Good morning! My name is Joanna, and I will be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation’s Second Quarter 2022 Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. Thank you. Ms. Valentini, you may now begin your conference.

Thank you, Joanna. Good morning, everyone, and welcome to TransAlta’s second quarter 2022 conference call. With me today are John Kousinioris, President and Chief Executive Officer; Todd Stack, EVP Finance and Chief Financial Officer; and Kerry O’Reilly Wilks, EVP, Legal, Commercial, and External Affairs. Today’s call is being webcast, and I invite those listening on the phone lines to view the supporting slides that we have posted on our website. As well, a replay of the call will be available later today and the transcript will be posted to our site shortly thereafter. All of the information provided during this conference call is subject to the forward-looking statement qualification set out here on slide two, also detailed further in our MD&A and incorporated in full for the purpose of today’s call. All amounts referenced during the call are in Canadian currency, unless otherwise noted. The non-IFRS terminology used, including adjusted EBITDA, funds from operations, and free cash flow are also reconciled in the MD&A for your reference. On today’s call, John and Todd will provide an overview of the quarter’s results. After these remarks, we will open the call for questions. And with that, let me turn the call over to John.

Thank you, Chiara. Good morning, everyone, and thank you for joining our second quarter results call for 2022. As part of our commitment toward reconciliation, I want to begin by acknowledging that TransAlta’s Head Office, where we are today, is located in the traditional territories of the Niitsitapi, the People of the Treaty 7 region in Southern Alberta, which includes the Siksika, the Piikani, the Kainai, the Tsuut’ina, and the Stoney-Nakoda First Nations, as well as the home of the Métis Nation, Region 3. TransAlta had a solid second quarter. I’m proud of the progress we’ve made in advancing our priorities and the performance of our company and our employees. In Q2, we delivered $279 million of adjusted EBITDA, leading to free cash flow of $145 million or $0.54 per share, and on a year-to-date basis, we have generated $538 million of adjusted EBITDA, resulting in free cash flow of $253 million or $0.93 per share. Our Alberta Electricity portfolio performed as we had anticipated, despite higher natural gas prices, compressed market heat rates, and a highly hedged position. Overall, our portfolio demonstrated the value of our strategically diversified fleet in Alberta and its ability to generate cash flow under dynamic market conditions. Our Alberta Wind and Hydro fleet led our results with excellent performance, benefiting from the higher pricing environment in the province and stronger production. Whereas our Alberta Gas Segment had limited opportunity to benefit from the higher power prices that were realized in the market as it was highly hedged during the quarter. Contributions from our new contracted assets at Windrise and North Carolina Solar, and the exceptional results from our Energy Marketing segment further supported our financial results for the quarter as we continue to track towards the midpoint of our 2022 guidance. During the quarter, we delivered on a number of key priorities. On the growth side, our development team secured another 200 megawatts of renewables growth, with the announcement of the Horizon Hill Wind Project with Meta, formally known as Facebook. In Western Australia, we’re moving ahead with the Mount Keith Transmission Expansion project with BHP. We also made a commitment to invest $25 million in Energy Impact Partners' new Deep Decarbonization Fund, which is focused on making investments in companies with transformative technologies critical to Deep Decarbonization, including long-term storage, novel generation, and industrial decarbonization. We’re aiming to use this platform to take a targeted approach to diversification and define the next generation of electricity solutions for our company. So far in 2022, we’ve grown our renewable development pipeline by more than 300 megawatts across several prospective wind development sites in Canada and the United States. This is great progress towards our goal of adding over a gigawatt of opportunities in our pipeline this year. We’re targeting to reach investment decisions on another 200 megawatts of renewables growth later this year and are on track to deliver on our annual target of 400 megawatts for 2022. I remain confident in our ability to deliver on the remainder of our 2-gigawatt clean electricity growth plan. Switching to our recontracting activities at Sarnia, we have now secured capacity commitment extensions with all three remaining industrial customers at the facility, with one customer going out to 2031 and the remaining two customers going to 2032. We expect to hear from the ISO on their RFP process later this quarter. We announced a 10-year contract extension with New Brunswick Power, along with the receipt of a waiver from bondholders in relation to the Kent Hills wind facilities, and we have commenced our rehabilitation efforts there. We also continue to make progress on advancing our EBITDA contribution from renewable assets with the addition of Windrise and North Carolina Solar last year. Our EBITDA contribution from renewables and storage assets reached 58% in the quarter, another step towards our target contribution level of 70% by the end of 2025. Finally, in June, we debuted our new brand and visual identity along with our Energizing the Future campaign. This new identity encapsulates TransAlta of today while reinforcing the company’s focus as a leader in creating a carbon-neutral future for our customers. We continue to see considerable opportunities for TransAlta as the race to decarbonize unfolds. As you know, we plan to deliver 2 gigawatts of new renewables capacity by 2025 by deploying approximately $3 billion of growth capital, with the target of achieving cumulative annual EBITDA from the growth projects of $250 million by 2025. Currently, we have approximately $1.3 billion of construction projects ongoing. We are about a year and a half into the execution of the plan and we’re proud of the progress we’ve made. We have secured 800 megawatts of growth projects across Canada, the U.S., and Australia, representing 40% of our 2-gigawatt target by 2025. Combined, these projects will contribute approximately $136 million in EBITDA once fully operational, providing 54% of our five-year incremental annual EBITDA target of $250 million. On the construction front, turbine deliveries commenced in July at Garden Plain; racking and panels have been delivered at Northern Goldfields solar, and the battery is in transit to the site. All major equipment supply and EPC agreements have been executed at both White Rock and Horizon Hill, and the EPC agreement has been executed for the Mount Keith Transmission Expansion project. We are on track to deliver our current construction program across all three of our geographies. The demand for renewables remains strong in the U.S. and we see plenty of opportunity to capture growth in that market. We’re also actively looking at a number of additional opportunities to grow our development pipeline there. These include acquisitions of individual early-stage development sites and small development portfolios, as well as the prospecting of new sites, which we’ll continue to add through the balance of 2022. We’re also working to grow here in Canada, primarily in Alberta. While we have started to see inflationary pressures on capital for new projects, demand for corporate PPAs continues to be strong, and we’re seeing PPA pricing respond to the inflationary pressures. We have confidence in our ability to deliver appropriate risk-adjusted returns for our shareholders. Our team is actively seeking opportunities to contract our sites and advance our projects into the construction phase. We expect our 100-megawatt Tempest Wind project to be our next growth project here in Canada, targeting a final investment decision later this year. It’s currently moving through the AESO interconnection process, and we see strong interest with multiple customers for this opportunity. We’re also seeing growing opportunities in Western Australia in support of our remote mining customers. We are advancing several opportunities there, and we expect to reach a final investment decision on additional projects with BHP before the end of the year. I’ll now turn it over to Todd to take us through our financial results for the quarter.

