on the blades. And we think that that's going to result in about $1,000,000 $1,500,000 a year just to give you a sense of benefit there. The other thing we've been doing is we've been working pretty hard with the team from Stanford University over the course of the last year to deal with wake effects and yaw at the farms. And we think that the work that we've done there and the analysis that they've helped us with going to increase the output of our wind farms from between 1% to 1.5%. So we're really excited about the collaboration that we've been doing with them. Turning to our natural gas fleet, we've got about 1300 megawatts of natural gas in the generating fleet. It's located in Alberta, Ontario and Western Australia, where we have focused on meeting the needs of a diverse set of industrial, commercial and utility customers. This portfolio of assets is highly contracted with an average capacity weighted contract life of about 7 years and provides us with a stable set of earnings for our company largely based on the capacity payments that we have under those arrangements with very little variability. You'll hear from Aaron later in the presentation that we're now seeing a renewed interest in on-site generation, which we think is going to add to the size of the generating fleet that we have once our growth team begins working on it and ramps up there. So we're excited about that. Our gas team also spends a lot of time working on Project Greenlight initiatives. And I'll just give you one example or a couple of examples actually. In Australia, we're really focused on centralizing all of our remote operations. We've done it for the southern part of our generation in Western Australia. We're going to be folding in our South Heblin plant into that and expect that the reductions in labor costs by doing that are going to be roughly in that $1,000,000 to $1,500,000 a year. And again, that was an initiative that was developed by our employees. Another example is the work that we've done with our gas turbines at Sarnia, where one of our engineers took it upon himself to see if he could reduce the load point effectively, where the how fast the generator effectively is running with a view while meeting all of the needs that we have for the facility in terms of heat and steam, but also at the same time making sure that we stay within the envelope that we have for emissions, all the while lowering our fuel consumption because we're just burning less gas to see it through. And that's a significant initiative that will see us saving about $3,000,000 maybe a little bit more $1,000,000 a year in that facility. So another great example of the way our employees through our Project Greenlight are thinking about helping our business. Just want to touch on recontracting. We believe we've been very successful in securing extensions for our gas fired facilities. We've got over 65 years of incremental contract life that we've been able to achieve as indicated on the slide. One of our key focuses right now is on re contracting as I was just talking about Sarnia that 500 Megawatt Sarnia Regional Co Gen Plant, which has contract expiries coming up in the 2022 to 2025 with some of the customers that we have there and with the contract we have with the ISO. We're actively engaged in discussions with the government of Ontario, the ISO and our existing customers, but also prospective customers to see if we can get extensions there and even new contracts to extend the cash flows the contracted cash flows of that facility. And overall, I think it's important to note our company is pretty highly contracted with a weighted average contract life excluding our coal fired generation of approximately 11 years. And upon the expiry of the PPAs at the end of 2020, the thermal PPAs at the end of 2020, the majority of our EBITDA will still remain tied to contracted assets. And the uncontracted portion of the fleet will be located primarily in Alberta, where we think we're going to be able to realize the upside that we expect to get in our hydro cash flows and the benefit of the expectation of some of the higher prices that we expect to see in the province. Finally, I'd like to just touch on our trading and marketing team, which is very, very important to the company and our operations. And generally, it fulfills 4 basic functions, 4 major functions. First, there's measured proprietary trading for profit that we do in each of the markets in which we operate and even some that we don't. And part of the benefit from that activity is just the information flow and price discovery that we have for the company as a whole, which really helps a number of the business units in the company. The second element that we have in our trading group is just market intelligence and forecasting, which is used throughout our business, both from a planning perspective and with Aaron and Brett's growth teams. The 3rd element is asset optimization and the hedging of our entire fleet, the merchant component of our business. And finally, we have a pretty robust C and I business where we try to develop solutions for commercial and industrial customers, again, primarily in Alberta. Some of those contracts are longer life contracts, some as large as 5 years in length. And we tend to think of that as another way to well, really 2 things. Another way to actually hedge our merchant exposure in the province, but also it's actually been a source of leads essentially for our growth team as we stay close to the customers and they identify opportunities that we have to serve them better. Thanks very much. I'm going to now turn it over to Wayne to talk about the coal to gas conversions. Thank you, John, and good morning, ladies and gentlemen. My name is Wayne Collins, and I'm Executive Vice President of Generation here at TransAlta. So we've been talking about our plans to convert our coal fired units to gas for a number of years now. And so I'm really pleased to be staying here today to tell you that this process is well and truly underway. And our Alberta coal fired power plants are now all capable of consistently being able to regularly produce more than 30% of their energy from gas coal firing. There are significant benefits from our plants to 100% natural gas co firing. And based on our co firing experience, we're already seeing those benefits through lower combined fuel and GHG compliance costs and lower OM and A costs. As we complete the full conversion of our fleet, these improvements will increase. Further, in an environment where gas costs are expected to remain very competitive in Alberta and we're subject to a carbon emissions levy or tax, Conversion of all of our units to burn 100% gas continues to make really strong economic sense. So we've now completed all of the preliminary work that's necessary to allow us to firm up exactly the type of conversions that we want to undertake and also the conversion schedule and I'll have a little more on this shortly. Because of the work we've done, we're very confident that the investments that we've made and made to date and which we'll make to convert the Alberta coal plants to burn 100% gas over the next few years will deliver very strong cash future cash flows and very attractive investment returns. We're also confident and Brett will show you in his section of the presentation that the Alberta portfolio of converted gas power plants that we're creating be very competitive under the anticipated future market conditions. So turning now to our specific gas conversion plans. The base plan involves 3 border conversions in the period 2020 to 2021. In that period, we will convert Sundance 6, Keybills 2 and Keybills 3 and 2 repowered combined cycle conversions, which will be Sundance 5 and Keybills 1 and they'll be straddled approximately a year apart. Keybills 1 and Sundance V, the 2 future repowered combined cycle plants will either co fire until they're repowered or potentially be converted to 100% gas via a boiler conversion before then, because as Brett will show you, the carbon savings are significant and the payback times are relatively quick. The options for Sundance Stream Pool will be evaluated over the next year to 18 months. And as are obligated to do, we'll continue to look at those plants in light of the future long term market fundamentals. The plan that we're presenting here today assumes also that there are no delays in getting the approvals, the regulatory approvals we need, particularly for the repowered combined cycle plants and in securing the additional gas requirements that we need. On this slide here, we're looking to really show you that boiler gas, coal to gas conversion is technically a fairly straightforward process. We're essentially replacing the coal burners with gas burners and a new set of gas fuel controls. There's also some changes we'll do to the way the air gets into the boiler. But and the plant outage that is required to do this and implement this conversion is relatively quick. It's approximately 6 weeks in duration. And as you can see from this slide, boiler gas conversion results in a materially simpler production process. It takes away the need for substantial items of plant and in particular eliminates the need for the mine. In addition to that, the coal handling plants are no longer required, coal mills, burners, pulverized fuel piping, a lot of wearing parts, our ash handling equipment, air quality control systems, so whole areas of plant like precipitators and bag filters are no longer required. So moving on to the repowered combined cycle plant. And on this slide, we illustrate what a repowered combined cycle plant entails. The repowered combined cycle process involves the installation of a new gas turbine and generator, and that generator will be connected to the grid and transmit its power through a new grid connection. We'll use the exhaust gas from the gas turbine and pass it through a heat recovery steam generator to produce steam and that steam will then be connected into the existing steam turbine, the condensing and feeding equipment and the existing steam turbine and generator and the existing grid connection will be used to transmit that power to the network. So the repowered combined cycle plant uses of new and existing equipment to produce a plant that has heat rates that are very comparable to those of a brand new combined cycle gas turbine. However, as it uses a lot of our existing equipment, the capital cost is much, much lower. It's 40% to 50% lower than that of a new greenfield combined cycle gas turbine. Now these repowered combined cycle plants are not a novel concept. There's something that's quite well proven. We're aware of at least 8 of these that have been completed in the U. S. And a number of conversions are also currently in progress. Our team have visited some sites with lots of operating history. And on this slide here, we're showing you the NXL Energy site, which is located in Minneapolis. This plant had a conversion, a repowered combined cycle conversion completed in 2,009. It's been running for the last 10 years very, very reliably at high capacity factors. Now the timeline for this conversion, it's our intention to seek the regulatory approvals for the prepared combined cycle plants, the 2 of those at the same time. We've got a parallel construction plan in mind with a slight offset in there, which will allow for the site construction team on Sun 5 repowering to finish that job and the bulk of those people to be able to move on to Kiplers Unit 1 once the Sun5 is completed. The commercial operation date for Sun 5 repowering is the end of 2023 and for Keybills 1, it's the end of 2024. Now moving to what this program of work will cost. The gas conversion outages have been scheduled to align with the normal turnaround maintenance outages for our plants. And it's our intention to complete kind of turnaround work scope and the gas conversion work in parallel. So on this slide, we're really showing you the total capital that we expect to spend on all of the activities at the Alberta coal plants during the period that have been converted to gas, so between 2020 2024. The total capital expenditure expected for the 2 repowered combined cycle conversion plan is our base case and that's approximately 1,500,000,000 dollars And that includes the boiler gas conversion capital, the sustaining capital that we have to spend on turnarounds, a life extension capital for that period 2020 to 2024. It should be noted that the repowered combined cycle gas conversions are a relatively high cost compared to the boiler gas conversions. However, the repowered plants have 40% to 50% lower capital costs and they're very competitive with the greenfield gas greenfield combined cycle gas turbine heat rates as I indicated earlier. Now we haven't been sitting idle. There is a substantial body of work that's complete or well underway. And I'm just going to walk through some of that now. So we have received the regulatory approval that we need for the boiler gas conversions, which have already been scheduled. The Pioneer pipeline, as Dawn