Good morning. My name is Mike. I will be your conference operator today. At this time, I would like to welcome everyone to the TransAlta Corporation fourth quarter and full year 2018 results conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, press star then the number one on your telephone keypad. If you would like to withdraw your question, press the pound key. I will now turn the call over to Sally Taylor, Manager, Investor Relations. You may begin your conference.
Thank you, Mike. Good morning, everyone. Welcome to TransAlta's fourth quarter 2018 conference call. With me today are Dawn Farrell, President and Chief Executive Officer, Brett Gellner, Chief Strategy and Investment Officer, Christophe Dehout, Chief Financial Officer, and John Kousinioris, Chief Growth Officer. Today's call is webcast. I invite those listening on the phone lines to view the supporting slides, which are available on our website. A replay of the call will be available later today. The transcript will be posted on our website shortly thereafter. As usual, all information provided during this conference call is subject to the forward-looking statement qualifications, which are set out on slide two, detailed in our MD&A, and incorporated in full for the purposes of today's call. All amounts referenced during the call are in Canadian currency unless otherwise stated.
The non-IFRS terminology used, including gross margin, comparable EBITDA, funds from operation, and free cash flow, are reconciled in the MD&A for your reference. On today's call, Dawn, Brett, and Christophe will provide an overview of the past year, an update on our coal to gas conversion and hydro assets, followed by the financial results. After these prepared remarks, we will open the call to questions. With that, let me turn the call over to Dawn.
Thanks, Sally. Thanks to everyone for joining us on the call today. In just 22 months, the remaining legislated PPAs that were set up here in 2000 to bridge to the full deregulation of the electricity markets will expire. Really, that's not that far away. By the end of 2020, Alberta's transition to a fully competitive market for power generation will be in place. This event creates significant opportunity for investors and companies that hold low cost and competitive assets here in the province. Only producers with strong portfolios of competitive assets can be profitable. TransAlta has that portfolio. Today, we intend to assure you that our plan to position for the new capacity market in Alberta is not only well underway, but it's tracking.
You will also get the information you need to see that moving to a clean power company is profitable, it's right for the environment, and most importantly, it keeps prices affordable for consumers. Our presentation has been extended so that we have time to outline the significant progress we've made on our strategy. Of course, we want to take the time to share the highlights of our 2018 performance. On performance, you'll hear that 2018 was one of our best years in terms of safety, operational, and financial performance. Lots to be proud of. On safety, total injuries declined 44% relative to 2017, a great accomplishment for all our teams out in the field. On operations, we had the best availability at Sundance and Keephills since 1990 and 2011, respectively. Again, a great accomplishment from the teams up at Wabamun.
On financial performance, the cash we collected in 2018 from our operations, along with the one-time payment for the expiry of the Sundance PPAs, has made a real dent in our debt reduction target. Our performance has also been positively impacted by the Greenlight program. Over 1,600 initiatives by employees generated CAD 70 million of value in our 2018 numbers, value that also rolls forward into 2019. In 2019, the program moves into sustainment and becomes a permanent feature in our operating model. On strategy, you'll hear that we're growing the cash flows of TransAlta Corporation with investments in coal to gas, the realization of value from our hydro operations, and through our ownership in TransAlta Renewables. Our strategy is simple and the outcomes of it are measurable for shareholders. By the end of this call, we hope that the many questions around our hydro assets will be answered.
We want investors to understand that the change in profitability of the hydro assets here in Alberta in 2021 is real, it's positive, and it's sustainable over the long term. You'll also be able to see that the returns in the coal to gas conversions are more than compelling and benefits increase to shareholders and customers if we can accelerate that program. The list of things to do is getting shorter as we move towards executing our first investment from coal to gas at one of our Sundance units. Finally, we will discuss the growth we landed in 2018, which is not only profitable but can be financed entirely inside of our TransAlta Renewables entity. This is a critically important point that we really want to land today on this call.
Windrise, Antrim, and Big Level are great projects with returns that exceed the cost of capital and that combine together at CAD 40 million-CAD 45 million of EBITDA by 2022. Today, we've structured the call a bit differently. Brett Gellner has joined us on the call as he is the lead on the coal to gas investments, and he'll also provide you with an update on the hydro front so that you have clear line of sight to what happens when the PPA expires at the end of 2020. Following my remarks and Brett's discussion, Christophe will take you through the details of our financials in 2018. I provided this slide because I want to talk for a minute about how we strengthened the executive team here at TransAlta to ensure that we have the amount of focus that we need on our strategy.
Some of you have briefly met Christophe Dehout, our new Chief Financial Officer. Christophe comes from a large international European energy company, has over 25 years experience in all aspects of financing large infrastructure, and that includes power generation. You are going to hear from him shortly. Kerry O'Reilly Wilks has joined as the Chief Legal and Compliance Officer. Her career in one of Canada's top legal firms and her comprehensive and practical experience in the mining business has allowed her to get up to speed in our industry very quickly. Jane Fedoretz accepted a role as the Chief Talent and Transformation Officer. She brings with her an impressive track record that combines a background in law with her exceptional skills in people development and leadership.
Her role is to move Greenlight to sustainment in 2019 and to develop even stronger programs and practices to strengthen and develop our people in this time of intensive change. The addition of these talented leaders has allowed the rest of the executive team to really focus on key elements of our strategy. Brett Gellner has built a team to execute the coal-to-gas strategy. He will take you through the extensive work they have done and also take you through the hydro analysis. John Kousinioris is now focused exclusively on running and growing our gas and renewables business. He is ensuring that TransAlta Renewables can fund both the growth we have delivered and what we are planning. Dawn de Lima is focused on creating an exceptional shared services business so that we can continue to gain efficiencies in our overhead.
Finally, you will see today that having Wayne Collins focus exclusively on day-to-day operations at coal has really paid off. This slide outlines some of our key accomplishments in 2018, and congratulations to our employees who did all of this work. This morning, we reported strong financial and operating performance in 2018, including our highest free cash flow generation in recent years and an 18% increase over last year. Our focus remains on increasing sustainable free cash flow as our key metric, as we believe that this metric gives investors clear line of sight on the amount of capital available for debt reduction, shareholder returns, and growth. I am very pleased to be able to say today that we delivered free cash flow that exceeded the high end of our guidance in 2018.
You all know that we have been focused on paying down debt and strengthening our balance sheet so that we can enter into a new competitive and regulatory environment in our major Alberta market with the financial strength and flexibility we need to be successful. Today, already, we have one of the strongest balance sheets in the industry and strong credit supported by our contracted assets. We have reduced net debt by CAD 1.1 billion since 2015. In 2018, we transitioned our Sundance plants off the PPAs and into the merchant market. The one-time payment from the Balancing Pool was effectively three years of capacity payments for those units. After consolidating the units, our job was to make the remaining Sundance units profitable without PPAs until such time that they could be bid into the capacity market.
The coal team in 2018 was able to deliver availability, utilize gas through co- firing, reduce costs, achieve profitable margins, and improve safety. A very impressive outcome. Brett is going to take you through the detail on how far we've come on our execution of our plan to convert units to gas. He will also demonstrate that our units on gas create sustainable cash flows until the 2035 to 2039 time frame, even at low prices. This next slide talks a bit about the work we've been doing at TransAlta Renewables. TransAlta Renewables has had some nice wins on the growth front in 2018. This past year, we successfully progressed construction of several projects and secured new contracts for other.
By investing very moderate development dollars in brownfield projects in TransAlta, then taking advantage of the lower cost of capital in TransAlta Renewables, we can finance growth in TransAlta Renewables to the benefit of both sets of shareholders. The capacity of TransAlta Renewables to finance using its credit facilities allows us to hold our 61% ownership. We don't need to allocate cash from TransAlta to this growth. This is a key point on our call today. Growth in TransAlta Renewables benefits TransAlta by ensuring our dividend payment remains steady. It extends our overall portfolio life, which reduces the cost of capital for TransAlta Corporation as a whole. Another key point.
Last year, we grew TransAlta Renewables by dropping down Lakeswind, Kent Breeze, and Knott Solar projects, generating over CAD 100 million in proceeds that we then used to strengthen our balance sheet at TransAlta. We also completed Kent Hills three wind projects. We advanced the construction of Big Level and Antrim Wind Facilities. Our most recent announcement of the Windrise Wind Project here in Alberta is an excellent future candidate for TransAlta Renewables. We'll show you today that TransAlta Renewables can fund all of these projects using its credit facilities. Why is this such an important point? It means that the free cash flow at TransAlta can be directed to strengthening our balance sheet, funding our coal to gas conversions, and eventually increasing our ability to return cash to shareholders.