Thank you, John, and good morning everyone. In Alberta, our hydro, wind, and gas facilities are dispatched as a portfolio in order to benefit from base load and peaking energy sales. In the second quarter, the fleet generated approximately 2,700 gigawatt hours of electricity. Strong pricing throughout the quarter resulted in the average pool price for Q2 settling at $122 per megawatt hour, compared to $106 per megawatt hour in 2021. In 2021, high power prices were driven by extreme weather driving strong demand, as well as from multiple unit outages impacting the supply of electricity. This contrasts with Q2 2020 to 2022, where strong power pricing was largely a result of higher natural gas prices. The quarter saw natural gas prices of roughly $7 per gigajoule, compared to approximately $3 per gigajoule last year. In this pricing environment, our merchant wind and hydro fleet in Alberta performed extremely well. The wind fleet benefited from strong availability in production, but also gained from strong on and off-peak pricing and realized an average merchant revenue of $96 per megawatt hour. This is an outstanding outcome for intermittent wind energy. The high gross lead also performed well in the energy-only market with realized prices in excess of $130 per megawatt hour. Ancillary services revenue in the Hydro segment was lower than 2021 due to lower realized prices driven by increasing competition and supply in the ancillary services market. The gas and energy transition segment results were negatively impacted by several factors. As expected, production in the quarter was lower due to the retirement of Sundance Unit 4 and Keephills Unit 1, as well as higher dispatch optimization on the remaining gas units due to the higher gas prices and tighter spark spreads. In addition, a significant portion of our production was hedged below spot merchant prices, which limited upside performance. Looking at the balance of 2022, we see forward prices in excess of $130 per megawatt hour. Based on expectations for the balance of the year, we’re carrying a lower hedge level into Q3 and Q4 in comparison to our Q2 hedge level. We have approximately 3,000 gigawatt hours of our Alberta gas generation hedged for the balance of the year at an average price of $76 per megawatt hour, and we have 31 million gigajoules of natural gas hedged at approximately $3.70. As John mentioned, our performance in Q2 was led by the wind and solar fleet, which delivered a 60% increase in adjusted EBITDA, from $55 million in the second quarter of 2021 to $88 million this quarter. The increase in performance was driven by multiple factors. First, Q2 benefited from incremental contributions from the new Windrise and North Carolina solar facilities. Second, we had strong wind resource and production across all regions. Third, we had higher realized merging pricing in Alberta; and finally, we had higher environmental credit sales in the quarter compared to 2021. This increase in the wind and solar segment was partially offset by the extended outage at Kent Hills. Our energy marketing team delivered another strong quarter with $50 million in adjusted EBITDA. We now expect the energy marketing segment to generate between $110 million and $130 million in gross margin for the year. Overall, TransAlta’s results were in line with our expectations, and we are on track for solid full-year results. I’m going to turn now to highlight our longer-term trends for free cash flow and EBITDA performance and the continuing financial strength of the company. In the second quarter, we delivered EBITDA of $279 million and $538 million year-to-date, broadly in line with our expectations, and we continue to track within our 2022 EBITDA guidance range. Free cash flow of $145 million or $0.54 per share and $253 million year-to-date was also in line with our expectations and consistent with our 2022 free cash flow guidance range of $455 million to $555 million. Recent volatility in energy market pricing has resulted in both higher cash collateral provided and higher cash collateral held. This movement of cash collateral impacts both accounts receivable and accounts payable balances and resulted in negative working capital in the quarter. I expect these balances to remain elevated for Q3, but begin to reverse in Q4 and in early 2023. Despite this volatility and higher price environment, our balance sheet and liquidity remain very strong. We closed the quarter with approximately $1.9 billion of liquidity. This positions us extremely well to fund our future growth pipeline, including our 680 megawatts of projects under construction. Before turning things back to John, I’ll turn to TransAlta Renewables. Our operating wind and solar assets, as well as the majority of our contracted gas assets, are held within TransAlta Renewables and are fully consolidated in TransAlta’s results. Despite the ongoing suspension of operations at Kent Hills, RNW's results for the quarter have also demonstrated the resilience of the diversified contracted fleet and the value of our 2021 growth investments. During the second quarter, TransAlta Renewables delivered $126 million of adjusted EBITDA, an increase of $29 million compared to the same period in 2021. The increase was a result of incremental production from our Windrise and North Carolina Solar facilities, strong wind resources during the quarter, and an increase in the sale of environmental credits. As John mentioned, during the quarter we executed a 10-year extension to the PPAs with New Brunswick Power for Kent Hills wind facilities, allowing us to proceed with the rehabilitation plan for the site. Construction of the site is underway. We have two cranes on-site working on the disassembly activities, with nine turbines fully disassembled and three foundations removed. A concrete batch plant is now on site, and we’ll soon be ready to start pouring the new foundations. We have strong liquidity at RNW for the upcoming funding needs. In addition to our $700 million committed credit facility, we had $218 million of cash at the end of the quarter. And with that, I’ll turn the call back over to John.

