TransAlta Corporation (NYSE:TAC) Q1 2025 Earnings Call Transcript

TransAlta Corporation (NYSE:TAC) Q1 2025 Earnings Call Transcript May 7, 2025

TransAlta Corporation misses on earnings expectations. Reported EPS is $0.04 EPS, expectations were $0.09.

Operator: Good morning, and welcome. My name is Carmen, and I’ll be your operator for today. At this time, I would like to welcome everyone to TransAlta Corporation First Quarter 2025 Results Conference Call. [Operator Instructions] Ms. Paris, you may begin your conference.

Stephanie Paris: Thank you, Carmen. Good morning, everyone. My name is Stephanie Paris, and I am the Vice President of Investor Relations and Corporate Strategy of TransAlta. Welcome to TransAlta’s first quarter 2025 conference call. With me today are John Kousinioris, President and Chief Executive Officer; Joel Hunter, EVP, Finance and Chief Financial Officer; and Blain van Melle, EVP, Commercial and Customer Relations. 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 website. A replay of the call will be available later today, and the transcript will be posted to our website shortly thereafter. All information provided during this conference call is subject to the forward-looking statement qualification set out here on Slide 2, detailed further in our MD&A, and incorporated in full for the purposes of today’s call.

All amounts referenced are in Canadian dollars, unless otherwise noted. The non-IFRS terminology used, including adjusted EBITDA and free cash flow, are reconciled in the MD&A for your reference. On today’s call, John and Joel will provide an overview of TransAlta’s quarterly results. After these remarks, we will open the call for questions. With that, I will turn the call over to John.

John Kousinioris: Thank you, Stephanie. Good morning, everyone, and thank you for joining our first quarter conference call for 2025. As part of our commitment towards reconciliation, I want to begin by acknowledging that our company operates on the traditional territories of indigenous peoples across Canada, Australia, and the United States. We recognize the rich and diverse histories, cultures, and contributions of the First Nations, Inuit, Metis, Aboriginal, and Native American communities. And it is with gratitude and respect that we thank the people who have lived on these lands for generations for reminding us of the ongoing histories that precede us. Before diving into our quarterly results, I want to take a moment to reflect on our strategic direction.

We’re excited about the growing demand for electricity across our core markets. Whether it is driven by population growth, economic expansion, electrification trends, increased use of electric vehicles, the rise of AI and data centers, or supportive policy environments, it’s clear the future is very bright for our industry and our company. With opportunity, however, comes complexity. We faced real challenges, political and regulatory uncertainty, long interconnection queues, tariffs, supply chain challenges, and rising costs, all of which serve to make near-term organic greenfield growth more difficult. In response, we are focused on diversifying our portfolio and increasing the stability and contractedness of our cash flows. This means our reliance on the Alberta market will evolve and likely decrease over time.

It also means that we will remain technology agnostic, as we believe a mix of generation sources is essential to meet growing demand safely, reliably, and sustainably. Our deep operational experience across fuel types uniquely positions us to advance a balanced growth portfolio, including reliable thermal assets and clean, locally sourced power generation. We will continue to pursue growth with discipline and a sharp focus on shareholder value. In the near term, that includes maximizing the value of our legacy thermal assets, evaluating M&A opportunities, maintaining a strong balance sheet, and returning capital to our shareholders through dividends and share buybacks. At the same time, we’re positioning our company to deliver sustained value through the rest of this decade and into the next.

I’ll now turn to the quarter. We delivered exceptional operational performance across our entire fleet during the first three months of the year. While our Alberta merchant portfolio was impacted by softer-than-expected prices, our hedging strategy and active asset optimization generated realized prices that were well above spot prices during the quarter. We delivered adjusted EBITDA of $270 million and free cash flow of $139 million, or $0.47 per share. And we announced an 8% increase to our common share dividend to $0.26 per share on an annualized basis, which represents our sixth consecutive annual dividend increase. In the year to date, we have also returned $24 million, or $0.08 per share, to shareholders through share buybacks at an average price of $12.42 per share.

Returning capital to shareholders remain a key part of our capital allocation strategy, which we adapt to market conditions and the timing and progress of our growth opportunities. We plan to renew our annual normal course issuer bid at the end of this month, and we retain the option to continue to make accretive share buybacks during the year of up to $100 million. We have a number of business highlights during the quarter. First, we achieved exceptional average fleet availability of 94.9%. Second, we mothballed Sundance Unit 6 on April 1 for a period of up to two years, depending on market conditions. This reflects our ongoing commitment to optimize our portfolio and minimize costs. We maintain the flexibility to return Sundance 6 to service when market fundamentals improve or opportunities to contract the facility are secured.

Third, we completed the integration of Heartland Generation safely on schedule and have realized our targeted synergies across both the corporate and operational teams. And finally, we continue to engage with the Government of Alberta and the AESO on the restructured energy market design, or REM. The government and the AESO recently announced that they had refined the scope of the REM, most notably by removing the day-ahead energy and commitment products that had previously been proposed. The revised scope includes the day-ahead procurement of operating reserves and new ramping ancillary services along with a higher offer and price cap. The proposed offer cap of up to $2,200 per megawatt hour, with the ability for pricing to administratively go up to $3,000 per megawatt hour, is a significant and positive change to the current offer and price cap of $999 per megawatt hour, which has been in place unchanged for over 20 years.

The AESO also intends to move forward with a locational marginal pricing framework and plans to allocate transmission system and ancillary services costs on the basis of causation, also a positive development from our perspective. We expect the Government of Alberta and the AESO to provide more details on the REM later this month and are actively engaged with both parties on the redesign. We remain supportive of initiatives that provide long-term stability and reliability as well as incentives for existing and new infrastructure investment. During the quarter, we also advanced our strategic priorities. First, we’re pleased to announce our strategic partnership with Nova Clean Energy. Nova is the U.S. development arm of Bluestar Energy Capital, a platform founded in 2022 and led by Declan Flanagan, the former CEO of Orsted’s onshore renewables business, and Neil O’Donovan, a former EVP at Orsted who served as CEO of its onshore business unit.

