TransAlta Corporation (NYSE:TAC) Q3 2023 Earnings Call Transcript

TransAlta Corporation (NYSE:TAC) Q3 2023 Earnings Call Transcript November 7, 2023

TransAlta Corporation beats earnings expectations. Reported EPS is $1.41, expectations were $0.32.

Operator: Good morning. My name is Jenny, and I will be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation’s Third Quarter 2023 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 [Operator Instructions]. Ms. Valentini, you may begin your conference.

Chiara Valentini: Thank you, Jenny. Good morning, everyone. And welcome to TransAlta’s third quarter 2023 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, commercial, Legal, and External Affairs. Today’s call is being webcast, and I invite those listening on the phone lines to view the supporting slides that are posted on our Web site. A replay of the call will be available later today, and the transcript will be posted to our Web site shortly thereafter. All the information provided during this conference call is subject to the forward-looking statement qualification set out here on Slide 2. It’s detailed further in our MD&A and incorporated in full for the purposes of today’s call.

All amounts referenced during the call are in Canadian currency, unless otherwise 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 can call for questions. And with that, let me turn the call over to John.

John Kousinioris: Thank you, Chiara. Good morning, everyone. And thank you for joining our third quarter results call for 2023. 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 seven region in Southern Alberta, which includes the Siksika, the Piikani, the Kainai, the Tsuut’ina, and the Stoney-Nakoda First Nations, including the Bearspaw, Chiniki and Good Stony First Nations, as well as the home of Matis Nation of Alberta Region 3. TransAlta delivered another strong performance in the third quarter with $453 million of adjusted EBITDA and free cash flow of $228 million or $0.87 per share.

Both metrics were in line with our expectations for the quarter. Our performance was led by our Alberta gas, delays in supply returning to service along with the reduction of power imports into Alberta and the lower water and wind resource enabled our merchant gas fleet in Alberta to perform exceptionally well. Our asset optimization program for the Alberta gas fleet also delivered higher contributions than the third quarter of 2022 due to higher hedged volumes at overall higher hedge prices than the previous year. This, coupled with lower realized gas prices in 2023, significantly expanded gross margin from our Alberta gas portfolio compared to Q3 of 2022. Our Alberta hydro fleet also performed well, although, more normalized as compared to last year’s exceptional quarter due to the impact of lower prices and lower water resource availability, which impacted production.

Overall, our fleet availability was excellent at 91.9%. During the quarter and more recently, we have delivered on a number of key priorities and strategic initiatives. First, we announced that TransAlta had entered into a definitive agreement with an affiliate of Energy Capital Partners, the parent of Heartland Generation, pursuant to which TransAlta will acquire Heartland and its entire business operations in Alberta and British Columbia for $390 million, subject to working capital and other adjustments, as well as the assumption of $268 million of low cost debt. This opportunity will enable us to expand and enhance our competitiveness and generation capabilities with 1.8 gigawatts of additional capacity to meet the changing demands of energy transition.

Second, we closed the acquisition of TransAlta Renewables, which represents a key milestone for the company. The simplified corporate structure and unified asset ownership, capital resources and capabilities will enhance cash flow predictability and enable us to better realize future growth. Third, we fully commissioned the Garden Plain wind facility, adding a 130 megawatts to our installed capacity. The facility is fully contracted with Pembina and PepsiCo and has a weighted average contract life of 17 years. Fourth, we significantly advanced the rehabilitation of Kent Hills with all 50 turbines now fully reassembled and being returned to service as commissioning activities are completed. To-date, 36 turbines have been fully placed back in operation and are now earning revenues from New Brunswick Power.

Full commercial operations is expected to be reached before the end of the year. Fifth, we were proud to have ranked first on Newsweek’s inaugural world’s most trustworthy company’s 2023 for the energy and utilities category, following an extensive global survey and evaluations of companies that people trust as a customer, as an investor and as an employee. And finally, with another quarter of strong cash flow, our balance sheet position is strong with excellent liquidity to fund our recently announced transaction with Heartland Generation, as well as our growth projects. We made significant progress on our growth initiatives during the quarter and are on-track to complete all our contracted renewables projects under construction either during the fourth quarter of 2023 or early in 2024.

