TransAlta Corporation
Q2 2020 Earnings Call Transcript

Published: 1 Aug 2020

[Operator:]

Ladies and gentlemen, thank you for standing by and welcome to TransAlta Corporation Second Quarter 2020 Results Conference Call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question-and-answer session. [Operator Instructions] Please be advised, today’s conference is being recorded. [Operator Instructions]. I would now like to hand the conference over to Chiara Valentini. Thank you, please go ahead.

[Chiara Valentini:]

Thank you, Chris. Good morning, everyone and welcome to TransAlta’s second quarter 2020 conference call. With me today are; Dawn Farrell, President and Chief Executive Officer; Todd Stack, Chief Financial Officer; John Kousinioris, Chief Operating Officer; and Kerry O’Reilly Wilks, Chief Legal, Regulatory and External Affairs Officer. Today’s call is webcast and I invite those listening on the phone to view the supporting slides that are posted on websites. A replay of the call will be available later today and the transcript will be posted to our website shortly thereafter. All the information provided during the conference call is subject to the forward-looking statement qualification set out here on Slide 2, further details 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 comparable EBITDA, funds from operations and free cash flow are also reconciled in the MD&A for your reference. On today’s call, Dawn and Todd will provide an overview of the quarter’s results, along with expectations for the balance of the year. After these prepared remarks, we will open the call for questions. And with that, let me turn the call over to Dawn.

[Dawn Farrell:]

Thanks, Chiara and welcome everyone to the call today. We are presenting our results today from our offices here in Calgary. So as of last Monday, all our employees are now either back in their offices here or at the plants across our locations in Canada, United States and Australia. I cannot tell you how great it is to be here today, presenting a strong second quarter, along with all our people safely back at our sites and doing what they do best, which is working to deliver low cost, reliable and clean power to our customers and communities. Our TransAlta employees are all leaders here at work and in their communities and families, as they have quickly learned how to practice COVID safety protocols, which are keeping us safe and allowing us to see each other in person, of course, while maintaining a two meter distance. We’re very excited to report results for the quarter that are solid. Our quarter is only slightly below what we expected to be able to do in a pre-COVID world. And this is actually exceptional when one step back to reflect on how much different the world is under the cloud of the pandemic. It is a true testament to the diversity and stability of our portfolio and the resilience and tenacity of the employees who work at this company. When we left the offices in early March, we were facing into a significant drop in power demand in almost every jurisdiction we either operated in or traded in. We immediately set up systems to measure our liquidity, because we needed to be able to assess the ability of our customers to pay their bills. We also saw reduced volatility in electricity pricing in every jurisdiction, which could have impacted the ability of our trading business to deliver their results. And of course, we were worried about the safety of our employees, many of whom had to continue to go to the plants, and many had to stay in their homes, where they did their work in mix shift offices, while taking care of their families. I’m very pleased today to tell you that many of our concerns simply did not take hold. We are reporting our second quarter that is strong, with excellent safety and operational results and stronger than expected revenue in our Alberta business, due to some great hedging by our asset optimizers. We had outstanding performance in our trading business, which delivered one of the strongest Q2s in recent history. Our trading operations ran smoothly, albeit from their homes, and our plants achieved strong availability, all while dealing with the uncertainty of a pandemic, and the challenges of having kids out of school. As we look at the cash that we generated in the first half of the year, and what’s to come as we look ahead, we’d continue to close in on our goal of reducing senior recourse debt to CAD1.2 billion by November. You all know that we’ve been after this objective for several years now and cannot wait until our fourth quarter call to tell you that it’s finally been done and dusted. We’re also confident that we can complete our investments under our strategy without the need for additional funding. So our highlights of the second quarter include, delivering CAD217 million of EBITDA and CAD91 million a free cash flow or CAD0.33 per share results that were ahead of 2019 by 94% on a per share basis. We achieved strong availability and safety performance. The entire fleet had an average availability of 90.7% for the quarter, up from 83.8% last year, and year-to-date, we’ve achieved a safety result of 1.4 on our total injury frequency rate, which is great performance. We delivered strong operational performance. Well, all our plants’ staff showed up every day, and worked together under COVID-19 protocols that were approved by our local health authorities in each region. We are deeply grateful to the men and women in our health authorities across our sites, who worked side-by-side with us to develop safety protocols that kept our workforce in the field and head office safe. We needed to provide electricity for the economy and our customers. And they built our confidence around what people can do together if they’re willing to follow a few very simple rules. They also helped us continue with all our construction projects and we are moving ahead on every project with very few delays. Now, unfortunately, COVID had a negative impact on the stock price of almost every Alberta company, as it had such a tremendous impact on oil demand, oil pricing and oil production here in Alberta. As such, we use that as an opportunity to use our NCIB to return an additional CAD12 million of capital to our shareholders with our share buyback program and year-to-date, we’ve returned approximately CAD21 million to shareholders at an average price of CAD7.51 per share. Our finance team did an outstanding job of managing cash and our long-term contracts with our customers were excellent. Any worries that we had about the depth of this crisis were set aside through the quarter as all our customers continue to pay their bills. We ended the quarter with continued strong liquidity at CAD1.6 billion, which includes approximately CAD250 million of cash, and we’re poised to repay our 2020 bond maturity later this year without further funding requirements from the markets. So just a few words on our strategic priorities. We continued to track on all our priorities with very little delay or very little change in timing. Our strategy continues to focus on delivery in our pipeline of investments regarding our coal-to-gas here in Alberta, our wind and our cogeneration projects. On our coal-to-gas strategy, we are set now to kick off the Sundance six conversion in September of this year, as both Keephills conversions are on time and getting ready to go in the 2021 period. We also continue to advance our gas supply strategy here in Alberta and based on that progress, we now do not see a need to complete a dual-fuel conversion on our K 3 unit, and that unit will be fully converted to gas only in Q3 of next year. This slightly reduces our capital requirements for that project. We’re progressing the repowering of Sundance unit 5, and have advanced the competition for the EPC contract and expect to receive bid proposals here in the fall. We gave notice to retire our currently mothballed Sundance unit 3 coal-fired unit out of the market by July 31st 2020 today. This decision was largely based on the condition and age of the unit and our flexibility and options around repowering our units and our existing generation portfolio. This is another milestone in our transition plan to get to a 100% clean energy by 2025 and closing the chapter on our coal-fired generation. On the cogeneration front during the quarter, we finalized the acquisition of our first cogeneration facility in the United States. We welcome the Ada facility located in Michigan along with the new customers, Consumers Energy and Amway. This marks our first toehold in the US in this segment as we progress on our on-site generation goals. On our Kaybob project with SemCAMS, we are on track to start construction in early fall. Factory tests of the gas turbines have been completed and we have major equipment delivery set for later this year. On the renewables front, we have construction underway on both wind drives and wind charger. We expect to reach COD on wind charger in a few weeks, bulk of the equipment is now on-site and installed and we’re progressing with the factory testing on the transformers. On Windrise, site construction commenced as planned in April and is tracking well with turbine deliveries expected later this year. Our diligence and compliance to COVID-19 protocols remains solid to-date, which enables that project to continue. Skookumchuck now has 18 turbines up, with 8 mechanical completion certificates issued. The first circuit of 6 turbines have been energized and the rest are expected to commission in the next quarter. And we’ll make our decision on our option to buy 49% of the project sometime during the quarter. As we look towards the balance of the year, we continue to have confidence in our 2020 free cash flow guidance. Todd will talk you through our views of the second half recovery in power demand here in Alberta, as everyone returns to their offices and schools. And if all goes as expected, we also expect to hit the lower end of our EBITDA guidance. I do have one last comment before I turn it over to Todd. We did see particularly weak Alberta spot market prices in June due to short-term disruptions in supply and demand. Lots of supply due to both high winds and lots of hydro coming into the Pacific Northwest, Albert, of course, through our line. Demand fell by almost 1,000 megawatts in March. It has recovered somewhat since then. But June was a month with lots of supply and an unheard of level of demand destruction. Spot prices in the Alberta market in June are not an indicator of the future, which we will talk you through today. What you’ll see from Todd today is that our diversified fleet, our level of contractiveness and our approach to asset optimization, mostly offset these shorter-term headwinds in the Alberta market. TransAlta’s diversified EBITDA, our free cash flow, our liquidity and the fact that we have our strategy fully funded, allows us to be one of the few companies globally that can deliver on our investment plans, with very minor changes in timing and on the path that we set prior to the full impacts of this pandemic, but pretty remarkable in my view. So with that, I’m going to turn it over to Todd for more color on the financials. And then we’ll all come back with questions for the team.

