Good morning. My name is Carmen, and I will be your conference operator today. I would like to welcome everyone to TransAlta Corporation's First Quarter 2024 Results Conference Call. All participants are currently in a listen-only mode. After the speaker's remarks, there will be a question-and-answer session. Thank you. Ms. Valentini, you may begin your conference.

Thank you, Carmen. Good morning, everyone, and welcome to TransAlta's first quarter 2024 conference call. With me today are John Kousinioris, President and Chief Executive Officer. As well, we have Todd Stack, VP 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 the information provided during this conference call is subject to the forward-looking statement qualification set out here on slide 2, details further in our MD&A and incorporated in full for the purposes of today's call. All amounts referenced during the call are in Canadian currency unless otherwise noted. The non-IFRS terminology that we are using, including adjusted EBITDA and free cash flow, are also reconciled in the MD&A for your reference. On today's call, John and Todd will provide an overview of the quarterly results. And after these remarks, we will open the call for questions. With that, let me turn the call over to John.

Thank you, Chiara. Good morning, everyone, and thank you for joining our first quarter 2024 conference call. As part of our commitment towards reconciliation, I want to begin by acknowledging that TransAlta's Head Office, where we are today, is located in the traditional territories of the people of Treaty 7, which include the Blackfoot Confederacy, comprising the Siksika, the Piikani and the Kainai First Nation, the Tsuut'ina First Nation and the Stoney-Nakoda, including the Chiniki, Bearspaw, and Goodstoney First Nations. The city of Calgary is also home to the Métis Nation of Alberta, Districts 5 and 6. TransAlta had an excellent first quarter, which exceeded our expectations and is strongly in line with our stated outlook for the year. We delivered adjusted EBITDA of $328 million, free cash flow of $206 million or $0.67 per share, and net earnings to shareholders of $222 million. Our results stem from the strong performance of our merchant fleet, the exceptional efforts of our optimization team, which managed our hedging strategies, and our solid operations with improved fleet availability of 92.3%. We also benefited from stronger power prices, particularly during periods of market tightness in January. We continue to perform well in managing the evolving markets of our operating portfolio and our diversified fleet illustrated its resilience and flexibility by generating excellent results from both merchant and contracted assets. With another quarter of strong cash flow, we continue to maintain a strong balance sheet with over $1.7 billion in liquidity, including $417 million in cash, and are well-positioned to deliver on our priorities. In addition to our financial performance, there are a number of updates on our strategic initiatives to share with you this quarter. First, I'm pleased to announce that we have largely completed the construction program that underpinned the first phase of our clean electricity growth plan, which we launched back in 2021. We've achieved commercial operations at our 300-megawatt White Rock East and West wind facilities in Oklahoma, along with the Mount Keith transmission expansion in Australia. Our 200-megawatt Horizon Hill wind facility is in the final stages of commissioning and expected to reach commercial operations in the near future. Together, these assets will contribute over $115 million to our company in adjusted EBITDA annually. With the completion of Horizon Hill and White Rock, we will have over 1 gigawatt of contracted renewables in operation in the United States, providing contracted cash flows to our company. Next, and as you all know, we recently announced the Chief Financial Officer succession plan and would like to take a moment to express my own as well as the Board's gratitude to Todd Stack for his incredible 34-year career with the company. Todd joined TransAlta as an engineer in our former transmission business, held roles in business development, and went on to take greater and greater responsibilities within the company, culminating in his current role as CFO. His contributions to TransAlta are many and significant and are reflective of his values founded on hard work, commitment, and integrity. We wish Todd the very best in his retirement. As we say farewell to Todd, I'm pleased to welcome Joe to take on the role of Chief Financial Officer. Joe will bring over 25 years of experience spanning various areas in the Energy Sector to our company. His established reputation as a strong collaborative leader will be important as we pursue our strategic objectives. We look forward to Joe joining us in July and know that we will benefit from his extensive industry experience and capital markets knowledge. Finally, during the quarter, there were a number of regulatory changes and announcements made by the Government of Alberta, which I will now address both substantively and in the context of the impact we expect them to have on our business moving forward. The Government of Alberta recently announced changes in three key areas that will affect the Alberta Electricity market in the near-term and the long-term. First, the government introduced new requirements for renewable projects and power plant regulatory approval processes. Overall, these requirements will place additional constraints on where new projects can be physically cited, require developers to have greater financial resources to secure future reclamation obligations, and grant standing to additional stakeholders in regulatory proceedings. These regulatory outcomes are all as we expected. Second, the government announced two interim regulations, the Market Power Mitigation Regulation and the Supply Cushion Regulation. They provide new near-term rules around offer behavior and fleet availability respectively and will take effect on July 1, 2024. Third, the Ministry of Affordability and Utilities directed the Alberta Electric System operator and the Market Surveillance Administrator to commence work for the design and implementation of a restructured energy market. The design is to be finalized by the end of 2025, with implementation to occur in 2026, an aggressive timeline from our perspective. The interim regulations will expire on November 30, 2027, at which time the restructured energy market is expected to be fully implemented. The Interim Market Power Mitigation and the Supply Cushion Regulations provide new market mechanisms aimed at enhancing the affordability and reliability of Alberta's Power market. The Market Power Mitigation regulation applies an offer price limit, set at a value equal to the greater of $125 per megawatt hour or 25 times the day-ahead natural gas price. It's triggered when a hypothetical reference generating facility earns the equivalent of two months of prescribed net revenues. When the offer limit is triggered, it's applied for the remainder of the calendar month and then resets at the beginning of the next. The offer price limit does not apply to market participants with offer control below 5% of generating capacity in Alberta, to renewable energy resources, or to energy storage resources. Although TransAlta will be caught by the