mentioned in her opening remarks, was completed last May about 4 months ahead of schedule. And we have been taking gas from that pipeline since then. We have an EPC contract that's selected for the Sundance and Keyfields boiler gas conversions. We've issued the full notice to proceed for the boiler conversion at Sundance 6. We've issued a limited notice to proceed for Keycl's Unit 2 boiler gas conversion. Now Keycl's 3 is a slightly different technically in the boiler. So we have a separate we've been out to the market with a separate request proposal for the convert the boiler gas conversion on K3. We're currently evaluating that and we expect to make a decision on that late this year or early next year. We also have an owner's engineer on board to assist us with the work we need to do on the combined cycle repowering for Sun 5 and Keybills 1. And we've also entered into a carbon cost benefit sharing agreement with the balancing pool in Alberta for Keybills 12. And that will actually allow us to co fire fairly heavily on those two units and share the benefits between now and when the PPAs finish at the end of 2020. Discussions are also underway for additional pipeline and gas supply capacity to improve reliability and Brett will touch on that a bit more later on. So you can see that, overall we are well into implementation here. Also as I indicated in my opening remarks, we believe that there are substantial benefits from conversion to gas. Firstly, it provides attractive investment returns and Brett will give you some more insights into that. Significantly extends the life of our fleet and I've got some more detail on that later on. It also substantially lowers our operating, our capital and our GHG compliance costs. And natural gas is in abundant supply and very competitively priced. And you also need to understand that natural gas conversion or gas conversion avoids the need for us to engage in significant expenditures on emissions reductions, so Oil and gas conversions are very Oil gas conversions are very low capital and if and we're very quick to do those conversions in the order of 6 week outage to do that. The repower combined cycle plants, 40% to 50% lower capital costs than greenfield combined cycle plants. And so on the next few slides, we'll take you through some more detail on some of these benefits. So let's now look at the life extension that this plan delivers. So the dotted line on this slide shows you that the TransAlta coal fleet would all be closed down by 2029 and if we did not undertake these conversions and in fact some of those closures would have commenced in the mid-2020s. The boiler gas conversions extend the plant lives well into the mid to late 2030s and the combined cycle the repower combined cycle conversions extend those plant lives into the late 2040s. And further, it's also possible that we could undertake a repowered combined cycle gas conversions on previously boiler converted units. So for example, a plant like K3 would be an ideal candidate for that. As shown on the earlier slides, the converted gas plants are technically and substantially simpler plants than coal fired plants. There's a huge reduction in the volume of equipment in service and that allows for the elimination of the need for a lot of routine operation and maintenance on all of that equipment. Co firing and gas conversion also allow for significant reduction in the materials that we consume such as chemicals and lime and activated carbon bag replacements on bag filters. And the reduction in equipment in service and the work associated with the operation and maintenance on that equipment supports significant reductions in the operations and maintenance workforce. It should be noted that the plant changes that we've already implemented and co firing with gas have allowed this workforce transition to commence. It actually commenced in 2018 and you're already seeing the benefits of the lower OM and A costs in 2018 and also in 2019. And so really in terms of our workforce transition, we are really on the journey to being fully converted to gas and our workforce force transition is probably more than 50% completed already. This slide this next slide shows you the substantial change in sustaining chart is showing you what our kind of average mining capital cost run rate, sustaining capital run rate on the mine has been. It's in that £30,000,000 to £40,000,000 per annum. Post gas conversion, the mine moves into a reclamation mode and this capital spend is largely eliminated. And because of the reduction in the amount of equipment that's in service that I've talked about a couple of times earlier, the need for capital replacement, all those elements that are no longer operating is eliminated as well. And finally, the gas combustion is kind of much kinder to our plants. It results in a lot less tube wastage and erosion in our boilers. And so there will be less tube repair and shielding and those sorts of capital costs associated with those plants. So all up, you can see from this slide, we expect to see a fairly substantial 40%, 50% kind of run rate reduction. There'll be years where it will go up and down a little bit post conversion. So in summary, the plan we've laid out today and confirmed today will see us complete a minimum of 3 border gas conversions by the end of 2021 and 2 repower combined cycle gas conversions by the end of 2024. That will considerably simplify our plant operations with significant reductions in OpEx, CapEx, GHG compliance costs moving forward and it will substantially extend the life of our existing coal plants. These plants will be very, very competitive in the Alberta market. And I'm now going to pass you over to Brett Galmer. And Brett's going to take you through some more detail on the economics that underpin the plan and the portfolio that we're looking to create here. Okay. Thanks, Wayne. Good morning, everyone. It's great to see you. So as Wayne I'm going to build off what Wayne just talked about, and I'm going to walk you through some of the financial analysis in behind our conversion plans. And what this will show is that the fleet will be very well positioned for an energy only market going forward. Then I'm going to walk you through the expected EBITDA impact for the Alberta thermal fleet under different energy prices once we're fully converted to gas. And then I'll conclude my section with an update on our natural gas strategy. So as Don indicated, our conversion plans are designed for the energy only market by really striking a balance between having low marginal cost units and the amount of capital reinvested in Alberta that can be funded with our near to medium term sources of capital. And Todd is going to take you through that in more detail later. Originally, our initial plans when the capacity market was going to go ahead, we were thinking about repowering 1 of the units into combined cycle and the rest through the boiler convergence. Now with the retention of the energy only market, we've pivoted those plans to look at repowering 2 units into combined cycle as they will have very low operating costs in that market. So now what I'm going to do is walk you through the competitiveness of our plan, both from a marginal cost perspective and from a capital cost perspective. So first, just turning to marginal costs. This chart compares a coal unit, a boiler converted unit and a repowered unit under different natural gas prices. So you can see that the repowered unit is the most competitive because of its low heat rate and virtually no to very low carbon costs going forward. The boiler and conversions are also very competitive, especially when gas is at $2.50 a GJ or lower. And as John showed earlier, the forward curve going out to 2020 currently is actually below $2 a GJ. So these are very competitive, even as boiler converted units. Our conversion plans are very competitive from a capital cost perspective as well. As you can see from this chart, the capital cost per kW of capacity for a boiler converted unit is very low, and I'm going to walk you through on the next slide, this capital can be paid for in under 1.5 years based solely on the carbon and other air emission savings we'll get from converting from coal to gas. The cost for the repowered combined cycle is also very attractive when you compare it to a greenfield brand new combined cycle or even a brand new greenfield cogen, as we've seen some announcements. And this is due to, as Wayne said, we're going to be able to use the existing steam turbine and other infrastructure that's already on-site. So as a result of these competitive marginal and capital costs, our investments in converting to gas will generate very strong returns even under a low energy price scenario. So let me now take you through the emission savings. And what this shows is the emission savings being 100% on coal units and then boiler converted unit. The top chart shows the savings on a per megawatt hour basis. The total reduction is in around $18 a megawatt hour. Most of this is due to carbon, but we also eliminate mercury and we avoid any operating costs to meet NOx and SOx going forward. The bottom chart then converts these savings per megawatt hour into total annual savings. As you can see, it ranges from $25,000,000 to $50,000,000 per year for a 400 Megawatt unit. And that depends on the capacity factors that the unit runs at. So given a capital cost to convert a unit in around the $30,000,000 to $35,000,000 you can see that the emission savings alone results in a payback of 1.5 years or less, resulting in these being very low risk investments. Furthermore, this analysis does not factor in the avoidance of about $40,000,000 of capital we would have to spend per unit to meet the NOx and SOx if you stayed on coal, nor does it factor in the lower future OM and A sustaining and mining costs that Wayne just walked you through. So what I'm going to do now is take you through the investment metrics of the repowered combined cycle units. So you can see on this chart, depending on energy prices, the investment cost multiples, which as you know is akin to an enterprise value to EBITDA multiple, ranges from only 2.6x to 7.3x. So very attractive and well below what a new greenfield project would deliver because of the higher cost to build the greenfield. So you can see, as a result, the repowered units will generate very solid returns and cash flows even under low energy prices. So this slide now brings it all together to show what the EBITDA generated under different energy prices from the Alberta fleet will look like once it is fully converted to gas. The chart on the left has the fleet with 1 repowered combined cycle and the chart on the right has 2 repowered combined cycles. So you can see the EBITDAs are very strong under all the energy prices shown here. And under our 2 repowering, it's significantly higher than a 1 repowering, clearly because of the lower cost structure. Just to give you a sense, roughly every $5 change in energy price equates to about a $75,000,000 to $85,000,000 change in EBITDA. So also as a reference point, we show here what we expect our 2019 EBITDA to be. John showed earlier, we expect energy prices to come in just under $60 for this year. So if you pick the $60 point on this chart, you can see if prices are at that and we're fully converted, we're actually going to generate significantly more from this fleet than we do today. It's also important to remember, converted, these EBITDA's are going to go much longer because the coal fleet, as Wayne pointed out, has to start to retire at the end of 2026 and completely retire by the end of 2029. Plus, as Wayne pointed out, the maintenance costs going forward will be quite a bit lower with the converted fleet than it will be with a coal fleet. So now what I want to do is turn to our gas supply. As you know, we invested 50% in Pioneer Pipeline. As both Don and Wayne mentioned, this came on 4 months ahead of schedule. It's allowed us to increase our co firing, which has resulted in lower carbon and fuel costs for those units. Starting November, our firm commitment of 139 TJs per day starts. And therefore, at that time, we'll start significantly increasing the amount of coal firing we do ahead of even the boiler conversions that will start later next year. In terms of our long term gas requirements, once we're fully converted, we expect to consume on average approximately 3 50 terajoules to 400 terajoules a day. Now there will be certain hours and days where it's higher than this or lower than this. But on average, this is roughly what we expect. So in addition to the commitments we have with Tidewater, including the fact that, that pipe can handle up to 440 terajoules and the commitments we have currently with the Nova off the Nova system. We're in active discussions with other third parties for securing additional gas supplies for the Pioneer line, as well as potentially adding additional pipeline capacity into the sites. And we'll keep you posted on these developments once they're finalized. So as you can see, our strategy