Good morning, and welcome. My name is Carmen, and I'll be your operator for today. I would like to welcome everyone to TransAlta Corporation's First Quarter 2025 Results Conference Call. Ms. Paris, you may begin your conference.

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.

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, including 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 remains 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 de-risked 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.

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 the 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 purchased 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.

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.

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

One moment for our first question. It comes from Robert Hope with Scotiabank. Please proceed.

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?

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.

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?

Yes, Robert, I think when we analyze our current trading position and the significant increase in costs for greenfield development, we are facing pressure on PPA prices and the timelines for project growth. However, I would say that we are identifying better opportunities, particularly in M&A. Our small M&A team is quite active right now, exploring a variety of projects, primarily with a focus on U.S. assets and the multiples associated with certain types of contracted renewables. More importantly, we are looking at particular gas assets that align with our company's strategy. This is a priority for us, especially considering our strong balance sheet and the expected free cash flow in the near future. We are positioning the company for conventional greenfield growth later in the decade, which aligns with our Nova project. For now, we're concentrating on legacy investments that yield higher returns and pursuing M&A opportunities that align with our risk-adjusted returns strategy.

All right. I appreciate the color. Thank you.

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

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 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?

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 I 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.

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.

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.

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?

Yes, it's quite early to comment on that. We don't yet have ministers in place for a Carney government. Our working assumption, based on some preliminary discussions, is that things will remain largely the same. Currently, we are not anticipating any significant changes in our business planning compared to what we've experienced recently. One important point we've communicated is that it is crucial for us to stay competitive on carbon pricing compared to our major trading partners. This is something we are aware of, and many businesses in Canada recognize that inconsistencies can create challenges, even if adjustments are made for export-exposed industries. This is a topic we will continue to discuss with the government. But at this moment, it's hard to make predictions. So, we expect a stable regulatory environment at the federal level.

Are any of these policy landscapes or the REM major hurdles in your discussions with the data center counterparties, particularly regarding time and delays or any absolute obstacles in Alberta?

I believe the straightforward answer is no. This hasn’t been a significant concern in any of our discussions regarding data center opportunities. Even when talking about Centralia, our main focus has been on the Canadian regulatory environment. We're not particularly worried about federal or state/provincial regulations hindering our ability to extract value from our legacy assets. The only aspect that has been influenced from a data center standpoint is our focus on utilizing the renewable credits generated by our substantial renewables fleet in Alberta to help lessen the carbon exposure from our data center offerings. This is something we can specifically do in Alberta. Overall, it has not been a critical topic in our discussions.

Very clear. Thank you.

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

Hi, thanks. Good morning. To start off, regarding your data centers, you've mentioned the size and focus in your Phase 3 at this point. Do you feel that even though you're focusing on 400 megawatts or more, there might be an opportunity to increase that capacity over the medium to long term during your negotiations?

Good morning, Ben. Our initial discussions have mainly centered on the base 400 megawatts. Honestly, it's known that we can add another 400 megawatts, and our Q application actually envisions an 800-megawatt development there. For now, we are focusing on a sequential approach. However, it is promising to share with others, in the conversations we've been having, that if there is demand or long-term planning in place, we can anticipate scaling up. This is certainly feasible on-site. One of the advantages of this area is that we have about 1.2 gigawatts of transmission access available there. I believe it is roughly 2.1 gigawatts at Sundance, which is a later project and more of a redevelopment, but overall, I think we are in a solid position. So our base offering is established, with the potential to expand to 800 megawatts. Most of the technical work completed so far has primarily focused on that 400 megawatt K2 offering.

Okay, got it. Regarding the gas development on Centralia, is the timing expected to be an update later in the year, or could there be something before mid-year?

No, it's more the latter. From a commercial perspective, I am quite satisfied with how things are progressing. Blain has been doing an excellent job of advancing this, and I will let him share some insights on the timing. We are quite advanced on aspects such as pricing, timelines, permitting, and other related factors. Blain, could you provide some additional details?

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.

What I would say is that the tenor we are exploring would be a real positive from a company perspective. It's something we can implement quickly. The cost per megawatt for delivering 670 megawatts to our customer is only a small fraction of what a new build would cost, both in terms of timing and capital. We're quite excited about that, and it's in an advanced stage.

Okay, great. Thanks for the updates.

Thank you.

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

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?

