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TransAlta Corp
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Ladies and gentlemen, thank you for standing by, and welcome to TransAlta Corporation's Second Quarter 2020 Results Conference Call. [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.
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 our website. 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 this conference call is subject to the forward-looking statement qualification set out here on Slide 2, further 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 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.
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 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 2-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 training business to deliver their results. And of course, we were worried about the state 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 and make 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 a 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 run smoothly albeit from their homes, and our plans achieve 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 continue to close in on our goal of reducing senior recourse debt to $1.2 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 $217 million of EBITDA and $91 million of free cash flow or $0.33 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, while all our plant 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 used that as an opportunity to use our NCIB to return an additional $12 million of capital to our shareholders with our share buyback program, and year-to-date, we've returned approximately $21 million to shareholders at an average price of $7.51 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 $1.6 billion, which includes approximately $250 million of cash. And we're poised to repay our 2020 bond maturity later this year without further funding requirements from the market. So just a few words on our strategic priorities. We continue to track on all our priorities with very little delay or very little change in timing. Our strategy continues to focus on delivering 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 6 conversion in September of this year. And both key post-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 do it -- we now do not see a need to complete a dual fuel conversion on our K3 unit. And that unit will be fully converted to gas only in Q3 of next year. This slightly reduces our capital requirement 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 big 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 31, 2020, today. This decision largely -- 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 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 U.S. 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 Windrise and WindCharger. We expect to reach COD on WindCharger in a few weeks. Bulk of the equipment is now on-site and installed, and we're progressing with a 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 remain solid to date, which enables that project to continue. Skookumchuck now has 18 turbines up with 8 mechanical completion certificates issued. If 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 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 in through the Pacific Northwest, the court of -- into Alberta's courts through our tie lines. 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. It's 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.
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 conditioned impacted -- as these conditions impacted our merchant sales, our fleet-wide operational and financial results for the second quarter of 2020 continued to be strong and were indicative of the resilience of our operations, our hedging and marketing capability and our portfolio diversification. During the quarter, we generated $217 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 $42 million year-over-year to $91 million in Q2 versus $49 million last year. On a per share basis, we delivered free cash flow of $0.33 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 reduced capital spend on major maintenance with 2 outages in Q2 2019 versus no major outages in 2020. Year-to-date, we've generated $200 million of free cash flow or $0.72 per share, a 41% increase over 2019's 6-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 $30 per megawatt hour and were considerably lower than the second quarter of 2019, which averaged $57 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 but is now trending in the 500 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 reopen and people returned 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 $51 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 selling at these prices for the following reasons. First, there is 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 $40 per tonne 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 will structure their energy offers accordingly to reflect the recovery for return of and 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 market and where demand crosses supply, the average price often settles in the financial and spot market to an average of $60 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 close to a historical average, but our job will be to position ourselves to increase margins in periods of volatility. We had a strong -- 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 U.S. 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 with higher production due to excellent wind resource across all regions. The U.S. coal segment returned to normal results for the quarter and were substantially higher than the second quarter of 2019. We benefited from lower-priced power purchases and strengthening of the U.S. 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 $36 million, this was offset by lower maintenance capital spend, resulting in strong segment cash flow. EBITDA in the segment was also impacted by a $7 million increase to our provision in fuel and purchase power relating to the Alberta AESO 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 AESO used to calculate transmission loss fees for all generators in the province. During Q2, the AESO was able to provide the results for the recalculation of 3 of the 11 years under dispute, which allowed us to better estimate the potential impact. In total, we've recognized a $20 million provision relating to this dispute. The estimated amounts continue to be uncertain, and the AESO's recalculated loss factors remain subject to further review and change. Revenue from the Alberta thermal fleet in the quarter averaged approximately $65 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 $40 per megawatt hour compared with $33 last year. A portion of this increase, about $3, 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 were -- 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 $10 million. Results were attained 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 $5 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 $12 million compared to 2019, an excellent result for the segment. For the quarter, our segmented cash flow of $191 million was ahead of 2019 by $47 million. And as I discussed earlier, the company generated a consolidated free cash flow of $91 million, an increase of $42 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 $1.6 billion in liquidity, including approximately $250 million in cash. In addition to the current liquidity, we will be receiving $400 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 have repurchased and canceled $21 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 are 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 $437 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 from merchant production through hedging and optimization. Looking at our merchant exposure in Alberta, 75% of our thermal baseload generation is hedged at $53 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 $1 change in Alberta power prices would result in an approximate $2 million change in EBITDA. Given the unprecedented impact to demand in Alberta, we currently expect EBITDA to be at the low end of our guidance range. This is primarily driven by 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 in 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 3 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 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 and 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.