Thanks, Todd. As I look at our strategic priorities for 2022, our goal is to continue delivering clean electricity solutions to customers and to be the supplier of choice for customers that are focused on sustainable growth and decarbonization. In 2022, we’re focused on progressing the following key goals: Reaching final investment decisions on the equivalent of 400 megawatts of additional clean electricity projects across Canada, the United States, and Australia, and we’re on track to secure another 200 megawatts in addition to the 200 megawatts already announced so far this year. Achieving COD on the Garden Plain Wind and Northern Goldfields solar projects; progressing construction on our U.S. wind projects at White Rock and Horizon Hill; and advancing our Mount Keith Transmission Expansion project in Western Australia. Expanding our development pipeline with a focus on renewables and storage; re-contracting with the ISO at Sarnia in Q3; progressing the rehabilitation of Kent Hills Wind; achieving EBITDA and free cash flow within our guidance ranges; and advancing our ESG objectives, which include reclamation work at High Vale and Centralia, provision of indigenous cultural awareness training to all of our employees, and achieving at least 40% female employees by 2030. I’d like to close by highlighting what I think makes TransAlta an attractive investment and a great value opportunity. First, our cash flows are resilient and are supported by a high quality and highly diversified portfolio. Our business is driven by our clean wind and solar portfolio, our unique reliable and perpetual hydro portfolio, and efficient gas portfolio, all of which are complemented by our world-class asset optimization and energy marketing capabilities. Second, we’re a clean electricity leader with a focus on tangible greenhouse gas emissions reductions. We’ve been recognized by MSCI for this leadership with an A rating. We’ve adopted a more ambitious CO2 emissions reductions target of 75% by 2026 from 2015 levels and are committed to setting science-based emissions reductions targets this year. In addition, our focus on removing systemic barriers through our commitment to equity, diversity, and inclusion and good governance shows our commitment to leadership across all dimensions of ESG performance. Third, we have an extensive and diversified set of growth opportunities, expanding our renewable development pipeline by over 300 megawatts so far this year, with a talented development team focused on realizing its value. Our execution is on track, and we’ve delivered on our growth pipeline in 2021 and we’re continuing to deliver on it in 2022. Fourth, our company has a sound financial foundation. Our balance sheet is strong, and we have ample liquidity to fund our growth plan. Finally, our people. Our people are our greatest asset, and I want to thank all of our employees and contractors for the work that they have done to deliver our results this quarter. TransAlta is at an exciting point in its evolution. We focus each and every day on meeting and exceeding the targets that we set for ourselves as a leader in low-cost, reliable, and clean electricity generation focused on meeting the needs of our customers. Thank you, and I’ll turn the call back over to Chiara.

Thank you, John. Joanna, would you please open the call for questions from analysts and then the media.

Thank you. The first question comes from Mark Jarvi at CIBC Capital Markets. Please go ahead.

Thanks. Good morning, everyone. First, maybe give us a bit more color in terms of the dynamics that are happening in the Ancillary market in terms of the softer pricing. You referenced a bit more competition. Is that sort of permanent, could that reverse? Just maybe a bit more details there?

Yeah. Good morning, Mark. So on the Ancillary services, it actually transpired pretty much, I think, the way we expected it to, given where gas prices were during the course of the year. What we’re basically seeing is given where gas prices are and given the dynamics that are in the markets, a number of generators are basically making the decision, 'Do I run, or do I basically bid into the AES market?' effectively looking at what the best avenue is for them to monetize given where the spark spreads were. What we saw is more participation from the gas fleet in the AES market as a consequence of basically high gas prices. Even though we had strong power prices, the cost, the variable cost of generating was super high – that’s what we saw. Our expectation is that it would moderate over time regarding the competition once we have what I would call more normalized gas prices. We still had really good volumes, I would say. Instead of the normal, at least in my mind, kind of 50% to 60% of kind of spot price clearing prices, it was closer to I think in the 40%, 45% range, Mark. So hopefully that gives you a bit of a sense of what we saw.

So, if spark spreads expanded, then you would say it’ll come back to you and be more favorable for your fleet?

That’s exactly right, and I wish I would’ve said it as simply as that.

No, understood! Okay. And then, your updated views in terms of what you’re seeing on the Clean Electricity Standard, the consultation, the framework, and sort of how you think it impacts your fleet, but also just supply in Alberta broadly?

Yeah, it’s interesting. I’m not sure – I’ll answer it maybe in reverse first. I’m not sure that we’re seeing a big impact in terms of some of the regulatory initiatives that are taking place in terms of the incremental supply that’s coming into the province. What we’re seeing is considerable renewables growth that is being driven largely from the ESG requirements that customers have, and frankly, on both sides of the border, we are seeing U.S.-based companies procuring renewables in the province, particularly given some of the timelines to bring some of those renewables to market effectively in the United States. The gas additions that we’re seeing have already been pretty much locked and loaded, I would say, prior to the policy decisions that were being made. We do think that things are moving forward on the clean electricity standard or regulation as we move forward. Our team is working closely with the government as they evolve that. I think the government is trying to make sure that the pathway to decarbonization is met but in a way that also maintains reliability in an appropriate way, kind of post that 2035 period, so we’ll see how that evolves.