Yes, good morning. Hedging is one of our main priorities, particularly concerning Alberta. We have significant hedges in place for 2025, and for 2026, we’re looking at around 6,500 gigawatt hours at a price near $68, while the forward curve in Alberta for that year is in the low to mid-40s. We continue to build our positions in 2027 and beyond, with approximately 35% to 40% of our hedge positions involving our commercial and industrial customers in Alberta, which typically have a three-year tenor. Our customers in this segment tend to remain loyal. While the prices we've been able to achieve have decreased somewhat, they still offer a substantial premium over the wholesale prices, often exceeding $60 per megawatt hour. Additionally, one of our competitors in the C&I sector, ENMAX, is scaling back their efforts, which positions us as one of the largest C&I providers in Alberta. This remains a key area of focus for us. Another priority is our strategy around data centers. We aim to reduce our merchant exposure in the Alberta fleet and secure contracts, primarily through financial hedges. Although there is limited liquidity ahead, our main focus will be on the C&I business and our data center strategy. Blain, do you have anything to add?

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.

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.

Great, thanks. The free cash flow was slightly lower in the first quarter, but we still have confidence in the full year guidance, acknowledging the hedge dynamics. Can you discuss the expected cash dynamics for each quarter until the end of the year and what factors might influence movement towards the upper or lower end of the guidance range? Thank you.

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.

Great. Thank you for the time.

Thank you.

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

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?

Yes. Good morning, Patrick. Regarding Centralia, our returns are strong, honestly stronger than what we could achieve with a traditional new build or greenfield project, and likely stronger than what you would expect from a merger or acquisition transaction. The same applies to data centers. The key here is that we are partly repurposing capital and spending it to make the facilities suitable for their intended use. The main benefit is actually repurposing and extending the life of legacy assets. One unique challenge at Centralia is that we face some gas supply constraints. While we believe we can accommodate a 670-megawatt gas plant to meet our customer's needs for additional thermal capacity at the site, this will probably require some debottlenecking. The next phase of growth there is likely going to be greener, with potential wind and some solar projects offering more conventional returns. These are important for us, but our current priority is the coal to gas conversion, focusing on that if we can debottleneck the site. It's ideally located for data with 12,000 acres available. We're actively working to explore further possibilities. As for Keephills, we are seeing very good returns but face more constraints from a gas perspective, making it a more unrestricted opportunity. I'm not sure if that answers your question, Patrick, but I hope it provides some additional insights.

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.

We're not particularly focused on British Columbia as a core market. This is an area where the team has set up to participate, but our primary focus, in the immediate term regarding facilities, will be on organic growth as well as M&A growth in the Western United States. We are looking to align our organization's skill set, particularly in our energy marketing group, with the opportunities available. We believe the long-term fundamentals in the market there are quite strong. When we mention the Western U.S., we are thinking broadly around California, but not necessarily within California itself. We see some attractive return multiples there, and our main focus will be on the Pacific Northwest and the Desert Southwest, particularly with the capability to transfer power in and out of California.

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?

Yes, we're currently adjusting our assumptions for ancillary services after a shift that happened about three weeks ago. We're expecting an increase in volumes over time and believe our fleet is well-positioned competitively. Additionally, we're considering a capital project that could enhance our capacity to provide more ancillary services from our hydro resources in the future. With the removal of some price gaps in the province, increased volatility may also lead to greater benefits from our fleet. Overall, we're optimistic about volume and pricing trends as we adopt a long-term perspective. However, it's important to acknowledge that we are somewhat oversupplied in the province in the short term, which we anticipated. Looking at the decade ahead, we remain cautiously optimistic about the outlook.

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.

Yes. We've experienced periods in the past where we've added to the system, and it takes three to four years for everything to settle before things tighten up. We're currently navigating this phase, and I believe what Blain mentioned is accurate.

Okay. That's a great color. Thanks, guys. I'll leave it there.

Thanks so much, Patrick.

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

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?