[Todd Stack:]

Thank you, Dawn and welcome to everyone on the call. I’ll start by reviewing the financial highlights on Slide 6. During our Q1 call, we indicated electricity demand was expected to remain low and that merchant power prices would be weak in Q2, which they were. While these conditions impacted or these conditions impacted our merchant sales, our fleet wide operational and financial results for the second quarter of 2020 continued to be strong, and we’re indicative of the resilience of our operations, our hedging and marketing capability and our portfolio diversification. During the quarter, we generated CAD217 million of EBITDA, which was in line with the same period in 2019, despite the challenge of lower electricity demand. As I will highlight later on merchant sales from our Alberta coal segment represents a relatively small contribution to the company’s overall EBITDA. Our EBITDA in the quarter was generated by strong and predictable contributions from our gas and renewable segments, combined with strong cost controls and performance from our energy marketing team. Free cash flow also improved by CAD42 million year-over-year to CAD91 million in Q2 versus CAD49 million last year. On a per share basis, we delivered free cash flow of CAD0.33 per share in the quarter and exceeded 2019 results by 94%, which was in line with our expectations. Stronger free cash flow was largely attributable to reduce capital spend on major maintenance with two outages in Q2 2019 versus no major outages in 2020. Year-to-date, we’ve generated CAD200 million of free cash flow or CAD0.72 per share, a 41% increase over 2019’s six month performance. This is an exceptional result for the company and one of the strongest first halves in the last decade. Turning to the Alberta power market, spot market Alberta prices – power prices in the quarter averaged CAD30 per megawatt hour and we’re considerably lower than the second quarter of 2019 which averaged CAD57 per megawatt hour. However, our merchant units at Alberta thermal were able to continue to realize revenues in the mid 50s due to our financial hedging and dispatch optimization. As Dawn said earlier, the province had significant supply available from both within the province as well as from imports. In the province, supply was strong due to fewer planned outages and strong resource supply from the wind and hydro segments. During the quarter, we also saw significant low cost imports into Alberta from excess hydro and wind production from the Pacific Northwest. Electricity demand was impacted throughout Q2 by COVID-19 and the continuing impact of lower oil prices on demand. We estimate load reductions peaked at about 1,100 megawatts, that is now trending in the 500 megawatt to 600 megawatt range versus 2019. As we’re moving through the summer, we’re seeing demand recover week-by-week as the economy starts to reopen. Over the past several weeks, we’ve seen many offices and businesses reopened, and people returned to restaurants and other attractions. We expect this to continue through the fall as kids go back to school and some of the shut in oil production is brought back into the market. Our Alberta coal baseload generation is now completely hedged for Q3, and we are partially hedged for Q4, which is the right position as we see prices recovering somewhat to reflect the increases in demand from increased economic activity. For the Alberta market, when we look ahead to 2021, we could hedge volumes if we wanted into the CAD51 per megawatt hour range. That market is thinly traded and will begin to adjust as the market gets a sense of how demand is recovering over the second half of this year. We aren’t a seller at these prices for the following reasons. First, there significant number of plant outages scheduled in 2021 as many of the coal units have planned outages to be converted to gas or dual-fuel. These outages will naturally tighten supply-demand balances in the province. Second, we expect the provincial carbon tax to increase to CAD40 per ton to remain in line with the federal program. This raises the cost of production and has to be recovered through higher power prices. Third, the Alberta power purchase arrangements will transition next year. Six generating units representing roughly 2,400 megawatts of mid merit thermal capacity are currently dispatched by the balancing pool and contracted under the existing PPAs. Beginning in January, the owners of the PPA assets will now be in complete alignment with the risks of owning, operating and investing in the assets. In order to recover capacity costs, we anticipate plant owners who will structure their energy offers accordingly to reflect the recovery for return of an on capital, as there is no mechanism outside of price – of energy to do so. We were pleased to see the clarification provided by the MSA Enforcement Statement in late June on economic withholding. The MSA provided that in an energy-only electricity market, the pool price must sometimes exceed short run marginal cost, if the cost of generation capacity is to be recovered from the market. This will be the first time in the Alberta market that this new alignment in ownership and clarity and rules will play out in terms of price formation. And finally, as the economy reopens, we see increasing demand as schools and businesses ramp up to higher levels. Increasing demand generally correlates to increasing prices. As an aside, when you study the cost structure of the generating units in the market, and where demand crosses supply, the average price often settles in the financial and spot market to an average of CAD60 per megawatt hour. Next year, we expect additional volatility, so taking an average price times volume will not tell the tale of how we’ll do in the market. For our fleet, peaking plants and hydro will make their money as prices increase during periods of tightness, due to outages, demand and weather. We do expect the market to settle closed to a historical average, but our job will be to position ourselves to increase margins in periods of volatility. We had strong operating performance across the generation fleet and segmented generation cash flows improved year-over-year by 16%. This was led by expected strong performance from our US coal segment and the increased contribution from the wind segment. Overall, we continue to produce strong cash flows across all of our fuel segments, with our largest contribution this quarter coming from the wind and solar segment, which has contributed about 30% of our segment cash flows so far this year. Wind and solar EBITDA improved in the quarter primarily due to the full period contribution of Antrim and big level wind facilities, which were commissioned in December, along higher production due to excellent wind resource across all regions. The US coal segment returned to normal results for the quarter and were substantially higher than the second quarter of 2019. We’ve benefited from lower price power purchases and strengthening of the US dollar relative to the Canadian dollar. For the remainder of the year, we continue to expect strong results for the segment as the majority of our production is hedged. Cash flow from the Alberta thermal fleet was in line with 2019 and represents about 11% of our total segment cash flow. Although EBITDA declined by CAD36 million, this was offset by lower maintenance capital spend resulting in strong segment cash flow. EBITDA in the segment was also impacted by a CAD7 million increase to a provision in fuel and purchase power, relating to the Alberta ISO line loss dispute for transmission losses for the years 2006 to 2016. Many of you may not recall this proceeding, so let me take a minute to go through it. This regulatory process has been ongoing for over a decade and relates to how the ISO used to calculate transmission loss fees for all generators in the province. During Q2, the ISO was able to provide the results for the recalculations of 3 of the 11 years under dispute, which allowed us to better estimate the potential impact. In total, we’ve recognized the CAD20 million provision relating to this dispute. The estimated amounts continue to be uncertain and the ISOs recalculated loss factors remain subject to further review and change. Revenue from the Alberta thermal fleet in the quarter averaged approximately CAD65 per megawatt hour and was fairly consistent with last year. We were able to maintain our per megawatt hour revenues through capacity payments on our PPA units, as well as from significant hedging and dispatch optimization in the quarter. Strong per megawatt hour revenues were offset by increased fuel costs of CAD40 per megawatt hour compared with CAD33 last year. A portion of this increase about CAD3 is due to the recognition of the transmission line loss provision. The residual increase is related to higher year-over-year gas prices and our fixed coal costs now being spread over lower volumes as a result of lower production in the mine in the quarter. We had strong production from our hydro segment in Q2 due to strong seasonal runoff. But with an oversupplied power market, there was limited opportunity to capture any price premiums. Realized prices in the quarter for energy and ancillary services were off compared to our historical averages due to lack of price volatility. Our energy marketing segment exceeded last year’s quarterly performance by CAD10 million. Results were changed through short-term strategies across our various geographic regions in both the power and natural gas markets. Our corporate segment incurred a quarter-over-quarter favorable run rate impact of CAD5 million due to lower operating costs. After including for the impact of the total return swap, our corporate segment cash flows decreased by a total of CAD12 million compared to 2019, an excellent results for the segment. For the quarter, our segmented cash flow of CAD191 million was ahead of 2019 by CAD47 million. And as I discussed earlier, the company generated consolidated free cash flow of CAD91 million, an increase of CAD42 million compared to the same period last year. As Dawn mentioned, liquidity at TransAlta is very strong and has been for some time. We ended the quarter with CAD1.6 billion liquidity, including approximately CAD250 million in cash. In addition to the current liquidity, we will be receiving CAD400 million from the second tranche of financing from the Brookfield investment in the fourth quarter of 2020. Our strong liquidity position sets us up well to repay our upcoming bond maturity, and to continue funding our coal-to-gas program and advance our renewable development projects. With respect to our share buyback program, year-to-date, we’re repurchasing cancelled to CAD21 million in shares, which is tracking with our capital allocation strategy for 2020. As you can see on Slide 10, over the past few years, we’ve been focused on reducing our corporate debt levels in preparation for a fully merchant market in Alberta. We’re on track to meet this goal in November and continue to be comfortable with our current debt levels. On Slide 11, I’ll provide an update on our long-term contract and hedging levels. Year-to-date, we’ve realized CAD437 million of EBITDA which is in line with 2019. For the full year 2020, approximately 90% of our EBITDA has been realized to-date or is contracted or hedged for the balance of the year. We continue to manage the remaining EBITDA contribution for merchant production through hedging and optimization. Looking at our merchant exposure in Alberta, 75% of our thermal baseload generation is hedged at CAD53 a megawatt hour for the remainder of the year. For Q3, we are fully hedged in our baseload generation, which provides the company protection from the near-term fluctuations in power prices related to the COVID-19 pandemic and resulting weaker energy demand. As we look to the final quarter of 2020, we are opportunistically adding additional hedges and are closely monitoring the recovery in power prices to take advantage of this on our open exposure. At these current hedge levels, we estimate that a CAD1 change in Alberta power prices would result in an approximate CAD2 million change in EBITDA. Given the unprecedented impact of demand in Alberta, we currently expect EBITDA to be at the low end of our guidance range. This is primarily driven by the limited ability to sell additional merchant megawatt volumes into the market until the economy fully recovers. At the same time, we also expect sustaining and productivity capital to be at the low end of our range as we’ve been able to respond with adjustments in our capital investment plans. These reductions combined with our year-to-date results give us confidence and achieving our full year free cash flow at the midpoint of our outlook. Before I close off my section, I just wanted to summarize the strength of the quarter. The performance of the business and our people over the last three months demonstrates exceptional performance, a strong commitment and significant resilience. Our business model and operating practices came through Q2 with flying colors. And not only are we able to see that in the health of our employees, but also in the health of the company. As we look forward, we have confidence that our business operations and portfolio are well positioned to respond to the challenges and opportunities that lie ahead. Given our ability to navigate the impact of this pandemic and delivery of our cash flows, we have every confidence in our business model as we look towards the back half of 2020 and into 2021. Our strategy is on track can be completed with little delay and within the financial resources we have raised to-date. With that, I will pass the call back over to Chiara to start the Q&A.