Just a quick follow-up on that, John. Just in terms of the tier equivalency review, but also just clean electricity standard, how you think that’ll impact the cogeneration units in the province of Alberta?

That’s – Mark, I wish I knew the answer to that question. You know, I think all I would say is it’s hard to imagine, at least from my perspective, I think our company’s perspective, how the federal government can kind of look to meet the targets that are set for the sector without looking to, at least deal with or bring in some way the cogeneration side of the equation in the province, so we’ll see how they do that. I think candidly, they’re struggling with how to do that, and we’re in discussions with them, but I think it’s hard to get to where they are purporting to get to without at least having some element of including them in the approach. I wish I had more clarity, but I...

No, understood. Thanks for your time today, John.

Yeah, thanks so much.

Thank you. Next question comes from John Mould at TD Securities. Please go ahead.

Thanks. Good morning, everybody. Maybe just starting with your efforts to secure longer-term contracts in Alberta. You know I know you announced earlier this year that you were going to sell 100, I think it’s 100 gigawatt hours a year of wind to one of Lafarge’s plants. How much of your merchant wind would you consider contracting, and maybe the answer is all of it, and what appetite do you see among corporate clients for contracting output from existing assets versus new ones? You know this concept of additionality, particularly in the current power price environment in Alberta?

Yeah, and I think so – first of all, good morning, John. When I think we – you know our C&I team and even our growth team gets it into discussions. It’s not unusual for them, at least in Alberta, to begin having a bit of discussion on whether or not a strip could be sold off of our existing generation, whether it’s wind or hydro. The challenge around hydro, as you know, is it’s a premium product, and it’s interesting how we have to walk people through that so they understand that’s probably a harder one for them to sort of contract with, given the nature of the product that’s there, but we do see interest, both in the wind and in the hydro. There is a strong element of additionality, but I think within the energy sector within the province, more than I would say consumer goods or other commercial counterparties, just a sense of maybe a little bit less focus on additionality and more just how do I meet my ESG requirements, and you do have some existing generation that’s there, and it doesn’t make sense for us to look at doing something there, and it might actually result in a more favorable pricing environment for them than would be the case, particularly in an inflationary period from having a new build. So it’s nuanced, but it’s definitely there, I would say John.

Okay, thanks for that. And just in terms of contract length, you know I’m sure the appetite is all over the place, but are you still seeing that sort of other opportunities to sign for a bit of a longer period in those sorts of customer, I guess non-asset specific negotiations, that you know five to ten-year time horizon? Does that exist?

I would say, so you’re not talking about new builds that need a PPA to bid under a pennant; rather, you’re talking about more on the existing merchant fleet. I think it is a bit all over the place. I think – and I’m just looking at Todd here. I think conventionally on the C&I side, sort of three to four years is what we would see. So in terms of strips off of generation, our goal would be to see if we could do a bit better than that, from a temporal perspective going forward. Ten years is probably a bit of an outlier. That would be a stretch I would say John.

Okay. Thanks for that. And maybe just on the U.S. note maturity later this year. Todd, any just insights you can provide on how you’re approaching that, whether you’re looking at any opportunities to optimize your capital structure a little bit that come along with that refinancing?

Yeah, absolutely. I think we’ve communicated that we are looking to effectively roll it over with a similar bond issuance, and we’ve disclosed that we have pre-hedged a good portion of that bond refinancing. So the movement in underlying interest rates doesn’t really give us a lot of concern, but the bond market has been pretty much disrupted over the last quarter with all of the inflation reports coming out and the increasing and the underlying rates. It’s been a bit of a spotty market over the past several months here, but we’re still confident that windows will open up and allow us to refinance that bond. But more importantly, just to give confidence that we have a lot of access to different sources of capital, we are sitting on lots of capacity in our credit facilities, significant cash balance, and have access to the bank market as well for bridge and term loans, and then access to either the Canadian or U.S. bond markets as well. So a lot of different options for refinancing that, or really just letting it mature and then refinancing it when the markets settle. But I’m confident that there’ll be opportunities to refinance that going forward, but it is going to be a rollover of effectively debt for debt.

Okay, thanks for that detail. I’ll jump back in the queue.

Thank you. Next question comes from Maurice Choy at RBC Capital Markets. Please go ahead.

Thank you, and good morning. I just want to come back to the discussion about AES pricing and maybe take it more broadly to the guidance. You’ve obviously increased your energy marketing guidance, but you kept your overall guidance unchanged, which you mentioned that you are tracking to the midpoint. Was it that you were previously tracking to the bottom end of the range and therefore the revised marketing guidance brings you to the midpoint, or are there some offsetting items that you can speak to, such as the AES pricing being softer?

Let me start with that, and then I’ll hand it back to John. Good morning, Maurice. Just on the energy marketing side, I mean we bumped it by about $15 million in gross margin, which maps after cost about a $10 million increase in EBITDA, so a relatively modest amount on the energy marketing side. I would say John, one of the key drivers for the balance of the year, I think it is a little bit of what we saw in Q2, you know just uncertainty about the performance, the higher gas prices, and how that will impact the gas fleet here in Alberta. We are well hedged. About 75% of our electricity production for the balance of the year is hedged, and at the same time, the gas to support those hedges is also procured. So I would say it's really not that much different, and July came out pretty strong; power prices were pretty good in July, so we'll see how the rest of the summer runs here.

