All right. 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 Chiara 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 a 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 two exits to this room, one 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. The 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&A report. Without further delay, I would like to 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, Chiara. Thanks, Chiara , welcome everyone, thanks for all of you for coming out today. I am going to start with some introductions of the team, 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. For those of you that do, just bear with me. It won't take that long. I'll get into the meat of what we're here to talk about today, which is our strategy. Today, of course, we have John Kousinioris 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, 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 the 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 follow pipeline of unique investment opportunities. He's joined by Wayne Collins. Wayne is our Executive Vice President of Generation. 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 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. Aron 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. He's back now in Canada, and he's focused on working with Brett to prospect, develop, buy, build, and contract new generation plants here in Canada, in the U.S., 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. He'll also update you on the construction projects that we currently have underway. 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 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 Aron, and we'll have a Q&A at the end of the session. Let's get started. I want to start with why invest in TransAlta. 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 December of 2017. 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. 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. 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. 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. 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.
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 sustainable future. Our mission is to provide safe, low cost, reliable, and clean energy. 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. Today we own and operate 71 facilities across three countries and five fuel technologies.
Our marketing and trading group optimizes cash flows in markets where we have merchant supply. 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. 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. Today, we'll be presenting our company in a very simple way so you can see where we are driving value.
We operate one 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. By focusing on 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. 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, we know that we always have questions from investors about the relationship between TransAlta and TransAlta Renewables. If there are benefits to having the two companies under a single operating model. 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. 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 CAD 367 million in 2018. This was before the additional CAD 157 million of PPA termination proceeds that we received from the Balancing Pool. We also received an additional CAD 58 million in funds in August 2019 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 CAD 70 million 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 are going to show you how we have adapted our plan to take advantage of the decision to continue with an energy-only market in Alberta.
We also acquired 100% of Keephills 3 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. In terms of our renewables growth strategy, we have secured three 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 first new small on-site cogeneration project.
Aron will show you how we're developing that business. On the capital front, we've reduced the TransAlta corporate debt by CAD 323 million. We've improved our credit position and our balance sheet significantly. In addition, we secured CAD 750 million 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 CAD 250 million of shares, accelerate our coal-to-gas transition, and achieve CAD 1.2 billion in senior bonds by the end of 2020. These are all extremely important pieces of our execution plan. 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. 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 talent 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 Aron 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 3x 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 exciting space.
There's quite a furor these days over ESG metrics as investors really try to get under all the disclosures that are necessary to understand the true value and risks of cash flows in companies. 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 first 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, we've always been there, and we've always had an offering to our customers.
TransAlta has reported its sustainability measures since the early 1990s. Four 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 & Young. There's an array of measurements we track in our report. Not only do we track greenhouse gases and air emissions, 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. We pride ourselves in our progressive plans and the results on all these fronts. We do know from talking to investors that making progress on all of our goals is important.
We also test our practices externally and our 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. I can say that getting a B score with CDP 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 three 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 flow per share. Those of you who know us know that to be the case. 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 three years, and the market has rewarded us for that growth, as shown in the chart on the left. Okay. That's it for the overview. Why are we here? For all of you who are going, "Please stop." 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 plants 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. Our priorities are simple.
Our first priority is to invest between CAD 600 million- CAD 1.2 billion in our Alberta thermal fleet to set it up for the future. The second is to complete over CAD 800 million of construction projects that we have underway today, on time and on budget. Our third is to grow our onsite and cogeneration business. Fourth, we have a team focused on building a pipeline of renewables and cogeneration projects in the U.S., projects that will grow RNW, utilize this debt capacity, and deliver further dividends back to TransAlta shareholders. 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 3x 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 CAD 1.4 billion- CAD 2 billion over the next five 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 CAD 800 million 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.
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.
The plan continues to allow us to invest in ourselves by using up to CAD 250 million in share repurchase over the next three years. He'll also show you how cash at RNW is being used to increase returns for TransAlta shareholders. Today, the dividend from RNW 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. 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 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 life of those assets. Our Alberta portfolio is diverse, which helps us stabilize cash flows from our Alberta business. Finally, although the PPAs created more stable cash flows, they were set in 2000 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. 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 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. Why is that? It's because we have a very competitive Alberta business, and we've developed a fantastic reinvestment strategy in Alberta that will continue to create cash for a long time forward. 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 renewables 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 three years, we are going to continue to return capital to shareholders through the share buyback of up to CAD 250 million. 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. 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. With that, I think, just 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 out investments that are profitable for you. We believe we set the trends, and we definitely do not follow them. We figured out how to beat the disadvantages of hierarchy by networking the organization around the projects that will matter most to adding value to your holdings. With that, I'm going to turn the podium over to John to talk about the Alberta market.
Thank you, Dawn, and good morning, everyone. My name is John Kousinioris, 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 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 new build. 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. 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 zero-cost wind and hydro, which, as Dawn showed you in one of her 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 CAD 30 per CO2 ton 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 CAD 57 per megawatt hour range over the past 18 years. That would be a little bit higher, probably closer to the CAD 60 range, if you take away 2016 and 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 CAD 57 per megawatt hour, and the balance of the forward price is just a bit over CAD 60 a megawatt hour. You can also see that the forward curves for 2020 and 2021 are suggesting prices in the CAD 56-CAD 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 CAD 60-CAD 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 2009, and which is being forecasted to grow by up to 1,700 MW 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 first quarter 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 repowering strategy. 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. On that last point, we remain driven by our desire to reduce our per megawatt hour cost of generation.
The two 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. 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. 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.
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 two gas-repowered units, we expect our weighted average marginal cost per megawatt hour to fall by about 35%, pretty dramatically, to approximately CAD 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 province's load being met with a required level of reliability.