to convert to gas is full steam ahead. As Wayne pointed out, the strategy involves converting 2 of the units to combined cycle. We are timing these about a year apart. And really, this allows us it gives us the flexibility to modify some of our plans if market fundamentals do not fully support the investments, but it's also to help optimize the construction of the 2 units. So by executing these conversion plans, not only will this fleet become even more competitive source of electricity in Alberta, but it will also generate solid cash flows even under conservative energy prices and generate attractive returns for shareholders. So with that, I think we're going to take a break. And then afterwards, Aaron is going to kick us off with going through our growth strategy for on-site generation and renewable energy. Oh, 15 minutes, is that the game? 15 minutes. Okay. Good morning, everyone. The doors at the back of the room are closed. So that's my cue to start. Aaron Willis is my name, and I lead TransAlta's growth team and just wanted to say welcome back. I'm going to speak with you this morning about our growth strategy and program. And I hope that through my part of the discussion, you'll get a good understanding about how we're thinking about growing our company. Not just growing in terms of adding megawatts, but in terms of how we're targeting projects where we can add some value to ensure this addition of strong contracted cash flows to the bottom line. From my discussion, I want you to take away the fact that we're very focused in our growth ambitions and that we're already having success in the markets that we've targeted. We know what our competitive strengths are and we're leveraging those strengths to add contracted cash flows to the company. I'm also going to touch briefly on each of the growth projects that we currently have underway as it's a list that demonstrates the progress that we're making in these targeted markets already. Our team's been doing some great work, developing a strong pipeline of projects, and we're building on an impressive track record of successful growth that goes back decades. That's what makes me confident that we're going to hit our targets here. And I hope that you'll share that view with me when I'm finished today. So I want to start with where we're placing our focus. And it's really 2 areas or 2 key segments of the market. 1st, the on-site and cogeneration business and second, the corporate contracted renewables market, which today is primarily wind and it's primarily in the United States. We have 900 megawatts of on-site and cogeneration opportunities in our pipeline today. These projects are on industrial sites such as natural gas processing facilities, petrochemical plants, mining operations and oil sands operations. Our experience in this space actually goes back to the 1990s. And in fact, many of those plants and relationships that we developed in the 1990s are still very much an active part of our operating fleet today. There's no doubt that this market is growing again. We're seeing a real resurgence in demand here driven by a few things: customers wanting to gain more control over their energy costs replacing aging or inefficient boiler equipment reducing their exposure to network costs, and lowering their carbon footprint. On-site generation delivers benefits in each one of these areas. Additionally, the improvement that we've seen in both cost and efficiency of smaller scale gas turbine and reciprocating engine technologies now allows us to bring this technology to customer sites that were previously too small for the economics to make sense. On the renewables side, we continue to see the corporate PPA market setting records year over year with very few signs of slowing down. Importantly, this market is also diversifying from what once was the domain of the big tech and telecom giants to now being a very broad spectrum of buyers across almost all industry sectors. Many of these buyers are also now driving their sustainability objectives down through their supply chains, which is further increasing demand and also increasing demand or creating demand in other markets around the world. Our focus initially here is on the U. S. As that's the most active market today. And we currently have about 2,000 megawatts of projects and development sites that we have under evaluation today. You'll also notice that both of these growth focus areas are customer based. Now for me when I think about value adding growth for the company, this aspect is absolutely key. Deals with customers create benefit in terms of the economics of the specific deal itself, but they also create the opportunity to do more. Many of these customers have multiple sites or very significant ESG objectives that they're trying to satisfy getting into business with them and delivering on our commitments puts us in a really strong position to do more with these same customers. This is particularly true in the on-site and cogeneration market. Now with those target markets clear, I actually want to take a minute just to look back and show you what our historical performance looks like from a growth perspective. Our growth track record since 1990 actually spans 5 countries and includes gas, wind, solar, coal, geothermal and hydro assets. I like this slide because it demonstrates the number and size of projects that our team has developed over the last 30 years. You can also pretty clearly see a shift from gas in the earlier years to renewables from the mid-2000s onwards. The bubbles on this chart represent more than 30 projects and across those 30 projects I also want you to notice the relatively steady pace of growth. While there's been a variety of project sizes that might swing 1 year's total megawatts up or down, the pace in terms of the number of projects has been relatively consistent. We haven't added a whole bunch of projects in 1 year and then gone quiet for a few years. Rather that steady effort and being in the market consistently has allowed us to add assets at a very good pace. I personally had the chance to be involved in many of our most recent projects in addition to the gas assets that we developed in Australia since 2012. I'm always impressed with the capability of our team and the expertise that we have to do this work in house. Our team manages the entire process front end development, permitting engineering, site acquisition, resource assessment, contract negotiations and construction. On top of that, we have the capability to analyze and move quickly on attractive acquisition opportunities. This set of skills positions us very well to continue to build on this success that we've seen over the last 3 decades of growth. The skill set is also the foundation for how we've created some competitive advantages that we can build from. I'm excited about these two growth focus areas and I'm very confident that our team is going to build on our competitive advantages to deliver some excellent projects into the portfolio. I see us having some pretty strong advantages in these markets. 1st, in the on-site and cogeneration market you must be able to operate safely and reliably. We've been doing that on customer sites for 30 years. Frankly, our operating teams makes this part of my role quite easily. They've got a track record that I'm proud to put in front of prospective customers when I go see them. The next thing that I talk about with customers is how we can design a plant that will fit within their operating requirements and deliver against their objectives. I don't have a cookie cutter plant design that I'm trying to sell. Rather, my team works to understand the customer's site in detail and then design something that's going to suit their operation and deliver against their objectives at the lowest possible cost. Once that's complete our team can construct the plant and then hand it over to the operations team. So we really can provide a start to finish solution for these customers. In the wind market, again it's our track record and our experience that positions us as an expert in this space. We were an early mover in wind in the early 2000s and we have one of the largest fleets in Canada and we've been operating these types of assets as long as anybody in the game in North America. Again, we know the whole project lifecycle here from site prospecting and wind resource assessment through permitting, construction and operations. We maintain about half of our fleet through our own in house team and we operate the entire fleet through our remote operations and monitoring center in Pincher Creek. Our team of experts today is operating one of Canada's oldest wind farms on the Gaspe Peninsula in Quebec and next year we'll start construction at Windrise utilizing the very latest technology in what will be the largest wind turbines in use in Canada. Underpinning these areas of strength is our trading and marketing organization, a group that understands the regions and markets that we operate in deeply. Their expertise in energy and transmission markets allows us to deal with things like optimizing excess energy from projects, managing basis risk and dealing with any other aspect of how a plant needs to interact with the local market. Having this expertise in house allows us to manage these positions with a tremendous level of confidence and really deliver some significant value for customers in this way. So I want to move for a couple of minutes to a few of the trends that we see driving these markets that we're focused on. First of all, notwithstanding the load growth in Alberta that John shared earlier, in many regions we're actually seeing low or even flat demand for electricity. Even as more of the things that the world relies on are increasingly being powered by electricity, a relentless focus on efficiency is driving many very successful conservation initiatives and putting downward pressure on demand. At the same time though power generation is transforming. As the existing fleet ages and retires it's being replaced by smaller much more distributed technology and there's no doubt that the drive to decarbonization is firmly underway, meaning a significant portion of fleet replacement will ultimately be through the addition of wind and solar assets. The same focus on efficiency is also driving a high level of direct procurement and an increasing desire by customers to actually choose their supply technology. This is creating a high volume of corporate renewable procurement that I'll talk about in a moment. And it's also opening opportunity on the on-site and cogeneration space as customers with the right type of facility see a significant benefit from a dedicated generation source at their facility. And we also see some very interesting processes to procure what we refer to as hybrid generating plants. Generally, these are facilities that include a portion of on-site baseload generation supplemented by some renewables as well as some form of energy storage. This is actually becoming more common as customers want to have a hand in actually deciding the type of generating plant that's going to be based at their facility. Now you may have seen this graph before or some version of it. It's a fairly highly used piece of data. It's so frequently used because it's telling a pretty incredible story. The graph shows the continued build out of renewables in the United States that is directly contracted to corporate off takers. 