Nova’s development team, under the leadership of Declan and Neil, has a successful track record of investing in and developing grid-scale wind, solar, and storage projects across the United States with over 10 billion of capital investment in global clean energy. Our relationship has a number of components. We have negotiated and structured a $100 million revolving credit facility and a $75 million term loan to Nova with phased draws over the first two years, providing an annual return on capital secured against project values and strategically sized and balanced with our other capital allocation priorities. We have secured the exclusive option to purchase projects developed by Nova in the WECC, one of our core growth markets that are competitive on a risk-adjusted return basis, and the transaction provides TransAlta with potential upside through an equity conversion option, which could provide us up to a 23% ownership stake in Nova.

Our investment thesis in Nova is as follows. First, it aligns us with a world-class developer, enhancing our ability to achieve strategic growth priorities in the latter part of the decade with technology-agnostic customer solutions in the Western U.S. Second, it provides competitive differentiation through an advantaged path to late-stage development M&A with exclusive purchase rights from Nova. And third, it allows us to monitor, govern, and influence project development by Nova prior to any notice to proceed, resulting in attractive return profiles that can be augmented by our capabilities. The investment in Nova complements our existing growth capabilities. We remain focused on executing our near-term brownfield projects, opportunistic M&A, and selective complementary projects.

Opportunities will be evaluated and selected with a view to ensuring we’re unlocking the most value for our shareholders. Moving to our legacy thermal sites. We continue to make significant steps forward in both the United States and Alberta. At our Centralia site, we’re advancing discussions with our customer on a redevelopment opportunity to extend the operating life of Centralia through a contracted coal-to-gas conversion. Our team is forecasting significant near-term capacity and energy supply deficiencies in Washington State, and our Centralia facility can play an integral role in supporting ongoing reliability in the region. Over the past number of months, we’ve been progressing engineering and commercial negotiations, including term sheets and pricing, with the target of executing a definitive agreement in mid-2025.

Aside from the coal-to-gas conversion, we also continue to evaluate other opportunities to build out the Centralia energy campus on our significant land holdings, including wind, solar, batteries, and next-generation technologies. We expect to be able to share detailed development plans for Centralia in the coming months as we finalize negotiations. We’re also advancing opportunities at our legacy thermal sites in Alberta, which we believe offer ideal conditions for data center opportunities, including speed to power Tier 4 reliability, and competitive power pricing. We’re now actively in the commercialization phase of the project with discussions around detailed and derisked commercial offerings, which are being showcased to potential customers, including through access to our virtual data room.

We continue to focus on securing exclusivity with key partners by mid-year, with detailed design and definitive agreements expected by year-end. A data center would be operational 18 to 24 months after signing definitive agreements. Finally, we continue to focus on our financial strength and capital discipline. In March, we successfully closed the $450 million, seven-year senior unsecured green note offering with a coupon of 5.625% maturing in 2032. This marked a return to the Canadian debt capital market by the company for the first time since 2013, and we’re extremely pleased that the offering was well received. The majority of the net proceeds were used to repay our $400 million variable rate term loan facility in advance of its scheduled maturity later in the year.

Following the offering, we exited the quarter with over $1.5 billion in available liquidity, including approximately $240 million of cash on hand, which positions us well to execute our strategic priorities. I’ll now pass the call over to Joel.

Joel Hunter: Thanks, John, and good morning, everyone. Overall, we are pleased with our first quarter operational performance across all of our business segments and remain confident in our ability to meet our 2025 guidance range. During the quarter, we generated $270 million of adjusted EBITDA, which was $72 million lower when compared to the first quarter of 2024, primarily due to the milder weather in Alberta, which contributed to lower power prices. Turning to our segmented results relative to the same period of 2024, the hydro segment produced adjusted EBITDA of $47 million, which declined due to lower spot power and auxiliary prices in Alberta, partially offset by higher merchant and ancillary services volumes and positive contributions from our hedging activities.

The wind and solar segment produced adjusted EBITDA of $102 million, an increase of 15%, primarily due to the addition of our Oklahoma wind facilities and higher production volumes from the fleet. Adjusted EBITDA in the gas segment decreased by 17% to $104 million, mostly due to lower realized power prices in Alberta and higher carbon pricing, partially offset by the addition of Heartland and fleet optimization. The energy transition segment delivered $37 million of adjusted EBITDA, an increase year-over-year due to lower purchased power costs, which were driven by higher availability at our Centralia facility. Energy marketing adjusted EBITDA decreased by $18 million to $21 million, primarily due to muted market volatility across North American natural gas and power markets.

Corporate costs increased to $41 million, largely due to increased spending to support strategic and growth initiatives and the addition of corporate costs related to Heartland. Our adjusted EBITDA composition was amended to remove the impact of realized gains and losses on closed exchange positions, which was included in adjusted EBITDA until the fourth quarter of 2024. The adjustment was intended to explain a timing difference between our internally and externally reported results and was useful at a time when markets were more volatile. The minor quarterly adjustments are reflected in our quarterly results file posted to our website. As a reminder, our adjusted EBITDA excludes the impact of ERP integration and Heartland acquisition costs.

Our free cash flow excludes the impact of the Brazeau penalties, which were paid in January of this year. These items are not reflective of ongoing operations or performance of our operating assets. Free cash flow of $139 million in the first quarter was lower than the same period last year. This was primarily due to lower adjusted EBITDA along with higher sustaining capital expenditures and higher net interest expense. Turning to the Alberta portfolio. The first quarter spot price averaged $40 per megawatt hour, which was significantly lower than the average price of $99 per megawatt hour in 2024. The decline year-over-year was primarily due to incremental generation from the addition of new gas, wind, and solar supply in the province, as well as benign weather in the quarter.