Using the Alberta Electric System Operator's 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 two years. If you remove the dark green, and I think on one of the slides it 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 wind in the intertie supply, and expected daily peak demand over the course of the next few years. 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 Keephills 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, seven days a week, 365 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, 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, we supply almost 50% of this important segment through our hydro fleet, we do it in a manner that permits us to conserve and manage our water position throughout the year. 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'd like to have 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. 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. 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 for 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 four major elements. The first is simplification. By simplification, we mean leadership consolidation, a focus on reduced OM&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. 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. 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. Third, we're also focused on the full implementation of our shared services model, which really isn't something we've spent 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 single leadership and one that is coordinated with our generating fleet. The kinds of services that we're focusing on are things like IT, supply chain, op services such as compliance and engineering, and a number of the HR functions that we have.
As I mentioned, it'll be all one leadership team, no duplication, and it'll be oriented towards just providing those services that the generating fleet requires. 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. The two 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.
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 first-hand 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. I'll give you some examples of that as I talk specifically about our various operations. 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.
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. It's in the process of seeing pretty significant growth with four 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.
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. I'd like to just give you a sense on just a couple of the initiatives they're 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 has 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.
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, and 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 and beyond. Again, I just want to give you a Project Greenlight example on our hydro fleet. Over the course of the last year or so, the team has been 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 flows and more precisely measure our reservoir levels, which we think conservatively has resulted in our cash flow improving by CAD 3 million-CAD 4 million this year alone.
That was a tremendous piece of work that 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. Taking 2018 as an example, while the average price in the market was in that CAD 50 per megawatt hour range, we were able to secure an average price of CAD 59 per megawatt hour for our wind fleet from the energy that we generated there.
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. 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. 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 Balancing 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. 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. 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 three 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 two payments.
The first one is an annual energy payment that we give them, which is based on a notional quantity, a prescribed notional quantity of annual energy generation. 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. Turning to the bridge on the chart, which summarizes 2018 actual monetary flows for the hydro fleet. You'll see that we earned about CAD 90 million from energy sales, a further CAD 104 million from ancillary services sales in the year, and we were paid CAD 56 million from the Balancing Pool in terms of the PPA through the capacity payment that they provide. That payment will disappear at the end of the PPA.
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 earns another CAD 41 million on its hydro fleet from the non-PPA hydro assets that we have, our transmission, which is part of the segment in the way that we report it, and also from other hydro services that we provide, like water management services and black start capabilities. That's a pretty stable cash flow year-over-year. The cost of our hydro operations in 2018 was CAD 47 million. When you deduct it from the revenue streams that are outlined on the chart that I just went through, would give you pro forma EBITDA for the hydro businesses roughly in that CAD 240 million-CAD 244 million range.
We believe is within the range of what we would normally expect the business to provide following the expiry of the PPA. 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 CAD 135 million in the form of that annual energy and ancillary services payment that I was talking about earlier. 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. That would have led to the reported number, which was CAD 109 million in the year. That payment, that CAD 135 million 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 CAD 50-CAD 70. At these prices, we expect our hydro business to generate an EBITDA in the range of CAD 200 million-CAD 250 million, which roughly translate to an EBITDA lift of about CAD 18 million-CAD 20 million for every CAD 5 per MWh increase in the price, is roughly what it translates to. Turning to our wind and solar fleet, we have over 1,300 MW of capacity. Actually, in 21 facilities, the additional facilities actually are solar in Massachusetts. Our wind is located in Alberta, Ontario, Quebec, New Brunswick, Wyoming, and Minnesota.
We're currently developing four projects, again, in a diverse set of locations, which will increase the size of the fleet by almost 400 MW. 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 CAD 250 million a year. We're the largest wind generator in Canada and have one of the largest platforms in N.A. We have extensive in-house experience in wind farm development, which Aron is going to be speaking to you about a bit later. 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. Our wind fleet too, is really focused on Greenlight initiative and examples. 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. We think that that's going to result in about CAD 1 million-CAD 1.5 million 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. We think that the work that we've done there and the analysis that they've helped us with is going to increase the output of our wind farms from between 1% to 1.5%. We're really excited about the collaboration that we've been doing with them.
Turning to our natural gas fleet, we've got about 1,300 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 seven years. It 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 Aron 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. We're excited about that.
Our gas team also spends a lot of time working on Project Greenlight initiatives. 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 Hedland plant into that and expect that the reductions in labor costs by doing that are going to be roughly in that CAD 1 million-CAD 1.5 million a year. 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, how fast the generator effectively is running, 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. That's a significant initiative that will see us saving about three, maybe a little bit more, CAD 3 million a year in that facility. Another great example of the way our employees, through our Project Greenlight, are thinking about helping our business. I 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 recontracting, as I was just talking about Sarnia, that 500-megawatt Sarnia Regional Cogen Plant, which has contract expiries coming up in the 2022 to 2025 period 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 contracted cash flows of that facility.
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. Upon the expiry of the PPAs at the end of 2020, the thermal PPAs at the end of 2020, the majority of the EBITDA will still remain tied to contracted assets. 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. Generally, it fulfills four 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. 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 Aron and Brett's growth teams. The third element is asset optimization and the hedging of our entire fleet, the merchant component of our business. Finally, we have a pretty robust C&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 five years in length. We tend to think of that as another way to Well, really two things. Another way to actually hedge our merchant exposure in the province. 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. Good morning, ladies and gentlemen. My name is Wayne Collins, and I'm Executive Vice President of Generation here at TransAlta. We've been talking about our plans to convert our coal-fired units to gas for a number of years now. I'm really pleased to be standing here today to tell you that this process is well and truly underway. 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 co-firing. There are significant benefits from converting our plants to 100% natural gas co-firing. Based on our co-firing experience, we're already seeing those benefits through lower combined fuel and GHG compliance costs and lower OM&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. 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 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 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 will be very competitive under the anticipated future market conditions. Turning now to our specific gas conversion plans. The base plan involves three boiler conversions in the period 2020- 2021. In that period, we will convert Sundance 6, Keephills 2, and Keephills 3, and two repowered combined cycle conversions, which will be Sundance 5 and Keephills 1, and they'll be straddled approximately a year apart. Keephills 1 and Sundance 5, the two 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 3 and 4 will be evaluated over the next year to 18 months. As we're obligated to do, we'll continue to look at those plants in light of the long-term market fundamentals. The plan that we're presenting here today assumes also that there are no delays in getting 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. The plant outage that is required to do this and implement this conversion is relatively quick. It's approximately six weeks in duration.