[Chiara Valentini:]

Thank you, Todd. Chris, would you please open the call for questions from the analysts?

[Operator:]

Certainly. [Operator Instructions] Our first question that comes from Rob Hope with Scotiabank. Your line is open.

[Rob Hope:]

Good morning, everyone. I just want to follow up on your comment about setting behaviors into 2021. Just taking a look back at Q3, you know, and I guess year-to-date in 2020, you know, we are seeing some of the balancing pooled, unit dispatched more than I would have expected. So, you know, do you think there will be – do you think these are currently being bid economically? And do you think there will be a large shift in 2021 with the new directions?

[Dawn Farrell:]

Yeah, let me start with that and then Todd and John can jump in, because it’s something we’ve been looking at closely. I really can’t comment on what the motivations are of the balancing pool. They do have when you look at the structure of the PPAs they have – they – remember those PPAs were set up in 2000. And so they really do have quite a different economic signal in them, than what it looks like when you actually return the PPAs back to all the owners. So what we’ve looked at is a couple of things, you return everything back to the owners and effectively, you know, people do have to recover their costs, and they have to recover a capacity payment somehow in the market. And they have the right to, you know, to recover the capital that they’ve invested. People have forgotten that the original PPAs did not have recovery of sustaining capital in the last five years or so. And the theory at the time was, that if the generators wanted to continue to reinvest towards the end of the PPAs, it was really on their dime to do that reinvestment to set up the units for the coming market. So if you put that all in a big pot and stir it, what it really means is, as everybody gets their PPAs back, they really, you know, start to bid the proper cost structures into the market, the proper return. So of course, there’ll be a competition for what that return might be depending on supply and demand conditions. But that we finally get the full fundamentals of that energy-only market. So we’ve done a lot of analysis on that, and when we look at that, that’s where you start to see things like the impact of a CAD40 carbon price comes into effect. And then you also see that kind of generally the generators all have pretty similar cost structures. So at the end of the day, they’re all going to be equally motivated to get – to ensure they get their costs out of the market. Does that make sense, Rob?

[Rob Hope:]

Yep, that’s great. And then the follow up question, just how are you thinking about deploying capital? You have a bunch on the balance sheet, you got Pioneer coming in soon. You know, when you look at the fact of opportunities in front of you, you know, how do they rank? You know, could we see do some contracted or merchant renewables in Alberta further cogen M&A development in the US, how are you thinking about deploying capital?

[Dawn Farrell:]

Yeah, I mean, there’s some really, really interesting opportunities that, you know, we’re seeing in the marketplace. I mean, we’re generally quite focused on serving, as you know, we don’t retail power, we sell to retailers. But we’re really quite focused on the large commercial and large industrial sector. And, you know, just through the pandemic, I think people have often wondered whether or not the ESG framework will remain or will it get kicked aside and what we’re seeing is, you know, investors are even more – they find it even more important to ensure that they reduce the risks of what the size may bring, which means that all companies are focused on how do they create some sort of path towards lower greenhouse gas emissions. And so, we see opportunities here in Alberta with our large oil and gas customers. We see a lot of opportunities across the United States, almost everywhere go, you know, even this, you know, having Amway as a customer, it’s pretty cool, these guys are, they’re growing their businesses based on what they see as the future. And of course, as a result of doing that, they want to make sure that they’ve got power behind that business that’s sustainable. So lots of opportunities here in Alberta, but also in the US.

