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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. [Operator Instructions] Ms. Valentini, you may 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 website shortly thereafter. All the information provided during this call is subject to the forward looking statement qualifications set out here on slide 2. Also details 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 towards 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 Metis 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 54 cents 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 93 cents 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 Wind Rise 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 BHB. 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 to find the next generation of electricity solutions for our company. And so far in 2022, we've grown our renewables 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 3 remaining industrial customers at the facility, with one customer going out to 2031, and the remaining 2 customers going to 2032. And we expect to hear from the ISO on their RFP process later this quarter. We announced the 10-year contract extension with New Brunswick Power, along with the receipt of a waiver from bond holders in relation to the Kent Hills Wind Facilities, and we've commenced our rehabilitation efforts there. We also continue to make progress on advancing our EBITDA contribution from renewables assets, with the addition of Wind Rise 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. And finally in June, we debuted our new brand and visual identity, along with our Energizing the Future campaign. This new identity encapsulates the 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 continues to unfold. 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. We currently have approximately $1.3 billion of construction projects ongoing. We're about a year and a half into the execution of the plan, and we're proud of the progress that we've made. We have secured 800 megawatts of growth projects across Canada, the US, 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 5-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 Goldfield 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's Transmission Expansion Project. We're on track to deliver our current construction program across all 3 of our geographies. The demand for renewables remains strong in the US, 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 ASO 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're advancing several opportunities there, and we expect to reach 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 pull 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 to Q2 2022, where strong power pricing was largely as a result of higher natural gas prices. The quarter saw natural gas prices of roughly $7 per DJ, compared to approximately $3 per DJ last year. In this pricing environment, our emergent wind and hydro fleet in Alberta performed extremely well. The wind fleet benefited from strong availability and 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 hydro fleet 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, as a result of 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 Keith Hills unit one, 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 3000 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 DJs 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 Wind Rise and North Carolina Solar facilities. Second, we had strong wind resource and production across all regions. Third, we had higher realized merchant pricing in Alberta, and finally we had higher environmental credit sales in the quarter as 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 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 54 cents 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 a 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 Wind Rise and North Carolina Solar Facilities, strong wind resource 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 at the site is underway. We have 2 cranes on site, working on the disassembly activities, with 9 turbines fully disassembled, and 3 foundations removed. A concrete batch plant is now on site, and will 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 securing another 200 megawatts in addition to the 200 megawatts already announced so far this year. Achieving COD on the Garden Plain Wind and Northern Goldfield Solar projects, progressing construction on our US 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, recontracting with the ISO at Sarnia in Q3, progressing the rehabilitation of Kent Hill's wind, achieving EBITDA and free cash flow within our guidance ranges, and advancing our ESG objectives, which include reclamation work at Hibail and Centralia, the 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 our efficient gas portfolio, all of which are complimented 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 a science based emissions reductions target 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 that 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?
[Operator Instructions] First question comes from Mark Jarvi at CIBC Capital Markets.
First, maybe give us a bit more color in terms of the dynamics that are happening in ancillary market, in terms of the softer pricing, and reference a bit more competition. Is that sort of permanent? Could that reverse? Just maybe a bit more details there?
Yes, Mark. So on the ancillary services, it actually transpired, pretty much I think the way we expected it to, given where gas prices were in during the course of the year. So 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 AS market, effectively looking at what that best avenue is for them to monetize given where the spark spreads were? So what we saw is more participation from the gas fleet in the AS market, as a consequence of basically high gas prices. And even though we had strong power prices, the variable cost of generating was super high. So that's what we saw. Our expectation is that it would moderate over time in terms of the competition, as soon as we ended up having what I would call more normalized gas prices as a consequence. And we still had really good volumes, I would say. I think what we saw was rather than the normal, at least in my own mind, kind of 50 to 60% 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'd come back to you, it'd be more favorable for your fleet?
That's exactly right. And I wish I would've said it as simply as that.
No, understood.
That's exactly right.
Okay. And then your updated views in terms of what you're seeing on the clean electricity standard, the consultation, the framework, as sort of how you think it impacts your fleet, but also just supply in Alberta broadly?
Yes, it's interesting. 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. I mean, what we're seeing is a considerable amount of 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 US based companies procuring renewables in the province, particularly given just some of the timelines to bring some of those renewables to market effectively in the United States. And 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 basically being made. We do think that things are moving forward on the clean electricity standard or regulation as we move forward. We've been commenting on the process. 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. And then the tier review is happening in Alberta as well and across the country. So a lot of discussion and analysis. In fact, we just provided, we will be on the weekend actually, providing our input on the first round of comments that the province is looking at on tier. I would say that's also ongoing. We're seeing signals from the government about a declining performance standard. So a greater exposure of carbon emissions to the carbon price as we go forward. But I think when we look at it, we're trying to guide our strategy in a place that effectively is independent on some of the buffeting that you see from a policy perspective, which has really underpinned some of the contracted, clean electricity growth that we're really trying to land as a company. And as you've seen, I mean, our EBITDA is much more green, if I can call it that, directionally in terms of where it's going.