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. Whole areas of plant, like precipitators and bag filters, are no longer required. Moving on to the repowered combined cycle plant. 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 with the condensing and feeding equipment. The existing steam turbine and generator and the existing grid connection will be used to transmit that power to the network. The repowered combined cycle plant uses a mix 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%-50% lower than that of a new greenfield combined cycle gas turbine. Now, these repowered combined cycle plants are not a novel concept. They're something that's quite well proven.
We're aware of at least eight of these that have been completed in the U.S. 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 Xcel Energy site, which is located in Minneapolis. This plant had a repowered combined cycle conversion completed in 2009. It's been running for the last 10 years very reliably at high capacity factors. The timeline for this conversion, it's our intention to seek the regulatory approvals for the repowered combined cycle plants, the two 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 Keephills Unit 1 once the Sun 5 is completed. The commercial operation date for Sun 5 repowering is the end of 2023, and for Keephills 1, it's the end of 2024. 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 turnaround work scope and the gas conversion work in parallel.
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 they're being converted to gas, so between 2020- 2024. The total capital expenditure expected for the two repowered combined cycle conversion plan is our base case, and that's approximately CAD 1.5 billion. That includes the boiler gas conversion capital, the sustaining capital 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 higher cost compared to the boiler gas conversions. However, the repowered plants have 40%- 50% lower capital cost, and they're very competitive with the 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 gonna walk through some of that now. 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 four months ahead of schedule, and we have been taking gas from that pipeline since then. We have an EPC contractor selected for the Sundance and Keephills boiler gas conversions. We've issued the full notice to proceed for the boiler conversion at Sundance 6, and we've issued a limited notice to proceed for Keephills Unit 2 boiler gas conversion. Keephills 3 is slightly different technically in the boiler. We've been out to the market with a separate request for proposal for the boiler gas conversion on K3.
We're currently evaluating that, 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 Sundance 5 and Keephills Unit 1. We've also entered into a carbon cost benefit sharing agreement with the Balancing Pool in Alberta for Keephills 1 and 2, and that will actually allow us to co-fire fairly heavily on those two units and share the benefits between now and when the PPA is finished 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. You can see that overall, we are well into implementation here.
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. Natural gas is in abundant supply and very competitively priced. 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 SOx and NOx emissions reductions, which would be required if these plants stayed on coal. Boiler gas conversions are very low capital and we're very quick to do those conversions in the order of six-week outage to do that.
The repowered combined cycle plants are 40%-50% lower capital costs than greenfield combined cycle plants. On the next few slides, we'll take you through some more detail on some of these benefits. Let's now look at the life extension that this plan delivers. 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. 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 repowered combined cycle conversions extend those plant lives into the late 2040s. Further, it's also possible that we could undertake repowered combined cycle gas conversions on previously boiler converted units.
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. 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&A costs in 2018 and also in 2019. Really, in terms of our workforce transition, we are really on the journey to being fully converted to gas. Our workforce transition is probably more than 50% completed already. This next slide shows you the substantial change in sustaining capital spend that we expect once all of the plants are converted to gas. The light blue section of this slide, of the first bar on this chart, is showing you what our average mining capital cost run rate, sustaining capital run rate on the mine has been. It's in that CAD 30 million-CAD 40 million per annum. Post-gas conversion, the mine moves into a reclamation mode and this capital spend is largely eliminated.
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 of all of those elements that are no longer operating is eliminated as well. Finally, the gas combustion is much kinder to our plants. It results in a lot less tube wastage and erosion in our boilers. There will be less tube repair and shielding and those sorts of capital costs associated with those plants. All up, you can see from this slide, we expect to see a fairly substantial 40%- 50% run rate reduction. There'll be years where it'll go up and down a little bit post-conversion.
In summary, the plan we've laid out today and confirmed today will see us complete a minimum of three boiler gas conversions by the end of 2021 and two repowered 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 Gellner, 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. 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. What this will show is that the fleet will be very well positioned for an energy-only market going forward. 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. I'll conclude my section with an update on our natural gas strategy. As Dawn 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.
Todd's 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 one of the units into combined cycle and the rest through the boiler conversions. Now, with the retention of the energy-only market, we've pivoted those plans to look at repowering two units into combined cycle as they will have very low operating costs in that market. 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. 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.
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 conversions are also very competitive, especially when gas is at CAD 2.50 a GJ or lower. As John showed earlier, the forward curve going out to 2020 currently is actually below CAD 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.
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 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. 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. 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. Let me now take you through the emission savings.
What this shows is the emission savings being 100% on coal units and then a boiler converted unit. The top chart shows the savings on a per megawatt hour basis. The total reduction is in around CAD 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 converts these savings per megawatt hour into total annual savings. As you can see, it ranges from CAD 25 million to CAD 50 million per year for a 400-megawatt unit. That depends on the capacity factors that the unit runs at.
Given a capital cost to convert a unit in around the CAD 30 million-CAD 35 million, 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 CAD 40 million of capital we would have to spend per unit to meet the NOx and SOx if we stayed on coal, nor does it factor in the lower future OM&A sustaining and mining costs that Wayne just walked you through. What I'm going to do now is take you through the investment metrics of the repowered combined cycle units.
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- 7.3x . Very attractive and well below what a new greenfield project would deliver because of the higher cost to build the greenfield. You can see as a result, the repowered units will generate very solid returns and cash flows even under low energy prices. 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 one repowered combined cycle, and the chart on the right has two repowered combined cycles.
You can see the EBITDAs are very strong under all the energy prices shown here. Under our 2 repowering, it's significantly higher than a one repowering, clearly because of the lower cost structure. Just to give you a sense, roughly every CAD 5 change in energy price equates to about a CAD 75 million- CAD 85 million change in EBITDA. 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 CAD 60 for this year. If you pick the CAD 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 EBITDAs 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 cost going forward will be quite a bit lower with the converted fleet than it will be with a coal fleet. Now what I want to do is turn to our gas supply. As you know, we invested 50% in Pioneer Pipeline. As both Dawn and Wayne mentioned, this came on four 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. Therefore, at that time, we'll start significantly increasing the amount of co-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 350-400 terajoules a day. There'll be certain hours and days where it's higher than this or lower than this, but on average, this is roughly what we expect.