Thank you, Todd. Chris, would you please open the call up for questions from the analysts and the media.
[Operator Instructions] Our first question comes from Rob Hope with Scotiabank.
Just want to follow-up on your comment about bidding behaviors into 2021. Just taking a look back at Q3 and, I guess, year-to-date in 2020, we are seeing some of the balancing pool being dispatched more than I would have expected. So 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?
Yes. 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, 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 recover the capital that they've invested. People have forgotten that the original PPAs did not have recovery of sustaining capital in the last 5 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 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 we finally get the full fundamentals of that energy-only market. So when we -- 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 $40 carbon price comes into effect. And then you also see that kind of, generally, the generators all have pretty similar cost structure. 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?
Yes. That's great. And then the follow-up question. Just how are you thinking about deployment of capital? You have a bunch on the balance sheet. You've got Pioneer coming in soon. When you look at the stack of opportunities in front of you, how do they rank? Could we see you do some contracted or merchant renewables in Alberta, further cogen, M&A, development in the U.S.? How are you thinking about deploying capital?
Yes. I mean there's some really, really interesting opportunities that 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 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 investors are even more -- they find it even more important to ensure that they reduce the risk of what the science 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 we go, even this 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 U.S.
Our next question is from Patrick Kenny with National Bank Financial.
Dawn, maybe just a follow-up on the capital allocation. So you've had success in signing up the big corporate off-takers for renewable capacity. Curious your thoughts on being able to leverage off your existing relationships with Microsoft and others to potentially accelerate your clean energy transition and take advantage of the strong growth being experienced across the tech industry? And then I guess if internal capital is a constraint to take advantage of that growth, how you might think about bringing in partners or other external sources of capital?
Yes. So a 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, 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 dog 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 project, which, everybody goes on, "why do you want to invest USD 27 million in a company like that, blah, blah, blah, it's too little". And I'm looking at it going, "yes, 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 a 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.
Okay. That's great, Dawn. And maybe just a follow-up for Todd. 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 until power prices recover, there might be a delay here in getting down to that sub 3x target. Just wondering, does that impact at all the priorities with respect to dividend policy, share buybacks or debt repayments as you look to refinance that '22 bond coming up there?
Yes. 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 are correct, although our -- I think our consolidated cash flows are actually very strong and stronger than they were prior quarter or as of 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 will be a significant contribution to that deconsolidated cash flow.
Our next question is from Ben Pham with BMO.
Last question on the hydro PPA that expires like this year, you're going to next year, the production from that facility, is that going to be part of your hedging program with some of your storage/run-of-river? Or is it going to be mostly open exposure?
So I'll start and then John can add. I mean, you've got to think about that hydro as several different streams of revenue. But if you're just thinking about the sort of energy component and the capacity, remember that, in this spring, there's big runoffs. We never know quite when it is. We never know if it's going to be in May -- April, May or June, it depends. 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-of-the-river is more energy. And it is -- some of it is hedgeable 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 it -- 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?
Yes. I mean, I think, Ben, Dawn answered it well. There is a component. I think of it as a strip effectively of the anticipated generation that we have 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.
Okay. Great. And anything was some of the pump storage project that picked in a lot of lights about 1.5 years, 2 year ago? There's been some activity around BC Energy, partnering Alberta and some stuff going on Ontario. Would love an update there, if there's anything.
You must be in the walls at TransAlta. Are you, Ben? So everybody knows that Brazeau'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 ahead, Ben, I -- what I see is you have to go 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 Brazeau is 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 7 years. So we've got some really cool ideas about how we can maybe create some sort of picture between now and 7 years with some of our existing assets on our way -- on the road to So it's not dead, but it's certainly not something that we're talking about with investors are really putting out in the front lines 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 K1 is our net combined cycle plant for 2025, maybe we should be thinking about K1 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 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 aligned all of that up. We're looking at how would fit into that, what the timing would be. And then a final thing about 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 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 announceable then. But lots of work going on behind the scenes as we think all that through relative to our future.
Okay. Maybe...
That's probably more than one.