[Rob Hope:]

All right, that’s great, thank you.

[Operator:]

Our next question is from Patrick Kenny with National Bank Financial. Your line is open.

[Patrick Kenny:]

Yeah. Good morning, Dawn, maybe just a follow up on the capital allocation. So you’ve had success in signing up the big corporate offtakers for renewable capacity. I’m curious to your thoughts on being able to leverage off your existing relationships with Microsoft and others to you know potentially accelerate your clean energy transition and take advantage of the strong growth being experienced across the tech industry? Then I guess if internal capital is a constraint to take advantage of that growth, you know, how you might think about bringing in partners or other external sources of the capital?

[Dawn Farrell:]

Yeah, so couple of comments on that, Patrick. So first of all, one thing you want to look at when you look at our Alberta portfolios, we actually – we have – there’s not a lot of green power here in Alberta and we’ve got most of it, like we’ve got kind of 90% of it between our hydro and our wind assets. And of course, you know, when we’re finished with Sun 6, we have a way to back it up with clean gas. So that is something that we really see as a big opportunity for existing customers that we’ve got long-term relationships with here in Alberta, that’s number one. Number two, when you look at the Microsoft and the tech industry, they are highly sought after, like everybody in their dark wants a contract with Microsoft. So those returns tend to be bid really, really thin. Not that we don’t want to compete there. But when you’re thinking about capital allocation like you are, you want to go where your highest returns are. And typically what we’re finding is, go back to our little Michigan, a project which you know, everybody goes, oh, why do you want to invest USD27 million and a company like that, blah, blah, blah, it’s too little. And I’m looking at it going, yeah, behind that is a really big supplier of products to the market in Amway, and if we could capture them as one of our – if we became their preferred supplier on green electricity, that’s a massive move for us. So as we look at the customer business, we do – we are starting to really partition and say to ourselves, who actually needs us the most? Who needs our skills? Because our skills are a combination of how do you trade energy? How do you build new energy? How do you bring green credits and offsets? How do you understand the regulations around offsets? How do you bring that whole mix together and then provide something to your customer? And we find actually the industrials who are retooling their businesses to have – to be better prospects for us because they need us more and most people aren’t focused there.

[Patrick Kenny:]

Okay, that’s great, Don and maybe just a follow up for Todd. You know you mentioned the Alberta merchant contributions continue to represent a smaller portion of overall cash flows. But I guess this looks to be putting some pressure on your deconsolidated leverage ratios. So, you know, until power prices recover, there might be a delay here and getting down to that sub 3 times target. Just wondering, does that impact at all the priorities with respect to dividend policy share buybacks or debt repayment as you look to refinance that ‘22 bond coming up there?

[Todd Stack:]

Yeah, no, I would say actually no change to any of our capital allocation plans that we talked about, I think it was last September, we announced on our deconsolidated basis. You’re correct although our – I think our deconsolidated cash flows are actually very strong and stronger than they were prior quarter or as it compared to 2019. What we’re really looking at is reinvestment in the coal-to-gas is consuming some capital right now. And so we really need to get through some of that program. And similarly, we will see higher deconsolidated free cash flows once the hydro comes off PPA at the beginning of next year, that’ll be a significant contribution to that deconsolidated cash flow.

[Patrick Kenny:]

Okay, great. Thank you very much.

[Dawn Farrell:]

Thanks, Patrick.

[Operator:]

Our next question is from Ben Pham with BMO. Your line is open.

[Ben Pham:]

Great, thanks good morning. Just a question on the hydro PPA that expires like this year, please going on that here the production from that facility. Is that going to be part of your hedging program with some of your storage slots on a river that can lead mostly open exposure?

[Dawn Farrell:]

So I’ll start and then John can add. I mean, you’ve got to think about that hydro has several different streams of revenue. But if you’re just thinking about the sort of energy component in the capacity, remember that in the spring, there’s big runoffs we never know quite when it is. We never know if it’s going to be, you know, in May, April, May or June, it depends. I’ve, you know, in Alberta, it’s been 30 above at the end of April, and sometimes it’s a cool spring, and the runoff doesn’t come until June. But net-net, that energy that comes, it’s more run in the river is more energy. And it is – some of it is tangible in our program. And then there’s the storage component of it, which is really what we use for both ancillary services and then selling into the market when – like last week when the market was really high, our hydro loves those days, right. So it’s the asset optimizers do a lot of risk probability assessments and then they decide how much they’re going to hedge. Maybe John do you want to add to that?

[John Kousinioris:]

Yeah, Dawn. I mean I think that Dawn answered it well. There is a component, I think of it as a strip effectively of the anticipated generation that we had through the year that we do view as being baseload like, if I can use that sort of expression it would factor into the work that the optimization team does from a hedging perspective for sure.

[Ben Pham:]

Okay, great. And anything although what was some of that reserved pump storage project that gain a lot of rates about a year and a half year ago, there’s been some activity around PC energy buffering in Alberta and some stuff going on Ontario would love an update there, if there’s anything.

[Dawn Farrell:]

You must be in the wilds of transitory event. So everybody knows it, Brazeau. So it’s the CEO’s favorite project and she’s going to find some way come hell or high water to figure out how to make it go, because when I look a headband, I – what I see is, you have to go, you know, in over 20 years, it’s not going to happen tomorrow, but over 20 years in Alberta, you’ve got to go from natural gas and renewables much more towards storage and renewables. To me that if the truth is that Canada as a whole is going to go after net zero by 2050, Alberta produces the most greenhouse gases, our oil and gas industry needs us to find the cleanest way to produce electricity so that they can continue to sell oil and gas. So we do think perhaps always in the mix there. So we continue to work behind the scenes on it. Part of it is, as you know, it’s challenging to get people’s attention on a project that won’t be ready for seven years. So we’ve got some really cool ideas about how we can maybe create some sort of picture between now and seven years with some of our existing assets on our way to – on the road to Brazeau. So it’s not dead. But it’s certainly not something that we’re talking about with investors or, you know, really putting out in the frontlines, because we want to make sure that it is also competitive with other things that people will be thinking about. People will be thinking about how to put hydrogen, for example, into the gas stream at our plants, because if we can do that, you get some greenhouse gas reductions. We’ve resurrected the files on CCS. So for example, if K 1 is our next combined cycle plant for 2025, maybe we should be thinking about K 1 having carbon capture and storage on it, so that we can sell really clean energy to the oil and gas sector here. We’re also looking at, you know, other – we’ve got a little program, where we’ve looked at almost every kind of battery storage that there is, and there’s some really interesting things going on with different technologies there. So we’ve basically got a little team that’s lined all of that up. We’re looking at how Brazeau would fit into that, what the timing would be. And then a final thing about Brazeau I think if Canada is going to build infrastructure coming out of this pandemic, as a way to get us out of the mess that we’re in here, something like Brazeau is what I call productive infrastructure. It actually creates value and long-term streams of income to investors and long-term employment for people and it also would create a tax stream for governments. So I think the time is now to get that kind of infrastructure funded. So we’ve got all of that on our minds, but certainly nothing unanswerable then. But lots of work going on behind the scenes as we think all that through relative to our future.