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 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. We'll keep you posted on these developments once they're finalized. As you can see, our strategy to convert to gas is full steam ahead. As Wayne pointed out, the strategy involves converting two of the units to combined cycle. We are timing these about a year apart, and really, this 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 two units.
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. With that, I think we are going to take a break, and then afterwards, Aron's going to kick us off with going through our growth strategy for onsite generation and renewable energy. 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. Aron 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. 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 the 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. I want to start with where we're placing our focus, and it's really two areas or two key segments of the market. First, the on-site and cogeneration business.
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. In fact, many of those plants and relationships that we developed in the '90s 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 renewable side, we continue to see the corporate PPA market setting records year-over-year with very few signs of slowing down. Importantly, this market's 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. 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. 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. 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 onsite and cogeneration market.
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 five 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. 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 one 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 one 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've 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 three decades of growth. The skill set's 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. First, 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. 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 life cycle here, from site prospecting and wind resource assessment through permitting, construction, and operations. We maintain about 1/2 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 Gaspé Peninsula in Quebec, and next year, we'll start construction at Windrise, utilizing the very latest technology and 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. 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.
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. We also see some very interesting processes to procure what we refer to as hyper 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. 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 U.S. 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. 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's diversifying significantly. 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 2019, which puts this year again on pace ahead of the 13.4 gigawatts of contracts signed for the full year in 2018.
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. It's quite likely that we'll see a peak of activity and then a bit of a lower run rate going forward. 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 develop some great projects for the TransAlta fleet. 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. I'm under no illusions about the level of competition. There are many others out there who are focused on these markets and who would like to take their fair share of their market here as well. I'm confident that we'll succeed, particularly given that we've already had some great wins. I want to show you a few of those now.
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 CAD 750 million and CAD 800 million of growth investment. Soon I plan to have a cogeneration project added to this list. The list totals roughly 400 megawatts of new wind capacity, as John mentioned earlier, this accounts for a 30% increase in the size of the operating wind fleet that we have today. I want to briefly look at the specifics of each one of these projects.
We have three wind projects under construction in the U.S. today, and two of them are nearing completion. The first is Big Level, a 90 MW 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. This project is being funded directly by TransAlta Renewables, as is the next project at Antrim. Antrim, again, is directly contracted. There's actually two off-takers here, Partners HealthCare and New Hampshire Electric. The project is mechanically complete, so all nine wind turbines are fully assembled and commissioning is well underway.
This 29 MW project will be online in Q4 of this year, which will mark the start of its 20-year offtake agreement. The third 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 where we'll soon have wind under construction is back at home in Alberta, where we have the Windrise and Wind Charger projects, with both having equipment orders placed and planned construction start dates next year. Wind Charger will be the first 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. Last but not least, Windrise, a large 207-megawatt project that we won through the Alberta government's Renewable Electricity 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. Not just any wind farm.
For us, Windrise will be the largest wind farm in our fleet. 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. 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. 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 CAD 50 million 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. I'm really looking forward to adding the first cogen project to this list. 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.
With that, I thank you for your time and attention this morning, and I'll turn the podium over to our CFO, Todd Stack.
Thanks, Aron. Good morning, everyone. Over the past several years, the company has made significant progress in improving its overall financial position, strengthen 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 four 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% of TransAlta Renewables. As a result, RNW'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 RNW 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.
The lower cost of capital at RNW improves our ability to compete for new renewables projects in Canada and the U.S., as Aron described earlier. We regularly get questions about the cash generated by the remaining portfolio of assets held at the TransAlta Corp 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 CAD 770 million of consolidated funds from operations number, which is reported in our 2018 year-end MD&A, we first deduct distributions paid to our 50% partner at TransAlta Cogen.
To deconsolidate RNW, we deduct 100% of the FFO reported by TransAlta Renewables, which for 2018 was CAD 381 million. Remember that RNW's FFO is used to fund their sustaining capital, make payments on their amortizing debt, and pay dividends to their shareholders, who include both the public shareholders and TransAlta. To include our share of the cash from RNW, we add back the CAD 151 million of dividends paid to us. The resulting value of CAD 454 million 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 two of the presentation. 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. With these uses, we've 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%-15% of deconsolidated FFO for dividends to common shareholders. While setting the dividend is the responsibility of the board, we expect that they will be addressing the dividend amount early in 2020. We're currently paying out about 10%-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 be very lumpy, depending on the timing of major outages. Because of that, we focus on our average expected spend over the long term. The % allocation shown here represents a long-term average, and individual years may fall outside the range. In 2020 and 2021, we'll be taking major outages on at least three 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 to lower CapEx will allow more capital to be directed to other priorities, including dividends.
The largest portion of our allocation represents the cash that's left after funding CapEx, addressing debt amortization of 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 four 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 CAD 250 million of shares over the next three 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 five years in repositioning the balance sheet. We expect to achieve our goal of reducing our senior bonds to the CAD 1.2 billion level by the end of 2020. Cash on hand, free cash flow, and other sources of liquidity are sufficient to repay our CAD 400 million 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 forma 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 3x is appropriate. One item to point out on this slide is the inclusion of the Brookfield investment in the buildup. Under accounting rules, the Brookfield investment will be considered as debt 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 3x . Let me turn now to our funding plans.
As mentioned earlier, our base plan includes boiler conversions of three units in 2020 and 2021, and the repowering of two units as combined cycle plants scheduled to be in service in 2023 and 2024. If I continue to look at TAC on a deconsolidated basis, roughly 65% of our plan over the next four years is funded by internally generated cash flows, our dividends from RNW, and cash on hand. The second tranche of Brookfield investment is expected in 2020 and will provide an additional CAD 400 million 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 to access the debt markets in order to refinance our 2022 bond.