Yeah, and I’d say they’ve been pretty good in August as well, Maurice. I would say, look, we take a long – we look at the full year. We continually update what our forecasting is going to be for the year as we go forward, so our view on where the company would land; I mean the market really focuses on the quarter-by-quarter, but we look at that. We also look at it holistically from where the whole year is going and it's kind of unfolding about where we thought it was going to unfold, I would say you know by and large. To Todd's point, there are some tailwinds that we're seeing that might be a little bit more favorable, and one of the things that we certainly did as we tried to buy back some hedges in our gas fleet to make it a little bit more open, given that we're seeing some stronger pricing in the back half of the year, but I think we're pretty comfortable with where we are from a guidance perspective and you know are keeping it right now and we’ll look to see how this quarter comes in and then we'll reevaluate.

And then maybe just a follow-up to that, you mentioned that you are a little bit more open in Q3 and Q4 than you were in Q2. I guess as a result of buying back some of these hedges. I guess longer-term liquidity aside, would you be more open to being more open, or is the current hedging strategy still the same moving forward?

Yeah, you know it's a great question. We spend a lot of time debating that within the company, and I don't think we are in a place where we're shifting our approach from a hedging perspective. I mean, you know when the team was back in 2021 looking at putting hedges in for 2022, I don't think anybody – at least I couldn't predict that there would be a war in Ukraine and that gas prices would go where they were. So you know in the time it seemed like a rational decision in terms of where we were and it was based on our fundamental view of the market. Looking at Cal 23, which is really what the focus is for the team right now, I think it's rating kind of in that $95 range with gas prices, I think significantly off of what we see now, more in the mid-4s I think as opposed to somewhere in the 5s to low 6s going forward. So the team is looking at that. We are looking at what our fundamental view is in 2023. We think it will be another good year, candidly, so the team will be layering on hedges as we go forward and also looking to make sure that our gas contracted position is aligned with where we’re going. So I think kind of staying the course in terms of the process that we undergo in the company.

Got it. And my final question, you know recent thoughts about the relationship between TA and RNW. Any progress in your ongoing review?

Yeah, I would say, you know, we are continuing to work to just clarify I think the approaches between the two companies. There is convergence. I think you’ve heard us talk about that before in terms of the strategies, and I think it’s incumbent upon us to add some clarity in terms of particularly from a growth perspective where we see the two companies evolving and how our pipeline will play out as between the two companies. Have we sort of landed that with perfection at this point? We haven’t, but you know it’s my goal to be able to provide more clarity as we go through the balance of the year, so that folks have a better idea on how the two are going to evolve.

Thank you very much.

Thank you.

Thank you. Next question comes from Dariusz Lozny at Bank of America. Please go ahead.

Hey guys! Good morning! Thanks for taking my questions.

Good morning, Dariusz.

Just wanted to maybe touch on, in addition to your presentation materials here, alluding to some Alberta thermal redevelopment opportunities. It looks like it’s fairly remote or perhaps early stages at this point. But I’m curious, if number one, you can just speak to those opportunities specifically a little bit more and maybe discuss sort of what the level of discussions being held at present are? What you need to see, whether it’s in the corporate TPA market or otherwise to perhaps advance those, any of those opportunities as you see them today?

Yeah, no, great. Thank you for that. No, you've seen us and you would have seen in the materials both the reference of that at Centralia and also at Alberta Thermal. I think those assets or, more accurately, those geographies and the infrastructure around those geographies are super valuable in terms of how connected they are to the grid and generally even the skilled workforce that we have in those particular areas. So when we look at those sites, we’re thinking of storage, we're thinking of solar, we’ve been actively looking at solar on both sides of the border for those two particular sites, and in the case of both jurisdictions, it’s further away, and looking at the potential for hydrogen too, potentially. Those are longer-term opportunities, and when I referred to in the call to the 300 megawatts that we've added, those are much near-term opportunities. I wasn't referring to the redevelopment of those two sites. But the team has been actively looking at that redevelopment there, I can tell you in Centralia for years, and in Alberta certainly for the last couple of years to see what we can do, and it's just location and interconnectedness which helps improve the economics of those facilities, given that we have all that we need from a transmission perspective right there.

I think we talked about Alberta needing to firm up for some of the resources, and one of the things we see is fast ramping capability, whether that's supplied through batteries or other sources, and so these – as John mentioned, these are great industrial sites to expand that.

And one of the reasons why solar is also very prospective in those areas is it may hamper some of the reclamation work that we would need to do on the existing mine. You have to remember that we have a very large footprint in both of those locations that we're spending $30 million or so a year trying to reclaim, so that’s the other element as we go forward there.

Great! Thank you for that detail, I appreciate that. One more if I can, and this is just touching on Sarnia here. I know the conversations with the Ontario off-taker are still ongoing. Just with respect to, I think there was a large transmission project that was under consideration that looked like it's been put on hold as of earlier last week. Just curious how that may or may not affect your outlook for Sarnia and re-contracting with the province there.

Yeah, we don't think it'll have any impact candidly. I think what the ISO was looking at doing in Southwestern Ontario, Sarnia frankly, even thinking of Windsor as we go forward is really predicated on what they are seeing with the progress that they are making on the nuclear refurbishment program that they are going forward. At least all of the discussions that we've had with them would say that there isn't a correlation between the two, and they are looking to shore up supply of – or secure, I think more accurately supply of electricity into the balance of the decade as a bridge effectively to getting the broader work they are looking at getting done. So I don't think it has any impact certainly on the RFP that we're involved in.

And John, I think the process there is we're expecting that it'll be the ISO or the Ontario government that announces that towards the end of this month.

I think it is the ISO and we're expecting later this month or at the latest early September. But I think it’s August, is I think what we're thinking of, yeah.

Great! Thank you for that color. I'll leave it there.

Thanks.

Thank you. Next question comes from Ben Pham at BMO. Please go ahead.

Hi! Thanks. Good morning! I wanted to ask on the Alberta power prices year-to-date. I know it's really backward-looking. What's been driving the better-than-expected pricing? And then secondly, you'd think with the $95, that's been creeping up too. I mean, why do you think $95 seems reasonable as well?