2019 again is on track to be the largest year on record both from a capacity contracted perspective as well as based on the number of new agreements. This graph is showing data up to 2018, but I can tell you that at the halfway point in 2019 there were already 43 new agreements signed accounting for about 4 gigawatts of capacity. As I mentioned earlier this market is diversifying significantly and we see activity here now across almost all different industry sectors. It's not just a U. S. Story either, it's important to note. Globally there were over 8 gigawatts of PPAs signed in the first half of twenty nineteen which puts this year again on pace ahead of the 13.4 gigawatts of contract signed for the full year in 2018. Now in the U. S. We know that the upcoming end of the tax incentive program is motivating quite a high level of activity at the moment and through 2021. So, it's quite likely that we'll see a peak of activity and then a bit of a lower run rate going forward. But it's clear that this market is being driven by much more than a tax incentive program. Corporate ESG objectives and commitments are going to continue to drive this market at what will be a pretty exciting pace. Overall, these trends are creating opportunity. I see a tremendous market here for us to apply our experience and our expertise to to develop some great projects for the TransAlta fleet. And we already are. In this corporate PPA market specifically, we have our big level and Antrim projects that are both contracted to corporate off takers Microsoft at big level and Partners Healthcare at Antrim. Our competitive advantages really do set us up well to compete in these two markets. And I'm under no illusions about the level of competition. There are many others out there who are on these markets and who would like to take their fair share of their market here as well. But I'm confident that we'll succeed particularly given that we've already had some great wins. So, I want to show you a few of those now. And this next slide is really critical for me because I think it makes my job here this morning quite a bit easier in that I don't have to try and convince you that we're going to maybe grow someday by talking about a big development pipeline. Instead, I can just show you what we're already doing and where we're already having success. This is our list of announced projects today between $750,000,000 $800,000,000 of growth investment. The list is all wind and storage today but soon I plan to have a cogeneration project add to this list. The list totals roughly 400 megawatts of new wind capacity and as John mentioned earlier this accounts for a 30% increase in the size of the operating wind fleet that we have today. Now I want to briefly look at the specifics of each one of these projects. We have 3 wind projects under construction in the U. S. Today and 2 of them are nearing completion. The first is Big Level, a 90 Megawatt wind farm in Pennsylvania with a 15 year offtake agreement with Microsoft as I mentioned earlier. Obviously, we're very pleased to have added Microsoft as a customer and this project will be online later this year. I can tell you that nearly all of the turbine components have been delivered and have been staged at each of the turbine locations. Today over half of the wind turbine erection work has been completed. And this project is being funded by TransAlta Renewables as is the next project at Antrim. Antrim again is directly contracted. There's actually 2 off takers here Partners Healthcare and New Hampshire Electric. The project is mechanically complete. So all 9 wind turbines are fully assembled and commissioning is well underway. This 29 megawatt project will be online in Q4 of this year which will mark the start of its 20 year offtake agreement. And the 3rd U. S. Project is called Skookumchuck which is located in Washington State not too far from our Centralia facility. This project is under construction today. It's being built by Renewable Energy Systems or RES and we will purchase a 49% interest in the project at COD. Again, the wind farm has a 20 year offtake agreement this time with Puget Sound Energy. The other market we'll soon have wind under construction is back at home in Alberta where we have the wind dries and wind charger projects with both having equipment orders placed and planned construction start dates next year. Wind charger will be the 1st utility scale battery installation in Alberta and will be located at our existing Summerview 2 wind farm. The project is being supported by emissions reduction Alberta and we're very excited to be a first mover in bringing large scale battery storage to the province. We're working with Tesla on this project and together with them we've completed the final design and placed an order that will see the battery delivered early next year. A relatively short construction timeframe means we'll have the battery up and running by mid year. And last but not least, Windrise, a large two zero 7 Megawatt project that we won through the Alberta Government's Renewable Energy Procurement Program in late 2018. I have to tell you our team is really excited to be building wind again at home in the region where we started our wind business about 20 years ago. And not just any wind farm, for us Windrise will be the largest wind farm in our fleet and it will utilize some of the biggest wind turbines used in Canada, the Siemens Gamesa 4.8 Megawatt Machines with a 90 meter hub height. Again, another project with a 20 year offtake agreement. So that was a bit of a whirlwind tour. I'd love to spend more time talking about these projects with you this morning and I'm certainly happy to do that if you catch me a little later once the formal presentations have concluded. It's a great list of projects because they're a perfect fit within the strategic focus areas that I talked about. They're adding capacity to our fleet with a new suite of customers and in some cases new partners. And they're doing that while adding material EBITDA to the business. You can see from this graph how the EBITDA from each of these projects phases in over time as each reaches completion. By 2022 this set of projects will be adding roughly $50,000,000 in EBITDA to the fleet and that's just this list. With our track record for adding growth firmly established and our team already having this kind of success in our defined focus areas, I'm confident that in the near future we'll have more projects to tell you about that will further add to this result. And I'm really looking forward to adding the first cogen project to this list. And with the progress that we're making in that space I'm confident that I'll have a project to tell you about there in the not too distant future. And with that, I thank you for your time and attention this morning. And I'll turn the podium over to our CFO, Todd Staff. Thanks, Aaron, and good morning, everyone. Over the past several years, the company has made significant progress in improving its overall financial position, strengthening our balance sheet and managing cost pressures. In addition to operational improvements, we've executed a number of strategic financings to position us for the future. The result of these actions has been strong cash flows generated by the business and an overall reduction in net debt including a significant reduction in the amount of senior corporate bonds. These actions put us in a very strong position to execute the repowering strategy that we've been discussing this morning without accessing the equity markets. This morning, I'm going to be walking through how we're now thinking about capital allocation and funding plans over the next 4 years. In addition to funding the repowering strategy, we're able to continue our growth in the renewables business and deliver on our plan of returning capital to shareholders through our announced share buyback program. During this period, we also expect to further strengthen our balance sheet by repaying our 2020 bond maturity. As you know, TransAlta Corp. Owns 61 percent of TransAlta Renewables. And as a result, R and W's financials are consolidated within those of TransAlta. This morning, I will show you TransAlta's balance sheet and cash flows on a deconsolidated basis, that is how it would look if TransAlta Renewables was not consolidated. This deconsolidated view of TransAlta and RMW is one of the ways that we look at our funding plans. In 2013, we spun out a minority interest in TransAlta Renewables to highlight the value of our contracted renewable and gas assets. In addition to the lower cost of capital sorry, in addition, the lower cost of capital at R and W improves our ability to compete for new renewables projects in Canada and the U. S. As Aaron described earlier. However, we regularly get questions about the cash generated by the remaining portfolio of assets held at the TransAltaCorp level. The assets under TAC are predominantly merchant or soon to be merchant and include the Alberta hydro assets, the coal to gas assets, Centralia and our 50% of the TA cogen assets, which include our share of the Sheerness facility and several other gas plants. The waterfall chart on slide 84 is based on 2018 reported results and shows the deconsolidation of cash flows. Beginning with the $770,000,000 of consolidated funds from operations number, which is reported in our 2018 year end MD and A, we first deduct distributions paid to our 50% partner at TransAlta Cogen. To deconsolidate R and W, we deduct 100 percent of the FFO reported by TransAlta Renewables, which for 2018 was $381,000,000 Remember that R&W's FFO is used to fund their sustaining capital, make payments on their amortizing debt and pay dividend to their shareholders who include both the public shareholders and TransAlta. To include our share of the cash from R and W, we add back the $151,000,000 of dividends paid to us. The resulting value of $454,000,000 is our 2018 deconsolidated FFO. This cash is available to fund capital projects, retire debt and return cash to shareholders at TransAlta. A more detailed description of this reconciliation is included in the forward looking statements included on slide 2 of the presentation. So let me turn now to our capital allocation strategy. We start with deconsolidated FFO at the TransAlta level as the primary source of capital available for allocation. The breakdown at the bottom part of the page includes the uses that we consider in formulating our capital allocation plans. So with these uses, we have included percentages which represent our expected range of the allocation over the next few years. I'll start with the common dividend as this morning we announced that the Board has approved a formal dividend policy to allocate 10% to 15% of deconsolidated FFO for dividends to common shareholders. While setting the dividend as a responsibility of the Board, we expect that they will be addressing the dividend amount early in 2020. So, we're currently paying out about 10% to 12% of deconsolidated FFO to dividends, which is at the low end of our target range and provides the Board with some flexibility in the near term when assessing the dividend. With respect to sustaining and productivity capital, our CapEx spend can vary or can be very lumpy depending on the timing of major outages. And because of that, we focus on our average expected spend over the long term. The percentage allocation shown here represents a long term average and individual years may fall outside the range. In 2020 2021, we'll be taking major outages on at least 3 of our coal units to complete the gas repowering and to set these units up to run into the 2030s. However, as Wayne mentioned earlier, over the long term, we expect the proportion of FFO allocated to CapEx to decline as the operations become simpler and less capital intensive once the coal units have been converted or repowered. This trend allocation represents the cash that's left after funding CapEx, addressing debt amortization at TAC and paying preferred and common share dividends. This remaining cash is available to fund growth, debt reduction and share buybacks. Over the past several years, a large portion of this cash at TransAlta has been focused on debt reduction. As you'll see in the next few slides, we're on track with our debt reduction plans and able to achieve targeted levels. This gives us the confidence to commit a significant portion of our capital to our boiler conversion and repowering projects over the next 4 years. The coal to gas conversions provide a unique opportunity in our home market and we view these high returning projects as a high priority in our capital allocation strategy. Before I leave this slide, I just wanted to touch on our share buybacks. Earlier this year, we committed to repurchase up to 250,000,000 of over the next 3 years. This repurchase program is being funded with a portion of the Brookfield investment arranged earlier in the year and therefore doesn't take away from other potential uses of FFO. Next, I'll address the balance sheet progress I referred to earlier. As you can see from the chart, we've had considerable success over the past 5 years in repositioning the balance sheet. We expect to achieve our goal of reducing our senior bonds to the $1,200,000,000 level by the end of 2020. Cash on hand, free cash flow and other sources of liquidity are sufficient to repay our $400,000,000 bond maturity in 2020 without accessing the capital markets. We monitor a range of credit metrics to assess our financial position and our practice has been to disclose our targets and performance on a consolidated basis in order to align with rating agency treatment and presentation of our audited financials. However, internally, we also look at our credit metrics on a deconsolidated basis. In this slide, we look at our debt to EBITDA level on a deconsolidated basis both today and on a pro form a basis after the PPAs expire and we're able to realize the full revenue from the hydro assets. When we think about debt levels on a deconsolidated basis for TransAlta, we balance the predictability of our cash flows from our TransAlta Renewables dividend, the strong cash flows from our hydro business against the relative volatility of our merchant assets. Based on the makeup of our EBITDA, we believe that a target debt to EBITDA metric of below 3 times is appropriate. One item to point out on this slide is the inclusion of the Brookfield investment in the build up. Under accounting rules, the Brookfield investment will be treated will be considered as until it converts. Internally, our assessment is that the conversion is highly probable and we currently plan for it to convert post 2024. As you can see in the post PPA