This refinancing will keep our senior bonds at or below the CAD 1.2 billion 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 Skookumchuck projects. These wind projects have long-term contracts and are ideally suited for dropping down into TransAlta Renewables at some point in the future. Let me turn now to our funding plan for TransAlta Renewables. Funding in RNW 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 RNW and draws on RNW's credit facility.
We expect to close a tax equity financing by the end of the year to repay the credit facility borrowings. Looking forward, I mentioned that the Windrise and Skookumchuck projects are good fits for dropping into the RNW 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 RNW DRIP program. RNW has significant balance sheet capacity to finance its current build program in addition to these potential drop-downs. RNW has access to additional sources of capital to fund incremental growth projects, including the potential to raise between CAD 4 million and CAD 600 million 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 CAD two and a half billion. 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 3x .
From our view, it's clear that the market is not recognizing the full value of the conversion plan. The incremental value could add CAD 4- CAD 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. I know that everyone's chomping at the bit to get their questions out, I'm just going to quickly summarize what we want you to take away. 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 CAD 2 billion 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 a 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 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 one company with one team. You now have the information to see how the dividends from RNW benefit you as a TransAlta shareholder.
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&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&A session, and I'll direct you 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&A session here today. Who would like to be first?
Andrew Kuske , Credit Suisse. I think one of the comments that was made earlier was your business plan is really dependent on pricing in the marketplace, and you've laid out a pretty compelling cost reduction story for yourselves. 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? Yeah. Can you hear? Okay. In terms of increasing prices in the marketplace, 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 five 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 of 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. We've had a couple of units actually leave. Our Sundance 1 and 2 unit are gone.
I think we're looking at potentially Battle River 3 also leaving the market. That's another 750 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 prices spike up. 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. 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 peakers being introduced into the market in the future, just given the volatility and energy-only nature?
We may do. Right now, we don't see a significant kind of movement that way. It is possible given how some of the reductions in the cost of getting peakers and the technologies have come down. It is a possibility.
Yeah. Let me just add something on that. I think if you look at the simple boiler conversions, those are peakers. They're CAD 30 million-CAD 50 million to make a peaker compared to CAD a couple of hundred million to make a brand-new peaker. 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 Dumoulin-Smith, 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 the pluses and minuses, load growth, retirements of coal, potentially elsewhere? Also on the other side of the ledger, if you will, how do you think about your peers? You just presented, for instance, some pretty attractive multiples of your own conversions and even greenfield combined cycles, the multiples of EBITDA at, I think, roughly current power prices. Perhaps a little bit more of a deeper dive on the ledger. 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 one 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. Brett, I'll get you to take the first question and John the second, and then I'll do cleanup.
Sorry.
Yeah. Pluses or minuses, sorry. Certainly, the Suncor announced a cogen, which is planning to come in, they say, in 2023. 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. 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, coal units, smaller coal units, we'll see. They're not ours, may have to come out of the market soon, and what they do with those. There's a few pluses and minuses that we see when we run our models that balance out.
With the positive economics that we showed you, even if our generation is slightly lower, we're getting much higher margins out of it. You actually see that when you compare our 2018- 2019. All the work Wayne's been doing, and this is just on co-firing. We see our margins improving over time. Longer term, as our chart shows, eventually, and maybe this wasn't clear, the boiler conversions have a hard date to them. They can only run a certain amount of years post their coal life, and it depends on their emissions test. Eventually, long term, those units have to come out, whether they're ours or somebody else's. 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 probably that CAD 55-CAD 65 per megawatt-hour price over time to get a good return on and out of your capital and pay for your costs.
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 four things that they're looking at doing. Net net, we candidly don't think it's going to change our investment thesis in terms of what it is that we're doing. 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's been tasked with looking at the 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, I think, in February of 2020 with landing any of the changes that we have to those rules in the summertime next year, July of 2020. That is an ongoing piece of work. 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, the ISO's 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 market should be treated in an equivalent way. Frankly, the focus should be more on time periods when there isn't tightness 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. 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. 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 AESO, 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 change in dynamics or the approach that those agencies are going to be taking in overseeing the market.
Okay.
If I could clarify just quickly on that.
Yeah.
Net-net, it doesn't sound like barring, obviously, resolution on some of the carbon details, material changes with respect to markets, obviously logistical and organizational changes.
Yeah. I think that's fair. In fact, if you were to look at the key piece of legislation or regulation that kind of governs behavior, it's literally a 10-page document. It is, as I mentioned, a relatively pure market and regulatory light. We expect that to continue.
Great. Next question? Oh, go that way.
Sorry. Robert Hope, Scotiabank. Actually, maybe just to follow up on terms of the carbon. It seems that the plan's based on CAD 30 carbon. Do you see that progressing up to CAD 50? Is that included in the plan? Can you just talk about some of the flexibility in your coal-to-gas conversion plan, depending on where carbon goes?
Go ahead.
Sure.
I would get on a soapbox and talk for an hour, so you can just answer.
Look, it's a great question. We model it out when we look at our investments in a variety of ways. I think our base case is basically a CAD 30 case. Our sense of it is 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 that 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. 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. Hopefully, that gives you a bit of a sense.
Yeah. I would just be crystal clear. The current federal government has definitive rules that require the provinces to ramp up to the CAD 50 to be equivalent. If you don't do that, they'll put a backstop in place, and they did do that in Ontario. Depending on what happens in the election, if it is-
The courts are holding them up. Sorry.
Yeah. 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 CAD 30 framework for some reason, Alberta has to work proactively with the Federal Government to get that deal. We model CAD 30, but we don't model down from there.
Yeah.
We don't see a case where it's less than CAD 30, and we will model the CAD 40, CAD 50 to test our assumptions. We model an upward increase in carbon tax rather than downward.