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 co-generation units in the province of Alberta?
Mark, I wish I knew the answer to that question. 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 government, the federal government, can kind of look to meet the kind of targets that is set for the sector without looking to at least deal with or bring in, in some way, the co-generation side of the equation in the province. So we'll see how they do that. I think candidly, I think 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're purporting to get to without at least having some element of including them in the approach. I wish I had more clarity.
Next question comes from John Mould at TD Securities.
Thanks. Morning, everybody. Maybe just starting with your efforts to secure longer term contracts in Alberta. 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's all of it, and what appetite do you see among corporate clients for contracting output from existing assets versus new ones? This concept of additionality, particularly in the current power price environment in Alberta?
Yes. And I think, so when, I think, our CNI 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 kind of walk people through that so they understand that 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 with 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 does it 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, I'm sure the appetite is all over the place, but are you still seeing that sort of, are there opportunities to sign for a bit of a longer period in those sorts of customer, I guess non-asset specific negotiations, that 5 to 10 year time horizon? Does that exist?
I would say, so you're not talking about new builds that need a PPH bid under 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 CNI side sort of 3 to 4 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. 10 is probably a bit of an outlier.
That's for sure.
Seeing that would be a stretch, I would say, John.
Okay. Okay. Thanks for that. And maybe just on the US 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?
Yes, 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. So 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, have access to the bank market as well for bridge and term loans, and then access to either the Canadian or US 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.
Next question comes from Maurice Choy at RBC Capital Markets.
I just want to come back to the discussion about AS pricing and maybe take a more broad view into the guidance. You've obviously increased your energy marketing guidance, but you've 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 AS pricing being softer?
Let me start with that and then I'll hand it back to John. Just on the energy marketing side, I mean, we bumped it by about 15 million in gross margin, which maps after cost to 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, just uncertainty about 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 that the gas to support those hedges are 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.
Yes. 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, it's interesting, the market really focuses on the quarter by quarter, but we look at that, but 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, by and large. I would say, to Todd's point, there are some tailwinds that we're seeing that might help things and be a little bit more favorable. And one of the things that we certainly did is 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 where we are from a guidance perspective and are keeping it right now and we'll look to see how this quarter comes in. And then we'll reevaluate.
And maybe just a follow up to that. You mentioned that you're a little bit more open in Q3 and Q4 than you were in Q2, maybe 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?
Yes. 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, when the team was, back into 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 in the time it seemed like a rational decision in terms of where we were and 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 creating 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'll 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 contractive 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, your recent thoughts about the relationship between TA and R&W, any progress in your ongoing review?
Yes, I would say, we are continuing to work to just clarify, I think, the approaches between the 2 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 2 companies evolving and how our pipeline will play out as between the 2 companies. Have we sort of landed that with perfection at this point? We haven't, but 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 2 are going to evolve.
Next question comes from Dariusz Lozny at Bank of America.
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 PPA market or otherwise to perhaps advance any of those opportunities as you see them today.
Yes, no, great. Thank you for that. No, you've seen us and you would've seen the materials both in reference of that at Centralia and also at Alberta Thermal. I think those assets are... More accurately, those geographies and the infrastructure around those geographies is super valuable in terms of how connected they are to the grid. And generally even the skills 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 2 particular sites and in the case of both jurisdictions, and it's further away looking at the potential for hydrogen potentially. So 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 redevelopments of those 2 sites, but the team has been actively looking at 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, 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've talked about Alberta needing firming up for some of the resources. And one of the things we see is fast ramping capability, whether that's supplied through batteries or, or other sources. And so 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 temper some of the reclamation work that we would need to do on the existing mine. You have to remember that we have very large footprints in both of those locations that we're spending 30 or so million a year trying to reclaim. So that's the other element as we go forward there.
Great. Appreciate that. One more if I can, and this is just touching on Sarnia here. I know the conversations with Ontario offtaker are still ongoing. Just with respect to, I think there was a large transmission project that was under consideration that it looks like has 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.
Yes, 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're seeing with the progress that they're making on the nuclear refurbishment program that they're going forward. So I think at least all of the discussions that we've had with them would say that there isn't a correlation between the 2 and they are looking to kind of 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 that they're 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, it'll be the ISO, the Ontario government that announces that towards the end of this month.
I think it is the ISO, 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, yes.
Next question comes from Ben Pham at BMO.
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. Why do you think 95 seems reasonable as well?
So in terms of pricing in the year to date, Ben, 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 I'm looking at Todd and Chiara 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 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 principle 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 demand has been solid. I think variable costs led by the price of gas of really driven up the variable costs. And I think that's what we're seeing really impact pricing this year. And 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's 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, 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, variable costs would, would put that pricing well north of $50 in terms of where you are. So I think it's just 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.
Okay. And maybe to that, I know we're probably in an unprecedented territory of where gas and power prices are, but how do 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?