Throughout the quarter, we deployed hedging strategies to enhance our portfolio margins and mitigate the impact of lower merchant power prices, which resulted in realizing approximately 2,300 gigawatt hours of hedges at an average price of $71 per megawatt hour, a 178% premium to the average spot price. In addition, our hydro fleet delivered an average realized merchant price of $70 per megawatt hour, a 175% premium to the average spot price, while the gas fleet realized a 140% premium to the average spot price. Our merchant wind fleet, which cannot be used as firm power for hedging activities, realized an average price of $20 per megawatt hour. By optimizing our fleet throughout the quarter and fulfilling hedges with purchased power, we were able to respond to higher demand from the AESO and deliver additional ancillary service volumes across the fleet.

In the quarter, our average realized price for ancillary services settled at $28 per megawatt hour, or approximately 70% of the average spot price. Despite relatively benign weather in the quarter, which resulted in lower spot power prices, we captured additional margins by fulfilling a portion of our higher price hedges with purchase power when prices were below our variable cost of production, leading to an overall realized price per megawatt hour produced of $122. The Alberta merchant portfolio continues to notably outperform the challenging spot price environment due to our hedging and optimization activities. Looking at the balance of the year, we have approximately 5,800 gigawatt hours of our Alberta generation hedged at an average price of $69 per megawatt hour, well above the current forward curve of $45 per megawatt hour.

Going forward, we will continue to optimize our fleet and reduce production in low-priced, high-supply hours by fulfilling our financial hedges and customer requirements with open market purchases. Looking at next year, our team has increased our hedge position to 6,400 gigawatt hours at an average price of $68 per megawatt hour, well above current forward pricing levels. As a result of our hedging and optimization strategies and supported by the performance of our contracted fleet, we remain confident in our ability to achieve results within our guidance range for 2025 for both adjusted EBITDA and free cash flow. As I stated last quarter, 75% of our 2025 expected generation revenue is underpinned by our contracted assets and hedging position.

I’ll now turn the call back over to John.

John Kousinioris: Thank you, Joel. We remain focused on the following priorities for 2025. First, improving our leading and lagging safety performance indicators while achieving strong fleet availability. Second, delivering adjusted EBITDA and free cash flow within our 2025 guidance ranges. Third, maximizing the value of our legacy thermal energy campuses. Fourth, successfully executing on M&A opportunities that may arise, and finally, implementing an upgrade to our ERP system. I believe TransAlta offers a compelling investment opportunity. We’re a safe and reliable operator with strong cash flows underpinned by our diversified hydro, wind, solar, and gas portfolio located across three countries and complemented by our leading asset optimization and energy marketing capabilities.

We are a clean electricity leader with a focus on tangible greenhouse gas emission reductions as we remain on track to achieve our ambitious 2026 CO2 emissions reduction target. There is tremendous value in our legacy thermal sites, which our team is actively working to repurpose to meet the evolving needs of customers. We remain disciplined in our approach to growth, focused on delivering value to our shareholders. We’re working to diversify our portfolio and increase the stability and contractedness of our cash flows through both existing as well as new assets, advancing a growth portfolio that can deliver meaningful, reliable thermal opportunities as well as clean, locally-sourced power generation. Our company has a sound financial foundation.

Our balance sheet is flexible, and we have ample liquidity to pursue and deliver multiple growth opportunities with the ability to also return capital to shareholders through dividends and share repurchases. And most importantly, we have our people. Our people are our greatest asset, and I want to thank all our employees and contractors for their commitment in setting the company up for success in 2025. Thank you. I’ll now turn the call over to Stephanie.

Stephanie Paris: Thank you, John. Operator, Carmen, would you please open the call for questions from the analysts?

Q&A Session

Operator: [Operator Instructions] One moment for our first question. And it comes from Robert Hope with Scotiabank. Please proceed.

Robert Hope: Yes. Thank you, everyone. Maybe to start off with the Nova Clean Energy investment, how do you think about this investment and its 7% return relative to your existing U.S. renewable development pipeline?

John Kousinioris: Yes. Good morning, Robert. So when we think of Nova, we’re not really thinking of it in the context of really the loan facility that we made available to them. That is something that enables a highly capable team to be able to move forward and execute on their business strategy, which we’re supportive of. So the prize for us is not the 7% coupon that we’ll be clipping for the next five years or so off of the credit facilities there. It’s really about being able to take advantage of their development expertise, particularly as they focus on the Western United States with a view to exercising our kind of exclusive first option that we have to acquire those projects and also direct the development of those projects to get preferential returns on those projects. So really, the funding is enabling their team to actually create value substantively for us in the latter part of the decade as they advance projects in the WECC.

Robert Hope: I appreciate that. And then in your prepared remarks, you noted that there’s some challenges on organic growth for the industry just given the current environment. Does this push you more towards M&A rather than building new projects both on the renewable and the gas side?

John Kousinioris: Yes. Robert, I think — so, look, I mean, when we look at where we’re trading, when we look at the costs which have increased significantly for greenfield development, which puts pressure, frankly, on PPA prices and even the time to grow things, we’re seeing better. And I would say, Joel and Blain, probably derisked opportunities more on the M&A side. So we do have a small M&A team. I would say they’re pretty busy right now. They’re busy in looking at a variety of projects, mostly, I would say with the U.S. flavor right now in terms of specific assets, the kind of multiples that we’re seeing for some types of contracted renewables. And I think, candidly, more importantly for us, certain types of gas assets that are available work for where our company is.

And that candidly is a focus for us. And I think given our strong balance sheet and our free cash flow expectations over the next little bit. That is a focus for us, I would say a priority along with our legacy assets, Robert, which are core. We’re setting the company up to deal with what I would call conventional greenfield growth in the latter part of the decade, which is really what Nova was about. But certainly today legacy investments, which have much higher returns, and also M&A, which I think provide appropriate risk-adjusted returns, are the way we’re focused on it, for sure.

Robert Hope: All right. I appreciate the color. Thank you.

John Kousinioris: Thank you.

Operator: Thank you. Our next question is from Maurice Choy with RBC Capital Markets. Please proceed.

Maurice Choy: Thanks, and good morning, everyone. Just sticking with the strategy discussion here. So I guess when I listened to your prepared remarks, you mentioned diversifying your portfolio. So that’s a geography or power market thing. And you also mentioned increasing stability and contract some free cash flow. So that’s contracted versus merchant. So if I can just think holistically about your strategy here, I’m trying to understand like what is the ideal outcome here, whether that’s a three- or five-year plan. How do you see what markets you’re planning to be in? And also to that end, given that you’re not investment-grade credit rated, what is the contract EBITDA target versus merchant?