[Ben Pham:]

Okay, and then maybe –

[Dawn Farrell:]

That’s probably more than you wanted.

[Ben Pham:]

My last one. No, that’s – no that’s great to think about these things, especially a 10 year sort of development cycle for it, and maybe to my last question that on that when you think about the market 7, 10 years from now you have a very tight supply-demand conditions at that point of time, I guess the status quo has always been just building new gas generation at that time to replace the – take all the gas conversions. But do you think you think that you talk about hydrogen and renewables, do you think maybe there might not be the status quo, that it’s going to be more renewables, more storage, more that maybe pump hydro in that mix over gas?

[Dawn Farrell:]

Yeah, so the way I tend to think about it is, you know, if you look at net zero by 2050, that’s 25 years from 2025. And when I look at converting K 1 to gas, I think you’ve got to be prepared. And I do think that’s a fantastic investment. As you know, it’s similar to what we’re doing on Sun 5. And as you know, I’ve said before, any gas conversion has to be really capital conserving, because you’ve got to get your capital back through the timeframe. So if I look at K 1, like I say, as a potential combined cycle plant, the question I’ve got in my mind is, will it be one of the last combined cycle plants built? And will it require – will we build it actually with carbon capture and storage so that it lasts beyond 2050. Now typically, a gas conversion is about a 25 year. So I think what the team is doing here is, we’re saying okay, what are the gas projects that can go to 2050? How do you get them past 2050 you have to put CCS in place, and then what starts to replace it? Now I can say, I’m unfortunately have been in this industry far too long, that the cost of things like new chiller, like people are talking about new chiller, and I’m like, Oh my god. It is very, very costly. It’s CAD200 per megawatt hour, I do not want to put that on my grandchildren. So when we look at hydrogen, hydrogen is very expensive right now. But 20 years ago, wind was, as you know, it was CAD200 a megawatt hour, today it’s CAD40, so 20 years is a long time. So I do think we want to be very, very careful as a company in what those investments look like in gas on our way through the 2020s. And I would predict that the group that’s here at the end of the 2020 will be working really, really hard on those storage options, because I think renewables are pretty abundant. Wind is pretty abundant in Alberta. And there are some other ways to do hydro here like we’ve got to whole – we pulled as you know, the whole file of hydro projects that the company was looking at in the 50s. And they put aside, because they thought they would go to coal. So some of those would come back. Now, new hydro is really hard to permit as well. So I think you’re right on the money. As we go through the decade, gaps will start to fade away and other things will start to come into play. But it takes, you know, it takes customers who are willing to partner with us on those kinds of projects, because in this market, you can’t build a Brazeau in a in a merchant market. Using merchant risk, you have to have some partnerships on that. So I think that will be the other thing that will emerge as we go through the decade here.

[Ben Pham:]

All right, great. Thank you, Dawn.

[Dawn Farrell:]

Thanks, Ben.

[Operator:]

The next question is from Maurice Choy with RBC Capital Markets. Your line is open.

[Maurice Choy:]

Good morning. I guess just to follow up on that the big picture long-term discussion that you just had. Does that mean that, you know, unless we get an answer about all these new technologies, having the cost come down significantly, you are quite an unlikely to make a decision on, you know, K 1 and possibly even Sun 4, at least in a near-term?

[Dawn Farrell:]

Yeah, no, I would say again, if you look, remember, we’re a 8,500 gigawatt hour market here today and even if it doesn’t grow our gross at sort of 1%. But the current simple conversions that are in the market, they only have 15 years of life. Some of them last because of regulations, right. So even as you’re going forward through the 20s, you’re going to have to replace some of the supply and so I’m very bullish on K1 and potentially Sun 4 as repowering options, because they’re effectively replacing supply as you go later into the decade. And as you rightfully pointed out, when you start to look at around 2026, a number of people are looking at, you know, supply tightness and our job is to make sure that our low cost resources get into the market so we can keep prices low here for our customers, because Alberta is not competitive unless power prices are low and that’s just a fact. And you got to be able to make money in those price ranges. So I think those are still continued to be good candidates. But as we look at the mix going forward, we may add some investment on CCS, because if you look at the carbon market, if carbon is going to CAD50 and beyond, if you look at the clean fuel standard, which has an implied carbon price of CAD250 in it, all of that says that the carbon market itself starts to dictate the way you think of your investments. So we can see ways of making returns on greener and greener assets not just by selling gigawatt hours, but by selling clean gigawatt hours. So gas can be very, very clean. And in fact, it’s very, very plentiful here in Alberta. And the trick is, how do you either turn that gas into hydrogen? Or how do you turn that gas into greenhouse gas free gas by doing CCS. So those are the kinds of considerations that we’re making. And luckily we’ve got a great portfolio of assets as sort of our starter kit to attach those investments to for our customers.

[Maurice Choy:]

I guess just to you know pick up on I think there’s a comment earlier from Todd that usually power price does settle at around CAD60 per megawatt hour. Does that mean that as you think about all these projects you model or you underpin it by – with a CAD60, if not a higher than CAD60 power price?

[Dawn Farrell:]

Yeah, you know what and I think if you think about your portfolio and your mix. First of all, you know, CAD60 today has pretty low returns in it relative to the cost structure that’s underneath that, because the cost structure that’s underneath that has to incorporate a future view on carbon. And as you all know, the tier today allows gas to really effectively get off the hook, especially combined cycle gas for paying any carbon bill at all. We do expect as we go forward, that that will go away. Well I expect over time anybody who’s looking at returning capital over 20 years, has to be looking at natural gas having more and more of a carbon price associated with it. So when I think about CAD60, I often think backwards without a carbon price in it. When you start to put the carbon pricing in it, it might go up a little bit. It might be CAD70, CAD75, whatever. But it doesn’t mean that the returns are higher, it just means that the cost structure underneath it is higher. My bet is the way technology has worked. I mean, when we bet on wind in 2000, most people thought we were absolutely start raving mad. When we built our wind portfolio, you all know, I had more questions on the Street about selling the wind than I ever did about investing in it. I have more people yelling at me for investing in wind farms when I did supporting us. But net-net, as you look ahead, there’s going to be a lot of wind on this planet and a lot of returns are going to be associated with that. So I think the job of the industry is to keep prices in that CAD60, CAD70 range as long as they can, because it turns out, no one wants – you got to have low cost electricity to be competitive, and especially if you electrify everything that you can, it’s even more important. So if you, let’s say, the oil and gas industry here started to go for, let’s say, electric boilers, very, very expensive. But something they may be thinking about as they look at their own ESG goals, we have to come underneath that and provide them with low cost power. So I absolutely do not subscribe to a world where you charge people a ton of money to provide them electricity, because it’s green. Our job is to be innovative and get the cost down.

[Maurice Choy:]

Speaking about clean energy, can you update us on your thoughts on drop downs to TransAlta Renewables, their preference was –

[Dawn Farrell:]

I’m going to –

[Maurice Choy:]

Sorry, go ahead.

[Dawn Farrell:]

Yeah, so I’m going to let John take that one.

[John Kousinioris:]

Yeah. Maurice, we continue to have discussions with between TransAlta and TransAlta Renewables about the potential for drop downs. I think we’ve been you know, I think people have a sense of what the group of assets are, that would potentially be you know, with the right attributes for a drop down and, you know, all I can tell you is that we continue to work and have those discussions as we go forward in the year.