In terms of our plans, you can imagine if it goes to CAD 30, the gap between coal and even the boiler conversions even gets wider, and then even the combined cycle. Our plans actually fit nicely as prices go up. 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. 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. You had that slide highlighting inexpensive valuation, just breaking up the net asset value. On the hydros side, I'm curious, the CAD 2.5 billion, how are you getting that? Because it seems quite conservative when you use multiples that Brookfield's paying for that asset. Another thing is, I think you mentioned a few years ago around issues around dropping down an asset to renewables. Is that still the case throughout, the drop-down potential for the hydro asset?
Yeah. Let me start on the valuation side. The valuation is relatively straightforward. It is looking at, similar to John spoke in his slide, about CAD 200 million-plus of EBITDA long term once the PPA expires. We're using generally the multiple that we negotiated with Brookfield of the 13x on the valuation. That kind of sets up that CAD 2 billion-CAD 2.5 billion range. As far as drop-downs, so at this point, we're not really thinking about the hydro assets as a potential drop-down 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.
Go ahead.
Thanks. Lee Matheson, UFCW. Further to Ben's question, now that you have Brookfield as a financial partner, have you contemplated using a 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 with Great Lakes Hydro going back, I guess, 15 years? In essence, if the market's never going to give you credit for what it is, can you not manufacture that financially?
Go ahead, Brett. You want to take that?
Yeah. We've always thought about the hydro assets even before the Brookfield deal and whether there's an opportunity there. 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. At this stage, I would say, no, we're not considering this. Who knows over time? Certainly, we're less about are we getting credit for their hydro. I think our view is we're probably not getting credit for the thermal. Is our general view. Now, as we've laid this plan out and that we've liked the extent of 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.
No, the short answer is no, we're not evaluating that right now, and we're more focused on other contracted assets that could go into RNW.
Just to follow up on, in terms of some of the TA Cogen assets, there's been a change of control at Sheerness with ECP. Can you just walk through what your thoughts are on those assets? They seem sort of like, I don't think they really got a slide in the 85-page deck. What can we imply from that?
I mean.
Go ahead.
Yeah. It's an important asset in the TA Cogen part. We have effectively net to our company a 25% interest in Sheerness. They are moving forward to convert that plant. I don't actually think the transaction's 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'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.
Yeah, I think they're currently going to do a dual fuel.
Yeah.
They'll be able to run on coal and gas.
Coal and gas.
We expect them, as they move through the mid-2025, 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. Who do we
Hey, Dawn. Over here.
Yeah.
Robert Quanner, VC. Okay. If I can just ask about capital allocation, first on the dividend, just wondering what the thought process was around a payout ratio policy around FFO versus free cash flow. Then as you're in this capital build, do you cheat to the lower end until you're exiting the coal conversions?
Yeah. 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." We spent a lot of time looking at free cash flow, looking at ways that other people do their dividends. When it all settled down, it was clear to us that investors are having trouble seeing how the two companies fit together. They're having trouble seeing how the dividend from RNW is actually supporting the reinvestment in Alberta right now, and then that changes over time. It's really been hard to drive home the discussion around how the sustaining capital changes dramatically as you go to gas. 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. The company's had a run rate of capital for a long time based on capital in coal plants, which is significantly different than gas. 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. What Todd said is we're in that 10%-12% range now. I think we do fundamentally, as a team, believe that you have to tether your growth strategy to something. It can't be just, we just want to add more and more projects. What is going to frame and tether and pull all this together? There were two tether points.
One was the debt, and that's the 3x that Todd Stack 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. It just came back to the dividend. At this point, as we look at it, we like that range of 10%-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.
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 sharing some of that with the shareholders. Does that make sense? Really, it's the way we want you to start. That's how we're actually thinking about it behind the scenes. We wanted to make that very transparent.
Got it. I think just finish with a second part on capital allocation. You show the chart with your stock at 2.9x EBITDA. You're allocating the new growth circa 10-ish times EBITDA, at least with the renewables. With the gap that wide, what's the thought process of continuing to allocate capital to projects like that versus just giving that lift that you see just buying back stock?
I'll try this, and then Brett will make it right. No, I won't. Brett will make it right, and then I'll say, "Yeah, Brett made it right." Go ahead, Brett.
The way we look at it is, we're investing in those combined cycles at extremely good projects. The renewables, which is more the RNW type multiples, which is akin to what we're investing at. Again, remember, most of the contracted stuff is well-suited for RNW at some point, if it's not there already. We're investing that kind of capital in what we see as extremely good returning projects in Alberta because of the high returns we can get off those combined cycle or boiler conversions. I would look more at the 3x multiple against that. The renewables against more of the RNW side, because we stripped it out. At the same time, we still have the commitment to buy up to CAD 250 million of shares over the next three years, and that was part of the Brookfield transaction that we did.
It's a balanced capital allocation approach and investing also to extend those assets over the long term.
Got it. When you're doing the renewables, you're really thinking about it as developing and effectively warehousing it for RNW's purposes?
That's correct. We really need to break the back of that assessment. When we look at TransAlta as a whole, I thought we did a really great job of showing that deconsolidated slide there. What we see is, those 10x are really going into renewables, and there's cash building up in renewables that needs to be either reinvested or they need to increase their dividend. We make sure that we're getting valuable investments into renewables, which was what Aron's session was all about. We see the 10x renewable investments being in the renewables entity. We see the coal to gas and the hydro being 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. The TransAlta shareholders get two benefits. One 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 Sundance three and four, whether or not you guys would actually just maybe completely shut those down. Do you guys factor in insulated revenues coming into the repowering assets? What would tip you to go to three units repowering?
Yeah, as you know, there's 2 units mothballed today, and they're mothballed till November 21st, 2020. As we get through next year and into 2021, we'll look at just the market fundamentals, it's a matter of do we just bring them back as coal units and just co-fire them? 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. If that unit only runs 30%, it's burning 100% gas. We pull back on the coal. Those units could come into the market just simply as is, and we could co-fire them if we think the market needs them.
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. We'll get through as we start to 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. That's where we landed on being able to do the two 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 Keephills 3, for example, into combined cycle units, because now the boiler we don't need. If the steam turbine's 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. There's the opportunity later on to do more combined cycle repowerings. Right now, we're just balancing between the capital, the market dynamics, and that's why this plan, to us, made a lot of sense.