In terms of our financial highlights, I've already talked about our free cash flow of CAD 367 million, a strong result over 2017. When I sit back and reflect on 2018, the hard work and the perseverance of Wayne Collins and the Alberta Thermal teams must be recognized. This past year, they were able to improve availability and safety while transitioning the Sundance fleet. The team faced many challenges. They rose to the occasion. They delivered for the company. They found ways to add margin. They lowered fixed costs at the mine and at the plant. They lowered operating costs. They set up the mine for the coal deliveries to the end of its life, which is around 2023. The rest of the operations, people worked extremely hard and delivered what we thought they would.
We did have a nice surprise, a nice upside in the hydro business as prices improved in the market. You also see on this chart that EBITDA was slightly down, which is primarily due to our mark-to-market at Centralia. Chris is going to take you through that in his section. I do want to take a few minutes to talk about Greenlight because it's been a central transformation for the company since 2016. I want to congratulate the TransAlta team on the extensive work they've all done across this company to make Greenlight a very successful program. Let me remind you that Greenlight is a program we've been using across the company since September of 2016 to not only increase our execution capability, but to realize value and cost savings on many fronts. Greenlight projects are employee-driven.
We completed over 1,600 projects with over CAD 70 million of pre-tax value, which flowed into our 2018 results. These projects continue to produce value in 2019 and beyond. Every project in our Greenlight program is tracked, it's auditable, and we can trace the performance of these projects into our financial calculations. The benefits of the program are enormous, and they affect more than our financial results. Greenlight goes after projects that offset any headwinds that we experience after setting our budgets. It goes after future increases in costs from suppliers or service providers, and it delivers incremental new value in assets through innovation. Let me talk for a minute about the new value creation through innovation, and these are in our existing assets. Our team at Sarnia found a way to lower the set point on their turbines while running on steam. This reduced their natural gas costs.
Our team at Alberta Coal designed a project to utilize the existing gas infrastructure to co-fire gas and reduce greenhouse gas costs. Our team in gas redesigned their capital program to ensure that only projects with the highest returns and benefits to the company get through their stage gates. Projects in our transformation are not all about cost reductions in workforce, and direct value creation. They also streamline processes so that we can improve our focus on safety, which you saw results on, and our customers. This is a company-wide program where any group or any single employee can use the discipline in Greenlight to bring their projects to light and gain cross-company assistance for achieving milestones. Let me end by saying that I phone employees weekly to gain their insights on why the program works and what we can do to continue to improve it.
What they tell me is that we've moved accountability and decision-making to the right levels, people, and teams in the organization. I've included this next slide to reinforce how having two companies with different costs of capital benefit TransAlta shareholders. At TransAlta, we just started using serious capital to complete our coal to gas transition. Our investment in the Pioneer Pipeline project was the first series capital that we put to work to make this strategy a reality. Brett will demonstrate that we will lower our costs significantly and increase our competitiveness in the Alberta market by investing in these conversions as soon as we can. By maintaining our hydro assets, we are preparing for 22 months from now when the hydro PPA expires, along with the other PPAs here in Alberta.
You'll see in Brett's presentation that the combined cash flows of the thermal fleet and the hydro fleet under various pricing assumptions generates cash to 2035 and beyond. This information will demonstrate the value of TransAlta going forward. TransAlta Renewables has a very low cost of capital, which is expected in entities that invest in long-term contracted assets and that return most of their capital to shareholders through their dividends. As a 61% shareholder of that entity, we want TransAlta Renewables to add assets at returns above their cost of capital with long-term contract lengths in diversified geographies and technologies. TransAlta applies its expertise to prospect, develop, and construct contracted gas and renewables projects with a view to increasing value prior to a drop-down entrance to TransAlta Renewables. We get returns for this effort in TransAlta.
TransAlta will sometimes start a project and get it up and running for a future drop-down to TransAlta Renewables. Windrise falls into that category. Today, our three wind farms, Windrise, Antrim, and Big Level, can be entirely funded inside TransAlta Renewables. This means cash flow at TransAlta can focus on coal to gas conversions. In summary, as we complete our transition off the PPAs here in Alberta and move to the capacity market, as we move off coal and onto gas, TransAlta will have a strong foundation of cash coming in from TransAlta Renewables, the Alberta Hydro assets, and from our thermal fleet in Alberta. This cash will be available for allocation to shareholders through dividend and share repurchases.
I'd like now to turn the call to Brett, who will take you through all his work on coal to gas conversions, and who will give you a really good summary of how to evaluate what the value is in our hydro assets once the PPA expires.
Okay. Good morning, everyone, and thanks, Dawn. As Dawn indicated, I'm going to review our coal to gas strategy and the future upside in EBITDA for both our converted coal units and hydro assets. In terms of our coal to gas strategy, the first key message I want you to take away is that the economics and benefits of converting to gas is driven by a number of factors, not just carbon policy. Secondly, our strategy to convert is on track, and we're targeting the first conversion for the second half of 2020. Finally, we're also evaluating a repowering option for some of the units, which has the potential to deliver significant long-term value. In terms of our hydro assets, I'll walk you through the significant upside in EBITDA once we're off the PPA.
Our hydro business delivered CAD 109 million of EBITDA in 2018, I'll show you it would have delivered CAD 244 million without the PPA. I'll show you that there is significant potential upside in the combined converted coal fleet and hydro business in the future. Just turning to this slide, as we've discussed in the past, there are significant benefits to converting the coal fleet to gas. First, if the units are not converted, they have to shut down under provincial and federal government regulations between the end of 2026 and the end of 2029. This impacts all coal units in the province, not just TransAlta's. The outside date at which all coal units in the province must shut down is the end of 2029.
If converted to gas through a boiler conversion, the units can run significantly longer under the federal regulation that was put in place last year. How long a unit can run depends on its carbon emission intensity. For TransAlta units, we expect that all the subcritical units will receive eight more years and the supercritical units 10 more years. As a result, these units will be able to run out until 2034 to 2039. The cost of converting the units, and therefore getting the extra years, is very low at under CAD 90 per kW, compared to a new combined cycle or gas peaker in the range of CAD 1,400 per kW. Another significant benefit of converting is that it avoids the need to invest significant capital in low NOx burners and operating costs for dry sorbent injection in order to meet the provincial NOx and SOx regulations.
If the units are not converted, not only would we not get the extra years, we would have to spend over CAD 300 million to meet the NOx and SOx limits. The capital and operating costs, once converted, also decline significantly. Fewer people are required to operate the facilities, and the mine capital and operating costs go away. Maintenance capital is also expected to be lower as there is less wear and tear and maintenance on the boilers and equipment due to the elimination of coal and fly ash. Carbon costs are significantly lower burning gas than coal, and there's an abundant supply of gas in Western Canada, resulting in very attractive gas prices at some points in the year. The units are also more flexible on gas, allowing them to be more responsive to changes in load and market conditions.
Conversions are relatively low-risk projects and are proven. The outage time to do the conversion is expected to be approximately 60 days, and these projects have been successfully completed in the U.S., some of which we have visited. In terms of status, in order to fully convert, we need more pipeline capacity into the sites as the existing pipeline is relatively small in diameter, as it was designed just for startup gas and heating the buildings. We entered into the partnership with Tidewater to build the Pioneer Pipeline, a new 20-inch pipeline into Sundance and Keephills, and that pipeline is under construction and expected to be in service by the second half of this year.
Our overall pipeline strategy is to have two pipes into the site in order to ensure maximum reliability and flexibility and access to multiple sources of natural gas. Therefore, while we have the existing smaller pipeline, we are in discussions with other parties regarding the strategy for the second pipeline. While we have been co-firing some of the units since early last year to reduce carbon costs and take advantage of low gas prices, we are limited to how much we can co-fire given the limits on the existing pipeline. Therefore, the Pioneer Pipeline will allow us to co-fire even more even before we fully convert to gas. In terms of the boiler conversions, we have received approval for the conversions from the Alberta Utilities Commission and are just waiting for Alberta Environment and Parks approval.
We expect to issue limited notice to proceed for two conversions over the next couple of months in order to finalize the engineering work and plan on issuing final notice to proceed on those units by mid this year. We will then proceed with the other units after that. We're targeting all of the conversions to occur over the late 2020-2023 period, with the first one targeted for the second half of 2020. Now, as I mentioned earlier, we have also started to evaluate the potential to repower one or two of the units instead of doing boiler conversions on them. Repowering would involve installing one or more combustion turbines in HRSGs and then using the steam from them to operate the existing steam turbines in the coal units. As a result, the boilers associated with those units would be retired.
We have completed an initial study on this opportunity and visited a power plant in the U.S. that was repowered and has been successfully operating for 10 years. These projects are delivering heat rates consistent with new combined cycle plants, but at a capital cost that is 40%-50% less than a new combined cycle. The other benefit is that these units can run as long as equipment will allow, so potentially 20-25 years. Therefore, based on the work we've done to date, this opportunity looks promising, and we'll keep you posted as our work progresses. This slide compares the cost of the boiler conversion and repowering combined cycle to a new combined cycle and new gas peaker. As you can see, the boiler conversions and repowering are at a fraction of the cost of new builds because they utilize equipment that is already there.