No, it's great to think about these things, especially a 10-year sort of development cycle for it. And maybe to my last question, third on that. I mean you think about the market 7, 10 years from now, you have a very tight supply/demand conditions at that point in time. I guess, the status quo always been just building new gas generation at that time to replace gas conversions. But do you think it's -- that you talking about hydrogen and renewables. Do you think maybe that might not be the status quo that it's going to be more renewables, more storage, more of that maybe from hydro in that mix over gas?
Yes. So the way I tend to think about it is if you look at net 0 by 2050, that's 25 years from 2025. And when I look at converting K1 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 time frame. So if I look at K1, like I say, as a potential combined cycle plan, the question I've got in my mind is, will it be one of the last combined cycle plants built? And will we build it actually with carbon capture and storage so that it lasts beyond 2050? Now typically, our gas conversion is about a 25 year. So I think what the team has been 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's start to replace it? Now I can say, unfortunately, have been in this industry for too long that the cost of things like people are talking about and I'm like, oh, my god, it is very, very costly. It's $200 a 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 $200 a megawatt hour today, it's $40. 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 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 a whole -- we pulled out, 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, gas will start to fade away and other things will start to come into play, but it takes customers who are willing to partner with us on those kinds of projects because in this market, you can't build 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.
Our next question is from Maurice Choy with RBC Capital Markets.
I guess just a follow-up on that big picture, long-term discussion that you just had. Does that mean that as we get an answer about all these new technologies, having the costs come down significantly, you are quite unlucky to make a decision on K1 and possibly even Sun 4, at least, in the near term?
Yes. No, I would say, again, if you look -- remember, we're a 85,000 gigawatt hour market here today. And even if it doesn't grow, our growth at sort of 1%. The current simple conversions that are in the market, they only have 15 years of life, some of them less 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 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 continue 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 $50 and beyond, if you look at the clean fuel standard, which has an implied carbon price of $250 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, too, for our customers.
And I guess just to pick up on -- I think it was a comment earlier from Todd, that usually, pulp prices settle at around $60 per megawatt hour. Does that mean that as you think about all these projects, you model or you underpin it with $60, if not a higher than $60 power price?
Yes. You know what, and I think as you think about your portfolio and your mix, first of all, $60 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. 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 $60, I often think backwards without a carbon price in it. When you start to put the carbon price in it, it might go up a little bit. It might be 70, 75, 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 2,000, 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 than supporting us. But net-net, as you look ahead, there's going to be a lot of win 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 at $60, $70 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.
Speaking about clean energy, can you update us on your thoughts on drop-downs to that renewables preference -- sorry, go ahead.
Yes. So I'm going to let John take that one.
Yes. Maurice, we continue to have discussions with between TransAlta and TransAlta Renewables about the potential for drop downs. I think we've been -- I think people have a sense of what the group of assets are that would potentially be with the right attributes for a drop down. And all I can tell you is that we continue to work and have those discussions as we go forward in the year.
And just a key question about line loss or transmission line loss. Todd mentioned $20 million net liability, can you let us know what the free cash flow in the past any sort of upcoming quarters? And is that it to be a guidance
Maurice, I'm having a hard time hearing you.
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?
Correct. And where not that affects your guidance for free cash flow?
Yes.
No, it doesn't affect our guidance. We've built some of that settlement into our plan. So we do expect to settle roughly 1/3 of that this year and the remaining portion of it at some point in 2021, but that's been built into our forecast.
Our question is from Andrew Kuske with Crédit Suisse.
I appreciate the commentary and the perspective on your outlook for power pricing and just bidding behavior. I guess a question more directly to TransAlta's bidding behavior is going to change in the market as the market transitions, but how do you look at your energy marketing business? And how do that morph and change with the new market reality in Alberta?
Yes. 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 a -- always have a little separate book that they've had. And the reality is, as you can -- as you see, as we bring on all these assets that are all merchant, it's really their expertise that help 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 risks themselves in the electricity market here in Alberta because we've got all these assets, and 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?
Yes. No, 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 internally. As you can imagine, our whole -- the way we're thinking of 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 larger fleet is a balance that we're continually assessing now as we go forward.
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.
That was my next...
Yes. Go ahead, John.
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 -- if you look at it from a targeted perspective in terms of cash contribution, it is less than 1/5 of the way that we think of the various desks that we have on -- in the consolidated group.
Okay. That's great. 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, hunt 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 in BC?
Are you thinking about BC Hydro trying to attract everybody there because of all the power -- because of their hydropower? Is that what you're...