buildup, with the repayment of our 2020 bond next year and full revenues from the hydro assets in 2021, we're on track to meet our deconsolidated debt to EBITDA ratio of 3 times. Let me turn now to our funding plans. As mentioned earlier, our base plan includes boiler conversions of 3 units in 2020 2021 and the repowering of 2 units as combined cycle plants scheduled to be in service in 2023 2024. So, if I continue to look at TAC on a deconsolidated basis, roughly 65% of our plan over the next 4 years is funded by internally generated cash flows, our dividend from R and W and cash on hand. The 2nd tranche of Brookfield investment is expected in 2020 and will provide an additional $400,000,000 of funds. This will further support the funding of the conversion program and our share buyback program. This means that about 80% of our funding plan is known and not dependent on the capital markets. We are however expecting access to debt markets in order to refinance our 2022 bond. This refinancing will keep our senior bonds at or below the 1 $200,000,000 level. Our base capital program will result in a minimal draw on our credit facility over the next 4 years and is expected to be quickly repaid once the first repowered units come online. One other point to highlight on these funding slides is that the deconsolidated growth capital does not include the Windrise or spookum truck projects. These wind projects have long term contracts and are ideally suited for dropping down into TransAlta Renewables some point in the future. Let me turn now to our funding plan for TransAlta Renewables. Funding in R&W for the big level and Antrim projects is relatively straightforward. These projects are expected to be completed by the end of this year and have been funded with free cash flow, proceeds from the dividend reinvestment program at R and W and draws on R and W's credit facility. We expect to close the tax equity financing by the end of the year to repay the credit facility borrowings. Looking forward, I mentioned that the Windrise and Skookum Truck projects are good fits for dropping into the R and W portfolio. We expect to finance these assets with asset level financing in the form of project debt at Windrise and tax equity at Skookumchuck. The relatively small and manageable equity portion of these projects will be funded using the balance sheet and repaid with operating cash flows and proceeds from the R&W DRIP program. R&W has significant balance sheet capacity to finance its current build program in addition to these potential dropdowns. In addition, R and W has access to additional sources of capital to fund incremental growth projects, including the potential to raise between $400,000,000 $600,000,000 of project debt on currently unencumbered assets. The final message I want to share with you today is views on the valuation of our shares. EV to EBITDA multiples are a common way to quickly compare and value assets in our industry. Starting on the left, the enterprise value of TransAlta can be calculated based on the market value of our shares. Similarly, we can value and back out the enterprise value for TransAlta Renewables based on their trading price. This leaves us with the implied value for the remaining TransAlta assets. Within these assets, one of the key assets is the Alberta hydro facility, which we believe is valued at about 2,500,000,000 dollars When we subtract the hydro value out, the EBITDA from the remaining assets, which includes the Alberta thermal fleet is only being valued at about 3 times. From our view, it's clear that the market is not recognizing the full value of the conversion plan. The incremental value could add $4 to $7 to the share price. I'll now turn the podium over to Dawn for some final comments. Thanks, Todd, and thanks, everyone. Really great set of presentations and I think a lot of detail that will really help you assess the value of the plan that we're putting forward here today. Now, I know that everyone's chomping at the bit to get their questions out. So, I'm just going to quickly summarize what we want you to take away. So, first, we believe we are at a very attractive entry point as a company in Canada who has a really great future ahead of us. We are ready to invest up to $2,000,000,000 in a clean energy plan that is exciting, it's competitive and it has strong returns. We are the company to invest in if you want to position in the Alberta market as it responds to carbon pricing and final changes to an energy only power market. We have created a plan that gives us longer term and sustainable competitive advantage in a market where we've been a cornerstone generator since 1911. We're also the company to invest in if you want to participate in the increasing electrification of energy and if you want to get into the growing renewables and ESG space. The plan is comprehensive. It's funded and it's very, very transparent. We are backing our confidence in our plan by continuing to buy our own stock as we believe it's a great entry point and our investments are strong enough to maintain a strong balance sheet and contemplate dividend increases along the path. There are definite advantages to running 1 company with 1 team and you now have the information to see how the dividends from R and W benefit you as a TransAlta shareholder. So it's pretty exciting to be standing here today sharing all of this with you and we are ready to take your questions. For the Q and A, please limit yourself to one question, so that we can allow everyone the opportunity. If you have more than one question, just take some turns. I'm going to facilitate the Q and A session. You can and I'll direct it to the people that I think can do the best to answer the questions for you. Could you please just let everybody know who you are and who you represent as we begin the Q and A session here today? So who would like to be first? Annegas from Credit Suisse. I think one of the comments that was made earlier was your business plan isn't really dependent on pricing in the market place. And you've laid out a pretty compelling cost reduction story for yourselves. And then some of the consultancy slides that you showed actually had increasing pricing. What dynamics are driving the increasing pricing if some of the major incumbent players actually have decreasing cost profiles? John, do you want to take that? Sure. Is it working? Yes. Can you hear? Okay. So in terms of increasing prices in the marketplace, I mean, I think there's when we look at the prices, I think one of the key factors that has occurred in the market is the way it's actually been. It's a closed market. Effectively, we've got 5 major competitors. They compete very strongly against each other. They all have a mind to bidding not just their marginal cost, but also looking at getting a return over non capital in the market. I think that's a key factor. I think we are seeing some load growth in the market. I think there's also been some reductions in the number of supply in the market. I mean, we've had a couple of units actually believe our Sundance 1 and 2 units are gone. I think we're looking at potentially Battle River 3 also leaving the market. I think when you look at that, that's another 7, 7 50 megawatts I think of generation that's leaving. The market is very much an event driven market. I think it's tight very often. You see sort of prices spike up. And the other thing I think that is notable in our market is we do have renewables, but I don't think we're expecting to see, given the nature of the marketplace, the kind of impact or penetration of renewables that you've seen in maybe some other markets which act as a reduction on pricing. And I think as prices come down, in terms of some of the variable costs come down, I think the margins will continue to be pretty good even though we might get some variability on pricing. Maybe just as a follow-up, do you see a rise of beakers being introduced into the market in the future just given the volatility in energy only nature? We may do. Right now, we don't see a significant kind of movement that way, but it is possible given how some of the reductions in the cost of getting beakers and the technologies have come down. It is a Yes. Let me just add something on that. I think if you look at the simple boiler conversions, those are peakers. And they're $30,000,000 to $50,000,000 to make a peaker compared to a couple of $100,000,000 to make a brand new peaker. So if I was looking at the market, I would be looking at the potential for the existing stock to create pretty good peakers at pretty good heat rates. Excellent. Julien Mouldsmit, Bank of America. Great follow-up actually on that. Can you comment a little bit more on the market dynamics? What are you seeing in terms of retirements, especially given your own considerations to convert your units out there? How do you think about sort of the pluses and minuses, low growth, retirements of coal potentially elsewhere? But then also on the other side of the ledger, if you will, how do you think about your peers? Because you just presented, for instance, some pretty attractive multiples of your own conversions and even greenfield combined cycles, the multiples of EBITDA at current I think roughly current power prices. So perhaps a little bit more of a deeper dive on the ledger. And if I will, I'll just ask a second follow-up for the sake of getting it all out there. Just talk a little bit about the Alberta market, given the new government and potential, I suppose, consolidation of different regulatory regimes under what house? I'm thinking MSA here and what could happen and how you think about any future iterations or changes in rules. I'll leave it broad. Okay. So Brett, I'll get you to take the first question and John the second and then I'll do cleanup. Yes. So pluses or finuses, sorry, you certainly the Suncor announced Cogen, which is planning to come in, they say in 2023. We that's been on our radar for some time and we factor that into our models. John showed a chart from EDC that has pretty robust growth going out. But even if you look at more conservative growth in that 1% per year, which is being a bit conservative based on history, there's a need for new generation coming into the market. There are other units, as John said, that coal units, smaller coal units, we'll see they're not ours, but may have to come out of the market soon and what they do with those. So there's a few pluses and minuses that we see when we run our models that balance out. And with the positive economics that we showed you, even if our generation is slightly lower, we're getting much higher margins out of it. And you actually see that when you compare our 2018 to 2019 how we've been able to all the work Wayne has been doing and this is just on co firing. So we see our margins improving over time. Longer term, as our chart shows, eventually and maybe this wasn't clear, the boiler conversions are have a hard date to them, okay? They can only run a certain amount of years post their coal life and it depends on their emissions test. So eventually long term those units have to come out whether they're ours or somebody else's. So new capacity will have to come into the market. The final point I'll make is if you look at a brand new combined cycle trying to come into this market, clearly it's dependent on gas prices. Generally, you're going to need in public that $55 to $65 per megawatt hour price over time to get a good return on and of your capital and pay for your costs. And Julien, I think your second question was just about some of the additional changes that are happening in the market and what the impacts might be based on what the new government is looking at doing. I think there's really 4 things that they're looking at doing. Net net, we candidly don't think it's going to change kind of investment thesis in terms of what it is that we're doing. But they are just very quickly. One of them is just getting certainty on the carbon pricing. We're expecting that in about a month or so. The second thing that we're looking at doing is the ISO has been tasked with which looking at price ceiling, price floor and trying to make sure that we've got a workable regime as it relates to shortage pricing in the marketplace. That consultation hasn't really begun. They've been tasked with providing an update to the government in February of 2020 with landing any of the changes that we have to those rules in the summertime next year, sort of July of 2020. So that is an ongoing piece of work. And in general, I think the concern there is just making sure that there's enough signals to ensure there is appropriate build and to ensure that reliability is appropriate for the province. The third thing is, again, and the ISO has been tasked with this, is looking at market power and looking whether or not there's any mitigation that's required. I think that's scheduled to be completed just before Christmas late November. There hasn't been, at least to my knowledge, any sort of consultation that's really been initiated. We've had some discussions