We currently have 548 megawatts of products in the construction phase, representing an investment of $1.3 billion with approximately $1.2 billion spent to date and a $100 million left to go. Our Northern Goldfield solar project in Australia is nearing completion. Energization and testing processes are now fully in progress with the facility expected to achieve commercial operations by the end of the year. This project will deliver approximately $9 million of adjusted EBITDA annually. Construction at the Horizon Hill wind project in Oklahoma is also well advanced with all 34 wind turbines fully assembled. Construction of the transmission interconnection is now underway and expected to soon be complete with the facility reaching commercial operations during the first quarter of 2024.

At our White Rock East and West projects, equipment deliveries are now complete and wind turbine assembly is progressing well, with 34 out of 51 turbines fully assembled. The transmission interconnection is advancing and commercial operations are also expected in early 2024. Together, our Horizon Hill and White Rock Oklahoma wind projects will contribute over $100 million of EBITDA annually. Finally, our Mount Keith 132 KV expansion project is also making excellent progress with the transmission line and transformer installation now complete. The project will achieve commercial operations by the end of the year and contribute approximately $7 million of adjusted EBITDA annually. We are pleased that the finish line is in sight for all of these projects and look forward to adding all four to our operations in the near term.

Within our development pipeline, we have 418 megawatts of advanced stage generation and transmission projects that we are progressing towards final investment decisions, representing additional growth capital of approximately $750 million. They range from wind generation at Tempest to battery storage at WaterCharger. We have been patient and disciplined in advancing these projects, focused on ensuring that they are appropriately derisked and construction ready with appropriate risk adjusted returns to enhance shareholder value, given the inflationary environment in which we found ourselves. Finally, we are pleased with the advancement in our growth pipeline, having almost reached our 5 gigawatt target two years early. During the quarter, we added an additional 186 megawatts of future development opportunities to the pipeline and have added over 800 megawatts of projects in the year today.

I’ll now pass it over to Todd to go through our segment results.

Todd Stack: Thank you, John, and good morning, everyone. As I usually do, I will start my comments with an overview of our Alberta portfolio performance. Overall, during the first nine months of the year, we continue to realize high merchant power pricing for energy and ancillary services across the merchant fleet in Alberta and have been able to optimize our capacity across all fuel types in our portfolio. Spot price in the quarter averaged $152 per megawatt hour, which was below last year’s Q3 price of $221. The gas fleet again exceeded our expectations, operating with strong availability and capturing peak pricing throughout the quarter with a realized merchant price of a $173 per megawatt hour, which represents a 14% premium to the average spot price.

Similarly, the ability of our hydro fleet to capture peak pricing was demonstrated throughout the third quarter with a realized energy price of $195 per megawatt hour, which represents a 28% premium to the average spot price. Our merchant wind fleet realized an average price of $103 per megawatt hour, which is below the average price of $136 that we saw last year. But on a year-to-date basis, the merchant wind fleet has realized an average price of $89, which is tracking higher than what the flip wind fleet realized in the first nine months of 2022. Looking at the balance of year for 2023. We have approximately 1,700 gigawatt hours of Alberta gas generation hedged at an average price of $89 per megawatt hour, and roughly 95% of our required natural gas volumes are hedged at an attractive price of $2.34 per GJ.

Our hedging activities aim to mitigate the impact of unfavorable market pricing on the Alberta gas fleet and we continue to retain a significant open position in order to realize higher pricing during times of peak market demand, which was demonstrated in our strong Q3 and year-to-date results. Our financial results for the third quarter exceeded our expectations for the period. And as John noted, we generated $453 million of adjusted EBITDA and an impressive $228 million of free cash flow. Our performance in the third quarter was led by the gas fleet with adjusted EBITDA of $254 million. The gas fleet significantly exceeded management’s expectations for the segment and the performance is consistent with our revised expected full year financial guidance provided in the second quarter of 2023.

The segment performance at strong gross margins driven by higher production due to market demand, higher realized power prices and volumes from our hedging program and lower gas costs due to both lower spot gas pricing and benefits from our gas hedging program. The hydro segment performed very well with an adjusted EBITDA of $150 million. Hydro benefited from strong realized pricing and gains realized from our hedging program, but was affected by lower water resources as compared to 2022. The Q3 of 2022 hydro production levels were abnormally strong due to a late spring runoff, which boosted production last year. This year, Q3 production levels were about 10% below average, driven by the timing of spring runoff, which occurred earlier in the season.