John Kousinioris: Yes. Good morning, Maurice. Look, I think if you were to look at sort of where the company was over the course of the last three or four years, and frankly, historically, you would have seen a company that had probably about 50% of its EBITDA being largely from Alberta and an equivalent amount that would have been merchant, which had been largely again in the province of Alberta. I think as we roll forward, and frankly, you’re seeing it this year, I think you heard Joel say that about 75% of our revenue is effectively contracted in terms of what we’re seeing evolve for the company. Our focus is on increasing that reliability and stability of the organization. I think you’ll see the kind of cash contributions coming from the merchant fleet decline, I think, over time.

And I think you’ll see that Alberta, although continuing to be an important component of business for the company be kind of limited in terms of where we’ll be putting capital in the future. I mean, as we learned with the Heartland acquisition, our ability to actually deploy more capital in the province of Alberta is restricted candidly from a competition perspective. So we are focused on the U.S. We do have Western Australia. And as we look at the kind of growth that we’re focused on, it all has a contracted feel to it. There might be a slight merchant position that our energy marketing team can trade around and create sort of incremental value and incremental returns, given their expertise, but I think it’s a natural evolution of the company.

And I think the point I’m trying to make is it’s not accidental. It’s something that we’ve been focused on doing deliberately over the course of the last few years, and think ultimately it’s the way that we’ll end up creating more value for our shareholders. I don’t know, Joel, if you want to add anything to that.

Joel Hunter: One other comment I would make to this is, today, we’re roughly 52% contracted. And over time, we would like to be in excess of 70% contracted to have that stability to earnings and cash flows that we’ve been indicating as part of our strategy. I think with that, then comes a stronger business risk profile. Then ideally, over time, can improve our credit ratings, as you’ve highlighted. As we think about how we become more contracted, we have that opportunity to improve our credit ratings. But again, it takes time.

John Kousinioris: But I would say just on the credit rating point, I think we’re very comfortable with our credit ratings today. We see no kind of impediment to executing our strategy and all of the options that we have that we’re pursuing in the organization. And in many respects, I would say, Joel, it’s a bit of a sweet spot, frankly, in terms of balancing access to market flexibility and kind of a cost effectiveness in terms of the coupon. We just look at our recent note offering, and it was very well received at very competitive pricing. So, we feel very comfortable with where we are.

Maurice Choy: Understood. Understanding of the reliance on the Alberta market might decrease in the coming years. Still focusing on Alberta, what have you been hearing or are you expecting in terms of how the new federal government in Canada might amend the OBPS standards, the clean electricity regulations, or even industrial carbon tax?

John Kousinioris: Yes. I’d say — it’s pretty early, I would say, Maurice, on that. I mean, we don’t even have ministers yet, frankly, in the portfolios under a Carney government. Our working, I would say, assumption, which is supported by some of the preliminary discussions we have had, is kind of a status quo. I would say right now, we’re not, at least in terms of our business planning, expecting any sort of significant shifts from what we’ve been sort of experiencing over the last period. The one thing that we have communicated would be just a reminder that it’s critically important that from a carbon pricing perspective, we remain pretty competitive with our most significant trading partners. And it’s not lost on certainly us, and I know many businesses in Canada that having a divergence there, even if you’re trying to adjust for it for export exposed businesses creates a bit of a challenge.

So that’s a theme that we’ll continue to speak to the government about. But right now, very difficult to say. So, our expectation is sort of a steady regulatory kind of environment at the federal level.

Maurice Choy: Are any of these policy landscapes or even the REM — are any of these, in your discussions with the data center counterparties, major hurdles, whether that particularly is about time and delay or even absolute obstacles to have, anything in Alberta?

John Kousinioris: I think the simple answer to that right now would be no. That hasn’t been a major issue in any of the discussions we’ve been having from a data center opportunity perspective, I would say generally. And I would go so far as to say, Blain, even in our discussions around Centralia, we tend to focus on the Canadian regulatory environment. I mean, we — it’s not like we’re worried about federal or state/provincial kind of regulations kind of upending our focus on extracting value from our legacy assets. The only thing it’s done from a data center perspective is we are focused on how we can use the renewable credits that are generated from our considerable renewables fleet in the province of Alberta to kind of defray or reduce kind of the carbon exposure from the offering that we would make from a data center perspective.

And that’s something that we uniquely can do in the province of Alberta. But generally speaking, it has not been a critical path discussion, if I can put it that way.

Maurice Choy: Very clear. Thank you.

Operator: Thank you. One moment for our next question. And it comes from the line of Benjamin Pham with BMO. Please proceed.

Benjamin Pham: Hi, thanks. Good morning. Maybe the first question, to keep those data centers, you’ve put the size and the focus and — in your Phase 3 at this point. Do you get the sense that even though the focus is 400 megawatts plus that in your discussions that there’s room for that to be scaled up over the medium to long term as part of those negotiations?

John Kousinioris: So, good morning, Ben. The initial discussions that we’ve been having have been primarily focused on the base 400 megawatts. Candidly, I think people know that we have the ability to add 400, and in fact our Q application contemplates that we would do an 800-megawatt development there. But right now, the focus is on things being sequential. But I would say that it is attractive to be able to tell people, at least in the discussions that we’ve been having, that if the demand is there or the long-term planning is there, that anticipates them scaling up. That is something that we can do on-site there. One of the great things about that area is that we’ve got — I think it’s 1.2 gigawatts of kind of transmission access in that particular location.

I think it’s actually about 2.1 gigs at Sundance, which is obviously a later and more of a redevelopment, but I think we’re in pretty good shape there. So, like our base offering is on the floor with the ability to expand to eight. And most of the technical work I would say that we’ve been done is mostly focused on that 400 megawatt K2 offering.