Put the BC Hydro behavior a bit differently as far as what they've done with some contracts they have in the market. But when you think about cogen opportunities like you're doing with Kaybob, that's an interesting business mix. Clearly, those opportunities exist on the other side of the provincial
Yes. Yes. Yes. I think typically, the cogeneration opportunities emerge always because of the high steam and process 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, 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 steam, those -- we market to all of that.
And we've packaged full-service behind the fence products as well, combination of renewables with gas, which...
Yes.
That's the last piece that's really taken off here to Todd's point is exactly that.
Yes. Like we're seeing, for example, in Australia, which is completely we're got smacked by it, actually. But if you look at the Australian mining industry, they all have the goal. So 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.
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 for you because you've had the footprint in Australia for years? How much incremental do you think you can do there?
Yes. 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 $1 billion dollar investments. We like to place singles and doubles and occasionally a triple, which you'll see sometimes as well. But so when we look at the Australian market, what we're seeing right now is singles, like size, $100 million, $150 million. And if we can get 3 singles a year, $450 million, $500 million a year going on a sustainable basis, that's really what this company needs to grow. And we like singles and doubles because they tend to -- you don't get yourself all hung out on one customer, one deal. And there's a lot of issues that go along with that. We like the diversity of the customers and the different fuels. So Australia will give us a couple of those $100 million to $150 million investments over the next 5 years.
That should keep it hitting above $300 million. I appreciate that.
Yes, I know. I know -- that's what tells me all the time. If you can just hit it -- each row, it's Seattle. He just hit every time, right?
Our next question is from John Mould with TD Securities.
Maybe just going back to a bigger picture, Alberta market questions. There's been talk about federal clean energy stimulus. Certainly nothing concrete come about at this point. We've seen a number of market-driven renewable projects announced in Alberta. And just when you're thinking about the Sun 5 repowering, how do you think about the potential for, let's say, Alberta markets for renewable growth and the impact that could have on the market? And that could be a big benefit for a project like as your pump storage you were discussing earlier. But just 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?
Yes. So can I separate -- I'll separate for you, Sun 5 and Sun 6, right, because on Sun 6 be the gas by the end of this year. So one the peaker and 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 it doesn't care about volatility if prices are high, it gets that margin if prices are low against that margin, it runs. So when we stress test and pressure test, what the market can look like, that's 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 spy of wind showed up in Alberta and now you've 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 market. The prices are going somewhere between 0 and $500 and a peaker captures those market -- those margins. So the real issue is whether or not those peakers and 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 renewables market here in Alberta, you have to back it up with something. And in absence of things like 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 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 to create more volatility.
Okay. And then Todd referenced the MSA statement, I think, earlier on economic withholding. Are you anticipating any additional guidelines related to economic withholding or offer behavior from the MSA? Or with the ASO having completed its market power mitigation will review earlier this year, are you expecting a stable bidding framework, more or less...
Yes, we've got Kerry O'Reilly Wilks here, who runs our regulatory. So I'm going to turn it to her.
Sure. So we don't anticipate any new guidance. But that being said, we weren't necessarily anticipating the most recent statement. So I think as we enter into pure merchant market and the balancing pool falls away, I would suspect that we'll find that -- we'll receive more principles issue by the MSA in terms of going forward. But we believe that the market is stable, it's been confirmed that with fair, efficient open competitive on 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.
Yes. The only color I could potentially add is one of our Board members, Yakut Mansur was the Head of the ISO in California. And he did say to me once, he said, look at your market has 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 a return and a capacity payment out of the market, there might be some rural 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 transformation in that spot market. So we don't know yet what that could be. And Kerry and her tell be working sort of side-by-side 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 rural 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.
Our next question is from Mark Jarvi with CIBC Capital Markets.
Just may come back to alternatives, we've seen a big premium come in for pure-play renewables. So I'm just wondering how that might influence you're seeing on valuations in the market in terms of how you shape future drop-downs with R&W, if that changes your willingness to maybe put gas assets into that end of the year, get that split that 50-50 as it is now?
Yes. I mean, we -- I think it's fair to say, Mark, that we're relatively opportunistic in terms of 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 both of those kinds of assets, we think that the -- that both of them are valuable. I know that different multiples are assigned to each of them, but we would be looking at both of those categories as being things that once we had projects would be a good candidate potentially for R&W.
Okay. And then just coming back to the Power market and future supply, there's some speculation of combined cycle plant might get financed in the market. I'm just wondering how that might alter your plan for gas conversion is around either going to 2 repowerings or delaying any of the boiler conversions until you see what that entity does with that project?