Production was also impacted by overall lower precipitation levels. Ancillary services volumes were lower year-over-year due lower procurement demand from the ISO due to reduced import levels and from the lower availability of water resource. Our realized price of ancillary services remain strong in the quarter at 54% of spot prices. The wind and solar segment underperformed quarter-over-quarter. Although, we brought our new production from the Garden Plain facility and had commissioning production volumes from Kent Hills, we experienced lower overall production due to weaker wind and solar resources in all regions compared to the same quarter last year. We also experienced lower realized merchant prices in Alberta and lower revenue from the timing of environmental attribute sales.

Quarterly variability in wind resource is expected and we remain confident in our fleet’s ability to realize its long term average production levels. In the quarter, energy marketing delivered $26 million of gross margin and $13 million of adjusted EBITDA. Results in the quarter were affected by adjustments to revenues due to the timing of settlements, which we expect to be realized in subsequent quarters. We still expect the segment to meet our revised guidance range of $130 million to $150 million of gross margin. On a year-to-date basis, we are exceeding last year’s performance and have delivered over $1.3 billion of EBITDA this year, well ahead of the $1.1 billion delivered over the same period in 2022. Similarly, free cash flow delivered year-to-date is $769 million, a 19% improvement over 2022’s free cash flow in the same period.

Overall, TransAlta’s results are within our expectations and keep us well on track to meet our guidance target of $1.7 billion to $1.8 billion of adjusted EBITDA and between $850 million and $950 million of free cash flow. The strong performance of our hydro fleet continues to benefit our shareholders. In the third quarter, the hydro assets generated $150 million in EBITDA and year-to-date have generated just over $400 million. We continue to see strength in Q4 and are on track to deliver $500 million of adjusted EBITDA this year from the hydro segment. Although energy production and ancillary services volumes vary quarterly, they remain largely consistent on an annual basis. This provides long term predictability and a floor to cash flows that is unique to this asset class.

While water resource and energy production in Q3 of 2023 was below last year, we remain confident in the fleet’s ability to realize its long term average production levels. Realized pricing in hydro continues to be strong with a premium on spot electricity prices averaging roughly 26% over the last three years, and with ancillary services earning an average of 50% of spot prices. In Q3, we also executed a number of power hedges, which contributed positively to our third quarter results. As John indicated, last week, we announced our agreement to acquire the Heartland business. The availability of the Heartland portfolio created an unexpected opportunity for TransAlta and we were able to secure the acquisition at very attractive deal metrics.

The business includes 1.8 gigawatts of flexible capacity generation, comprising a combination of contracted co-generation, merchant peaking generation and transmission capacity rates. As we communicated last week, the transaction was priced with a TEV to EBITDA multiple of approximately 5.5 times and the purchase price sets the value of the portfolio at $357 per kilowatt. The purchase price is well below the replacement cost of current and other forms of reliable generation and provides a low cost expansion option to deliver reliable generation to the market demands of Alberta. The acquisition is accretive to free cash flow and will just deliver a strong cash yield with an expected average annual EBITDA contribution of $115 million. The portfolio is highly contracted with 55% of its revenues under contract with excellent counterparties.

The customer contracts have a weighted average remaining life of 16 years and will provide further diversification to our cash flows. And finally, with our local presence here in Alberta, we expect to drive corporate synergies of approximately $20 million a year on a pretax basis. As we discussed on the call last week, the transaction will require approval under the Competition Act here in Canada as part of customary closing conditions. In the meantime, our business operations will continue to operate separately and independently until the transaction closes. We are confident that the transaction will be successful and anticipate that the transaction will close sometime in the first half of 2024. We expect to fund the transaction price of $390 million using existing cash and available liquidity.

And with that, I’ll now pass the call back to John.