Yes. And I think 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. And 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 up ended. 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 our view would be in the province, 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 out, it sounds like you're really focused on delivering to that guidance rather than taking more of a direction calling on pricing. Maybe giving up some upside at some point in time, but it sounds like that's really a big priority for you.
So meeting our guidance is a priority for us. We don't take the guidance slightly. 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 we do try to beat our guidance. That's all the work that the optimization team does, and they're working hard to do that. And, and as I mentioned earlier, that's one of the reasons we bought back some of the head just 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.
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, yes.
We do have a large open position. It wasn't as much as we had originally planned on the gas side, but certainly the hydro and the wind business see that upside.
Yes. I mean the wind pricing was extraordinary that quarter.
Next question comes from Andrew Kuske at Credit Suisse.
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 parts 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?
Yes. Andrew, thank you for that. I would say if you would roll back kind of 2 or 3 years in the company, I think we were frankly, more Alberta focused than a little bit opportunistic. I think your observation, not I think, I know 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. In Canada, it's basically Alberta as really the only, I would say, dynamic market from a growth perspective. In the US, it is SBP, MISO, PJM, would be the areas, along with the Pacific Northwest, would be the areas that we have a focus on from a team perspective. And I think as the year go 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 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 in terms of competitive, clean power solutions for customers. So it's very much directed among those geographies and in sub sets of those geographies. So for example, in Oklahoma, given we've got a cluster there just to your point, maintenance, control, optimization terms of running the facilities. For sure there are benefits operationally to having clustered assets.
Appreciate that. Then maybe just focusing on that cluster of assets in Oklahoma is you've managed to build up a 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?
Yes. So I do think that it is bigger than people currently see, I would say, in terms of Oklahoma and the team has 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 US 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'd just say John, I don't think about it as maybe individual states. I think it more about the SBP region, that region. So the states just north as well and similar to the PJM region is good areas, good market structure, good demand from corporate clients in those regions.
Sure.
Okay. Appreciate that. If I could sneak in just one little one. Has there been any change in tone from developers that you talk 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. That's not us. 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. So 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, Andrew have kind of 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. Shipping costs are probably 3 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.
Yes, typically 90% of the costs are locked and loaded from a TA perspective. Yes.
Next question comes from Naji Baydoun at iA Capital Markets.
Just wanted to start in Alberta. I see that you revised your EBITDA expectations for Tempest, but not the cap tax figures. It's 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?
Yes. No, I think we are. So when you look at our clean electricity growth plan, we talk about the capital number to get the plan done. We are looking at that number because I think what's in your question is that's based on cost that would've been germane a year ago when we rolled it out and certainly the prices have or the cost has really increased. We are seeing some of the capital costs increase, but we're also seeing the PPA prices increase. We're 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. And just on the US side, given the good useful that we've seen there in the past few months, be it on the tariffs or the US 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's 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, is there some existing generation but more pipelines, maybe a development team with it, or a skillset 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 indifferent I would say, whether the policy environment 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.
The PTC structure really falls to a 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 projects economics to really take advantage of the ITCs or PTCs. And it's a pretty challenging market in the tax equity market for sure.
But we see...
It's just not a very deep and efficient market. It's very, very complex.
Whereas by contrast a more conventional project financing market, 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. We have customers that would, if we had more product, I think we'd be able to put it to them.
Absolutely.
Just maybe one last question on Canada. You mentioned Alberta's really the focus here, but we are seeing a pickup 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 stayed focus on Alberta for now?
No, we're not wedded to being sort of exclusively in Alberta. 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. 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 that's active at this point in time to be able to push through.
Final question comes from Chris Varcoe at The Calgary Herald.
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?
Chris, thanks for that question. Look, what we tell all levels of government when we speak to them is that they need to think of the market as a 3-legged stool, or the objective should be to think of things as a 3-legged stool. And I think the 3 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. And 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. And I think it's going to require an all of the above. In other words, we'll need gas, we'll need hydro, we'll need wind, we'll need storage, we'll need solar. There isn't any one element that's going to get us where we need to be in forget 2035, 2030. But they need to do it in a holistic balance 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 3 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. So 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. 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 there's question marks around all of that stuff, both from a cost perspective and from an effectiveness perspective. So 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 3 legged stool, great. But there's a tremendous amount of uncertainty as to when and how that will all evolve and will it be effective? Will it be cost effective for our customers? That's the other area of worry. And I know government is aware of that, and they're 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. And one of the things we implore 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. 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're 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. Let me answer the question in 2 ways. Do I think that we can substantially decarbonize the grid between where we are today and where 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 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. 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 because it was favorable for us to do it, whether it was coal, 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 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 3 legged tool as we get to that very, 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?
Yes, we're still working through our response on that, Chris. Look, 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 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 3 legged tool is really 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're very much focused on doing that. I think from that perspective, we're pretty aligned and not just TransAlta, I think most of the players within the province would be encouraging of that approach.
There are no further questions. You may proceed with closing comments.
Great. Thank you, Joanna. Thank you everyone. That concludes our call for today. If you have any questions, please don't hesitate to reach out to the TransAlta investor relations team. Have a great day.
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