around that. I can tell you our view as a company is that everybody in the in the market in terms of bidding behavior rather than those time periods when there is tightness in the market where you actually want people to be dynamic in their bidding. And then the last point, which you alluded to was the whole notion of just all of the various entities that we have that oversee the marketplace. So all of the agencies are being reviewed. The Department of Energy has been tasked with looking at that. I don't recall that there's a specific timeline for that and it is as you alluded to the ASO, the MSA. Our sort of internal view is that that is oriented more towards the red tape cutting efficiency drive that the government has more than a wholesale kind of change in dynamics or the approach that those agencies are going to be taking in the leasing market. Okay. If I could clarify just quickly on that. Net net, it doesn't sound like borrowing obviously resolution on some of the carbon details. Material changes with respect to markets, obviously logistical and organizational changes. Yes. I think that's fair. And in fact, if you were to look at the key piece of legislation or regulation that kind of governs behavior, it's literally like 10 sections a 10 page kind of document. It is, as I mentioned, a relatively pure market and regulatory light. We'll continue that to continue. We expect that to continue. Great. Next question. Sorry, Rob Hope, Scotia. Actually maybe just a follow-up on terms of the carbon. It seems that the plan is based on $30 carbon. Do you see that progressing up to $50 Is that included in the plan? And can you just talk about some flexibility in your coal to gas conversion plan depending on where carbon goes? Go ahead. I would get on a soapbox and talk for an hour. So you can just answer. So look, it's a great question. So we model it out when we look at our investments on a variety of ways. I think our base case is basically a $30 case. Our sense of it is that that is where broadly the government of Alberta is right now. I think from a longer term trend perspective, when you look at where the federal government is going, we have elections that are in place. We'll see what ends up happening depending on who wins the election and whether or not the approach of the federal government has on trying to impose ever increasing carbon prices among the jurisdictions. I think the trend is for higher carbon generally across the jurisdiction. And I think even in Alberta, the government has a pretty good understanding that we have an excess supply of gas in the jurisdiction. Frankly, when it comes to our sector, having a pretty good, a pretty robust carbon price actually increases the consumption of gas in the province. Net net actually helps the dynamic for the gas industry in the province. So hopefully that gives you a bit of a sense. Yes. I mean, I would just be crystal clear. The current federal government has definitive rules that require the provinces to ramp up to the $50 to be equivalent. And if you don't do that, they'll put a back stock in place and they did do that in Ontario. So depending on what happens in the election, if it is And the courts are holding them up, sorry to hear. Yes, if it is a Liberal majority, that is the current legislation federally. And if Alberta wants to do something differently, for example, if Alberta wanted to negotiate a longer term $30 framework for some reason, Alberta has to work proactively with the federal government to get that deal. So we model $30 but we don't model down from there. So we don't see a case where it's less than $30 and we will model the 40, 50 to test our assumptions, but we model an upward increase in carbon tax rather than downward. Yes. And in terms of our plans, you can imagine if it goes to 30, the gap between coal and even the boiler conversions even gets wider and then even the combined cycle. So our plans actually fit nicely as prices go up. And you got to remember, even a gas peaker in the market today probably has a range of heat rates, not dramatically different than some of these coal units. So they're going to also part of that increase in carbon costs could get reflected in the energy price because of the higher cost in the market. It's Ben Pham, BMO Capital Markets. So you had that slide highlighting expense evaluations, just breaking up the net asset value. On the hydro side, I'm curious the $2,500,000,000 how are you getting that? Because it seems quite conservative when you use kind of multiples that per field is paying for asset? And another thing is, I think you mentioned a few years ago around issues around dropping down an asset through to renewables. Is that still the case there? How do you look at the drop down potential for hydro asset? Yes. So let me start on the valuation side. So the valuation is relatively straightforward. It is looking at similar to like John spoke in his slide about $200,000,000 plus of EBITDA long term once the PPA expires. And we're using generally the multiple that we negotiated with Brookfield of the 13 times on the valuation. That kind of sets up that $2,000,000,000 $2,500,000,000 range. As far as dropdowns, so at this point we're not really thinking about the hydro assets as a potential dropdown into renewables. I think that was the question simply because they are merchant based and it really doesn't fit the risk profile of TransAlta Renewables. Further to Ben's question, now that you have Brookfield as a financial partner, have you contemplated using backstop PPA, using Brookfield's balance sheet on the hydro assets to then make them more appealing to be able to do a drop down into RNW, similar to what Brookfield did on with Great Lakes Hydro on going back, I guess, 15 years? Again, in essence, if the market is never going to give you credit for what it is, can you not manufacture that financially? Go ahead, Brett. You want to take that? Yes. I mean, we've always thought about the hydro assets even before the Brookfield deal and whether there's an opportunity there. But again, when we look at the Alberta opportunity that we're going into here and as it comes off the PPAs, we see quite a bit of value there. So at this stage, I would say, no, those were not considering this. We'll who knows over time. But certainly, we're less about are we getting credit for the hydro. I think our view is we're probably not getting credit for the thermal is our general view. And now as we've laid this plan out and that we've liked extended these assets, showed you they're going to generate very good cash flows going forward, that's where we think the value gap is probably at. Now is there always upside in the other assets? Sure. But so no, the answer short answer is no, we're not evaluating that right now and we're more focused on other contracted assets that could go into R and W. And then, sir, just a follow-up on in terms of some of the like the TA cogen assets, there's been a change of control at Cheerness with ECP. Can you just walk through what your thoughts are on those assets? It seems sort of like I mean, I don't think they really got a slide in the 85 page deck. So, what is that what can we imply from that? I mean, go ahead. Yes. So it's an important asset in the TA cogent part. I mean, we have effectively net to our company a 25% interest in share nest. I mean, they are moving forward to convert that plan. I don't actually think the transaction is actually closed yet. I think it's still conditional and they're working it through. Right now, from our perspective on that, it's just steady as she goes. We haven't we're just viewing it as being one of the key assets that's in that partnership arrangement we have with our partners and there's no suggestion that we do anything with that asset at this point? Yes. I think they're currently going to do a dual fuel. So they'll be able to run on coal and gas. And then we expect them as they move through the mid-twenty 5 to turn that to gas. They've been working to get gas supply sorted out and we've been supporting them in that process. Okay. Robert Quonner, BC. If I can just ask about capital allocation and first on the dividend. Just wondering what the thought process was around payout ratio policy around FFO versus free cash flow? And then as you're in this capital build, do you cheat to the lower end until you're exiting the coal conversions? Yes. I mean, so first of all, we wanted today to really set a very comprehensive framework for how we're thinking about everything because we didn't want to walk away today and then somebody said, well, you didn't tell us about what you're thinking about the dividend. So we spent a lot of time looking at free cash flow, looking at ways that other people do their dividends. We like the when it all settled down, it was clear to us that investors are having trouble seeing how the 2 companies fit together. They're having trouble seeing how dividend from R&W is actually supporting the reinvestment in Alberta right now and then that kind of changes over time. And it's really been hard to drive home the discussion around how the sustaining capital changes dramatically as you go to gas. So remember, we've been in coal since the '50s. We built most of our units in the '70s. We built additional units in the zeros. And the company has had a run rate of capital for a long time based on capital in coal plants, which is significantly different than gas. So, when we put all of that together and then of course looked at what our current dividend was, we wanted to be able to indicate how we would guide the board to think about it. And what Todd said is we're in that kind of 10% to 12% range now. And I think we do fundamentally as a team believe that you have to tether your growth strategy to something. And it can't be just we'll grow we just want to add more and more projects. So what is going to frame and tether and pull all this together? So there were 2 tether points. 1 was the debt, and that's the 3 times that Todd did a really great job of laying out because we believe fundamentally that makes sense for the mix of assets that we'll have that are contracted and merchant. It's a lot lower than you would see in a utility and it's about in the range that I think IPPs are thinking about. And so then it just came back to the dividend. So at this point, as we look at it, we like that range of 10 to 15. We do want our Board to have a discussion about it annually, look at the in year cash flows and also look prospectively at the cash flows. And we just think it's an important principle for the company to have that you have confidence that as you're going, you're achieving the cash flows and that you're So, we wanted to make that very transparent. So we wanted to make that very transparent. Got it. I can just finish with the second part on capital allocation. You show the chart with your stock at 2.9x EBITDA. You're allocating to new growth circa 10 ishx EBITDA at least with the renewables. With the gap that wide, what's kind of the thought process of continuing to allocate capital to projects like that versus just given that lift that you see just buying back stock? So and I'll try this and then Brett will make it right. So no, I won't. Brett will make it right and then I'll say yes, Brett made it right. Go ahead, Brett. Yes, I think you got to the way we look at it is we're investing in those combined cycles at extremely good projects. The renewables, which is more of the R and W type multiples, which is akin to what we're investing at. So again, remember, most the contracted stuff is well suited for R and W at some point if it's not there already. And so we're investing we can we can get off those combined cycle or boiler conversions. So I would look more at the 3 times multiple against that. And then the renewables against more of the R and W side because we stripped it out. But at the same time, we still have the commitment to buy up to 250,000,000 of shares over the next 3 years and that was part of the Brookfield transaction that we did. And so it's a balanced capital allocation approach and investing also to extend those assets over the long term. Got it. So when you're doing the renewables, you're really thinking about it as developing and effectively warehousing it for R&W's purposes? That's correct. I was we really need to break the back of that assessment. So, when we look at TransAlta as a whole and I thought we did a really great job of showing that deconsolidated slide there. What we see is those 10 times are really going into renewables and there's cash building up in renewables that needs to be reinvested or they need to increase their dividend. And we make sure that we're getting valuable investments into renewables which is what Aaron's session was all about. But we so we see the 10x renewable investments being in the renewables entity. We see the coal to gas and hydro being in TransAlta inside TransAlta. Of course, the cash flow comes back in from renewables. And I think that's exactly the point. The exact point is if we start something in TransAlta, there tends to be a lift for TransAlta shareholders as we move it into a lower cost of capital entity and that's the benefit. So the TransAlta shareholders get 2 benefits. 