Benjamin Pham: Okay, got it. And then staying on the gas development on Centralia — is the thinking on timing on that — is that more of a later year update on that, or maybe there’s something maybe before mid-year?

John Kousinioris: No, it’s more the latter. We’re pretty — I would say from a commercial perspective, I’m pretty happy with how things are advancing. So look — and Blain has been doing a great job here of pushing that forward, and I’ll turn it over to him to kind of give you a sense of timing. But we’re pretty advanced on things like pricing, timelines, permitting, kind of the nature, tenor, all those kinds of things. Blain, maybe you can give a little bit of color to it.

Blain van Melle: I think that’s accurate, John; targeting something in mid-year here. So, as John said, we’ve advanced a lot of those commercial discussions just working with our customer there to finalize some terms to get something that would be able. We have commenced a lot of the pre-FEED engineering work. A lot of work done on what we need to do from a permitting standpoint so that when we do get some definitive agreements in place, we can hit the ground running, get the permits in place, and move forward with some more definitive engineering to allow us to get construction started as soon as possible.

John Kousinioris: And Ben, what I would say is the tenor is a real — that we’re exploring would be a real positive one from a company perspective. It’s something we can do pretty quickly and candidly. The cost per megawatt of delivering 670 megawatts to our customer is just a fraction of what a new build would be, both from a timing and from a capital perspective. So, we’re pretty excited about that. It’s pretty advanced.

Benjamin Pham: Okay, great. Thanks for the updates.

John Kousinioris: Thank you.

Operator: Thank you. Our next question comes from Julien Dumoulin-Smith with Jefferies. Please proceed.

Unidentified Analyst: This is Tanner on for Julien. Good morning. Just a question on hedging here, and thank you for the commentary on the hedge build in ’25 and 2026. Can you speak to your perspective hedging strategy in the outer years of the plan? Are you seeing opportunities to add significant positions in future years, given the status of the forward curve? And how do you expect this to evolve over time?

John Kousinioris: Yes. Good morning. So look, hedging is actually probably one of the biggest focuses that we have, and I’m speaking primarily here in relation to the province of Alberta. So, we’re pretty heavily hedged, I would say, for 2025, and Blain — again, our optimization team reports into Blain. When we look at full-year 2026, I think we’re about 6,500 gigawatt hours of hedges that we’re at there at a price that’s roughly in that $68 range going forward whereas the forward curve for 2026 in the province of Alberta is in the low to mid-40s right now. I think the last numbers I had was — it was around 44, 40, to 30 for 2026. We continue to add positions in 2027 and beyond, probably in the range of 35% or 40% of our hedge position includes our commercial and industrial book in the province of Alberta.

That would typically have about a three-year tenor. And our customers tend to be, I would say, Blain, relatively sticky there. Although the prices that we’re able to obtain in the C&I business have come down a little bit, they are at a significant premium to what we are seeing the wholesale forward price be. So, like if one is kind of in the mid-40s, we’re still able to extract north of $60, I would say, a megawatt hour — substantially above $60 a megawatt hour through our C&I business. Another development that’s occurred in the province of Alberta is one of our competitors in the C&I space is de-emphasizing their C&I business. They’re shifting a little bit, and that — this isn’t secret. It’s ENMAX who’s been focusing on that. So, we’re now — I think if we’re not the largest, we’re pretty close to being the largest C&I provider in the province.

So that’s a real focus for us. So that would be one. The other one would be just our focus on data centers. Like candidly, we’re trying to reduce the merchant exposure effectively of that Alberta fleet and contract it up, whether it’s through financial hedges, and there’s limited liquidity going forward, I would say, Blain, it’s more our C&I business and what we’re doing with our data center strategy. Blain, I don’t know if there’s anything for you to add.

Blain van Melle: I think that’s a good point, John. We made a concerted effort in the last few years to increase the size of that C&I business, knowing the premiums that we extract from it. We did a strategic acquisition of a different, smaller portfolio two years ago, brought those customers on to our portfolio, and then really have used that as a strategic competitive advantage to get our contracted levels of the Alberta merchant fleet higher.

John Kousinioris: I mean, we foresaw three, three and a half, four years ago that we were expecting an oversupply situation like the one that we find ourselves in with pricing that candidly is pretty close to what we were forecasting was going to be the case. So this isn’t something that we’ve worked on sort of laterally; I’d say it’s something that we’ve been really focused on over the course of really since about 2020, 2021.

Unidentified Analyst: Great, thanks. And then the free cash flow was a little softer in the first quarter, but there’s still confidence in the full year guide, just acknowledging the hedge dynamics, of course, but perhaps can you explain the quarter-by-quarter cash dynamics you’re expecting through the end of the year and what might be some drivers or watch items that you — that move you towards the top or bottom end of the guidance range? Thank you.

John Kousinioris: Yes. No, we are confident in hitting our free cash flow measure, which is our principal measure. That’s the one that we primarily focus on as a company. Look, we’ve got our hedge position going forward. I’d say Q1 was relatively atypical from a weather perspective. It was probably about as benign as you could expect going forward. So if we end up with sort of more typical weather, especially in Q3 and the latter part of Q2, we’re very much focused on costs, I would say internally within the organization, and that’s something that we’re working hard to make sure that we manage. And we’ve already had a fair bit of sustaining capital spend from where we did a little bit of gas work, certainly as compared to what it was like, I think, in the first quarter of 2024.

So, there’s a number of puts and takes. And so, we remain confident in our ability to get there. We like our hedge position. I think we like our fuel costs and where they are going forward. I think the fleet availability has been excellent. So when we get opportunities, I think we can flex up, particularly here in the province of Alberta. So, we remain pretty confident in our ability to get there.

Unidentified Analyst: Great. Thank you for the time.

John Kousinioris: Thank you.

Operator: Our next question comes from the line of Patrick Kenny with NBF. Please proceed.

Patrick Kenny: Thanks. Good morning, everyone. Just on Centralia, John, you mentioned being agnostic on technology, but I guess as you approach the finish line here, from a commercial standpoint, would you say you’re also agnostic on the type of customer as well, just in terms of behind the meter versus utility customers? And I guess how should we be thinking about your internal hurdle rates or target build multiples for some of the larger utility-based ideas for Centralia versus, say, the Keephills opportunity with a single offtaker?