John Kousinioris: Thanks, Todd. As I look at our strategic priorities for 2023, our primary goal is to continue delivering clean power solutions to and be the supplier of choice four customers that are focused on sustainable growth and decarbonization. In 2023, we are focused on progressing the following key goals; achieving COD on the Northern Goldfield solar and Mount Keith transmission projects, while progressing the White Rock wind and Horizon Hill wind projects to completion early in 2024; continuing the expansion of our development pipeline with a focus on renewables and storage; completing the rehabilitation of Kent Hill’s wind; advancing the long term contractedness of our Alberta electricity portfolio; achieving EBITDA and free cash flow within our increased guidance ranges; and driving final investment decisions on our advanced stage projects with a focus on securing appropriate risk adjusted returns to drive shareholder value through capital and return discipline.

I would like to close by highlighting what I think makes TransAlta a highly attractive investment and a great value opportunity. First, our cash flows are robust and underpinned by a high quality and highly diversified portfolio. Our business is driven by our contracted wind and solar portfolio, our unique, reliable and perpetual hydro portfolio and our efficient gas portfolio, all of which are complemented by our world class asset optimization and energy marketing capabilities. Both, the acquisitions of TransAlta Renewables and Heartland Generation, will further diversify and increase the contractedness of our cash flows while Heartland’s peaking assets will contribute to our Alberta strategy. Second, we’re a clean electricity leader with a focus on tangible greenhouse gas emissions reductions.

This year, we adopted a more ambitious CO2 emissions reduction target of 75% by 2026 from 2015 levels, and our Board has recently approved our commitment to net zero by 2045. We remind everyone that the Heartland acquisition will not affect either of these commitments. Third, as noted earlier, we have a diversified and growing development pipeline and a talented development team focused on realizing its value. Fourth, our company has a sound financial foundation. Our balance sheet is strong and we have ample liquidity to close the Heartland acquisition, as well as to pursue and deliver our clean electricity growth plan. Finally, our people. Our people are our greatest asset and I want to thank all of our employees and contractors for the outstanding work they have done to deliver another strong and safe quarter.

Thank you. I will turn the call back over to Chiara.

Chiara Valentini: Thank you, John. Jenny, would you please open the call for questions from the analysts?

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Q&A Session

Operator: [Operator Instructions] Your first question is from Maurice Choy from RBC Capital Markets.

Maurice Choy: I just want to start with your growth plan. You seem to have dropped your 2023 priority of reaching FID on 500 megawatts of clean energy. And I believe it has been well over a year since you have lost FID to a renewable project, something that you have touched on in your prepared remarks. And your last two major announcements were acquisitions related to R&W and Heartland. So my question is how would you characterize your decision to hold back on renewables, and how would you define what you said as appropriately derisk projects in your prepared remarks?

John Kousinioris: You are right. We did begin the year with a target to hit 500 megawatts of new growth organically, greenfield and brownfield from the company and have been working hard all year. We do have a bit over 400 megawatts of advanced stage projects to advance. But I have to tell you, we have been showing a lot of discipline in kind of moving them forward. There were certainly times during the course of the intervening period where we could have moved forward and proceeded with those projects, but we continue to work to make sure that the supply chain and the costs associated with developing those projects are as tight as they possibly can be, and that the associated PPAs that the projects would have — would provide the appropriate level of returns that we need.

I think you alluded to it, we’ve seen interest rates go up, inflation go up. So from our own perspective, we’re trying to get higher, I would say, returns than we were looking at getting two years ago. And so it becomes an issue of balancing the increased costs associated with developing the project. And some of the reluctance that we’ve seen candidly on the PPA side to kind of provide the kind of returns that you need to appropriately balance out we think the risks and the incremental costs that we see from developing the portfolio. So rather than pulling the trigger, we’re being patient. We’ll wait to make sure that we’ve got an appropriate balance for those projects going forward. The one thing I would say though is we’re absolutely committed to our clean electricity growth plan.

We continue to work on growing that pipeline. From my own perspective, whether we’re behind by a year or six months in terms of achieving it, doesn’t trouble me as much as ensuring that we continue to progress, remain disciplined and continue candidly to build up the capabilities of the team going forward.

Maurice Choy: And maybe if I could follow up with that. And as you seek high returns for your projects, and obviously the score has demonstrated your cash regeneration. How would you then compare some of these opportunities in your pipeline versus M&A opportunities, which you’ve done already versus also buying back your shares, which you’ve also done prior to the R&W acquisition?