So in terms of pricing in the year-to-date – and by the way, good morning, Ben! You know, look, when you look at – and we've had heat rate compression frankly this year pretty significantly. I think when I think of last year, it was at times looking at Todd and Chiara, like approaching 40 frankly, and this year it's been sub 20 many times during the course of the year. So if you look at gas at, pick a number, $7, and you have a heat rate of 11, you're nudging up towards $77, $80 just for fuel. Add to that increasing carbon pricing, transmission costs, other variable costs for the facility. For the gas converted fleet anyway, you're in a place where you're nudging up like into $90, sometimes even more, just from a variable cost perspective. So I think that's one of the reasons we've seen power prices. I think frankly, the principal reason we've seen power prices go up where it is. I think we've also seen pretty dramatic load recovery in the province, so we're back to sort of a level of load that we had sort of pre-pandemic. So I think, you know, demand has been solid. I think variable costs led by the price of gas that’s really driven up the variable costs, and I think that's what we're seeing impact pricing this year. To a certain extent, when I think of the balance of the year, we are seeing probably tighter supply cushions in the sense that there are more outages that we're expecting certainly in an October and in November time period in the province that we'd expect the pricing to lift. Looking at Cal 23, you know in terms of $95, again, when you look at higher carbon prices, we are expecting the carbon price to go up by $15 next year. Gas is still comparatively expensive compared to what it was in 2021, certainly although it's lower than it is in 2022. I think again, you know, variable costs would put that pricing well north of $50 in terms of where you are. So I think it's reflective of kind of the margin over the variable costs that the companies need and people that are trading in the market are kind of calibrating to get through. So hopefully that gives you a little bit of color Ben, but I think that's the way we're seeing it.

And maybe to that, I know we're probably in unprecedented territory of where gas and power prices are, but how do you – you spoke on hedging too earlier. Isn't it better to just leave your hedge open, especially on the power side and hedge the fuel costs as much as you can, or is there risk to have that somewhat out of sync?

Yeah, and I think you know it's interesting. When you look at 2022, I really do look at it as a bit of an aberration. We had shocks that occurred in the system that were real tail events in terms of what our fundamental view would've been in terms of where the price is. I can tell you that what our optimization team does is, they look at supply fundamentals, demand fundamentals, they run it through a bunch of weather seeds that they have and basically look at what we as a company think in light of all of the variable costs and the market dynamics, prices will settle. Then we compare that probabilistically against where the forward curve is and then we make a decision as to whether it makes sense to hedge, to protect the cash flow effectively or not. And as you remember, in 2021 our view was that the forward market was not reflective of where power prices were going to go in the year, and we were, to your point, pretty open in terms of going into that year. We didn't expect that in 2022, quite candidly. I think the team thought that the kind of pricing that we were getting was going to be reasonable in the context of the gas pricing that we had, and things were upended. I mean, we saw gas prices double, triple from where they were, and it resulted in a bit of compression I think. I think the one thing then I would say is as time goes by and the units become – and I think it's not just our units, I think gas units generally in our view would become a little bit more peaking in orientation rather than more base load in orientation. It may be that the amount that you would hedge would need to be moderated effectively to permit you to get the kind of peaking prices that you would see. So I don't think we're quite there yet, Ben, but I think certainly as we look forward, that's a trend direction for sure, which I think your question picks up.

It sounds like then with your guidance, you're putting that – it sounds like you're really focused on delivering to that guidance rather than taking more of a direction call on pricing, maybe giving up some upside at some point of time, but it sounds like that's really a big priority for you.

So meeting our guidance is a priority for us. I mean, we don't take the guidance lightly. It is a genuine pre-estimate by the company in terms of where we think we'll perform over the course of the year, and that we do try to beat our guidance. That's all other work that the optimization team does, and they are working hard to do that, and as I mentioned earlier, that's one of the reasons we bought back some of the hedges to really open up the thermal fleet, given the market dynamics that we see at the midpoint of the year to give us a little bit more upside as we go forward.

Okay, understood. Thank you.

The only thing I would add is that we do see a lot of that merchant upside through the hydro and the wind facilities.

Sure, yeah. I mean the wind pricing was extraordinary this quarter.

Thank you. Next question comes from Andrew Kuske at Credit Suisse. Please go ahead.

Thanks. Good morning! I guess maybe just looking over a perspective of time. It seems like your development pipeline that you've got right now is a bit more concentrated in some very specific geographies. Is that a very purposeful action on your part to benefit from a network effect and an interplay between the portfolio, or is that just how things have sort of shaken out in the last little while?

Yeah. Good morning, Andrew, and thank you for that. I would say if you would roll back kind of two or three years in the company, I think we were frankly more Alberta-focused than a little bit opportunistic. Your observation is actually correct. We are being very directed in terms of the kinds of jurisdictions that we're focused on, certainly in the United States in terms of expanding our renewables pipeline. I mean in Canada, it's basically Alberta as really the only, I would say, dynamic market from a growth perspective. In the U.S., it is SBP, MISO, PJM would be the areas, along with the Pacific Northwest that we have a focus on from a team perspective, and I think as the year goes by, you'll see us adding more to the pipeline; that's a real focus for us. And that's in part because that's where the resources are, that's where frankly our skill sets are with our team that we've got in the United States, and that's where we're seeing customer demand for competitive, clean power solutions for customers. So it is very much directed among those geographies and in subsets of those geographies. For example, in Oklahoma, given we've got a cluster there just from, to your point, you know maintenance, control, optimization terms of running the facilities. For sure there are benefits operationally to having clustered assets.