John Kousinioris: Yes. Good morning, Patrick. So with respect to Centralia, look, our returns, I think, are strong — I mean, candidly stronger than we’d be able to get on a conventional new build, greenfield kind of project and probably I would say stronger than you’d expect in an M&A kind of transaction, Patrick. It’s a similar story with respect to data centers. And I mean the trick there is we’re repurposing capital in part. We are spending capital to make the facilities use or fit for purpose. So, the real prize is really repurposing and extending the life of the legacy assets. One of the things that we’re working on at Centralia, which is a little bit unique, is we are actually a bit gas constrained there from a supply perspective.

So although we’re feeling very comfortable that we’ll be in a position where we can deal with a Blain, a 670-megawatt gas plant to meet the needs of our customer there in terms of incremental thermal capacity at site — at Centralia, I think that’s going to probably require a bit of debottlenecking to actually take place. So the next phase tends to be a bit greener is what I would say in terms of growth there. So wind, potentially a little bit of solar with what I would call more conventional returns. So those are important to us. But the priority right now is more on the coal to gas conversion that we would be focused there if we could debottleneck the site. Candidly, it’s an ideal location for data where we’ve got 12,000 acres of land there.

It would be just from a geographic location about as good as you could get. So it is a bit of work that we’re doing to see if we could do more. With respect to Keephills, again, very good returns and much more constrained, obviously, from a gas perspective. So it’s sort of an unrestricted kind of opportunity there. I don’t know if that answers your question, Patrick, but I’m just trying to give you a bit of color.

Patrick Kenny: Yes, that’s great. Sounds like on par, I guess, from a later phase perspective. And then just on the strategy to look for opportunities to diversify the portfolio outside of Alberta. I know it’s early days here with respect to BC’s call for power, but just curious your initial thoughts on pursuing any greenfield opportunities in the province or whether or not you might have any low-hanging fruit to go after.

John Kousinioris: Yes, we’re not — I’ll be candid. We’re really not all that focused on BC as kind of a core market. So that is an area that the team has really set up to participate in. I would say our primary focus in the more immediate term in terms of facilities, both organic growth but certainly M&A growth, would be in the Western United States. We’re really trying to match the skill set that we have as an organization, especially in our energy marketing group, with the opportunities that we see. We like the long-term fundamentals of the market there. I think they’re excellent, candidly. And when we talk of the Western U.S., it’s kind of all-around California, not so much in California, if you see what I’m saying. So we like some of the return multiples that we’re seeing there, and that’s a real focus, particularly the Pac Northwest and the Desert Southwest with the ability to be able to flow power in and out of California would be, I would say, Joel, Blain, kind of top of the wish list in terms of what focus would be, Patrick.

Patrick Kenny: Got it. Okay. And then just coming back to Alberta on the REM. I know the final rules are still TBD, but from what you’re hearing on the ground, how do you foresee the value of ancillary services trending in the province under the new design and some of the new parameters being proposed, just given how the supply-demand dynamics have changed over the past five years or so? And I guess where might you see some upside across your Alberta portfolio with respect to ancillary?

John Kousinioris: Yes. So look, we’re — as you know, there was a bit of a pivot that took place, losing track of time now, probably about three weeks ago or so. And so, we’re reworking all of those assumptions, I would say thematically for ancillary services. Two things I would say. One, we are expecting more volumes to be procured over time. And I think from just a competitiveness perspective, we really like what our fleet can do. And frankly, we’re even exploring a little project. We’ve got a capital project that we could do to actually even enhance our ability to provide off of our hydro more ancillary services going forward. I also think with the lifting of some of the price gaps that we’ve had in the province, when you see a bunch of volatility, that’s when you might see more benefit from the fleet.

So I’d say we’re pretty optimistic both from a volume perspective and from a pricing perspective over time, as we take a longer-term view on where this is going to go. I mean, the reality remains that from a supply and demand perspective, we’re a bit oversupplied in the province in the near term, which is something that we knew was the case. But I’d say, I don’t know, Blain, as we look at the balance of the decade, we’re, I’d say, guardedly optimistic in terms of what it means.

Blain van Melle: I would agree, John. As we refresh some of our modeling currently that we’re doing right now, we start to see prices improve relatively well through 2028 into 2029. So just this little lull here as we chew through this. And with respect to the ancillary services, Patrick, it really comes to a fundamental hypothesis that as the grid continues to bring online more renewables, the need for balancing and frequency response and fast ramping units to maintain that grid reliability will become ever more important, and there’ll have to be value put to that to pay for it.

John Kousinioris: Yes. So I — and you’ve seen this before, Patrick, where we go through these periods where we’ve had some additions to the system, and it takes three or four years to kind of be digested, and then things tighten up. So, we’re working through it right now, and you heard what Blain said, so I think that’s all right.

Patrick Kenny: Okay. That’s a great color. Thanks, guys. I’ll leave it there.

John Kousinioris: Thanks so much, Patrick.

Operator: Thank you. Our next question comes from John Mould with TD Cowen. Please proceed.

John Mould: Hi. Good morning, everybody. First, maybe coming back to the Alberta data centers, and we’re supposed to get this update from the AESO this month. Just wondering if you can give us a bit of a preview on what you’re hoping for from AESO in terms of the methodology that they may use to allocate available capacity to proposals. And you previously articulated a view that there’s about 1.5 gigawatts to 2 gigawatts of grid capacity that should be available for large loads over the mid-term. Just wondering, have you seen anything so far in market dynamics, just given the supply increase from last year that would cause you to change that view one way or another?

John Kousinioris: Good morning, John. Look, we’re waiting for the AESO to come in and provide some clarity on these issues as well. I can tell you that we have had some discussions, including what we’re proposing to do, and our product’s a little bit unique because it is more behind the meter in terms of what we’re proposing. So we would be looking in our case to be supplying 90%-plus of the data center needs from our facility effectively behind the meter and then looking to the market for 10% to 12% of the time to meet the load that it would require. So it’s a relatively — given our configuration, which is a bit different from some of the others, relatively modest, I would say, impact generally in terms of overall numbers before reliability becomes an issue.