1 is that lift and the second one is they get to reinvest that cash or take it back. Thank you. Mark Jarvi from CIBC. Just wanted to delve into some of the commentary and details around the coal to gas conversion strategy. A couple of different items here. One would be a little vague on what the plans are for Sun III and IV, whether or not you guys would actually just maybe completely shut those down. Do you guys in and so the revenues coming into the repowering assets? And then what would tip you to go to 3 units repowering? So, yes, as you know, there's 2 units mothballed today. And so as we and they're mothballed till November 21. As we kind of get through next year and into 2021, we'll look at just the market fundamentals. And it's a matter of do we just bring them back as coal units and just co fire them. Because to be honest they're not going to likely run remember a coal unit co fired a 400 megawatt unit can burn about 30% gas with no modification and the rest coal. But if that unit only runs 30%, it's burning 100% gas. So we pull back on the coal. So those units could come into the market just simply as is and we could co fire them if we think the market needs them. Or because the payback is so high on that capital investment, we could convert them through a boiler conversion and then decide if we do another combined cycle on them. So we'll get through as we start to kind of make our way, see what some of the market changes are, see what the fundamentals look like. That's when we'll assess those units and make our decision. In terms of a third, as I said in my section, we're really trying to balance how much we can fund through our funds flows and also have a low cost set of assets. So that's where we landed on being able to do the 2 combined cycle units. That's not to say and I just want to make sure it's clear. When Wayne showed those units coming off, those were those boiler units coming off, converted units because they have a hard date. We can then repower some of those and we mentioned this on Keybills 3 for example into combined cycle units because now the boiler we don't need. But if the steam turbine is still in good shape and some of the other infrastructure there, then we can put another gas turbine on that unit and basically now run it for another 20, 25 years. So there's the opportunity later on to do more combined cycle repowerings. Right now we are just kind of balancing between the capital, the market dynamics And that's why this plan to us made a lot of sense. So just another way to think about it, depending on how demand and supply are in the province, if you do some of the math behind our plan, there is capacity that starts to free up by 2025 to finance a third conversion. And the team in 2023 or 2024 could actually look at either doing a combined cycle plant on one of the units that's already been converted to gas or they'll have the other ones. In the Alberta market, however, if the conditions change and those units that are mothball become profitable, Wayne would have to bring them back into the marketplace. So he has to attest that the amount of megawatt hours that he sells out of the units times the price doesn't cover their avoidable costs. And so as long as they're still in our fleet, if market conditions do change, they do have to come back into the system. And then just on the revenue streams between market and ancillary revenues, just any assumptions around that for the conversions and the repowering? You mean for the thermos side or the hydro? Yes. Yes. I mean if you look and this is if you just go on the ISO website you'll see we sell ancillary off of the 2 Sundance units today. Generally, it's in around the 80 megawatts. Now it's not always 80 every day. We can probably anticipate that kind of level going forward. But it will vary between 0 and 160 if you will. But they are available to participate. Our hydro is the main participant as you know. And the PPA units that's not ours. It's still the balancing pool. So if anybody is going to get ancillary, they get to until we get off those PPAs at 2021. Again, Julian, Vamil. Just wanted to follow-up on a couple of the conversations that just happened just to clarify some of the financial points you made. With respect to the capital allocation through 2023, if I'm reading it correctly, right, you have the step down in leverage metrics simply because of A, the conversion of Brookfield which I think you mentioned in your remarks. Separately, you've got the step up in cash flows from the conversions, right, I think which come in after 2023. And then thirdly, you have a run rate of cash flow from the renewables assets that you're investing in growth. So I suppose, first off, how do you think about just kind of the step up even beyond that 23% I know we're really early, but I'm sort of curious. And then coming back to that prior comment in the capital allocation piece of CapEx, you talked at length in various points about cogen investments. You showed again the multiples of investing. And again, to go back to don't want to put words in your mouth. How do you think about your don't want to put words in your mouth. How do you think about your disclosure where I believe you are not assuming R and W drops, you have a placeholder for buybacks. How do you think about eventually making this decision about to make the R and W drop and then subsequently these CapEx opportunities and just like even from a time line perspective? Yes. So Todd, do you want to take that? Yes. Maybe I can just start with the leverage graph that you're talking about. It's on Slide 87 that shows sort of where we're at today is where we're at. I think we call it post hydro PPA. That's not looking really at the 2023, 2024 period. That's looking really right after the PPAs expire at the end of 2020. And so what you're seeing there is the repayment of that additional bond coming up next year in our leverage as well as the step up in EBITDA from the hydro assets once we get the full revenue from it. So, it's not out as far as you are thinking. It's more near term. And then do you want to So Brett, go ahead. Can you repeat all the rest? When do you make the Julien, can I I think what you're asking is Julien, can I I think what you're asking is how would you think about doing a contracted cogeneration with a 20 year contract compared room in your capital plans? Right. So, the drops, we've done a lot of drops. And they just it's a process. It's either it's related parties. So we have to go through all that process. So that's just a matter of timing. And quite often, we'll acquire some of those assets earlier stage, get them up and running and then drop them in. Sometimes we'll drop them in earlier. So there's no magic, if you will. But once they're suited, then it makes sense to get them over there if that makes sense to both parties. You got to remember on the boiler conversion, 1st of all, the payback is huge out of the gate with carbon savings. And the outage time, as Wayne says, those units are only out 6 weeks, maybe 8 weeks for the actual work. The combined cycle is a a full permitting process we got to go through. It's a longer timeframe. And so getting some of these boiler conversions done and just getting that savings as soon as we can and being positioned when gas is cheap, as I mentioned to you earlier, some days we saw negative gas in the last couple of months. We just want to be positioned to capture as much of that as we can. And so that's again, we're back to this balance that we strike when we run all our models between putting a ton of capital in the length to convert versus building a combined cycle. Our plan kind of looked as we described here. That's not to say we don't kind of modify it as we go forward and like I say, do more combined cycles down the road when the opportunities are. Does that kind of capture it? I mean from a balance sheet perspective and talk about this. I mean you showed we only have $1,200,000,000 of bonds at the end of 2020 at the TA level. Remember that's being supported by these hydro assets which have a ton of value and all this converted. So balance sheet wise in very good shape from that perspective over the long term. Good question. Hi, John Mould with TD. I'd like to ask about new markets and how you're thinking about those. A number of your Canadian peers have, I guess, looked for growth all over the world. Maybe putting Australia aside for a second because that's a bit of a one off for U. S. Company. How do you think about potentially looking at other markets beyond Canada, the United States? And what would it take for you to make that decision? Well, I mean, I think that's hard to see you guys through these things. But I would say that when we look at the U. S. Market right now, there's quite a demand for what Aaron talked about in terms of these corporate customers that are looking for some sort of product for their own ESG goals. And that has changed significantly. So, there's a pretty big market there. And it's surprising to me how underdeveloped the market is for the actual developers that provide those projects. So there is it's still kind of more of a cottage industry. I mean, except for I mean, NextEra is a big player and there's a few big players, but there isn't really as many people as you would expect to see given the amount of demand. So I think part of our work in the next year, which Aaron's team is doing, is to really say, okay, how much can you get there and are the returns too low? Now we've seen that the returns currently are definitely too low on solar, like they're just not worth looking at. But there are people who buy them. I don't understand it, but they do. But still in the wind space, if you look at our Skookumchuck project, and I was just there probably 2 weeks ago climbing all over a mountain, looking at cranes and planes and automobiles to try to put all these things up. And it's still a fairly complex build because you're putting up 90 meter towers and they're big, big it's a big operation to get that thing built. So you can get the returns out of doing that still in the U. S. We are seeing in our Australian operation, of course, Australia is 100% focused on Asia. Like Australians focus on Asia and Canada focus as well in the United States. And of course, there's a lot of work going on in Asia with the Canadian government with TPP and things like that. So we are seeing, for example, in literally 20 like literally 20 coal plants are being canceled. I think it's in Indonesia. They just will not allow them. They have uprisings against them. They do not want them. And there's just a ton of solar being built there. And it's these are brand new markets with long, long timeframes against them, which goes back to what I was saying earlier. I think you're going to see over the long term quite a build out of renewables globally. And so we'll the way we tend to do things is we'll start a desktop study, we'll start to think about what that looks like. We have lots of contacts and lots of ways to do different partnerships to start to assess that. You wouldn't see that from us though in the next couple of years. We've got this plan to deliver. We've got good profitability in this plan. The cogeneration space is a nice little space. And again, it's not an easy space for a lot of competitors to come into because it takes complex engineering and process engineering and marketing and trading to be able to put all those together. So, we're focused there. But that's not to say that the team 3 or 4 years from now won't have started to think about what's going on in other parts of the globe. Jeremy Rosenfield with Industrial Alliance. So just a couple of questions to clean up on. First in terms of the outlook for gas supply via second pipeline, believe. I'm just wondering if you can sort of update us on that. And does that have to be in service by 2024 for the 2 repowerings? Just to clarify that. Yes. So we actually have 2 already. So Pioneer is 1 and it can go up to 440 at full capacity. There's actually an existing pipe into the sites. It was built when the plant started for start up gas. So that's what we've been using up until now for even coal firing. It's a small pipe. It's only 12 inches going up to keepers an 8 there. So there's limitations to it. So we are looking at potentially a third into the site just to have that reliability. Even though Pioneer can handle a lot, we just want to have the flexibility. Yes, we would look to probably have that 3rd part pipe available in that kind of 2023, 2024 for the hybrids for the repowered combined cycles. And then manage what we've got today to manage our co firing and the boiler convergence up until then. And then I had a question on hedging just looking forward. When you think about look to 2020 with the change in the structure of the Alberta hydro assets and you think about how you're going to hedge in 2020 and how you're already