Good morning, John. We're currently waiting for the AESO to provide clarity on these matters. I can share that we have engaged in discussions about our proposals, and our offering is somewhat unique as it operates behind the meter. Essentially, we plan to supply over 90% of the data center's needs from our facility, relying on the market for 10% to 12% of the time to meet the required load. This setup results in a relatively modest impact on overall numbers before reliability becomes a concern, which I estimate remains in the range of 1 gigawatt to 2 gigawatts based on our analysis. We'll see what direction the AESO takes. We've had high-level discussions with them, but I believe they are still evaluating the situation. Regardless, we feel positive about it. Additionally, some of our units, like K2, have a lower capacity factor, which means we are effectively introducing new capacity to the market. For instance, if a plant runs 30% of the time and is projected to run at 90% or 92% moving forward, it contributes significantly to capacity. The AESO understands this. Regarding the queue and interconnection progress, I'm cautiously optimistic. There are numerous applications, but we don’t expect all of them to be viable. I believe the AESO will assess applications based on their authenticity and commercial potential, distinguishing between realistic prospects and speculative ones. They seem to be taking a responsible and rational approach, which we hope will allow us to integrate some opportunities before needing to discuss more complicated transmission and generation expansions. It's clear to the AESO that the ideal locations for these projects are near existing capacity, generation, and transmission infrastructure, particularly around our facilities, along with Genesee and potentially Sheerness. Overall, I would say we are in a good position.

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?

When we consider the various regions, we will be discussing our strategy in more detail later this year. Our areas of focused growth will revolve around three main aspects. First, we examine the market dynamics, including pricing fidelity, transmission perspectives, and both population and industrial growth. We assess these factors to gain insights into long-term pricing trends and to compare different jurisdictions. Second, we analyze our operational capabilities, including the types of fuel we effectively manage and explore potential synergies or M&A strategies that align with our existing presence in the U.S., Canada, and Australia. Lastly, we look at how we can leverage our customer relationships and energy marketing expertise to create incremental value, which in turn guides us to specific geographies where we have established strengths. For instance, we are the largest power trader in the Pacific Northwest, a market we know very well. In summary, our three main areas of focus include Alberta due to our expertise, but on a broader scale, we are particularly optimistic about the U.S., especially the Western U.S., and Western Australia. If we prioritize, the U.S. emerges as the most significant area of interest, which is reflected in the focus of our M&A team and our collaboration with Nova in that region.

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.

Yes. We evaluate our pricing expectations and how the merchant component of our fleet will operate throughout the year. For instance, comparing 2026 to 2021, we believed the forward curve in 2021 was low, and our openness benefited us as we approached 2026, similar to what we experienced in 2025. We think we can surpass our previous predictions by hedging, which we've been doing. We have indeed increased the number of hedges for the entire year of 2026. I believe, Blain, we're still quite comfortable with the high $60 price, around $68, as the forward curve suggests pricing that could be $20 to $23 below that in the future. I don’t think the team is falling short in their preparation for 2026. Blain, you may want to add to that. However, we're confident in our approach. You'll see us maintain a relatively long hedging position for 2026. Regarding gas, I'm not sure what the forward curve indicates, but currently it's quite low, approximately 3 for 2026. We have hedges in place similar to this year, and our average hedge price for gas is actually a bit higher than the spot price, around 3.60, compared to the 2s we're seeing today. Our team considers variable production costs and assesses positions as we move forward. The prices for fuel and carbon will be significant factors ahead. Therefore, I'm not surprised by our current situation, and we will continue this approach. Blain, do you have anything to add?

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.

Okay, that's great. Thanks for all that detail. Those are my questions.

Of course.

Thank you. Our next question comes from Mark Jarvi with CIBC. Please proceed.

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?

Good morning, Mark. Regarding Nova, the team was exploring a partnership to support their next phase of growth. Fortunately, we connected with them and found our market perspectives aligned. Instead of seeking capital externally, we developed a structure to lend them funds through both a term facility and a revolving credit facility for a limited time. We anticipate that the funds will be repaid if we do not convert. If they create value by developing assets, we may choose not to acquire all of them or they might consider exiting their platform. We have the option to convert the loan into an equity component based on a formula that reflects a portion of the equity value. If they decide to exit in the future, our company could benefit, rather than just receiving a loan at 7%. Our focus is to achieve more than that return. For the assets, we realistically expect projects to reach the final investment decision stage around 2027 or 2028, as they navigate their pipeline and recalibrate efforts towards the west. We have a strict set of criteria that must be met before we consider acquiring a project from Nova. We’re embedding an employee in their Chicago office for oversight and will rotate additional staff as needed. We have observers on their board and can influence geographic decisions, partner selections, and technology choices. Our process for moving a project from concept to a viable acquisition by TransAlta is thorough and well-defined, aimed at making informed decisions as we approach the latter part of the decade. I hope this gives you a clearer picture of the situation.

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?

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.

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?

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.

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.

And then - go ahead.

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?

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.

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

I think broadly speaking, what we're looking at might actually enhance our contractedness, Mark.

Okay. All right. Thanks for fitting me in. Appreciate it.

Sure. Thank you.

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.

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.

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