I still think we’re in that 1 gigs to 2 gigs. I haven’t — at least that’s based on the work that we’ve done. We’ll see where the AESO lands. Had some very high-level discussions around that with them, and I didn’t take away. I know they’re still doing their work. Any sense that that would go in a significantly different direction from that. So, we feel good about that. The other thing is some of our units, like even if you look at K2, relatively lower sort of capacity factor. So it is effectively like bringing new capacity to the market. If you have a plant that’s running 30% of the time and now you’re going to be running at 90% or 92% of the time, which is what we’re estimating we’ll be able to do for our plant. So, we are effectively bringing new capacity to be able to move forward.

And I think certainly the AESO understands that. In terms of the queue and the interconnection and the work around that, I — like again, I’m guardedly optimistic there are two — there’s a tremendous number of applications. We certainly don’t think they’re all real. And I think the AESO is going to look at it. I think kind of an order of commercialization effectively. So — and I think that’s the way they should look at it, like what’s real versus what might be more speculative going forward. So I think they’re taking a pretty responsible and rational approach where hopefully, we’ll be able to bring some of the opportunities into the province before we need to have some of the harder discussions around transmission and incremental generation.

And I don’t think it’s lost on the AESO that the capacity for these things ideally is located where existing capacity and generation and transmission exists, which is really around our facilities and obviously Genesee as well further down and potentially even at Sheerness. So net-net, I’d say, pretty good in terms of where we are.

John Mould: Okay, that’s great. Thanks for that color. And then maybe just going back to your just broader market interest and the comment about your reliance on Alberta decreasing over time, and as you noted, function of your scale in the market, your focus with Nova is on the Western U.S. In the earlier question, you highlighted like Pacific Northwest and Desert Southwest. Just when you’re thinking about where you want to allocate that growth capital, is it mainly the Western U.S. that you’re looking at this point? Are there other key markets where either you’d like to grow your existing footprint or maybe you’d like to enter at some scale where you’re right now? How are you thinking about that?

John Kousinioris: So when we look at kind of the geographies — and look, we’ll be having our strategy session later in the year where we’ll be going through all of this in a bit more detail with everybody. But when we look at kind of the areas of focused growth for the company going forward, we really look at, I would say, three things. We look at the fundamental dynamics of the markets in question. So what is the fidelity of pricing? How is it from a transmission perspective? It doesn’t have population and industrial growth. From a long-term perspective, where do we think pricing is going? So it really is a deconstructed deep dive of the geography and question. So that’s first and foremost. It’s like how do we feel about this jurisdiction versus that jurisdiction from a focus perspective.

Number two, we look at it from an operational perspective. Is there fuel types that we are good at operating? And as you know, we’ve got quite a diverse skill set there. Are there synergies? Are there strategies that we can bring from an M&A perspective that would make sense given our footprint in the United States and Canada? Existing footprints in the United States, Canada, and Australia, where we could add value. So there’s that operational dimension. The last one is, how can we add incremental value because of our customer relationships and our energy marketing capabilities. And that also directs us to particular geographies because of the skill sets that we have there in our positions. Like a lot of people don’t realize it, but we’re the largest trader of power in the Pacific Northwest, for example.

It is a market that we’re intimately familiar with. So when you distill it all down, we’ve got three major areas of focus. Alberta is one just because of our scale and size of where we are here and our intimate understanding of the market here. But when we look at scale and scope — Alberta is pretty small. When we look at scale and scope and opportunity set going forward, certainly, we feel great about the U.S. generally, I would say, and the Western U.S. in particular, given some of the factors that I spoke about, and also Western Australia as well. But if you were to sort of prioritize those three markets, I think that the U.S. would be the area of greatest interest. So it’s no surprise to see our M&A team focus on there. And it’s no surprise to see kind of the work that we’re doing with Nova, for example, that focuses that area.

Hopefully, that gives you a bit of a sense.

John Mould: Yes, that’s great. Thanks for that, John. And just maybe one last one just on the hedging side. I think your hedging levels on the power side for 2026 are up fairly substantially, I think about 36%, unsurprisingly bringing down the average price level. Your gas levels didn’t change as much. I’m just wondering if you can provide a little more color on how you’re thinking about hedging next year and the gas cost side of things with LNG Canada coming on and all the dynamics at work there.

John Kousinioris: Yes. So look, I would say that we look at — so we model out what our expectations would be for pricing and how we think the merchant component of our fleet would be able to run over the course of the year. So, for example, if I were to compare 2026 to going into 2021, in 2021, we thought the forward curve was light, and we were open. And we benefited from being more open as we go into 2026, just like you’ve seen in 2025. When we look at the forward curve, we think that we can do better than that by hedging it up, and that’s what we’re doing. You’re right, we have increased the number of hedges for full year 2026. I’d say, Blain, we’re still pretty comfortable with kind of that high $60 price — $68 price, given kind of a forward curve signaling pricing that would be $20, $22, $23 below that going forward.

So I don’t think the team is doing their work, frankly, on setting up the portfolio for 2026. Blain, you can speak to that. But I think we’re comfortable. And again, you’ll see us be relatively long, I would say hedging in 2026 going forward. On the gas side, I don’t know, Blain, I’m not sure what the forward curve for gas is showing. I mean, right now, we’re — sort of year-to-date, it’s pretty low. When you’re looking at 2026, it’s 3-ish, I think. And so, we do have hedges in place just like we do this year. I think our weighted average price for our hedge position for gas is actually a bit higher than the spot price in the year for gas, more in that 3.60 range as opposed to kind of the 2s that we’re seeing today. But I think we’re — when we look at — and when the guys do their hedging, they do assess kind of the — what I would say, the variable costs associated with the production and kind of assessing the positions as they go forward.

So clearly, the price of fuel and carbon is a key component going forward. So not surprised at kind of where we are, and we’ll continue to do it. Blain, I don’t know if you want any color to that.