As I indicated, our capital and OM&A costs are expected to decline significantly once the units are fully converted. This slide shows our historical eliminating capital costs at the coal plants and what we expect them to be once the units are fully converted to gas. In the middle, we have also included the average annual cost to meet the NOx and SOx that would be required if the unit stayed on coal. As you can see, our costs will go down significantly once converted. I should point out that these are annual averages, and the amount in each year will vary based on the timing of planned major maintenance outages. In terms of the Pioneer Pipeline, as I noted, it's progressing very well as you can see by the picture. This project is being built at a very competitive cost when compared to other natural gas pipeline projects.
On the bottom left, we show the potential EBITDA that TransAlta could generate from its 50% ownership in the pipe at different throughput volumes. The range of volumes shown reflect the potential volumes TransAlta will need from the Pioneer Pipeline as the units at Sundance and Keephills convert fully to gas. Now I'm going to switch gears and spend a few minutes on the potential upside from our hydro assets once they come off the legislative PPAs at the end of next year. John Kousinioris, who heads up our gas and renewables business, is also here and can help answer any questions at the end of the call. Before discussing the ancillary market and our hydro, it's important to remind people that the hydro PPA was put in place at the same time as all the other legislative PPAs.
While some of those original legislative PPAs have already expired or been handed back to the asset owners, a number of them are still in place, including the hydro one. As you can see, all of them expire at the end of 2020, at which time the owners of the facilities, whether it's a coal PPA or a hydro PPA, will capture all the revenue they generate from the energy ancillary and capacity markets they provide to the market and also incur all the associated costs to operate those units. Our hydro assets in Alberta, because of their storage capability and ability to respond quickly to market needs, provide energy ancillary and capacity markets to services to the market and will continue to provide those services even after the PPA expires.
In terms of the ancillary service market in Alberta, this slide shows the size of the market by product and what technologies service the market. In total, the market is approximately 7,800 gigawatt hours in size, and hydro has historically supplied approximately 47% of the active market. As a result, TransAlta's Alberta hydro assets not only generate approximately 1,500 gigawatt hours of energy every year but also sell approximately 3,000 gigawatts in ancillary services. Ancillary service prices per megawatt hour vary depending on the type of product, but on average, sell for about 50% of the 24/7 energy price. As well, the 1,500 gigawatt hours of energy that hydro generates tends to be during more peak hours. Now to show the upside of the hydro assets once they come off the PPA, we have provided more disclosure in our MD&A under the hydro section.
In 2018, our hydro assets generated CAD 109 million in EBITDA, and as I will walk you through now, they would have generated CAD 244 million if the current PPA did not exist, assuming the capacity market was up and running and delivered similar capacity revenues. Let me now walk you through this chart. The first two bars on the left show how much energy and ancillary service revenue TransAlta generated in 2018 by selling those services into the merchant market. Even after the PPA expires, we will continue to sell those services, the price for which will be determined by market conditions. The third bar is the capacity payment we receive under the existing PPA.
This PPA, by the way, is a public document available from the Alberta Queen's Printer. This capacity payment will go away after the PPA expires, but we will receive capacity revenue once the capacity market begins at the end of 2021. Again, the price of future capacity is unknown at this time, but to put it into perspective, the current payment is under CAD 6 per kW month when applied to the full nameplate capacity of the Alberta Hydro assets. The next bar is other revenue we generate from our Hydro segment. We generate revenue from our other Hydro assets in Alberta, B.C., and Ontario. Most of those are under long-term PPAs with the local utilities. We also receive revenue in Alberta for other services such as black start and Water Management services. Finally, we include in this segment revenue from the very small regulated transmission assets we own in Alberta.
Our cost to operate all of our Hydro fleet was CAD 47 million in 2018. When this is deducted from all the revenue I just walked you through, you get the CAD 244 million of EBITDA that would have been generated if the PPA did not exist and we were in a capacity market. Under the PPA, however, we paid to the Balancing Pool in 2018 a net amount of CAD 135 million for energy and ancillary obligations, net of some costs. This is the amount that goes away once the PPA expires. I should note that the Balancing Pool in their public reports do provide the PPA obligation volumes for the energy and ancillary services for Hydro. As you can see, there's significant upside from our Hydro assets in the future. What we have shown here is based on 2018 results.
The amount these assets generate in the future will be subject to future energy, ancillary, and capacity prices. Now I just want to wrap up my section by showing you the potential EBITDA that the converted coal units and our Hydro assets in Alberta would potentially generate under different all-in prices. First, in terms of prices, this chart shows historical prices under the energy-only market and what one forecaster, EDC Associates, is projecting for prices once the capacity market is fully functioning. For the historical period shown, prices average approximately CAD 50 per megawatt hour. However, if you exclude 2016 and 2017, period during which some offers into the market were not being bid on reasonable commercial terms, the average price was just around CAD 60 a megawatt hour.
In comparison, EDC is projecting all-in prices in the range of CAD 75-CAD 80 a megawatt hour once the capacity market is in place. I should also note that the ISO did some analysis about a year ago that provided prices in the low to high CAD 60 range once the capacity market was in place. This chart shows the potential EBITDA from our Hydro segment and the converted coal fleet using the price range discussed on the previous chart. As you can see, at an all-in price of CAD 50 a megawatt hour, the assets are expected to generate EBITDA similar to what they generated in 2018. Using the more normal historical average of CAD 60 a megawatt hour or EDC's forecast, you can see the assets would generate significantly higher EBITDA. These EBITDAs assume the capacity market is fully functioning and TransAlta's coal-to-gas strategy is complete.
Also note that this chart does not include the EBITDA from all the other assets TransAlta owns in Alberta and other jurisdictions. With that, I am going to now turn the call over to Christophe.
Thank you, Brett, and good morning, everyone. I am thrilled to participate in my first TransAlta conference call and look forward to many more with you in the future. I will start with a quick overview of our performance for the fourth quarter of 2018 and our financial results for the full year. Following that, I will take you through the evolution of our debt and capital allocation for both TransAlta and TransAlta Renewables and the impact of our last renewable projects on our future results. First, looking at the quarter. Oil prices in Alberta were strong, averaging CAD 55 by megawatt hour compared to CAD 22 for the same period in 2017. This increase is primarily due to higher carbon compliance costs and improved market fundamentals. As Dawn mentioned, our fleet availability was stronger during this quarter than it was in 2017 due to lower outages and derates in Canadian coal.
This was partially offset by higher outages at our coal units centrally in the U.S. These factors supported financial results equivalent to the fourth quarter of last year, during which we still benefited from the Sundance PPA. Our fourth quarter EBITDA of CAD 233 million was CAD 42 million lower than in 2017, partially due to outages and a negative change of CAD 28 million in the mark-to-market of our commodity hedges for our U.S. coal operations. This mark-to-market movement does not impact our funds from operation or free cash flow, and we expect it to reverse in 2019. We also saw a reduction of CAD 10 million in our Canadian coal EBITDA due to higher carbon compliance and coal costs, as well as lower fixed revenue due to the terminated PPA at Sundance. Hydro, Australian and Canadian gas operations had stronger quarter results and outperformed the fourth quarter of 2017.
As you can see at the bottom right of the slide, our 2018 EBITDA reached more than CAD 1.1 billion. This amount includes the one-off PPA termination payment of CAD 157 million for some of our Canadian coal assets. After adjusting for this amount and the CAD 34 million one-off OFED payment in 2017, our EBITDA is slightly below our 2017 results, at CAD 966 million. However, this amount also includes the negative mark-to-market of our commodity hedges for a total amount of CAD 22 million. Without this, our EBITDA would reach CAD 988 million. From 2019 onwards, we will report our EBITDA without the mark-to-market of commodity hedges, as this does not correctly reflect the performance of our operations.
I would like to strengthen the fact that we view this 2018 EBITDA result as positive, as we have managed to transition away from a PPA environment to full merchant operation for some of our coal assets in Canada, benefiting also from our investment in gas co-firing. We also saw stronger performance in the Canadian gas segment, as well as higher results in wind and hydro, which benefited from higher prices in Alberta, both in the energy and ancillary services. During the fourth quarter of 2018, our total cash flow was higher than in the fourth quarter of 2017, at CAD 192 million. All operating businesses outperformed last year, with the exception of energy marketing and slightly higher corporate costs due to some one-off items.
On a full year basis, after adjusting for the OFED payment in 2017 and the PPA termination payment in 2018, our cash flow from our businesses increased by CAD 67 million year-over-year. This increase was primarily driven by high availability of our units, positive impact of Greenlight initiatives in operations, higher power prices in Canada benefiting our gas, hydro, and wind businesses, lower capital expenditures in Canadian coal, thanks to an optimum allocation of the units with the end of the PPA agreements, and additional revenues from transmission services in Australian gas. I will now turn to free cash flow, which includes interest expense, taxes, non-controlling interest, and preferred share dividends. Our total free cash flow for the year amounted to CAD 524 million.
