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.

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 steps 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 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 makeshift 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 continued 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 K3 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 31, 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 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 has been energized and the rest are expected to commission in the next quarter. 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. 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, Alberta, 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. 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 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 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 represent 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 reduced 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 were 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 are 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 must 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 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 in rules will play out in terms of price formation. 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 close 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 with 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 recognized the CAD20 million provision relating to this dispute. The estimated amounts continue to be uncertain and the ISO’s 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 driven 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 the impact of the total return swap, our corporate segment cash flows decreased by a total of CAD12 million compared to 2019. An excellent result for the segment. For the quarter, our segmented cash flow of CAD191 million was ahead of 2019 by CAD47 million. 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 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 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 three months demonstrates exceptional performance, a strong commitment and significant resilience. Our business model and operating practices came through Q2 with flying colors. 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 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 for questions from the analysts?

Good morning, everyone. I just want to follow up on your comment about setting 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 pooled unit 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?

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 – 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, 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 ensure they get their costs out of the market. Does that make sense, Rob?

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?

Yeah, I mean, there are 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 we 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.

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 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 capital?

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 portfolio is we actually 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 and 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, 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.

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.

Great, thanks good morning. Just a question on the hydro PPA that expires 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?

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?

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.

So it’s not a dead project in the sense of continuing to get better interconnections and building over time. So I think we’re really proud to be there, and we’re looking forward to trying to make more work happen there.

Okay, great. And anything although what was some of that reserved pump storage project that gained a lot of rates about a year and a half 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.

You must be in the wilds of transitory events. 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 ahead, 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 is the truth. 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 that’s 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 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 next 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, 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 are 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.

Okay, and then maybe –

That’s probably more than you wanted.

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 condition 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 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?

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 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 timeframe. So if I look at K1, 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 lifecycle. 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 chillers, like people are talking about new chillers, 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 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.

Good morning. I guess just to follow up on that big picture long-term discussion 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 unlikely to make a decision on K1 and possibly even Sun 4, at least in a near-term?

Yeah, no, I would say again, if you look, remember, we’re an 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. 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.

Okay, great. Thank you very much.

Thanks, Patrick.

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?

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?

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.

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

Some technologies on a competitive basis.

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?

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.

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.

So I think we’ll be talking about some opportunities that we’ve got in Alberta that existing energy companies are looking at that need power. And we’re really actually graduating this industry in this environment, particularly coming out of the pandemic.

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

I think we’ll be talking about some opportunities that we’ve got in Alberta that existing energy companies are looking at that need power. And we’re really actually graduating this industry in this environment, particularly coming out of the pandemic. I think our energy team sees opportunities everywhere, and you know, that mix between renewables and natural gas is going to be fully supportive.