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. 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 mothballed become profitable, Wayne would have to bring them back into the marketplace. He has to attest that the amount of megawatt hours that he's fell out of the units times the price doesn't cover their avoidable costs.
As long as they're still in our fleet, if market conditions do change, they do have to come back into the system.
Then just on the revenue streams between market and ancillary revenues, just any assumptions around that for the conversions and beaver power?
You mean for the thermal side or the hydro?
Yeah. How much they have.
If you look, this is if you just go on the ISO website, you will see we sell ancillary off of the two Sundance units today. Generally, it is in around the 80 megawatts. It is not always 80 every day. We can probably anticipate that kind of level going forward. It will vary between zero and 160, if you will. They are available to participate. Our hydro is the main participant, as you know. The PPA units, that is not ours, it is still the Balancing Pool. If there anybody is going to bid ancillary, they get to, until we get off those PPAs in 2021.
To Julien, I guess.
Again, Julian Smith . Just wanted to follow up on a couple of the conversations that have 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. Thirdly, you have a run rate of cash flow from the renewables assets that you're investing in growth. I suppose, first off, how do you think about, just the step up even beyond that 2023? I know we're a little early, but I'm sort of curious.
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 this point of a third combined cycle, it would seem, at least on paper today, that the multiple is reasonably attractive. I don't want to put words in your mouth. How do you think about your disclosure, where I believe you are not assuming RNW drops, you have a placeholder for buybacks. How do you think about eventually making this decision about, to make the RNW drop and then subsequently these CapEx opportunities and just, even from a timeline perspective?
Yeah. Todd, do you want to take that?
Maybe I can just start with the leverage graph that you're talking about is on slide 87 that shows sort of where we're at today as 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. 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. It's not out as far as you are thinking. It's more near-term. Do you want to
Brett, go ahead.
Can you repeat all the graphs?
When do you make?
Julien, I think what you're asking is how would you think about doing a contracted cogeneration with a 20-year contract compared to a third combined cycle? I was to simplify.
Yeah. Just the timeline of that versus just simply announcing the drops to create the headroom in your capital plans.
Right. Brett.
Yeah. The drops, we've done a lot of drops, and it's a process. It's related parties, so we have to go through all that process. That's just a matter of timing. 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. There's no magic, if you will. 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, first of all, the payback is huge out of the gate with carbon savings. The outage time, as Wayne says, those units are only out six weeks, maybe eight weeks, for the actual work. The combined cycle is a full permitting process we got to go through. It's a longer timeframe.
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 as that as we can. 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 modify it as we go forward and like I say, do more combined cycles down the road when the opportunity is there. Does that kind of capture it?
Yeah.
From a balance sheet perspective, Todd can talk about this. He showed we only have CAD 1.2 billion 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. Balance sheet-wise, in very good shape from that perspective over the long term.
One 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 you as a company. How do you think about potentially looking at other markets beyond Canada, the U.S., what would it take for you to make that decision?
Well, I think that's hard to see you guys through these things. I would say that when we look at the U.S. market right now, there's quite a demand for what Aron talked about in terms of these corporate customers that are looking for some sort of product for their own ESG goals. That has changed significantly. There's a pretty big market there. It's surprising to me how underdeveloped the market is for the actual developers that provide those projects. It's still more of a cottage industry. Except for 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.
I think part of our work in the next year, which Aron's team is doing, is to really say, okay, how much can you get there, and are the returns too low? We've seen that the returns currently are definitely too low on solar. They're just not worth looking at. There are people who buy them. I don't understand it, but they do. Still in the wind space, if you look at our Skookumchuck project, and I was just there probably two weeks ago, climbing all over a mountain, looking at cranes and planes and automobiles to try to put all these things up. It's still a fairly complex build because you're putting up 90-meter towers, and it's a big operation to get that thing built. 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. Australians focus on Asia, Canada focuses on the United States. Of course, there's a lot of work going on in Asia with the Canadian government, with TPP, and things like that. We are seeing, for example, in parts of Asia, where coal plants are being canceled daily. Literally 20 coal plants have been canceled. I think it's in Indonesia. They just will not allow them. They have uprisings against them. They do not want them. There's just a ton of solar being built there. These are brand-new markets with long time frames 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.
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. 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. We're focused there. That's not to say that the team, three or four 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. Just a couple of questions to clean up on. First, in terms of the outlook for gas supply via second pipeline, I believe. I'm just wondering if you can sort of update us on that. Does that have to be in service by 2024 for the two repowerings? Just to clarify that.
Brett?
Yeah. We actually have two already. Pioneer is one, and it can go up to 440 at full capacity. There's actually an existing pipe into the site. It was built when the plant started for startup gas. That's what we've been using up until now for even co-firing. It's a small pipe. It's only 12-inch going up to I keep hearing it's an eight there. There's limitations to it. 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 third-part pipe available in that kind of 2023, 2024 for the hybrid, or not hybrids, for the repowered combined cycles.
Then manage what we've got today to manage our co-firing and the boiler conversions up until then.
I had a question on hedging just looking forward. When you think about the power trading operations in the Alberta market.
We can hear you.
We can hear you.
We'll repeat the question.
When we 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. 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.
Yeah, sure. The question was, I don't know if people heard, and it's just wanting, 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. The team is looking at layering in appropriate hedges for the 2020 period. We've started doing that and expect it to be by and large, 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 what would be an appropriate level of hedging in terms of 2021. You have to remember that in Alberta, it's not like you've got multiple years of liquidity in terms of being able to hedge. It's more of a 2020, a bit of 2021.
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. That's in full flight, and we're considering that with a view to what we're going to do in our C&I business in terms of that also providing a bit of a hedge. I think overall, our general sense is keeping our hedge levels broadly where they've traditionally been is about where we are. At least when I think of it, that's in that 70% range in terms of being targeted at an appropriate time. Hopefully, that gives you a bit of a flavor.
If I can, just one more question. Aron, you mentioned-
My one-question rule is not working here today.
Well, it's only like two, three more follow-ups.
I know.