Blain van Melle: Yes. It’s active. I would say we track it every month just so that you know, John. And it’s probably the first when we do our Alberta business review. It’s topic number one, topic number two, topic number three as we go forward.

John Mould: Okay, that’s great. Thanks for all that detail. Those are my questions.

John Kousinioris: Of course.

Operator: Thank you. Our next question is from Mark Jarvi with CIBC. Please proceed.

Mark Jarvi: Thanks for putting me in. I was wondering if you guys could fill in a little bit more details around the Nova structure, just in terms of what would you need to see happen for you to convert your equity. And then I guess on the late-stage projects, how soon could that come? And from my understanding area that would require incremental capital beyond the capital that you’ve already committed so far. Is that correct?

John Kousinioris: It is, Mark. Good morning. So on Nova, the — so what basically happened there is the team there was looking at developing a partnership that would fund kind of the next iteration of growth that they’re developing. And through a bunch of circumstances, we had the good fortune of connecting with them and getting to a place where their view of markets aligned with ours. And there was just a lot of comfort in working with each other going forward. So rather than them going sort of externally to seek capital, we came up with a structure where we would lend them the capital that we did, both the term facility and the revolving credit facility for a limited period of time. We fully expect those funds that we’re providing to them would be repaid to the company if we don’t end up converting.

If we see that they’re creating value because they’re developing assets, we may not buy all of the assets that they’re developing and selling them, or they’re looking at maybe exiting their platform. We do have the ability to convert that loan amount into an equity component. And there’s a formula that kind of contemplates what the value of that would be approaching a quarter of the equity value. So that if they were looking to exit at some point in time in the future, our company could participate in that and actually benefit from that, as opposed to just getting the loan at 7%. I mean, we didn’t make the investment to make 7%. We made the investment to do better than that. On the actual assets themselves, I think realistically, we’re looking at projects that would be reaching FID, certainly not in ’25, certainly not in 2026.

We think it’s more sort of ’27, ’28-ish in terms of where things are going forward as they work through their pipeline of assets and candidly recalibrated a bit to the west. We have a very detailed structure of how all of the criteria that they have to meet before the project becomes appropriately eligible for TransAlta to consider actually acquiring it and ultimately developing it from Nova. So it’s very detailed. We’re embedding an employee in their office in Chicago, so we’re having oversight, and frankly, we’ll be rotating people through there as well as we go forward. We have observers on the board. We have the ability to influence geographies and the types of counterparts they’re pursuing and even technology types and OEM suppliers as we go forward.

And so, there’s a very — how can I put it? Detailed, scripted kind of approach on how a project goes from a twinkle in the eye to a place where it makes sense for TransAlta to consider pulling the trigger and acquiring the project in the latter part of the decade to see it through. So hopefully, that gives you a little bit of a sense of what it’s like.

Mark Jarvi: And then how much of an equity stake would you have? Would you be partnering on some of those advanced-stage projects? Or you take them off of them and develop them yourself, so you’d be the sole sponsor of those projects once you get to FID?

John Kousinioris: Yes. The current vision would be the latter, Mark. We would end up acquiring the projects from them for kind of a predetermined, call it a development fee for them. That still provides us with the return thresholds that we prescribed. That makes sense for our company, given our cost of capital. So that’s exactly what it’s like. And if we don’t proceed to acquire the asset for whatever reason, they’re then free to monetize the asset to a third party.

Mark Jarvi: Can you give a sense just based on what could come in that sort of three- to four-year time frame, number of megawatts, potential investment opportunity? Can you frame that at all in terms of financial numbers?

John Kousinioris: Look, I think it’s early days, but I would say that we wouldn’t have done it if we didn’t think that the kind of opportunity set that we would be getting would be well in excess of a gigawatt over that time period.

Mark Jarvi: Got it. And Joel, just for you now with that there, you obviously still do the buyback dividend increase. You’ve got some money allocated, I’m sure, for Centralia and Keephills upgrades. What else do you guys have in terms of funding capacity to do more M&A or greenfield in the short term, or what else would you have to do then to sort of fill in the funding needs if you do see something you like on an M&A side of things?

Joel Hunter: Yes, Mark, really good question. The first thing we would look to is rotating capital. We’ve highlighted before. We have 88 assets in the portfolio today. A lot of these assets could be actionable in the marketplace. And so, one of the things we would look to is if there is an opportunity out there that’s going to really add long-term value to the shareholder where we can acquire a multiple below where we can actually invest the assets at. We would like to do that first. We always retain the option with common equity for the right offering. It has to be something that is transformational for us and be highly accretive both on an earnings per share basis and a cash flow per share basis. But then the first source of capital, if you will, Mark, would be looking to rotate capital in the event that we have a shortfall and we’re looking at opportunities outside of our current base plan.

John Kousinioris: And then – go ahead.

Mark Jarvi: I was just curious if you guys have been testing the water in terms of asset sales. If you are seeing potential uses of capital opportunities to deploy, have you been seeing what’s out there in terms of assets that would be for the best value realization, monetization opportunities?

John Kousinioris: I would say, Mark, the answer to that question is although it’s early stages, we have been selectively testing in relation to a couple of the facilities that we have in the portfolio and exploring the possibility of divesting them as we go forward, given kind of the disconnect between what we think they’re worth to us versus what they might be worth in the market, if you see what I’m saying.

Mark Jarvi: But with the view that any transaction would be sort of net neutral on contractedness?

John Kousinioris: I think broadly speaking, directionally, we would be — at least what we’re looking at might actually enhance our contractedness, Mark.

Mark Jarvi: Okay. All right. Thanks for fitting me in. Appreciate it.

John Kousinioris: Sure. Thank you.

Operator: Thank you. And this concludes our Q&A session for today. I would now like to turn the conference back to Stephanie Paris for closing remarks.

Stephanie Paris: Thank you, everyone. That concludes our call for today. If you have any further questions, please don’t hesitate to reach out to the TransAlta Investor Relations team.

Operator: And thank you. This concludes our conference call. You may now disconnect. Good day, everyone.