John Kousinioris: No. Look in terms of share buybacks, we’ve done, I think it’s about $71 million worth of buybacks this year, roughly in sort of in the mid $11 price, I think about 11.60, 11.62. It continues to be something that we look at doing. And it’s my expectation, I would say, Todd, that we’ll be back in the market doing share buybacks before year end. As you can appreciate, given the kind of work that we’ve done around Heartland and even TransAlta Renewables, we’ve been blacked out for considerable periods of time in terms of being able to be in the market and do share buybacks. But going back to sort of the initial premise of your question, we do think that share buybacks are appropriate, it is something our company is committed to.

We do think it’s a good tool to provide capital back to our shareholders, especially when we view our share prices being undervalued. But growth is critical too. And when we see opportunities like the Heartland portfolio, when we think and are able to pursue the kind of benefits that we see from putting the two companies together and simplifying our transaction and developing our clean electricity growth plan, we think that long term executing on those kind of growth projects will ultimately provide our shareholders the best possible value for growth.

Operator: Your next question is from Mark Jarvi from CIBC.

Mark Jarvi: Just coming back we had some discussion last week’s call, but I just want to revisit some of the chat around market reforms in Alberta. One of the things we’ve been hearing is maybe some evolved measures to, I guess, protect against or deliver reliability, whether or not that’s ancillary service products or something like that. What are you guys advocating for around that? How do you think your hydro assets line up with that? Do you think there’s more revenue opportunities around the hydro assets for around reliability and AS products or they maxed out? And then I guess maybe the peakers from Heartland in terms of how they might fit into anything you are advocating for or expect to come into the market?

John Kousinioris: I think — look, the work in terms of the pathways for the future that the [ISO] was looking at and even the notion that the provincial government has in terms of making sure that we have a proper sort of transition in the generating fleet, and that the energy transition occurs in a responsible way or ongoing. I mean, we’re in the thick of that as you can imagine. But when it comes to the kind of asset classes that you talked about, I tend to think of them as falling broadly within sort of three buckets. One, if you look at some of the, I would say, more traditional, maybe less flexible thermal plants, we do — and you’ve heard me say this before, we do view them as being sort of a Alberta style peakers, our work shows that they will be needed in the marketplace notwithstanding the addition of new gas generation.

So some of the things that we’re looking at and it’s something that the ISO and the provincial government are very aware of is how do those — that asset class helped to underpin reliability in the jurisdiction. So when we have discussions with them, the notion of potentially out of market payments to keep those assets appropriately in place well into the balance of the decade, whether it’d be through contracts or other mechanisms to see them through, is something that we’re actually talking about. And we think is more perspective than it might’ve been even a few years ago now that people kind of understand the magnitude of the impacts that the transition will provide. So that’s one. Two, on hydro, we think that the way the market is evolving will continue to support our hydro fleet.

So I think ancillary services will continue to be critically important and might actually expand in terms of the various categories that we see. So for instance, fast frequency response is something that the [ISO] was grappling with, and that is something that our hydro batteries, a combination of the two, could really help us go forward. And when we think of our water charger project that fits sort of squarely in that sort of category of potential attribute. And then finally, with Heartland, not to sort of get ahead of the acquisition taking place, but having more flexible and fast responding peakers, setting aside ancillary services and reliability, we just think is something that will be very important to underpin reliability and candidly cost effectiveness in the province going forward, and think that those assets, certainly at the price that we’re proposing to buy them at, are just an excellent addition to the fleet going forward.

So hopefully that gives you a bit of a sense.

Mark Jarvi: Just on the last item around the peakers. Are you saying that you don’t think there’s necessarily a reliability or firming type revenue contract for those assets? It’s mostly just where you think the market’s heading in a wire dispersion of pricing hours, they’ll be able to pick off those high priced hours?

John Kousinioris: Yes, there may be, but I think at least the current way that we envision them is more in the latter part of the scenario that you articulated, where they would be more of, what I would call, traditional peakers, Mark, where they would be oriented towards stepping in rapidly when there is a reduction in supply coming from the renewable and providing reliability of the system that way but really benefiting from the energy price as it responds to kind of a tightness in the moment. Our work would show that if the renewables come in, both wind and solar, we may see periods where the supply stack shifts. I know, Todd carry, like, kind of in that 2,000 megawatts kind of on an hourly basis. So having something that was pretty extraordinary compared to what we normally would have seen in the province. So having somebody that’s fast response like that would be critical.