Go.
Okay. The new rule is one question, one follow-up. This is your second follow-up, Jeremy.
I'll leave it here after this one. Okay, just in terms of on-site renewables and cogeneration opportunities, Aron, you mentioned before, just do 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?
Yeah. It's hard to ballpark because each of these plants is bespoke, right? Like I said in my remarks, there's not a cookie-cutter solution that we're putting in. It's not a CAD 100 million solution, you multiply that by five. One might be CAD 100, one might be double that. Based on where our pipeline's at, we would like to see ourselves add, just internally, we've set ourselves a target of one to two of these things every year. I would say the range of investments you'd be looking at would be CAD 100 on the low end to maybe CAD 250-CAD 300 for something that I would say would be much larger, probably at the top end.
Aron, I think it's fair to say that Alberta obviously is a key market there, but it's not just Alberta.
Yeah.
We are seeing opportunities.
Yeah.
On-site is not just cogen. It could be just behind-the-fence, simple cycle or combined cycle units as well.
Rob Utell, 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, Brazeau. Where does that factor? What kind of dollars? Are they bite-size amounts, or are they massive amounts, which are pipe dreams at some future date?
Yeah. If you look at Brazeau, we still have that project. We still have it on our shelf as something that could be developed in somewhere around the mid 2020s, mid 2025- 2030. There's a discussion of a third combined cycle. I think the reason people are looking at these repowered combined cycles, they're fantastic investments. We also have a carbon policy regime here in Canada. It's sitting at CAD 30. It could go to CAD 50. There are people who talk about it even going higher than that in the post-2030 period. I can tell you, no amount of Tesla batteries will power Alberta. Not going to happen. I've been making it 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 interesting flow battery guys out there.
They're way more advanced than I expected them to be. I shouldn't have thought that way, because when I think about how quickly solar has advanced, 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 four hours of storage. I think the way to think about that is when you have an 82% system load factor, 18% 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. 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?
You have to have something. That's where something like Brazeau comes in. I think what the team can develop Brazeau as three 300-megawatt units, rather than one 900. We have work to do to sort of continue to look at that. I think it is the competitor to the potential third combined cycle in Alberta in the mid-2025. 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 CAD 3 billion in a merchant market. Is there a way to look at doing those units one 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. It's still on our radar, but it's definitely not part of the plan in the next five years.
We've given you a very clear picture of the next five years, and all the questions are about the five years after that, but we need to get these five years in. Sorry, and the other question was?
No, 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 far out?
Yeah. No, it's not. I was surprised, actually. We've got a young smarty pants guy that probably will be a future CEO sometime in his life, working on batteries. I was very surprised. I think they're starting to come into that CAD 2,000 a kilowatt range. They're competitive, it's exactly the same formula as the solar guys did. You invent the technology, you get the guys in who can take the engineering and the procurement costs down, you've got to just keep getting money from places. There's a lot of money for this. There's tons of money for these kinds of investments. We've looked at one company extensively. We're going to look at three or four more. I expect to be surprised. I think it is a market that's emerging.
Hi, Rupert Merer from National Bank. I thought I'd throw in an Ontario RNW-focused question here. John, you mentioned you're looking to recontract the Sarnia gas plant, the contract's expiring starting in the next couple of years, I believe. Can you give us your view on the Ontario market and the opportunity to recontract Sarnia, but also the opportunity to maintain the cash flows where they have been over the last few years?
Yes. No, it's a good question. Actually, I'm glad you asked the question the way you did, because that's actually the way we tend to look at it, is we tend to look at it from the perspective of what are the cash flows of the facility and what do we need to do to layer on various levels of opportunity that we have to actually maintain it there. As I mentioned, I think we do think that we're going to see a capacity market here in the province. 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, then you've got basically the nukes and a bit of hydro, which are quasi government-owned.
The place that an IPP like us can play is a more compressed, if I can put it that way, place. When it comes to Sarnia, in particular, 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 hard-pressed 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.
We're also spending a lot of time, and frankly, the team is spending as much time on this, is trying to actually get other 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. It's everything from chemical processing plants to actually Bitcoin-type companies that have high power needs, that we're actively trying to create additional cash flow streams for the facility. We're working hard to keep it flat, frankly, or do better than that as we look at the 2022 to 2025 time period. 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 location.
It's needed.
It's needed in that part of the grid, the customers rely on it for steam. 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. I think it's got all the right attributes that you need for recontracting. These things take a long time. There's a lot of customers to work with and the ISO here in Ontario. It'll muck along for a while, maybe we can advance it, but it could take right until the end of 2025 to get it done.
Recently, the changes here have occurred.
Partners
our customers are not getting the Global Adjustment charge effectively levied against them now. It's one of the things that we've been able to achieve there. It's a pretty competitive power solution for them regionally, 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?
Our Mississauga plant was shut down. To Dawn's point, it was located in an area where, candidly, the power wasn't required there once its contractual life was over. 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.
Yeah. I think gas plants that are just supplying power to the grid-
To the grid level.
most of them don't run that much. That's not helpful. Sarnia is a big thermal producer, so it's a true cogeneration. It supplies steam to the customers. It's a huge sustainability part of the Ontario grid. It does help in that part of the grid. It's got a different set of attributes.
Thank you.
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 to someone that already has. No? Okay. Here you go, Robert.
Sure. Robert Hope, Scotiabank. Getting a little bit granular, and I guess maybe front-running your 2020 guidance, which I would assume we'll expect in December. Just want to clarify the comments you were 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 2019? All else being equal, and let's assume power prices are relatively similar, where do you see cash flows shaking out in 2020?
Okay, we're not going to do 2020 guidance today. I think that really, if you think about we're doing a coal-to-gas outage, so we've given you CAD 30 million-CAD 50 million as the cost of what you need to do one of those outages. At the end of the day, we'll give you the guidance in December or January. A great question to end on. I was surprised you didn't start there, actually. 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. If you could stay and have a sandwich with us or whatever it is we're providing, we'd love to do that. Yeah, I don't know if you're getting what you're getting. Thank you very much.