positioned? And then just longer term, if there's a broader change in the strategy around trading in the Alberta power market and hedging your open positions going forward? Yes. Sure. So the question was I don't know if people have heard it. I mean, if I can sort of synthesize it, basically a bit of an overview on where we are from a hedging perspective in 2020, 2021 given sort of the market dynamics that are there. I think when we look at 2020, it's more of a normal year, if I can say that, because a lot of the PPAs in terms of the structure of the market is more of a continuation of what we have today. So the team is looking at layering in appropriate hedges for the 2020 period. And we've started doing that and expect it to be by and large kind of a normal year for us in terms of where we go from a hedging perspective. When you look at 2021, we will be more merchant in Alberta. And we are evaluating kind of what would be an appropriate level of hedging in terms of 2021. You have to remember that Alberta thought you've got multiple years of liquidity in terms of being able to hedge. It's more of a 2020, a bit of 2021. So we're looking at that, assessing what the levels of hedging should be. Remember, we typically only hedge the thermal component of our portfolio, not the wind or the hydro. So that's in full flight and we're considering that with a view to what we're going to do in our C and I business in terms of that also providing a bit of a hedge. I think overall, our general sense is kind of keeping our hedge levels broadly where they've traditionally been is about where we are. So at least when I think of it, that's kind of in that 70% range in terms of being targeted at an appropriate time. So hopefully that gives you a bit of a flavor. If I can, just one more question. Erin, you mentioned My one question rule is not working here today. The new rule is 1 question, 1 follow-up. But this is your second follow-up, Geraldine. Okay. I'll leave it here after this one. Okay. So just in terms of on-site renewables and cogeneration opportunities, Aaron, you mentioned before, just you have sort of a ballpark in terms of total investment opportunity as to what that market might look like or what it might become in Alberta going forward, just to give everybody I think a sense as to how big the opportunity is? It's hard to ballpark because each of these plants is bespoke, right? There's not a like I said in my remarks, there's not a cookie cutter solution that we're putting in. So it's not a $100,000,000 solution, you multiply that by 5, one might be 100, one might be double that. But based on where our pipeline is at, we would like to see ourselves at just internally. We've kind of set ourselves a target of 1 to 2 of these things every year. I would say the range of investments you'd be looking at would be 100 on the low end to maybe 250, 300 for something that I would say would be much larger, probably at the top end. So And Aaron, I think it's fair to say that Alberta obviously is a key market there, but it's not just Alberta. We are seeing opportunities. And on-site is not just cogen. It could be just behind the fence simple cycle or combined cycle units as well. Rob, you tell Oak West. A quick question really on growth and things that you used to talk a little bit more about which were storage and batteries and pump storage, Brazo. Where does that factor? What kind of dollars? Are they bite sized amounts? Are they massive amounts, which are pipe dreams at some future date? Yes. So, if you look at Brazo, I mean, we still have that project. We still have it on our shelf as something that could be developed in somewhere around the mid-twenty 25, 30. There's a discussion of a 3rd combined cycle. And I think the reason people are I mean, they're looking at these rebar combined cycles. They're fantastic investments. But we also have a carbon policy regime here in Canada. It's sitting at $30 It can go to $50 There are people who talk about it even going higher than that in the post-two thousand and 30 period. I can tell you no amount of Tesla batteries will power Alberta. Not going to happen. I've been making it sort of one of the things that I do at the company to go and visit these guys that are building these flow batteries. There's some really, really interesting flow battery guys out there. They're way more advanced than I expected them to be. But I shouldn't have thought that way because when I think about how quickly solar has advanced and I'm not surprised by the way in which people are starting to advance these flow batteries. Again, Alberta is not going to run on a warehouse full of flow batteries that are the size of refrigerators that are all tied together. It's just with 4 hours of storage. And I think the way to think about that is when you have an 82% system load factor, 18 percent of the time, the system itself doesn't need somebody to be running, but the 50% of the loads need you to run 100% of the time. So, if you decide to run 12 hours on solar and 12 hours on flow batteries, the capital requirement for that solar and flow batteries is too much, right? So, you have to have something. And that's where something like Brazo comes in. So I think what the team can develop Brazo as 300 megawatt units, rather than 1900. So we have work to do to sort of continue to look at that. I think it is the competitor to the potential 3rd combined cycle in Alberta in the mid-twenty 25. And us figuring out how to do that in a bite size is important. We can't do the big project. It's too much capital. You can't put $3,000,000,000 in a merchant market. But is there a way to look at doing one of those units 1 at a time and seeing how they would fit because again, they're 100 year units, right? They're not 30 year. They're not affected by carbon tax. So it's still on our radar, but it's definitely not part of the plan in the next 5 years. So we're allocating we've given you a very clear picture in the next 5 years and all the questions are about the 5 years after that. But we need to get these 5 years in. So, sorry, the other question was? So, just really as a follow-up, if you could just compare for a second the cost on a pump storage versus a flow since you touched on it. Is flow something that you really can look at yet or is it still too confusing? Yes. I was no, it's not. I was surprised actually. And we've got a young smarty pants guy that probably will be a future CEO sometime in his life working on batteries. And I was very, very surprised. I think they're starting to come into that $2,000 kilowatt range. They're competitive and it's exactly the same formula as the solar guys did. You invent the technology and then you get the guys in who can take the engineering and the procurement costs down. And then you've got to just keep getting money from places and there's a lot of money for this. There's tons of money for these kinds of investments. So we have we've looked at one company extensively. We're going to look at 3 or 4 more. And I expect to be surprised. I think it is a market that's emerging. Rupert Merer from National Bank of Baudetroen, Ontario. R and W focus question here. John, you mentioned you're looking to recontract the Sarnia Gas Plant, the contracts expiring starting the next couple of years, I believe. Can you give us your view on the Ontario market and the opportunity to re contract Sarnia but also opportunity to maintain the cash flows where they have been over the last few years? No, I'll take your question. And actually, I'm glad you kind of asked the question the way you did, because that's actually the way we tend to look at it is we tend to kind of look at it from the perspective of what are the cash flows in the facility and what do we need to do to layer on various levels of There it's an It's an interesting market from our perspective because you've got a whole bunch of stuff that's contracted. You've got a relatively small piece that might become a capacity market. And then you've got basically the nukes and a bit of hydro, which are quasi government owned. So it's the place that an ICP like us can play is a more compressed, if I can put it that way, place. But when it comes to Sarnia, in particular, we do we've already initiated discussions about what it is that we can do to actually kick out the time period for the contracts. I think when it comes to the customers that we have in the region that we're currently supplying, whether it's power or heat or steam to, it's a very competitive facility. I think it would be they would be hard for us to find a better alternative than us providing and meeting their needs on a go forward basis. We've initiated discussions with the government and the ISO about what we can do from a contract perspective. We're assessing what the capacity market, if it came to that, would be able to provide us. But we're also spending a lot of time and frankly, the team is spending as much time on this, is trying to actually get contracts. We are looking at the capacity we've got there. We've got quite a bit of land that's there. We're developing the Bluewater Energy Park. So it's everything from chemical processing plants to actually Bitcoin type companies that have high power needs that we're actively trying to create sort of additional cash flow streams for the facility. So we're working hard to keep it flat, frankly, as we look at the 2020 or do better than that as we look at the 2022 to 2025 time period. And we've been at it for probably a couple of years already in terms of trying to move that forward. The greatest thing about Sarnia is it's in a nice sort of a nice location. It's needed in that part of the grid and the customers rely on it for steam. And I don't think there's a need to build a couple more cogeneration projects there because you can't get a long term contract for Sarnia. So I think it's got all the right attributes that you need for recontracting. But these things take a long time. You got a there's a lot of customers to work with and the ISO here in Ontario. So it'll muck along for a while and maybe we can advance it, but it could take right until the end of 2025 to get it done. And we've and recently, I mean, the changes here have occurred. I think our customers are not getting the global adjustment charge effectively. Leviticaine for now is one of the things we've been able to achieve there. So there it's a pretty competitive power solution for them regional in terms of where we are. In Ontario, we have seen some gas plants get mothballed at the end of the contract, but that's not in the scenarios that you're looking at. You don't think the worst case could be that bad? We're not I mean, our Mississauga plant was shut down. And to Don's point, it was located in an area where candidly the power wasn't required there once its contractual life was over. But when we look at Sarnia, we think of just that industrial base in the valley there effectively and we think that it's got good potential to continue to operate. Yes. I think gas plants that are just supplying power to the grid, most of them don't run that much. That's not helpful, but starting as a big thermal producer, so it's a true cogeneration. It supplies steam to the customers. So it's a huge sustainability part of the Ontario grid and it does help in that part of the grid. So it's got a different set of attributes. So we have time for maybe one last question. Is there anyone that hasn't had an opportunity to ask a question that would like to ask one? If not, we'll turn it over someone that already has. No? Okay. Here you go, Robert. Sure. Rob Hope, Scotia. Getting a little bit of granular and I guess maybe front running your 2020 or 2020 guidance for 3rd, you would assume we'll expect in December. Just want to clarify the comments you're making on the increase in maintenance over the next couple of years, just given the outages that you're seeing there. Is that relative to the future run rate? Or is that relative to what we're seeing in 20 19? And then all else being equal, let's assume power prices are relatively similar kind of where you see cash flows shaking out in 2020? Okay. So we're not going to do 2020 guidance today. And I think that really if you think about we're doing a coal to gas outage. So we've given you $30,000,000 to $50,000,000 as the cost of what you need to do to do one of those outages. So you've got that to think about. And at the end of the day, we'll give you the guidance in December or January. But a great question to end on. I was surprised you didn't start there actually. So with that, listen everybody, we really appreciate you taking your morning with us. I think we've given you lots of data and lots of granularity in terms of how we're thinking about our plan. I think it's comprehensive. We really would love to have time to discuss this with you over lunch. So if you could stay and have a sandwich with us or whatever it is we're providing, we'd love to do that. And yes, I don't know if you're getting it's what you're getting. And thank you very much.

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