Mark Jarvi: And then coming back to the projection of about $115 million of EBITDA over the next five years from the Heartland assets. When you model that out in those assets, is that number you are arriving at just based on what’s optimal for maximizing profitability for those assets without impairing revenue potential across your fleet or the market? I guess, is it just that’s the most you think you can get out without harming your hydro assets, your coal-to-gas assets? Or at that price of $115, do you think there is potential how you’re assuming those might run that there is, call it, revenue synergies across your portfolio in terms of how you might optimize all your assets?

John Kousinioris: I mean, Todd, do you want to…

Todd Stack: Look, Mark, those assets have been operating for many years here in the market. And so our projections on the future are somewhat driven off of a similar operating mode that they have had in the past. And remember that half of the revenue — over the half of the revenue is contracted. So it is really on a standalone basis from the contracted revenue consistent with the way they have operated in the past and then adding on the synergies that we expect to get more from a head office operational cost basis.

John Kousinioris: Yes, we haven’t — we sort of we did the assessment primarily on a standalone basis, I would say, Mark. So to the extent that you were to look at sort of portfolio wide kind of analysis in the future on the assumption that the transaction takes place, that’s not something that would — that was a focus at the time that we did the acquisition.

Mark Jarvi: No, obviously, pricing is one dynamic in terms of the realized profit from the assets. But if you just thought about what you assumed to get to the 115, that would be sort of comparable how you think those assets have run over the last, say, four to six quarters. Just so I am trying to understand in terms of their function in the role. You are not envisaging the meeting dramatically different is what I am hearing in your assumptions to get to 115 [Multiple Speakers] Okay, I’ll leave it there. Thanks.

Operator: Your next question is from John Mould from TD Securities.

John Mould: Maybe just starting with scale in Alberta, you have added or you will be adding considerable scale in the province with Heartland. Just when you consider FID on additional renewables, at what point — and maybe it is not reasonable to hold all else equal on the terms, but at what point, you prefer to add developments outside development projects — outside of Alberta, rather than further increasing your exposure to that market. Is there kind of an upper limit in terms of percentage of your asset base or cash flows that you would like to see in that province or does it really just come down to returns more than anything else?

John Kousinioris: To be honest, John, and by the way, good morning, to be candid. I mean, it’s really a function of the opportunities that we see in any given particular time from our development portfolio and as you’ve seen with Harlan on an M&A basis. I would say, in terms of sort of allocation of capital going forward, when I think of our clean electricity growth plan, I think I’d say, Todd, we’re pretty comfortable with where we are now. I think, we have, John, our Pinnacle project, which is a peaker and we’ve got Tempest and we’ve got WaterCharger. Those are probably the key projects that we’re looking at in Alberta. We would love to be able to grow in the US. We would love to be able to grow more in Australia. And actually are really focused on landing that and expect to be able to move that forward.

So increasing the diversity of our cash flows, increasing the contractedness of our cash flows and by diversity, I mean, by customer and also by geographic footprint, is clearly something that we’re focused on. And I would’ve thought we’ve kind of had a bit of an Alberta moment is what I would say to put it that way over the last little bit. And I would expect it on a go forward basis, it’d be a little bit more balanced and probably geared a bit more to jurisdictions outside of Alberta rather than inside of Alberta with the kind of assets that we would be bringing in Alberta would be more oriented towards providing reliability in the province. So like Pinnacle with peaking, when I think of our pumped hydro in terms of providing storage and water charger, I think, it’s more in that vein, given the evolution of the market rather than more sort of, what I would call, conventional contracted renewables going forward, if that makes sense.

John Mould: And then maybe just moving to the US wind projects you’ve got under construction right now. Could you give us an update on how you’re thinking about the permanent financing for those projects and options for monetizing those PTCs once the projects are online, and what timeline you’re looking at for finalizing that funding decision?