[Maurice Choy:]

Thanks. And just a cleanup question about my last question. I thought you mentioned CAD1 billion net like really I believe. Can you let us know what is the cash flow in the past at least for the upcoming quarters. And is that [technical difficulty] guidance?

[Todd Stack:]

Maurice, I’m having a hard time hearing you.

[John Kousinioris:]

Maurice, I’m having a hard time to hear you.

[Dawn Farrell:]

So – Maurice I think your question and we’ll have to make this your last one because we’ve got to move to Andrew. But I think your question is, what is the cash flow impact of the line loss settlement?

[Maurice Choy:]

Correct. And then whether or not that affects your guidance for free cash flow?

[Todd Stack:]

Oh, no, it doesn’t affect our guidance. We built some of that settlement into our plan. So we do expect to settle roughly a third of that this year, and then the remaining portion of it at some point in 2021. But that’s been built into our forecast.

[Maurice Choy:]

Yeah, okay. Thanks.

[Dawn Farrell:]

Great. Thanks, Maurice. Andrew.

[Operator:]

Next question is from Andrew Kuske with Credit Suisse. Your line is open.

[Andrew Kuske:]

Thanks. Good morning. I appreciate the commentary and the perspective on your outlook for power pricing and just bidding behavior. I guess the question more directly to TransAlta’s you know bidding behaviors going to change in the market as the market transitions, but how do you look at your energy marketing business? And how does that morph and change with the new market reality in Alberta?

[Dawn Farrell:]

Yeah, so Andrew, are you thinking about that being more. So I think a simple way to say that is our energy marketing business has kind of run as always having a little separate book that they’ve had. And the reality is, as you see as we bring on all these assets that are our merchant, it’s really their expertise that helps us optimize around that. So I think they’ll continue to be the big value adders in how we look at the market here. And I think at the end of the day, it doesn’t – they don’t really need to be taking any real risk themselves in the electricity market here in Alberta, because we’ve got all these assets that we’ve got to trade around. So they’ll do like what they do at Centralia, they’ll trade around the assets and at the same time provide a lot of asset optimization for the portfolio. John, do you want to add anything?

[John Kousinioris:]

Yeah, no you know, all I would say is, I mean, your question is a timely one in the sense that it’s a very active discussion that we’re having. Actually as you can imagine, our whole the way we’re thinking about asset optimization is being reviewed and we’re getting prepared for the merchant market in 2021. So the balance between what you would do to kind of from a prop trading perspective in Alberta versus what we would be doing just in terms of the hedging that we’re looking at doing for the for the larger fleet is a balance that we’re continually assessing now as we go forward.

[Dawn Farrell:]

But Andrew, if you’re worried about how they’ll do as a separate little business going forward, they have really diversified away from Alberta.

[John Kousinioris:]

That was my next.

[Dawn Farrell:]

Yeah, go ahead, John.

[John Kousinioris:]

So Andrew, when you look at what the actual floor is doing, I mean, Alberta is probably kind of 15% of the way we think of kind of, you know, if you look at it from a targeted perspective, in terms of cash contribution, it is, you know, less than a fifth of the way that we think of the various tests that we have on – in the consolidated group.

[Andrew Kuske:]

Okay, that’s clear. I appreciate the color. And then maybe my second question really just revolves around your Kaybob opportunity. That’s a very interesting opportunity, it’s a very interesting business group. How do you think about just the risk management across the Alberta-BC border is obviously there’s different markets and different behaviors on counterparties across the border, as we’ve seen in the last few months. So how do you think about just the size of the opportunity in Alberta and then also on BC?

[Dawn Farrell:]

Are you thinking about BC Hydro trying to attract everybody there, because of their hydro power? Is that what you’re – sorry what –

[Andrew Kuske:]

I may put the BC Hydro behavior bit differently as far as what they’ve done with some contracts they have in the market, but when you think about your cogen opportunities, like you’re dealing with Kaybob, that’s an interesting business mix. You know those opportunities exist on the other side of the provincial boundary.

[Dawn Farrell:]

Oh, yeah, yeah, yeah, yeah. Yeah, yeah, yeah. Yeah. You know, I think typically the cogeneration opportunities emerge always because of the high steam and processing demand. So they have – it is interesting though, because there's a lot of surplus power coming out of BC. And I think they’ve been able to market some of that into some of the developments that have been going on in BC. But net-net, as we work with customers, it’s any customer, anywhere in Canada, anywhere across the United States, anywhere in Australia, that has a requirement for either behind the fence gas, which is what a lot of our Australia guys have or behind the fence team. Those that we market to all of that.

[Todd Stack:]

And we’ve packaged full service behind the fence products as well. Combination of renewables with gas with –

[Dawn Farrell:]

Yeah that –

[John Kousinioris:]

And that’s the last piece. That’s taken off here to Todd’s point is exactly that.

[Dawn Farrell:]

Yeah, like we’re seeing for example in Australia, which is completely we’re gobsmacked by it actually. But if you look at the Australian mining industry, they all have ESG goal.

[John Kousinioris:]

They do.

[Dawn Farrell:]

So, you know, we’re seeing people now talking to us about providing them with some solar power at the same location where they’d have a gas plant. So some really interesting things emerging there as well.

[Andrew Kuske:]

Okay, that’s great. If I could maybe sneak in one last one just on that point. How big do you think that market opportunity is? Are you busy part of the footprint in Australia for years? How much incremental you think you can do there?

[Dawn Farrell:]

Yeah, I think it’s – so the way we kind of look at it always, Andrew is, we love singles. As you know, we don’t need CAD1 billion investments. We like to play singles and doubles. And occasionally a triple, which, you know, you’ll see sometimes as well. But so when we look at the Australian market, right, what we’re seeing right now is singles, like bite sized CAD100 million, CAD150 million. And if we can get three singles a year, you know, CAD450 million, CAD500 million a year going on a sustainable basis. That’s really what this company needs to grow. And we’d like singles and doubles, because they tend to, they, you know, you don't get yourself all hung out on one customer one deal. And you, you know, there’s a lot of issues that go along with that we like the diversity of the customers and the different fields. So Australia will give us a couple of those CAD100 million to CAD150 million investments over the next five years.

[Andrew Kuske:]

That should keep it hidden above CAD300 million. I appreciate that. Thank you.

[Dawn Farrell:]

Yeah, I know, I know. That’s what Brandon tells me all the time. If you can just hit it, where it was each row, you know, in Seattle, he just hit every time right.

[Operator:]

Our next question is from John Mould with TD Securities. Your line is open.

[John Mould:]

Good morning. Maybe just going back to a bigger picture, Alberta market questions. You know, there’s been talk of a federal clean energy stimulus certainly nothing concrete that comes out at this point. We’ve seen a number of market-driven renewable projects in Alberta. And just you know, when you’re thinking about the Sun 5 repowering, how do you think about the potential for, let’s say, out of market supports for renewable growth and the impact that can have on the market? And that could be a big benefit for a project like Brazeau your pump storage as you were discussing earlier, but wondering how you think about the impact of a potential push to green, Alberta’s electrons on the returns from an investment like Sun 5 and what it can earn in the energy market?