If we exclude the one-off items in both 2017 and 2018, our free cash flow still shows an increase of CAD 57 million over 2017 to CAD 368 million for the whole year. The increase is mainly due to the stable funds from operation and lower sustaining capital due to further optimization of capital expenditures in the company, with most initiatives developed within the Greenlight program. As Dawn noted, this is the highest free cash flow the company has generated in the past several years. As you can see on this slide, through a very strict financial discipline, we have managed to reduce our recourse corporate debt by CAD 1.6 billion over four years, and we still target CAD 1.2 billion by the end of 2020. I will get into more details on this in the next few slides. Our capital allocation reflects our current strategy for TransAlta Corporation and TransAlta Renewables.
Both share the same goal, sustaining our businesses. If you now look at each entity, for TransAlta Corporation, our focus has mainly been reducing our debt in last four years, while also investing in developing projects before transferring them to TransAlta Renewables. We also pay regular dividends and have opened a program in 2018 to buy back shares. As we near the end of our debt reduction program and as uncertainties lift in Alberta, we may also consider investing faster in the coal to gas conversion of our Canadian coal assets. After 2020, look at shareholders remuneration. At TransAlta Renewables, the picture is simple and will remain consistent. Maintain the dividend distributions, pay back project finance debt, and mainly invest in new projects.
As we look forward over the next three years, our capital allocation strategy at TransAlta Corporation will continue to focus on our three key areas: debt reduction, investment in coal-to-gas, and for the development of projects for TransAlta Renewables, and finally, shareholders' remuneration. On the balance sheet front, we intend to repay the CAD 400 million bonds maturing in late 2020 with a strong excess cash flow generated by the business, further strengthening our balance sheet. In addition, between TransAlta and TransAlta Renewables, further debt reduction occurs through the mandatory principal payments associated with amortizing project finance debt. TransAlta Renewables will focus on growth and allocate capital to long-term contracted growth opportunities. These projects will be highly levered within TransAlta Renewables, which has the capital available to grow its business independently from TransAlta.
As Dawn mentioned, the announced growth projects can all be funded with our cash and the existing TransAlta Renewables credit facilities and will not require any capital investment from TransAlta or the market. Consequently, we do not anticipate to go to the equity market to finance the current projects. As outlined in the Investor Day in 2017, our capital allocation plan for 2018 to 2020 is underpinned by our ability to deliver at least CAD 1.2 billion in free cash flow during the three-year timeframe of 2018 to 2020. This target included the expected PPA termination payment of CAD 213 million, of which we have already received CAD 157 million.
Our guidance for 2019 of CAD 270 million-CAD 330 million of free cash flow takes into account several assumptions, like Alberta power prices in the range of CAD 50-CAD 60 per megawatt hour, load factor of 30% for Sundance coal units, sustainable capital in the range of CAD 160 million-CAD 190 million, as well as the full impact of our performance plan, Greenlight. On a consolidated basis, the growth from TransAlta Renewables will lift our EBITDA. As you can see on this chart, we already see the benefits of the South Hedland project. In this year and the next, we will start to see the benefit from some of the recently announced growth projects in TransAlta Renewables. With long-term contracted assets further strengthening our balance sheet and reducing the business risk on a consolidated basis.
To sum up, you can see we've continued to generate strong cash flow from a highly diversified set of assets, and we have one of the strongest balance sheets in the industry, positioning us well for the future. With that, I will now pass the call back to Dawn for the conclusion.
Thanks, Christophe, and welcome to Canada. Thanks, Brett, for all of that great information. Just a couple of closing comments, because I'm hoping you're all anxious to get to the Q&A period, because I think we've provided you with a lot of information today that you haven't heard before. As you can see, we've really advanced. You heard today that in 2018, we delivered what we set out to do. You've heard that we've advanced our strategy and our execution plan significantly on our coal to gas and are really positioning to advance those conversions into the 2020-2023 timeframe. You've heard that we have strengthened our balance sheet and are really set up to go into what will be a competitive market.
As you all know, in a competitive market, it's only about cost, cost, so that you can deliver value to customers, because that's what they expect. We've shown you today that going green is profitable and that it benefits consumers. That's a significant change in my 33 years in the industry. I think this is really the first time that I can say that clearly consumers can get what they want, which is green and low-cost power. We've shown you that TransAlta Renewables can fund the long-term contracted projects. We've got John Kousinioris here ready to answer questions on that front. We've been able to find excellent projects. We've shown you that we can take some of the returns of that into TransAlta as we do all the development, the prospecting, and really the setting up for those projects.
I guess the other thing we've shown you is that our strategic plan is extremely simple and it's measurable, and you can measure our performance in it. It focuses on converting those plants to gas and creating sustainable cash flows for the next 15 years. Brett's shown you that there's even better opportunities now that we've looked very deeply at the idea of potentially using one or two of the locations for hybrids, which are significantly more cost-effective than anything anybody can put in the ground here in Alberta. We've shown you that the hydro PPA expires just like all the rest of them, and I think our disclosures are excellent now. You can see in our MD&A in black and white exactly how that works, and Brett's done a great job of showing that to you. With that, I think you know what our investment thesis is.
I think it's changed significantly over the past year, and I really look forward to your questions as we go forward, because I think we've given you a lot to chew on here today. With that, I'll turn it back over to Sally.
Thank you, Dawn. Mike, if you could please open up the call for questions.
At this time, I'd like to remind everyone, in order to ask a question, press star one on your telephone keypad. To withdraw your question, press the pound key. We will pause for a moment to compile the Q&A roster. Your first question comes from Robert Hope from Scotiabank.
Yes. Good morning, everyone. Appreciate the new hydro disclosure. Not surprisingly, the first question is on the hydro upside. If we look at slide 18 and the CAD 244 million of EBITDA that you outlined, that assumes some sort of capacity market. If we rewind this back to 2018, where there's no capacity market, would it be fair to assume that
EBITDA you would have generated in 2018 would have been CAD 244 less that CAD 56 million, so closer to CAD 190?
I think I'm going to start with that, and then John and Brett can come in, because I think one of the things you got to look at, and you can see it on EDC Associates' slides. Remember, in an energy-only market, the capacity price is in the energy price. Remember, the market today in Alberta is an energy-only market with PPAs. In a fully functioning energy-only market, if you went back to that, you have to put in place some safeguards and some guardrails to ensure you got enough capacity, which means that you really have to have capacity prices show up in the energy-only price in order for the market to create enough capacity for reliability.
Given that the hydro dispatches at prices, can dispatch by hour into the highest priced hours, you'd have to expect that under a true energy-only market with the right rules in it and with the right capacity response in the energy-only price, that I don't think it would be that much different. Let Brett and John comment on that.
To that point, think about those average prices that I walked you through historically. If you say CAD 60, remember, 2018 averaged CAD 50 on a flat energy. As I mentioned, ancillary gets about half that. We get a bit higher because we sell more into peak hours on the energy. Even just taking that extra CAD 10 and applying it to the energy and ancillary services that we sell, if you assume a CAD 60, you would recover maybe not all that capacity price, but some of it. It really depends on, there are some years where prices have been quite a bit higher than CAD 60. To Dawn's point, two different markets, I mean, technically, you are correct. It comes out. Our view is prices could be higher to overcome some of that.
Yeah. No, Brett, I think you've articulated it well. I think that's exactly what would probably happen. The other thing is, unlike other jurisdictions, we are capped. From a pricing perspective, when you have those high price hours of CAD 999, in other jurisdictions, you'd get more, and that kind of goes to Dawn's-
Yeah
point of market structure.
Yeah. If you look at true energy-only markets where they don't have PPAs or they don't have capacity calls, you cannot run the Alberta market with a CAD 1,000 a megawatt-hour cap. You'll run out of capacity. You have to be willing to take that cap up to CAD 10,000, CAD 14,000, CAD 15,000, CAD 20,000. The cap theoretically, in order to achieve the capacity that you need in the market, is the opportunity cost of the first unit that you take off the system. There's lots of theory that goes behind that. I think, if you want to be conservative, you could do that, Rob, but I think you have to really consider what a capacity, what an energy market would have to look like if it's going to achieve the capacity you need for reliability.
All right. Appreciate that. As a follow-up, just looking at 2019 year-to-date, your Sundance units have been running ahead of your guidance level. February pricing was CAD 100 a megawatt-hour, roughly. Just want to get a sense of how you think you're performing relative to your 2019 guidance.
Well, we'd love to tell you that we're going to hit it out of the park, but we also live in Alberta, and of course, January was a really low-priced month. When we look at January and February together, we're pleased. It's early in the year, Rob, and certainly, as we go through the year, we'll be sure to update you if we see that it's running more positive than we thought.
Thank you. I'll hop back in queue.
Your next question comes from Ben Pham from BMO.