I appreciate that. Then maybe just focusing on that cluster of assets in Oklahoma as you've managed to build up presence fairly quickly. Obviously, there's a lot behind the scenes, but from a visible standpoint fairly quickly, how big do you believe the Oklahoma opportunity could be for TransAlta?

Yeah, so I do think that it is bigger than people currently see, I would say in terms of Oklahoma, and the team is comfort in dealing in Oklahoma and getting all of our permitting. We continue to see demand in Oklahoma. So do we see some more additions there? We do, but we’re also mindful to have kind of an appropriate geographic within our concentrated areas, a bit of diversification as well. So I don't know that you would see Oklahoma become kind of our dominant wind jurisdiction in the U.S. if you see what I'm saying. I think it'll be an important jurisdiction for us, but I think you'll see other states pop up within the areas that have articulated going forward.

I'll just say John, I don't think about it as maybe individual states. I think it’s more about the SBP region, at that region, so the states just north as well and similarly the PJM region is good areas, good market structure, and good demand from corporate clients in those regions.

Sure.

Okay, I appreciate that. If I could sneak in just one little one. Really, has there been any change in tone from developers that you talked to, just given some of the market volatility and rising interest rates and just other pressures more broadly?

I would say for sure there are inflationary pressures. I would say I think we have heard anecdotally that some developers are struggling to actually complete or execute on some of the projects that they may have initiated. You know that’s not us. I mean when we contract for something, we’re laser-focused on getting it done. We have seen PPA prices adjust actually on both sides of the border, increasing to reflect some of the incremental costs that we’re seeing. A little bit of turbulence, but I wouldn’t say a ton of turbulence right now, and even from a supply chain perspective, at least looking at our own company, some of the concerns that we had just from a timing perspective have eased a little bit. We’re getting things broadly speaking within the timelines that we expect them to. The one thing I would say is the cost of delivery has increased pretty dramatically, like shipping costs are probably three times higher, maybe more than they were before.

And that really supports our strategy. When we sign a PPA and commit to a price with a customer, we want to make sure that we’ve locked in the majority of the costs on the other side to actually put that facility in place, so that’s sort of a key foundation of when we move forward with a customer.

Like you know, typically 90% of the costs are locked and loaded from a TransAlta perspective, yeah.

I appreciate the time. Thank you.

Sure. Thanks, Andrew.

Thank you. The next question comes from Naji Baydoun at iA Capital Markets. Please go ahead.

Hi! Good morning. Just wanted to start in Alberta, I see that you revised your EBITDA expectations for Tempest, but not the CapEx figures. Is it still within your target return ranges, but is that just a function of where the corporate PPA market or the overall Alberta pricing market is evolving?

Yeah. Good morning Naji. No, I think we are – so when you look at our clean electricity growth plan, you know we talk about that capital number to get the plan done. We are looking at that number, because I think what’s in your question is, you know that’s based on cost that would’ve been, you know germane a year ago when we rolled it out and certainly the prices have – or the costs have really increased, so we are seeing some of the capital costs increase. But we’re also seeing the PPA prices increase. I mean we are seeing well north of 10% increases in PPA prices in Alberta. I think our customers understand that the costs have gone up in doing it. Our view is that the returns that we were targeting to be able to realize, we’re able to still get, and even though the cost might be escalating, the EBITDA that you would get associated with that project are also being revised upwards to basically land you in the place that you need it to. Does that answer your question or did I miss it?

No, that’s helpful. That’s good, thank you. And just on the U.S. side, given the good news fold we’ve seen there in the past few months, be it on the tariffs or the U.S. tax incentive extensions, do you see this as sort of an inflection point for you to try to accelerate maybe growth, wind, or solar and maybe even look to do more acquisitions?

We continually look to see if there are acquisitions that make sense for us. We have a small M&A team, but they do see all of the processes that go on. The kinds of acquisitions that we would be interested would be, you know, is there some existing generation, but more pipelines, maybe a development team with it, or a skill set that maybe we don’t have quite as developed internally, that would be attractive to us going forward. To your point on the regulatory environment, it is a positive one in terms of what we see happening in the United States. I think we’re set up just given, I would say Todd, our tax position in the United States that we're almost different I would say, whether the policy environment kind of is more constricted in terms of PTCs and ITCs or not. I think the pathway for us is good either way. I don’t know if you want to add anything.

I mean the PTC structure really falls to benefit of the customers and what they actually pay for the electricity component. But it does on our part require tax equity financing to make the project economics to really take advantage of the ITCs or PTCs. It’s a pretty challenging market; the tax equity market for sure. It’s just not a very deep and efficient market. It’s very, very complex.

Whereas by contrast a more conventional project financing market is very, very liquid, much easier I think to be able to land. But we are, I would say Todd and Naji, the demand for renewables continues at least from our perspective to remain unabated. I mean we have customers that would – you know if we had more product, I think we’d be able to put it to them.

Absolutely!

So just maybe one last question on Canada. You mentioned Alberta’s really the focus here, but we are seeing a pick-up in activity in other provinces, be it Quebec or potentially more in Ontario and others. Is there a way for you to maybe access some of that growth in those markets via some partnerships, or you’d rather just stay focused on Alberta for now?

No, we’re not wedded to being sort of exclusively in Alberta. We just, you know, we don’t – we focused on developing a pipeline here. It’s our backyard. It’s a market that we know well, both from a customer perspective, a regulatory perspective, a construction perspective, and certainly an optimization and pricing perspective. So it’s more that we have nothing active particularly in whether it’s in Quebec or really Ontario from a renewables perspective at this point. Would we rule out doing something with somebody? The answer to that is no. But I don’t think we have anything active at this point in time to be able to push through.