Todd Stack: The market changes in the US that allow us to monetize PTCs on our own without a tax equity partner is very, very beneficial. We have been in discussions with a number of counterparties to lock in that revenue stream over a long term period, not just selling them on an annual basis. But our ability to monetize them really makes the need for tax equity partners to be significantly less. When I think about the financing going forward, look, we still have — our preference is always to have the units up and operating before we actually go out and seek financing, in particular project financing. But we do have a lot of corporate capacity and really not in any rush to go out and finance those assets. We currently have a bridge facility in place. We’re happy with that facility and we may look to extend that as well. So nothing urgent on that front.

John Mould: And maybe just one last one on your hedges. I think last quarter you had some disclosures on your 2025 hedging position. I don’t — apologies if I missed it, but I don’t think you’ve got any of this quarter. And I’m just wondering what you can tell us about how those hedges have maybe been updated over the last quarter and how you’re thinking about the market more over the midterm beyond the next 14 months?

John Kousinioris: As you know, John, it’s pretty skinny in terms of where the forward curve is out in 2025. So I would say we’re developing our position in 2025, a considerable amount of focus on our C&I business candidly, which has been, I’d say, pretty robust, both in terms of the component that basically flows with market pricing. But what we’re more focused is sort of in our fixed price component of that. So that’s actually been, at least from my own perspective, Todd, kind of the main focus of what we’re trying to do in setting up 2025. In some respects, at least I’m viewing 2024 a little bit like 2021 was. We’re seeing quite a bit of new supply come in the market. It’ll be a little bit of a reset in terms of what we see.

And I think we’re all, I think, at the company waiting to see, as the year progresses, what we can expect a little bit closer. We do, as you know, our own fundamental modeling internally, but just want to see the market evolve as we go forward. So I’d say, we’re still — we still have work to do for 2025, I think, at this point. So providing a lot of guidance associated with it is, at least my view would be premature. I don’t know if, Todd, you want to add…

Todd Stack: No, I think we will have an update at our Investor Day potentially.

Operator: Your next question is from Ben Pham from BMO.

Ben Pham: On the hydro results and your comment around hedges benefiting the quarter, we saw that also I think in the first quarter. Could you talk about if any there’s been any sort of structural changes in your portfolio that’s allowing you to hedge the hydro, because I don’t think you’ve really done it historically in the past?

John Kousinioris: I don’t think there’s been anything structural, I would say, from a hydro perspective in terms of where we are. I think we’ve just been opportunistic on occasion. So when we’ve seen strong pricing, particularly in a particular quarter that might have a different new compared to what our own internal fundamental forecast is internally, I think, the team goes and just takes the position and uses it to sort of guarantee the outcomes that we expect. And we’ve done it a little bit more, I’d say, Todd, over the last couple of years really. And I think it’s been a little bit more visible more recently just because we’ve seen strongest pricing, which just makes sense for us to do it. I don’t know if you want to add anything…

Todd Stack: Yes, I would say just the nature of the hydro assets where they’re able to capture the peaks that is the expectation out of that fleet is to be getting the peak pricing when the market really…

John Kousinioris: We still have an open position on…

Todd Stack: So it’s difficult to hedge at the average price or like we certainly don’t want to hedge at the average price often in hydro. And we really — as John said, we look for those opportunistic periods. And if you recall stepping back three months, August and September prices were very, very strong in the forward market. And so the team picked off some of those higher opportunities more in line with what we would expect the fleet to generate.

John Kousinioris: But it’s more opportunistic, I would say, very opportunistic.

Ben Pham : I guess with a quarter like this where hydro was below average. I mean, isn’t there a [necessary] situation where you could be short the curve quite a bit because of your hedging? No?

John Kousinioris: No. The hedges in the hydro business are relatively — remember there’s 800 megawatts of capacity there now. It can’t run 24/7 at that level. But it is very, very unlikely that we would be short on the hydro business.

Ben Pham: And then adding peakers then with Heartland. Do you — I know you mentioned Alberta, sounds like they need more peakers. But does TransAlta need or does your peaking plant you’re advancing, does that still make sense for you?

John Kousinioris: Look, I mean, in terms of the portfolio that we would be getting with Heartland, I think, we are very comfortable with those, peaking units. I think, there they have competitive heat rates. The cogen two candidly has competitive heat rates. Those assets at the purchase price that we have set are much, much cheaper than anything you would be able to bill for today. And then when we look at peaking going forward, we kind of like pinnacle, which would be a small addition kind of in that mid 40 megawatt rapid response inexpensive. So you get your return of it on capital closer sort of facility, might we do run more [Technical Difficulty] if possible. But I think we are kind of comfortable from a post acquisition portfolio perspective with how it’s kind of playing out.