Okay. Thanks. Good morning. I want to follow up some of Rob's questions on the hydro bridge. No doubt, there's certainly some EBITDA upside that's hidden here in terms of the future expectations. I'm just wondering, I guess, just some of the assumptions underpinning this, because it seems like this disclosure is not too different than 2017 Investor Day. Just doing some quick math, if you take energy plus capacity, doesn't that assume about a CAD 90 all-in power price, or am I calculating that wrong?
Yeah.
Okay.
Remember, you got to remember, the hydro sells the roughly 1,500 gigawatt hours and 3,000 gigawatt hours of ancillary. Two products plus capacity. When you take the revenue, I don't know which revenues you captured there, Ben, but you need to look at it from that perspective. I would say from a disclosure, I think it is more fulsome. We have broken out more on the buckets on the revenue between ancillary and energy and capacity, which we think is helpful because you can take those revenues, divide by your volumes, and look at how they compare to flat energy prices. Hopefully, that gives you more information for you to use in your modeling efforts. No, it wouldn't be generating, and without seeing your math, those kind of CAD per megawatt hour.
I think the numbers actually, Ben, are closer to 60 when you actually do the math. I think as Brett said, there was about 1,500 gigawatts of energy and a bit over 3,000 gigawatts of ancillary services, which we sold, which
Are roughly at 50% of what the realized energy price would have been over the period. I think the average, the flat price for the year would have been around CAD 50.
I just want to quickly clarify. On the revenue side, we could just take what you've provided here, but the denominator, I shouldn't be looking at 1,600.
Right
adding another 3,000.
Yeah, that's right.
That's right.
Think of it. Remember, ancillary services, you can't sell energy unless you're called to sell that energy. Think of it as you're really offering two products in the market on an hourly, daily basis, one of which flows through the turbines. One is kept on reserve and only used when called upon, and then it captures energy prices at that time as well. It's really for the system operator to manage the system for both planned events, but also voltage support and regulation. That has been going on since deregulation.
They're really necessary products here in Alberta. I think the other thing that we've done, Ben, to help people see what this is you're getting the disclosure of the volumes of the ancillary services and where you can go find them.
Okay
You can verify them independently.
Okay. That makes a lot of sense. It looks like it's more mid-60s, which seems reasonable versus, I think I was getting CAD 180 or so, which seemed really high.
Right.
Okay. There's some disclosure around some mothballing changes. Maybe I might have messed up some previous disclosures, but maybe just some thoughts on Sun 4, Sun 5, just some changes in the mothball timing.
Sun 3 and 5 are mothballed currently, and they currently go out to the end of March of 2020. I think we made that change several months ago. No major change there.
Okay. All right. Thanks. Very helpful.
Thanks, Ben.
Thanks, Ben. Thank you.
Your next question comes from Patrick Kenny from National Bank Financial.
Yeah, good morning. Dawn, just on Windrise, you made it clear on the last conference call that, in your view, the returns from these REP projects were less than stellar. Just wondering what other attributes, either economically or strategically, helped to convince you to allocate the CAD 270 million towards the project?
Well, be clear, Patrick, in all of our bids, we don't bid to the returns of the market. We just put in our price. We put in the returns that we require for the risk and return of that project. We evaluate. We have the site. We evaluate the cost that we can get turbines at. We evaluate our competitiveness on construction. We evaluate sort of the risk of the counterparty, which in this case was a strong counterparty. Then we put in the actual return that we need to make the project go, and we bid that price. If we get the project, then it meets our return thresholds. If we don't, then we let her go. When we bid projects like this into the first call, we didn't make the cut.
We did make it in the second call, we were actually surprised by that because we had ensured that we got the returns that we needed to achieve our target returns. Now, we're achieving target returns for long-term contracted assets with strong counterparties, with low construction risk. Remember, all of our guys that work in Southern Alberta built our wind farms, and they can build this one. They're ecstatic. John is their new buddy. We did have advantages there that we've had for a long time, but we were never able to get our projects through the process because the returns, they either had lower return thresholds or they had better competitive advantage than us. Net-net, that Windrise meets the criteria for sure of our target returns for TransAlta Renewables.
As I've said, it's sitting right now in TransAlta, but it's a candidate for TransAlta Renewables.
Okay, that's great.
The only other add was we did develop a site that we didn't have ready for that first round, which is a better site, and that's the one that won.
Yeah.
It had better attributes to it, so the economics were also part of that. Things had changed between the initial rounds and the second round even.
Well, also with just better turbine prices, right?
Right.
Yeah. All across the board.
Yeah
Got it. Okay.
Does that help, Patrick?
That's great. That does, thanks. I might have missed it in the release, but maybe you can just confirm if you intend to extend the NCIB beyond March 13th.
Oh, yes.
Just a comment. Okay. Maybe just a comment.
You might have missed it. Did we put it in the release?
I put it.
Okay. Yes, we are.
Maybe just a comment on how the NCIB competes for dollars relative to some of these contracted renewable projects out there.
Well, I really want to land this point. The NCIB is a TransAlta Corporation NCIB. Any sort of contracted assets, they're headed for TransAlta Renewables. You have to say, okay, how does TransAlta Renewables think about if it had its own NCIB? Of course it doesn't. How would it compare its capital allocation at TransAlta Renewables? What I see over there, Patrick, is renewables is a big dividend company. It gives its capital back to dividends, which we want at TransAlta, where we're making sure that we finance everything that we're carrying on those long-term contracted assets over there. Now when you think about capital allocation at TransAlta, you need to think about. We've got our cash coming from renewables, and it's fully financed when it comes over. Its debt has already been paid by the project debt over in renewables.
We have our cash from our rest of our business. The question around capital allocation is, when we think about that NCIB, is it a better use of capital than doing the coal to gas conversions? Right now, I can tell you that coal to gas conversions are a much better return, and you want us to do those. What Brett's presentation showed you today is that even if we can accelerate those sooner, they even give us better returns. Once they're done, the NCIB is really important because then there's quite a significant amount of capital available for return to shareholders through the NCIB or through dividend uplift. Does that make sense?
It does. Yes. I appreciate those comments, Dawn. Maybe just for Christophe, yes, welcome to these lovely winters here in Calgary.
Thank you.
As you look to position the balance sheet for the post-PPA era in a couple of years, I just want to get your thoughts on the importance of maintaining an investment-grade credit rating, what you feel are the most important credit metrics to focus on. Also, maybe you can comment on slide 25. You're now showing dividend increases as potentially part of your long-term capital allocation strategy. Maybe just a sense as to what your longer-term optimal payout ratio target might be as a percentage of FFO or earnings.
Well, the importance of being investment-grade has been shown certainly on the trading floor or the fact that we have access to several capital markets. As you know, the Canadian I would say capital markets is slightly different than in the U.S. For us, it's important to be investment-grade. I tend to focus on FFO to debt as the rating agencies also do. As far as talking about shareholders' remuneration and beyond, the end of the PPA, I think it's too soon to tell. I think the message here is really the fact that we've been consistent in our capital allocation till now, we aim at the CAD 1.2 billion of corporate debt by the end of 2020.
As I said, once the uncertainty is lifted also in the Alberta market, as we look to convert our coal units to gas, once we've invested and once we've realized also the upside on hydro, we'll allocate our capital in the best way we think.
Yeah, Patrick, let me comment here because I think Christophe is just really starting to pull things together here. Certainly, I agree with him entirely that in Canada, investment grade is an important criteria. The way I've been thinking about it is, Brett showed you that sort of the EBITDA under various scenarios. What's really important when you think about that chart is that the capital required to maintain the hydro and the conversions is significantly different than the capital that's required to maintain coal plants. The net cash coming out of that chart is stronger. When you take that net cash and add it together with the other cash that we have, the way I've been thinking about it is, if you start with your FFO, you need an allocation for the sustaining capital so that the assets continue to produce cash over time.
You need an allocation to debt repayment. By that time, that's gone away, as you know. I think the balance sheet that we're aiming for as we start into the decade is a good, strong balance sheet and really no IPPs ever have that balance sheet. They tend to over-lever. We're endeavoring to under-lever at the TransAlta Corporation level. If you think about capital allocation then, to me, it's you got to have money for the sustaining, you got to have money for the highest value growth projects. You really got to be clear about what high value is and what your targets are. You've got to distribute cash to shareholders. I think when we get there, depends on what the share price is.
If the share price is low, for sure, the majority of that capital return to shareholders would be through share buybacks. There may be an opportunity to start increasing the dividend. I think it'll be a combination of those two. We'll have to think about what is the amount that shareholders can depend on coming from us as a return of capital for their investment.
Okay, that's great. Thanks, Dawn, everybody.
Okay. Thanks, Patrick.
Thanks.
Your next question comes from Mark Jarvi from CIBC Capital Markets.
Good morning, everyone.
Good morning.