Okay, got it. That’s very clear. Thank you.

Great! Thank you.

Thank you. The final question comes from Chris Varcoe at The Calgary Herald. Please go ahead.

Hi John! I’m wondering if you could just elaborate a little bit on what are your biggest concerns or what do you see as the biggest challenges as the federal government moves forward with the Canadian clean electricity standards?

Good morning Chris, and thanks for that question. You know look, what we tell all levels of government when we speak to them is that they need to think of the market as a three-legged stool, or the objective should be to think of things as a three-legged stool. I think the three legs are reliability. We need to make sure that it’s affordable, and we need to make sure that it’s clean, and so our biggest concern would be that at times there is a focus on only one leg of the stool. For example, clean, potentially at the expense of reliability or affordability. I think in order for us to get to where we’re aspirationally trying to get to from an emissions perspective, it’s going to require just a lot of cooperation among industry and all levels of government in order to come up with a structure that gets us there. I think it’s going to require an all-of-the-above solution. In other words, we’ll need gas, we’ll need hydro, we’ll need wind, we’ll need storage, and we’ll need solar. There isn’t any one element that’s going to get us where we need to be and forget 2035, 2030. They need to do it in a balanced way, and so when we engage with government, we continually remind them of the importance of ensuring that there’s interactions between all levels and industry and also just keeping their focus on those three legs of the stool. It isn’t just about clean. You’re going to have a very clean grid, but if nobody can afford it, I’m not sure that you’ve met your objective, or if it’s unreliable in the sense that we don’t have the kinds of generation we need to be in the market to backstop the system when we don’t have a lot of water or the sun isn’t out, or the wind isn’t blowing, that’s a problem. We can’t have brownouts in the jurisdiction. It’s really about that, I would say, I think would be number one. The other thing I would say, Chris, is I think embedded in everything that we’re trying to do from a policy perspective is the notion that there will be technological solutions. Like there’s an assumption I would say that storage will become more effective and more cost effective as we go forward, or that hydrogen will come in, or that carbon capture and storage will be super effective in capturing the CO2 emissions, and you know there are question marks around all of that stuff. So both from a cost perspective and from an effectiveness perspective. If we knew for sure that all of that was going to land and we’d be able to get to 2035 in a way that ticks that three legged stool, great. But there’s tremendous uncertainty as to when and how that will all evolve and will it be effective? Will it be cost-effective for our customers? So that’s the other area of worry, and I know government is aware of that, and they are trying to develop programs and funding to accelerate development there. But I think there’s this general policy, trying to have a balanced policy, and the second one is trying to encourage technology to get to where it needs to get to, because I don’t think we’re quite there yet, regardless of which type of generation that you see. One of the things we implore the government to do is also to be a little bit technology agnostic. In other words, don’t favor one type of technology over the other, because we just don’t know whether that’ll be the one that really helps us land the plane at the end of the day. So hopefully that gives you a bit of a sense.

Yes, and just to follow up then, do you believe that a net-zero grid is achievable by 2035 given just the conversations you’ve had with the federal government? Is what they are seeking achievable in your point of view?

I think it’s a question of – so look, we do a bunch of modeling internally and trying to look at pathways to get to net zero. So, let me answer the question in two ways. Do I think that we can substantially decarbonize the grid between where we are today and where our aspiration we’re trying to go to in 2035? I think the answer is yes. And we can do that with a fair bit of the existing technology that we have. The challenge that we see is that the last 10% of emissions reductions is (A) hard to do and super expensive to do today in terms of where we’re trying to go to. So do I think that we’ll be able to substantially get to where everybody is hoping that we’ll be able to get? I think yes. I’m pretty confident in our ability to do that. I think we’re going to need a little bit of help to just get those last megatons of CO2 out. And when I say that, Chris, I’m thinking of more Alberta and Saskatchewan, where our provinces are more focused on frankly, you can throw New Brunswick into that mix too, where provinces that our generation was built on the resources that we had. It was favorable for us to do it, whether it was coal or whether it was natural. It’s not like we’re rich in hydro or water in our part of the world. So the burden, like nationally, there’s so much hydro and there’s nuclear in Ontario, as you know, and so it’s easier for much of the country; and frankly, electricity is substantially decarbonized in the country. The challenge is really in the prairie provinces, and I don’t mean Manitoba, who has a ton of water. It’s more Alberta and Saskatchewan, and that’s why I think it’s an all-of-the-above solution. I think we are going to move forward well, and I think it’s just being mindful of that three legged tool as we get to that very, you know the tail of getting to success.

Finally, just to follow up on that, with regards to the tier review, I know that the input process is I guess wrapping up. What would be your main recommendation or recommendations for the Alberta government as they conclude that tier review?

Yeah, we’re still working through our response on that, Chris. I mean, I - look, we – some of the things that we are looking at doing is we’re encouraging the province to chart a course, I would say, in a way that ensures that the levers that we control in terms of how carbon pricing is worked and applied is controlled within the province. In other words, developing a policy environment that meets kind of the dictates of where the federal government is directing us to get to, but really control of the details in terms of how it’s done, again looking at that three-legged tool is made in Edmonton, in terms of the kind of policy decisions that we made. That’s probably our key recommendations. There is a policy paper that’s out. We’re supportive of, I would say, very much most of the direction that the province is going in with that, and we’ll see how the review transpires over the course of the balance of the year. But I think the province would be well advised to really make sure that they land a policy that is controlled by the province, and I think they are very much focused on doing that. So I think from that perspective we’re pretty aligned and not just TransAlta; I think you know most of the players within the province would be encouraging of that approach.

Thank you.

Great!

Thank you. Joanna, would you please open the call for questions from analysts and then the media.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect your lines.