Todd Stack: And I would generally say, again, the Heartland portfolio has been in operation for a while. The team did see incremental opportunity in adding peaking capacity and fast responding storage to the province. So we need to go through all of the work before those projects are FID, but we still see positive attributes of both those projects for sure.

Ben Pham: And maybe just one last follow-up for upcoming investor day. Do you think you are in a position to talk with ’24 guidance at that point?

John Kousinioris: We are — what I would say, Ben, is stay tuned, that’s definitely something that we are focused on. Let’s put it that way.

Operator: [Operator Instructions] And your next question from Patrick Kenny from National Bank.

Patrick Kenny: Just on your emission credits, I see your inventory has doubled year-to-date towards $55 million. And I was just wondering on a pro forma Heartland basis if you can comment on how well protected or how long you might be sheltered from compliance costs? And then I guess taking it one step further and playing the hypothetical here, but given the fluid situation in Ottawa around the carbon tax. If there is a break on carbon tax for power generation similar to home heating oil or even if it is just reduced somewhat, can you just speak to what that could mean directionally to your overall margins across your portfolio or how meaningful that could be to your free cash flow outlook?

Todd Stack: Let me start with the emission credits service. I can’t remember exactly what word you used, but generally the emissions credits, we don’t consider them as sheltering the gas facilities. We look at them as having a certain market value. We see the value of that potentially increasing over time and we treat them on a standalone basis. And similarly, when we operate gas facilities that have a carbon footprint, when we look about what it will cost to offset the emission there, we again look at it on a standalone basis. So I don’t subsidize my gas business by using greatly created emissions credit. So we really do think of them as a standalone asset. But to your point, we do generate a fair number in the year, we do have a large inventory. So there is certainly no shortfall. But we are happy with the inventory receipt future value and I think you will see us starting to monetize some of that value over the next couple of years.

Patrick Kenny: And then just around the, I guess, the carbon tax and playing the hypothetical there?

John Kousinioris: Look on the carbon tax, let’s say it would go down to zero. I don’t know that it would really impact the margin — and look, I’m speculating here, but I don’t know that it would impact the margins on our gas fleet all that much. I mean, I think candidly the carbon price is kind of priced in and is sort of an expense that we do and doesn’t really, I think, drive overly at the end of the day, the margin. It would, though, I think have an impact on the overall average price, which would probably have a corresponding downward impact on pricing in the province, which would in turn impact probably the renewables more in terms of what pricing they would be able to realize if that incremental variable cost that is currently priced into the market is sort of reduced or removed, if you see what I’m saying. I think, that’s probably more likely what you’d see, I guess, Patrick, if I could sort of forecast, which I’m never very good at doing.

Patrick Kenny: And then I guess just looking at the BB plus credit rating and the stable outlook. Todd, have you had any confirmation from S&P that given your increased presence in Alberta with Heartland that they won’t be moving any goalposts on you or placing your rating on negative outlook like they have with others just given their view of Western Canada having higher exposure to physical risks related to some extreme weather events?

Todd Stack: Patrick, I think, we absolutely did reach out to the rating agencies ahead of the Heartland transaction just to understand the implications, broadly received as neutral in the discussion. I do not expect them to be moving any goal posts, certainly not in a negative fashion against us going forward. I think we’ve had really, really strong results and we’ve proven to the rating agencies how resilient the company is. And so I think the discussions ongoing with the rating agencies are very solid and we’re very happy with the BB plus and then the BBB low with DBRS for our company.

John Kousinioris: Yes, I mean, I think our US agencies would consider us a very high quality BB plus, but I don’t think that’s changing here.

Operator: Thank you. There are no further questions at this time. Please proceed.

Chiara Valentini: Well, thank you everyone. That concludes our call today. If you have any further questions, please don’t hesitate to reach out to the investor relations team at TransAlta. Thank you, and have a great day.

Operator: Thank you. Ladies and gentlemen, the conference has now ended. Thank you all for joining. You may all disconnect.