I wanted to quickly go back to the ancillary revenue services and just wondering what you guys think how that trends under a capacity market, if that's different at all versus the energy-only?
Yeah. We've done a bit of modeling, Mark, on that going forward, candidly, we don't see that changing significantly. When we do the work that we do, both internally and when we look at people from an external perspective that help us, we see it broadly continuing. When Brett went through his slide and he talked about kind of the notional capacity value that would be there for the fleet at kind of a CAD 6 sort of per kilowatt a month kind of value, we think that that isn't an unreasonable sort of proxy for what we expect in the capacity market as well. In general, we think it is more of the same.
One of the reasons we use that 2018 kind of bridge, it's just when you look at the pricing in that bridge, it's not an unreasonable snapshot of what you can expect on a go-forward basis. It's a reasonable proxy, I think.
Okay. In terms of market share, where the hydro is having nearly 50%, as you see a bit of a shift in the generation mix, a bit more wind and some of the coal coming offline, should that stay flat or is there anything you think will trend differently in terms of the percentage that the hydro captures?
Yeah. Right now, I think what we've seen is it's been stable for a period of time. You're right, the generation mix is changing. In fact, it's increased slightly as we've gone on. One thing you need to remember is we also have obligations in our hydro suite to manage water flows along the river. We have a number of permits, so there's an environmental. Everything from recreational users to making sure that ice flows are appropriate along the river. Our macro capacity to actually provide more ancillary services in terms of volumes is a little bit constrained in terms of what we're going to be able to do. Again, what you're seeing is a reasonable kind of proxy for the kinds of volumes I think that we're expecting.
Well, I think the thing you want to think about is in a market that has growing renewables, the demand for ancillary services is higher.
Should go up.
In some of the cold days here in February, the wind doesn't blow at all. It's really important to have capacity and ancillary services and operating reserves and all of that. I would expect, just given the pricing that you see on renewables and how far down it's come down, I would expect to see more in the systems all across the world, which I think puts a higher value on ancillary services.
Remember, it's the service that kind of matches supply and demand of those variability during the day.
Right. I just want to pivot to TransAlta Renewables. You guys talked about some of the growth that's happening there and potentially Windrise ending up in TransAlta Renewables. Can you guys just maybe update us in terms of what you guys think or what is the return hurdle right now, whether it's sort of an IRR or cash-on-cash yield for R&W investment?
Yeah. Mark, I'll be honest with you, we generally keep that kind of discussion in terms of what our hurdles are and what we're looking at from IRRs, I think pretty closely guarded to us. I can tell you that when we're looking at drop-downs from TransAlta to TransAlta Renewables, we have our independent committee go through it. They do get a financial advisor, and they go through a pretty rigorous process to make sure that the value of the asset that comes in, and effectively the development fee that they're paying to TransAlta for that asset is appropriate in light of the cost of capital of the company.
Okay. I'll jump back in the queue. Thanks for the answers.
Thanks, Mark.
Your next question comes from Andrew Kuske from Credit Suisse.
Thank you. Good morning. Not to harp on the hydro, I do appreciate the incremental disclosures in the quarter. Just one maybe easy question to start off with. Do you anticipate any changes to how hydro will be dispatched in the capacity market versus how they are now?
Yeah. It's a good question. We've been engaged with the ISO in terms of the technical rules that they're developing for ancillary services, which are particularly oriented around the hydro that we have. The short answer to that process is, in general, we think that the rules as they're being proposed are flexible enough to permit us to actually operate hydro as we have been. They've been developed with that in mind, given, as I mentioned earlier, the obligations we have from an environmental and permit perspective to manage the water flows on the river. I think we're expecting right now a very similar, not much of a change in the way that we're operating these things.
Andrew, we really want you to harp about the hydro a lot. Feel free to ask us a gazillion questions. We'll stay on the phone all day with you. We'd like everybody to harp about it. Thank you.
Okay. I'll continue harping on hydro later.
Okay. Thank you
stop now.
Thank you.
Sure.
When you think about just the outlook for pricing and the market structure in Alberta, clearly you're doing the coal-to-gas conversions. Initially, they're going to be high heat rate units to start off with. You're going to have less baseload coal in the overall market. Just how do you think about the generation stack in the capacity market in the next few years versus what we've seen in the last, say, 10 or 15?
Yeah. Andrew, it's Brett. Clearly, it's somewhat a function of the carbon policies and prices. Based on the current carbon policy that's in place today, coal-to-gas on a pure carbon is quite a bit less than coal. There's quite a bit of savings there on a per megawatt-hour. Now you're down to really your next variable is your fuel charge, and that's your natural gas versus coal. Ultimately, too, as I said earlier, coal goes away for everybody at the end of 2029. You've got a bit of what happens over the next decade and then longer term. Certainly, from our perspective, even though they have higher heat rates than obviously a combined cycle or something like that, because of those attributes, will continue to dispatch. We expect similar to the way they've been dispatching of late.
If the carbon policy changes and shifts that could shift it going forward. You also have to remember some of the units, like the older peakers that were put in place, the heat rates on those are still pretty high and aren't as good as a new peaker that's in place. Again, they tend to only operate certain hours and try to pick off those higher prices. Right now, we don't see a lot of change when we look forward, but again, it's subject to gas prices and other factors, carbon in particular.
Okay, that's great. Thank you.
Your next question comes from Robert Kwan from RBC Capital Markets.
Good morning. Maybe I'll just continue here on coal to gas. I'm just wondering some of the disclosures here around lengthening the conversion out to 2023. Then there's also a statement talking about some or all of your units. I'm just wondering what's in behind that as well.
Yeah. The 2020-2023 is really just, as you can appreciate, you can't do all of these in one shot.
I think we before were 2022, 2023, though, weren't we?
Yeah. 2021-2020.
We've actually moved it to 2020.
We've moved it in a bit. It's really somewhat a function of timing and outages and you're going to do one at a time, as you can appreciate, Robert. The some or all is really back to the comment I made about us evaluating this repowering option. If we see that as an opportunity, clearly, we may not spend money on the boiler conversion and just move into those instead. That's the purpose of the some or all.
Got it. Just moving to Windrise or just using Windrise as an example and really more taking a step back and looking at how you think about growth, risk versus return, growth versus other uses. Based on your EBITDA disclosure for both the pipeline and the total projects, it looks like you're constructing at ± the 11x range. Just wondering how you think about that versus M&A. That seems to be going in the 9x-11x range. Kind of just constructing it at where private transactions are going.
I'll jump in. John can jump in. I would say that we are seeing, for some assets, EBITDA multiples even higher. I also think it's very important to look at each market is going to be different depending on whether you have tax attributes, what the tax profile looks like, what the term of the contract looks like. We look at it less than from an EBITDA multiple perspective. We look at the long-term IRRs of the project, they have to stand and meet our hurdles. What we do is we also roll that into RNW because it may have some other attributes. For example, we may be able to accelerate some of the tax pools from that asset and apply it against the rest of the fleet. There might be some synergies that we can add to it.
It's less about a multiple and more about a return. I can tell you, the stuff we're seeing, Robert, especially on the solar side, but even you've seen some of the big hydro stuff is very low equity returns.
Not a lot to add to what Brett said, frankly. The only thing is that, again, every project, whether it's an M&A project or whether it's a development project that we're doing internally, when we think of the value of it's all based on the characteristics of the project. Everything from the regulatory certainty of the jurisdiction to the quality of the counterparty, to the tenor of the contract, to the technology that's being used and how comfortable and familiar we are with the technology. It's a much more nuanced kind of discussion. We continue to see, in many places, a very hot, from a pricing perspective, M&A market, for sure.
Robert, I just want to comment on the pipe because I think you rolled that in your comment. The pipe, again, as we tried to show there, once a pipe's in the ground, clearly, there's not much more incremental capital. We might have to do a bit of compression to get it beyond certain levels, but very modest. Any incremental volume that gets pushed through that pipe, it's just all straight to the bottom line. That's why once we start moving volumes that we expect to move through there, you can see it is a very good investment for us. Plus, I kind of view it no differently than owning the mine or drag lines. It's part of our fuel supply strategy and good returns coming with it.
Right. Then just to the risk versus return part of this question. This CAD 39 to CAD 41 a megawatt-hour that the ISO put forward, are there any other revenues that you'd receive as part of that? If not, how do you weigh that against just building merchant energy, carbon credits, capacity prices, especially when you square that up against your slide 19?
The price that we're getting under the PPA is the full price. The economics that we did in making the decision to proceed was based on that price, and it met our hurdle rates and everything there. There are people that are speculating, to your point, about whether or not you build something like that in a merchant kind of market and take those kind of assets. That is not in the kind of risk profile that we have had. Certainly for TransAlta Renewables and even for TransAlta, we're pretty clear about wanting to have contracted assets as best as we can and having the certainty and predictability associated with those assets, and that's been our focus to date.