[Dawn Farrell:]

Yeah, so can I separate, I’ll separate for you Sun 5 and Sun 6, right. Sun 6 will be gas by the end of this year. So one to peak around, one combined cycle energy project. So when I look at a combined cycle energy project and I look at the way the carbon tax works right now and the tier program works, it just gets in there and gets its money, period. So and it doesn’t care about volatility if prices are high, it gets that margin, if prices are low, it gets that margin and it runs. So when I – when we stress test and pressure test what the market can look like that still an excellent returning project because of the capital is lower than what you’d have to do if it was brand new. If you take the coal-to-gas project, it’s this is going to sound odd to you. But it actually does better, because effectively you create massive volatility in the market. So think about it this way. Let’s say you had another just magically woke up tomorrow morning, and another 1,500 megawatts of supply of wind showed up in Alberta. And now you got 3,000. Let’s say you get 3,000 megawatts in a 11,000, 12,000 megawatt market. Well, it turns out all that wind is in the same place. It all blows one day and none of it blows the next day. The prices are going you know, somewhere between CAD0 and CAD500. And a peaker captures those market – those margins. So the real issue is whether or not those peakers can get started up pretty quickly and John and his team have done an amazing job on that. So net-net. It turns out that in our renewables market here in Alberta, you have to back it up with something. And in absence of things like Brazeau, you need fast acting peakers. The other of course big benefit that our peakers have is, they're able to fully ramp all the way, they don’t have any restrictions. And I think under the federal rules, brand new peakers are restricted to only running 30% of the time. So that’s that's pretty hard to make money on. So I think net-net what we’re looking at is the volatility works for the peakers. And the cost structure works for the combined cycle plant over a range of options. And when you bring in more renewables, you create more volatility.

[John Mould:]

Okay, thanks for that context. And then Todd referenced the MSA statement, I think earlier on economic withholding. Are you anticipating any additional guidelines related to economic withholding or awful behavior from the NSA or with the ACL having completed its market power mitigation rule review earlier this year, are you expecting a stable bidding framework more or less for the foreseeable future?

[Dawn Farrell:]

I’ve got Kerry – yeah we’ve got Kerry O'Reilly wealthcare, who runs our regulatory so I’m going to turn it to her.

[Kerry O’Reilly Wilks:]

Sure. So we don’t anticipate any new guidance. But, you know, that being said, we weren’t necessarily anticipating the most recent statements. So I think as we enter into the pure merchant market, and the balancing pool falls away, I would suspect that will find – that will receive more principles issued by the MSA in terms of going forward but we believe that the market is stable. It’s been confirmed that you know, with fair efficient open competitive field regulation, we have what we need for the market to run properly and provide stability. So we don’t anticipate anything brand new coming out.

[Dawn Farrell:]

Yeah, the only color I could potentially add is one of our board members, Yakout Mansour was the head of the ISO in California and he did say to me once, he said look at your markets been designed for PPAs. The rules are set up relative to the PPAs. As you come out and the PPAs come off, and you go to bidding your costs and having to get a return and a capacity payment out of the market. There might be some real changes that are going to be required to make price formation as strong and as robust as it can be. Because as Todd said, the whole thing now, the whole market hangs off of really, really strong price formation in that spot market. So we don’t know yet what that could be and Kerry and her team will be working sort of side by side with you know with the ISO to see if there are any changes that are required as we go down through that. But what I find generally is those kinds of rule changes are very technical, very hard to understand. You take the PhD and power economics and math to understand what they’re really trying to do. But you could – so I think we could see some of that. But the main pieces of the market have really been set. And when they did that – when they issued that guidance, they put the final icing on the cake around how the energy-only market could trade so that effectively it can give the signals for capacity, which I think is really important and very positive for our strategy.

[John Mould:]

Okay, thanks for that. I’ll leave it there.

[Todd Stack:]

Thanks, John.

[Operator:]

Our next question is from Mark Jarvi with CIBC Capital Markets, your line is open.

[Mark Jarvi:]

Thanks. Good morning, everyone. Just want to come back to TransAlta Renewables. We’ve seen a no big premium come in for pure play renewables. I’m just wondering how that might influence your scene on valuations in the market. In terms of how you shape future drop downs that are in WTF that changes your willingness to maybe put gas-fired assets into that handy or kick that split at 50

[John Kousinioris:]

Yeah, I mean, I think it’s fair to say, Mark that we’re relatively opportunistic in terms of, you know, what would go down from a drop down perspective, the company’s strategy is a balanced one, we do have a focus on developing our renewable business. And we do think we have runway on on-site generation so as we develop, you know, both of those kinds of assets we think that there that both of them are valuable, I know that different multiples are assigned each of them. But we would be looking at both of those categories as being things that you know, once we’d have projects would be a good candidates potentially for our interview.

[Mark Jarvi:]

Okay. And then just coming back to for the power market and future supply, there’s some speculation of a combined cycle plant might get financed and we’re in the market just wondering how that might alter your plans for coal-to-gas, gas conversions around either going to dual repowering or delaying any of the boiler conversions until you see what that entity does with that project?

[Dawn Farrell:]

No, no delay whatsoever.

[John Kousinioris:]

No, no change to our approach.

[Mark Jarvi:]

Okay. And then last one here is maybe it’s not even feasible. But given your expectations of where new prices need to settle next year, some soft demand this year, is there any way to shuffle around planned outages or even just advanced either K2 or K3 boiler conversions?

[Dawn Farrell:]

Well, first of all, we can’t talk about that, because it has to go to the market overall at the same time. So all I would say is, my expectation is that as we end and this is just my expectation, as you start to come out of the pandemic, as the numbers start to drop, as people actually figure out that all you have to do is wash your hands, stay two meters apart, and where I’m at when you can’t, and as the kids come back to school, I think some of the hysteria would evolve in this and you’ll start to see the – you’ll start to see things climb out. And we’re certainly seeing that week-by-week here in Alberta, traffic’s getting heavier and heavier every day through the summer, which is quite unusual. Usually the traffic stays, you know, is pretty good in the summer. So I think demand as you have to expect that and we’re starting to see the curtailments on production going away on oil. So I think as demand lifts here, you know, how things are set up next year makes sense? And the other thing is, we got to get equipment and people and –

[John Kousinioris:]

Yeah that’s what I was just about to say, Mark like getting, the amount of advanced planning that remember, these are outages plus conversions. So the amount of planning that goes in, you know, as we’re thinking of Sundance 6 for example, there’s hundreds of people that are going to be on-site working on the facility to both to the outage and do the conversion. So just logistically, it’s not something you know, you can toggle all that easily. So it’s a lot of planning and timelines.

[Dawn Farrell:]

Yeah, I think the other thing people are going to people are going to realize that all over this country, and facilities everywhere, people are building stuff and operating stuff and nobody’s getting sick, because they’re all using very simple protocols. And hopefully that commentary is going to start to dominate the airwaves here pretty soon.

[Mark Jarvi:]

Okay, Thanks for clarifying. Appreciate.

[Operator:]

[Operator Instructions] Our next question is from Naji Baydoun with Industrial Alliance Securities. Your line is open.

[Naji Baydoun:]

Hi. Good morning. Just a quick question for me on the topic of repowering. Can you give us your thoughts on when repowering you know, particularly for some of your older one assets, is that something you could potentially be pursuing over the near-term?