No. No delay whatsoever.
No change to our approach.
Okay. And then last one here is, maybe it's not even feasible. But given your expectations of where prices need to settle next year some soft demand this year, is there any way to shuffle around planned outages or even just advance either K2 or K3 boiler conversions?
Well, first of all, we can't talk about that because I have to go to the market overall at the same time. So all I would say is my expectation is that as we -- 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 2 meters apart, and were a mass when you can't and as the kids come back-to-school, I think some of the worldwide of all of 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 is getting heavy and heavier every day through the summer, which is quite unusual. Usually, the traffic stays 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, how things are set up next year makes sense. The other thing is we got to get equipment and people.
Yes, 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 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 through the outage and to conversion. So just logistically, it's not something you can toggle all that easily. So it's a lot of planning and time lines.
Yes. I think the other thing people are going to realize that all over this country and facilities everywhere, people are building stuff and operating stuff and nobody is 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.
[Operator Instructions] Our next question is from Naji Baydoun with Industrial Alliance Securities.
Just a quick question for me, on the topic of repowerings. Can you give us your thoughts on wind repowerings, particularly for some of your older wind assets? Is that something you could potentially be pursuing over the near term?
Yes. 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 wind repowerings, we've got some of the earliest wind sites, which have got really great resources for wind. Typically, a lot of people will tend to put -- we're pretty conservative about what we put in as our terminal values of wind farms because we kind of look at 2 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 landowners, they are desperate to keep those wind farms there because usually that's what's keeping them alive, but the technology has changed so much. So if you look at our first wind farm, it was probably 300 kilowatts, right? And then it went to 660 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. 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 it typically -- the #1 thing is, have you been a good neighbor? Have you kept the noise low? 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 land owner awake all night? Have you got excellent environmental records? And are you doing the things you should be doing for birds? And if you get all that going, you'll get a long-term extension on the wind resource, but likely you're repowering is a replacement.
But on top of just the repowering, we also have a good inventory of other optional 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 U.S., John, I think we have 1,000. We have quite a few early-stage development sites that we can develop up as well.
And those would be all -- those are all new sites.
Yes. And that is back along with the strategy of saying 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.
Okay. That's good detail. And just I guess, do you have a target kind of similar to the cogen strategy of a certain amount of capital that you want to be investing in these types of opportunities? And if you do proceed with some recurrings, are the returns that you're targeting there similar to new build?
Oh, yes.
Absolutely.
Yes. Yes. 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 you're on a path where you're investing in that $450 million, $500 million a year on a consistent basis, the wind kind of fits in that. But net-net, if sell our return than cogen, we're going to do more cogen than wind and vice versa. So it really comes down to -- can we get the right prices for the investments that we make.
Our next question is from Chris Varcoe with Calgary Herald.
Dawn, I'm sorry if this question has 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?
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.
Yes. It is really cool, and we get pictures a bit 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 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 and notwithstanding the thickening of the border in COVID.
When you started the construction and when you're going to end?
Well, we're going to end it in a couple -- I mean we're -- it's basically there. We're 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 and in place. So -- and I think Dawn and I were right by there just a couple of months ago, and it was -- there wasn't a lot there in literally 2 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. It's tied to a wind farm that we have there. So we're really looking at learning from tying the 2 together and just seeing how it will operate to fill in kind of peaks of demand in the marketplace and sort of time shift effectively the generation that we have from the renewables to times when it would be potentially more valued. So it's a good project.
The marker for it, Chris, is so very simple, very fast to put up.
Really quick.
Very easy to permit. I mean we were standing in a field looking in 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...
It's about half the size of a soccer field. If you kind of give you a sense.
If you're in our industry where it takes 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 2 hours, and then you've got to undo it 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.
Just a follow-up. Can I ask you whether you see the potential for battery storage given the current technology? And what do you see as the limitations at this stage that really need to be overcome?
Yes. So in our industry, the limitation is always the capital, the size of the capital that you need to make the initial investment relative to the -- 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 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 you 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 the Tesla batteries are short duration batteries, 2 hours. We're looking at batteries, our storage project, which is pump storage. It has about 9 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 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 is going after these long storage batteries, and they've got all these different technologies. A lot of them are a 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.
Ladies and gentlemen, this does conclude our Q&A period. I'll now turn it back over to Chiara Valentini for any closing remarks.
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.
Ladies and gentlemen, this concludes today's conference call. Thank you for your participation, and you may now disconnect.