Robert, let me make a couple comments. I think that for TransAlta, the mix is important right now. The contracted assets that we'll add from 2018 from Antrim, Big Level, and Windrise. Also having the discipline to project finance those with low-risk counterparties and to de-risk those cash flows effectively. The combination of that portfolio with what we're going into Alberta with, which will be Coal to gas and hydro that will be subject to a market. That mix together gives us a lower cost of capital at the corporate level and allows us to continue to have a strong balance sheet on the investment-grade side.
As we go forward into the 2020 timeframe, we look at, if I was to line up the returns of what Brett showed today on a hybrid against a merchant wind project, I would take the hybrid because I think it's going to not only provide capacity to the market and ancillary services, but it's going to provide a ton of energy. It's going to be the lowest cost energy in the market because of the heat rates. We would look at in the Alberta market, that investment would be superior to a merchant wind project. Now, when you go over to the Australia market, where our teams kind of look over there under John's guidance.
If you were going to build merchant renewables, you'd go to Australia where the gas prices are CAD 12, and they're still burning brown coal, and they're charging people CAD 100 a megawatt hour. That'd be the better place to take that kind of risk. I would take that risk if I could see us getting our cash back in two to three years. I would not take the risk on a wind farm where you need seven to eight years to get your money back in a merchant market. Because I think, as you'll see over time, this isn't next week, I shouldn't even say it because people will think it's next week.
Over a long period of time, as ISOs have to think about what it looks like to have more of these intermittent renewables, they'll have to change rules so that they get enough capacity. The net-net for our portfolio, I think our mix of assets is right, and we like that contracted. We'll have a certain amount of contracted projects in TransAlta Renewables because that gives us a better cost of capital at TransAlta.
I think the one thing we also didn't mention, just in terms of your ability to project finance the asset when it's built, which is something that-
Where you can
we focus on, I mean, with the merchant project, that's not something that you're going to be able to do, including with a contracted asset.
Right.
It fits into that space much, much better.
Yeah, remember, a wind farm in the capacity market doesn't get paid a lot of capacity. It's a very low amount. Also, wind, as you know, tends to get a price at a discount to the average price because of when it blows. When you factor all that, the risk-
Yeah
The inability to put project debt against it is a much higher risk scenario, you have to think about that when you're looking at those prices that the AESO awarded.
Understood. If I can just finish with, sorry, Dawn, do you want to sign off?
Sorry, does that help, Robert? Just give you our thinking anyway?
Yeah.
Yeah. Okay.
If I can just finish with slide 19 and the energy and capacity. What's the underlying capacity price assumption, 22 plus? It looks really high.
Yeah. Again, this is-
Dawn.
This is from EDC. I think their capacity prices, what you need to do is, this is all on a megawatt. They're probably in that 15-
Yeah
to even CAD 20 per kWh.
Okay.
You can just basically, if you took that amount on a per MWh, what I usually do is just, there is about CAD 85 million gigs to get to a revenue and divide by a clearing capacity in the 10,000. Once you adjust for UCAP, that will give you a rough kW a month. Divide by 12, obviously, to get it on a monthly.
Yeah.
I think you will get kind of in that zone. I have the numbers. I just do not have them right in front of me.
Okay. Do you have any thoughts kind of from a TransAlta perspective, where you think capacity might end up landing?
My only comment there is, again, we think the all-in price is an important way to look at it, because especially for plants that are going to run frequently, like hydro and efficient coal and are repowering and conversions. It really comes down to that historical rate of CAD 60 to CAD 65, we think all in is kind of the number to compensate people that are already in the market, but also when required, attract new capital.
Yeah, I think if you look at where things are going to go through the '20s, you're going to have to add new capacity in Alberta. I think as an economist, no matter what forecasters show, high prices never persist forever, and low prices never persist forever. I think there's people that have talked about a CAD 30 price, and I'm like, "Well, if Alberta doesn't want any power, I guess they'll produce a CAD 30 price." I don't think that's sustainable. I think the AESO in terms of its capacity market, has been trying to achieve something that ensures that you can get cost of new entry, you can get new entry. They don't, in my view, think of new entry as only coming from the incumbents using their balance sheets. They have to actually get new entry to be financed by others.
When I look at the cost of new entry, it's been in the CAD 60 to CAD 65 range, depending on what gas prices are for a long time. We tend to see that as our, kind of how we think what the opportunity might be. For planning purposes, we take the lowest possible price we can dream of, and then we drive our cost to that low price.
Got it. Do you know, is EDC then assuming that cost of new entry is driving the price or the unconstrained bidders versus all of you who are going to be constrained at, I think, 85% of net count?
Yeah, I think you'll have to pay for their service.
That's interesting.
We can't give you more than.
All I can say is those numbers that are, if you really want to get a new generator in, though, you have to have some capacity prices that are that high for some period of time where these guys are coming in and not making any money.
No.
Sally's telling us we have to go. We'll put Brett on the phone with you offline, Robert, after with more detail if you want.
That's great. Thank you very much.
Thanks so much.
Your next question comes from Charles Fishman from Morningstar Research.
Good morning. I just had one question left for Brett on slide 12. You show the decision of repowering as a 2019 deliverable. Will that decision occur this year? Will you wait, let the capacity market start up and, obviously, which would have an impact on the energy market, which I would assume would be the driver for that decision. Can you add a little more color there, Brett?
Sure. Yeah, for sure. Definitely we're full steam ahead here. As I said, we're just close to issuing limited notice to proceed, which really just finalizes the engineering work that we've been done just in more detail. We go to limited notice to proceed, and we start ordering equipment, which is really the long lead time. The actual outage, as I mentioned, is only approximately 60 days, but we do have to order the equipment and so on. From our perspective, as I said, there's so many benefits to converting that this is not a, "Oh, we're still wondering." This is where we're going as a company. The timing, as I said, on when and how many and what years is really just us managing our work levels and stuff like that.
As I said, we're not going to do them all in one year or all in one month and all at the same time. We're full steam ahead.
The repowering decision, which adds probably what? Five, six, seven hundred CAD kW. Would that be a 2019 deliverable, that decision?
Sorry. If that's what you're referring to. We want to do a bit more work. As I said, we've done sufficient work that we're pretty excited about it. We need to do a bit more work around things like, just on the steam side, on the steam turbine and some modeling efforts. That would be a more longer permitted project, no question. We had a Sun 7 combined cycle project from a few years ago. Combined cycle that we got fully permitted. By the time you permit and build, you're talking closer to 4 years all in. We hope, by this year, that we would have advanced that enough to make that call and lay that out for people.
Thanks for the additional color. That's all I have.
Thanks, Charles.
Thanks, Charles.
Your next question comes from Sean Noel from Family Office.
Hey, guys. Thanks for the great call. I have two questions, and I appreciate you taking my time. The first question is, how do you think about bracketing in the possible political risks to both carbon and capacity markets, given the changes in Alberta politically? How do you sort of frame that range of outcomes financially? Any color you have there would be helpful.
Okay. That is Dawn Farrell here. Two things that we think about. On the political risk side for the capacity market, I think what we know is that the capacity market recommendation has come directly from the AESO, who is the regulator here in Alberta, and who is one of the top and most respected AESOs in the world. We know that AESO made that recommendation independently, and it was accepted under the current government. We know that the party that would like to be the new government also has a very high respect for the institutions in Alberta, the regulatory institutions in Alberta. I gain my confidence in knowing two things. One, that the leadership at the AESO is exceptional, and that their commitment to replace the existing PPAs with a market structure that will ensure that we have enough capacity and reliability in Alberta.
As you know, high reliability at low prices is the lifeblood of a competitive economy. I take my confidence in the respect that people have for them and that it's their decision, and it was their decision under the current government, and if the current party that would like to get to be the new government, it's their philosophy as well to respect regulators. That's on the capacity market. On the carbon levy, under the old conservative government, who's now the UCP, they had put in place a high emitter's tax. It was called a SGER. It had a somewhat similar form to what we have today. It wasn't as high as the one that we have today, but it certainly was there. We do know from discussions that there is a high probability that there will be some sort of a price for carbon emissions in Alberta.
We also, in our federal government, under the federal backstop, there is a carbon price. If any provincial government currently in Canada decides that they want to not have some sort of carbon price, they fall into the federal backstop, and the federal government actually sends the carbon bills to consumers. You see that going on in Ontario right now. Everything is pointing towards having a price for carbon on coal.
I think finally, the way we look at it is, clearly investors will support the cash flows coming out of a gas fleet, and they'll, I think, pay more for those cash flows than they would cash flows from a coal fleet, because they see those as being transient in nature and short-term because there's no stopping moving, I think, from higher carbon intensity ways of making electricity to low or zero carbon intensity ways of making electricity. We handicap it as a high probability of a capacity market and a high probability of some sort of price on carbon.
Okay. That's really helpful. One other quick question, plus something on hydro. I guess the other question on the repowering opportunity, CAD a couple hundred million of additional CapEx potentially there. How do you think about financing that? I just want to make sure there wouldn't be some sort of equity component there, obviously, given where the stock is.