[Dawn Farrell:]

Yeah, and Naji, thank you first of all being so patient to wait all the way to this time to ask that question, and it’s a great question. So as we look at when repowerings, we’ve got some of the earliest wind sites, which are have got really great resources for wind. Typically, a lot of people will tend to put – were pretty conservative about what we put in as our terminal values of wind farms, because we kind of look at two things. One, can you extend the contract with the landowner and two, can you reuse some of the equipment? You know, what we’ve mostly found is, you can absolutely extend the contract with the landowner they are desperate to keep those wind farms there, because usually that’s what’s keeping them alive. But the technology’s changed so much. So if you look at our first wind farm was probably 300 kilowatts, right. And then it went to 660 kilowatts. And now we’re looking at wind farms that are 5 megawatts, while the platform for 5 megawatts is quite a bit bigger and quite a bit deeper than the platform for 660 kilowatts. So typically, a repowering option is a renewal and a brand new wind farm at that site using that resource, and you have to do a lot of work on your substation and all the rest of it. So that’s how we look at it. So typically, the number one thing is, have you been a good neighbor? Have you kept the noise low? Have a fish if a door opens on at the top of the windmill, did you go out and shut it as fast as you could? So you didn’t keep the landowner awake all night? Have you got excellent environmental records? And are you doing the things you should be doing for birds, bats and bees. And if you get all of that going, you’ll get a long-term extension on the wind resource likely you’re repowering is a replacement.

[Todd Stack:]

But on top of just the repowering, we also have, you know, a good inventory of other optionable land to build out new wind farms. And that’s sort of how the Windrise facility came out, as opposed to repowering one of our retired sites is to actually go to a new site and again, that’s just Alberta down in the US, John, I think we have a 1,000, we have quite a few early stage development sites that we can develop up as well.

[John Kousinioris:]

And those would be all – those are on new sites.

[Todd Stack:]

And that is back along with the strategy of saying, you know, we need to have some early stage development sites or late stage development sites, to be able to bring forward to customers to get their attention to get them in a position where we can actually execute a contract in PPA.

[Naji Baydoun:]

Okay, that’s great detail. Thank you. And just, I guess, do you have a target kind of similar to the cogen strategy of certain amount of capital that you want to be investing in these types of opportunities? And you know, if you do proceed with some repowerings or the returns that you’re targeting they’re similar to the new bill.

[Dawn Farrell:]

Oh, yeah, yeah, yeah. Yeah and it’s and again, if you kind of sit back and say, okay, can you find enough things to do in the jurisdictions we’re in and the technologies that we love to get your on a path where you’re investing in that, you know, for CAD450 million, CAD500 million a year on a consistent basis. The wind kind of fits in that, but net-net if wind sell or return than cogen, we’re going to do more cogen and wind and vice versa. So it really comes down to, can we get the right prices for the investments that we make?

[Naji Baydoun:]

Thank you for the great detail.

[Dawn Farrell:]

Yeah, thanks.

[John Kousinioris:]

Thank you.

[Operator:]

Our next question is from Chris Varcoe with Calgary Herald. Your line is open.

[Chris Varcoe:]

Hi, Dawn, I’m sorry if these questions been asked. I just jumped on the call. But I was curious about the wind charger battery storage project. Can you talk about how the construction has gone? How the costs have gone on this project and whether they met your expectations? And maybe more importantly, what are you going to be watching for as the keys for success in this project?

[Dawn Farrell:]

It’s pretty cool, Chris, like I wish I should. I’m going to give it to John, because it’s his team that’s done it. But go ahead, John.

[John Kousinioris:]

Oh yeah. It is really cool and you know we get pictures of it from time to time from our crew down there and we’re excited to have it. It is essentially all in place. We’re just doing some, some testing on the transformers, the costs were pretty much right on top of where we thought. The timing was pretty much on top of where we thought now was standing, you know, the thickening of the border and COVID.

[Dawn Farrell:]

But talking about when you started the construction and when you’re going to end.

[John Kousinioris:]

When we’re going to end in a couple I mean, we’re basically there were more in a testing phase, but it was put together in just a matter of months to be in terms of construction. And it was great when we saw the batteries coming up from Tesla and in place. So and I think Dawn, you and I were right by there just a couple of months ago and it was – there wasn’t a lot there and in literally two months, it’s basically done. We are excited about it. It’s an opportunity for us to kind of match storage and our renewables wind power generation that’s tied to a wind farm that we have there. So we’re really looking at learning from tying the two together and you know, just seeing how it’ll operate to fill in kind of peaks of demand in the marketplace and sort of the time shift effectively, the generation that we have from the renewables, the times when it would be potentially more valued. So it's a different project.

[Dawn Farrell:]

The marker for it, Chris is a very simple, very fast to put up.

[John Kousinioris:]

Really quick.

[Dawn Farrell:]

You know, very easy to permit. I mean, we were standing in a field, looking at a field one day and the next day, we got the pictures and the batteries had been brought up by truck and we’re sitting on the – where they were supposed to be.

[John Kousinioris:]

It’s about half the size of a soccer field, just to kind of give you a sense.

[Dawn Farrell:]

If you’re in our industry where it takes, you know, forever to get anything done it was kind of remarkable, but the real challenge will be, will it make any money, because you store for about two hours and then you’ve got to undo it you know, when the prices are higher. So your time shifting the value of energy and it’s got to – at the end of the day, it’s got to pay for itself. So we’ll be able to – we won’t know for about a year or so whether or not it creates that value in the market here. But certainly it’s been a pretty interesting project to be involved in.

[Chris Varcoe:]

Just the follow up, can I ask you, what do you see is the potential for battery storage, given the current technology? And what do you see is the limitations at this stage that really need to be overcome?

[Dawn Farrell:]

Yeah, so in our industry, the limitation is always the cost, the capital, the size of the capital that you need to make the initial investment relative to the, you know, whatever the price differential is, you’re going after. So the way batteries work, Chris is, you need a fairly good differential between periods. So you need a low price period.

[John Kousinioris:]

When you’re charging.

[Dawn Farrell:]

So that you can charge and then you take the power out of the battery when there’s a higher price. Alberta is a little bit tougher than most jurisdictions, because we have such a high system load factor we need power 24/7 you don’t get as much day and night change to do maybe in other markets. But as more renewables come in, maybe that will change. So that’s something that you would watch for. The biggest constraint right now is the time duration. So these – the Tesla batteries are short duration batteries, two hours, we’re looking at batteries our Brazeau wind our Brazeau’s storage project, which is pump storage, it has about nine hours of discharge, but it takes 12 hours to store, right. So it takes 12 hours to charge the reservoir and then you can run it out for nine, that’s pretty good. We’re looking at some battery technologies that are kind of half and half. You store for about 13 hours and you – it comes out for 10 or 11. Don’t ask me why it doesn’t all add up to 24 hours, the engineer has to explain that to me, but so net-net the biggest constraint today is everybody’s going after these long storage batteries and they’ve got all these different technologies. A lot of them are chemical batteries where you’re adding ions to a chemical and then you’re taking the ions out as you’re discharging. So if you’re interested in it, come over and we’ll take you through a tutorial. And you can write lots of stuff about it.

[Operator:]

Ladies and gentlemen, this does conclude our Q&A period. I’d now turn it back over to Chiara Valentini for any closing remarks.

[Chiara Valentini:]

Great. Thank you, Chris. Well thank you everyone. That concludes our call for today. If you have any further questions, please don’t hesitate to reach out to the IR team here at TransAlta. Have a great day.

[Operator:]

Ladies and gentlemen, this concludes today’s conference call. Thank you for your participation and you may now disconnect.