No, we do not think about financing it with equity. I can say that clearly. Clearly we're just balancing our capital decisions as we go forward. We've got good capacity in the company.
Just on the other point, remember, it's spread out over time because it is a longer-term project. Secondly, as we indicated, we may not do some other projects instead. We're saving some capital on those projects that would go towards this. As John mentioned, the returns from our perspective are very good and these would be more starting later, even post 2020.
Yeah. I think people will need to think about it this way. We finance a significant amount of coal turnaround capital every single year in this company to keep these coal plants running. When you're financing the coal plants turnarounds, you're not just fixing the boilers after the [sub-floors] have made holes in them, but you're having to put significant capital into the mine. You're having to put capital into all the coal handling equipment, all the grinding equipment, all that sort of thing. The sooner that you can stop doing coal outages and you can actually do an outage where you do sort of a final piece of work on the boiler and you put in the new gas burners, you lower your capital significantly. There is some incremental capital for sure for the new burners and then getting the pipe into the plant.
It is offset by capital that's significant if you stay on coal. We're actually able to finance it indirectly through not spending money on the coal plant. Not entirely, but it's a marginal amount. Not marginal, I mean, it's a couple of CAD 100 million, but it's not significant relative to our current sustaining capital that we spend today. I hope I was clear there. Sorry if I wasn't.
Yeah. No, that totally makes sense. That helps a lot. Then just another quick question on the hydro. I just want to be clear, the home for that is TransAlta. There's no current discussion to drop that into renewables or something, right? Given the-
That's correct.
non-contracted nature?
Correct.
Okay.
That's correct.
Okay, great. Guys, keep up the good work. That's it for me.
Thank you.
Thank you.
Your next question comes from Mitchell Moss from Lord Abbett.
Hey, guys. Thanks for the very detailed slides and the long Q&A. Just talking about coal to gas, you guys have discussed the five to six Or I think a CAD 6 capacity price or a CAD 60-CAD 65 all-in price. Would you say that those are reasonable price levels or sufficient price levels for you guys to invest in the repowering to a combined cycle?
Yeah, for sure. Given that the capital is significantly lower than a new combined cycle, that's a repowering. If you take the actual conversion, boiler conversion, it's extremely low capital. As I said, we save a lot of money not having to do NOx and SOx and a whole bunch of other things. At those prices, yeah, things are very good. A new one, obviously, you double the capacity capital, so you would need more. You wouldn't get as good of a return at the same price.
Okay. It would be sufficient, though, to turn it into a. I just want to make sure there was also some confusion from an earlier question on boiler conversion versus a full combined cycle repowering. You're talking about the combined cycle repowering, correct?
Yeah. Remember, the boiler conversion effectively is just replacing the coal burners with gas burners, so relatively straightforward, small dollars, relative dollars, short outage. But you don't get the benefit of the lower heat rate. The repowering is putting new combustion turbines, gas turbines, effectively, and HRSGs to generate not only power but steam. We then take that steam and run it through the existing steam turbine that's being fed by that boiler today. We dismantle the boiler, but we utilize the steam turbine and the transformer and a lot of other capital and infrastructure that's already there. As a result, that's quite a bit lower than having to build a brand new, where you have to build a steam turbine as well, includes the steam turbine as part of the package. Two different capital profiles, but one has better heat rate and longer life.
The other one is very low capital, but you don't change the heat rate dramatically. Both are good economic projects. Remember, even if you do a boiler conversion and run it to the end of the legislated life, if that steam turbine's still in good shape, one can do the repowering on it, and now you've extended the life of that unit as well. That's farther down the road, clearly.
Think about it this way. A capacity market demands two products. It demands low-cost capacity and low-cost energy. The simple conversions are directed towards low-cost capacity, and the hybrid is really smoking hot low-cost energy. We believe that a portfolio with those two products in it is really competitive, and that's why we've decided to spend some resources this year to see if we can get one of these hybrids off the ground because of the way lower cost that they have relative to a brand-new combined cycle.
When you talk about the two units, is this going to be the potential is both Sundance and Keephills could be converted to one by one?
I think our focus on the one by one, or it could be a two on one, is more on Sundance. Because remember, there are higher heat rate units. Keephills one through three are newer plants, lower heat rate plants. If we do the repowering, it's highly likely one of the Sundance units, and that's what we're focused on.
Okay.
We have four units at Sundance and three at Keephills, we have seven units to make decisions on.
Okay. When you talk about two units, that's not the whole plant. It's potentially just certain units within.
Yeah. That's right.
That's right. Gotcha.
Okay. We've got two more people, and There's a hook coming in the office. We can get on the phone with anybody after as well. Okay.
The next question is from John Mould from TD Securities. Your line is open.
Good morning. I'll keep it quick. Just going back to slide 19, can you just clarify if the carbon pricing assumption in those estimates rises to CAD 50?
Yep. Oh, sorry. On the forecast?
Yeah.
Again, you'll have to purchase the
Fair enough.
All I can tell you is on the EBITDA sensitivity one that we showed as well for both hydro and coal, that you'll see in the footnote what we assume there. We assume the existing provincial program and CAD 30 per ton prices.
Okay. Then just lastly, on the federal backstop mentioned a little earlier. You're not subject to it today, but conceivably, you could be one day. Can you just maybe provide some color on your comfort with how that framework has evolved relative to the CCIR, particularly as it relates to your hydro facilities?
Yeah, for sure. We're obviously very involved whenever there's regulations and very thoughtful in terms of how we think about these things and approach them and work with other participants. It's not just industry, other people that have an interest. From our perspective, the backstop program is good. It's a declining proposal, so it starts higher than what the provincial one does today, but it declines essentially to where the provincial one is, I think, right in 2030, and which is essentially a combined cycle type of unit. From our perspective, our strategy fits nicely into both programs. We would have less and maybe even no carbon obligation on a converted facility for the first few years under the federal program, just because we would be coming in below the level until it declined every year. Both are fine.
Certainly the federal is a good one.
Better.
It's better for converted facilities, for sure. It doesn't change a combined cycle or a gas plant. They're both at around 0.37, they're unaffected. It really impacts coal and coal to gas and co-firing.
Okay, great. I'll leave it there. Thanks for the extended Q&A.
Thanks, John.
Thanks for waiting. Thank you.
Your next question comes from Naji Beydoun from Industrial Alliance Securities.
Hi, good morning. Just a couple of brief questions. Could you go back to the Sundance 4 Unit? I think the previous question on mothballing was the change in the outlook. Could you just talk about how we should think about the maintenance work and the outlook for the unit for the year, and does it impact your guidance at all?
Remember, currently mothballed is Unit 3 and Unit 5, and they are mothballed currently till the end of March of 2020. 4 and 6 are the only 2 units from Sundance that are currently operating. In our disclosure, I believe we outlined our planned maintenance for which units we have. Sun 4 does have a bit of an outage that will go into that unit this year. I think the other one, we have one of the Keephills units. That's in our disclosure. Is that what you're referring to?
Yeah, just any units that are mothballed, there's very minimal expenditure and they're captured inside our guidance. Our guidance has not changed at all for this year on anything.
Okay. Got it. Thanks. Just to wrap up, final question on the additional updates on the hydro assets and the progress on the coal-to-gas conversion. Appreciate the additional color that you provided today on both of these. Just wondering, what do you see as the significant risks to the outlook on both of these initiatives?
Look, any projects involve a lot of effort. Right now, as Dawn says, we try to model multiple scenarios. The conversion, you got to remember, we always compare it first against staying on coal. Based on all those things I walked you through, it makes a lot of economic sense. We test a lot of different price scenarios, both on gas, carbon, energy capacity, and these all make sense. We look at how much capacity is needed in the market going forward. That's why we also look at things like repowering and so on, and do a mix of that going forward. There's always a risk. I would say the main risk is just, we don't know what the energy and capacity prices are going to be. We can only do our modeling, and they will be what they will be.
As Dawn says, we're setting these plants up to be very low cost, both from a capacity and an energy perspective, in a market that needs this kind of capacity. You got to remember, a lot of people live here in Alberta. It's a heavy industrial 24/7. You need power all the time, and you can't do that, unfortunately, with all wind.
Yeah, I think that's it.
Appreciate that. Thank you.
All right, thanks.
Thank you.
Thank you.
There are no further questions at this time. I'll turn the call back over to our presenters for closing remarks.
Thank you, Mike. Thank you, everyone, for joining us today, and particularly thank you to all those people who patiently waited to ask questions. I know it was a bit longer today. I would just like to reiterate, as usual, anyone who has further questions, please do not hesitate to reach out to either myself or Alex in Investor Relations. We can set up a call if you have further questions that we can't answer. Thank you. Thank you, everybody.
Goodbye.
Bye.
This concludes today's conference call. You may now disconnect.