offer price limit, our hydro, wind, and battery assets will be excluded from the offer price limit regime. These facilities continue to retain full pricing discretion within the market. It's also important to note that the offer price limit is not the same as the clearing price. The market clearing price will continue to depend on the system marginal price based on merit order including offer prices by generators or facilities that are not constrained by the regulation. We have assessed the proposed Market Power Mechanisms and Mitigation Mechanism and do not expect them to significantly impact our company. We believe that market prices will continue to be set primarily by bidding behavior driven by pre-existing supply and demand fundamentals in the province of Alberta, which are reflected in the weaker pricing conditions we expect over the period that the regulations will be in place. The second interim regulation is the Supply Cushion Regulation, which will require the AESO to direct generators online that require one hour or more to synchronize to the grid. Specifically, the AESO must forecast the direct long lead time generation into service when the supply cushion is expected to be equal to or less than 932 megawatts. Generation directed to user service will receive a cost guarantee to cover startup and variable costs if the pool price revenues are not sufficient to compensate them. Although the impacts of this regulation are still unclear given the lack of any details around the proposed mechanism, once again, our current expectation is that the market pricing dynamics under the Supply Cushion Regulation will largely be as they are today when the market is expected to be tight and short on supply. In such circumstances, long lead time assets such as our coal-to-gas units will already be planning to start up and run to supply electricity to the grid given the economic incentive to do so. Finally, the government of Alberta announced that it would be restructuring the energy-only market. While specifics have yet to be determined, the restructuring is intended to result in stronger incentives for dispatchable generation and to provide long-term signals for investment to promote greater reliability within the product. The restructured energy market is expected to include the introduction of a day-ahead market, an administrative scarcity pricing mechanism, the allowance of negative pricing alongside a higher price gap, and the reduction of settlement windows from one hour to 15 or five minutes. TransAlta has actually advocated for and supports a number of these market reforms. We share the government's view that a market redesign is necessary and look forward to working with the AESO and the government to develop a framework that delivers reliable and affordable electricity for Alberta. At the same time, the new market needs to enable companies to invest in projects and technologies that will be needed in the future with appropriate risk-adjusted returns on their investments. A market would also need to find ways to better incentivize reliability services to address the issue of increasing generation intermittency. We have the assets that can fulfill this reliability need, but require a market construct that values and incentivizes such services. We're hopeful that through the consultation process, the right parameters will be put in place to ensure strong future development opportunities for all forms of generation required to achieve a net-zero grid. We will continue to be actively engaged in the industry working group and stakeholder processes and are confident that the government of Alberta wants to retain an investor-owned energy-only market. As we take stock of the government of Alberta's regulatory announcements, we've reassessed our own growth plans in the province. Our 300-megawatt rippling wind project has been impacted by the new restrictions on development near protected areas and pristine use cases and will not be advanced. The project has been removed from our growth pipeline. Also due to the near-term uncertainty stemming from the forthcoming market redesign and the impact of changing frameworks on resulting market prices, we've decided to pause the development of three advanced stage greenfield projects: our 180-megawatt water charger, 100-megawatt tempest, and 44-megawatt Pinnacle projects. These projects all have varying degrees of merchant market exposure and have been put on hold until we receive sufficient clarity regarding the future market structure. We want to ensure that market changes will not impact our investment thesis on these projects before we proceed and have pushed out financial investment decisions until at least 2026 as we work to better understand the impact of the evolving market. That said, we continue to have a robust pipeline of approximately five gigawatts distributed across Canada, the United States, and Western Australia. We will allocate development efforts and capital to markets which offer geographic diversity, market stability, and strong returns. In the near to medium term, we will be focusing on organic growth projects that have limited merchant exposure in Alberta as well as sites that are located in the United States and Western Australia. We won't grow simply for the sake of meeting targets. Long-term shareholder value creation will continue to drive our capital allocation decisions. With the recent regulatory changes in Alberta, we've also reassessed our proposed Heartland generation acquisition. We continue to see benefits of acquiring Heartland and continue to work on advancing the transaction through the regulatory review process with the Competition Bureau. The Heartland acquisition will serve to enhance our generation capabilities to meet the opportunities and challenges of the energy transition in Alberta, which have not fundamentally changed with the market changes being advanced by the government. The market will still require low-cost, highly flexible, and fast-responding generation, which will be supportive of grid reliability over the coming years. We've seen multiple grid alerts since the beginning of 2024 where Heartland's assets were supportive in providing reliability, illustrating their potential value as part of our portfolio and we expect the interim regulations to have a modest impact on the economics of the proposed transaction. Heartland's assets acquired at a cost significantly lower than new build will support our competitive positioning in response to the changing market dynamics and provide diversification and stability to our cash flow profile. We also remind everyone that the purchase agreement provides that the economic benefits of the portfolio arising after October 31, 2023, accrue to the account of TransAlta. Heartland's performance over the past several months will result in a favorable purchase price adjustment for TransAlta. Todd will now provide more details on the quarter.

Thank you, John, and good morning, everyone. Let me start my comments this morning with a discussion on our Alberta portfolio and how we performed during the first quarter of 2024. For the quarter, we continued to realize higher than average merchant spot power pricing for energy on our Hydro and Gas fleet, and we effectively optimized our capacity and ancillary services across the fleet. The spot price for the first quarter averaged $99 per megawatt hour, which, as we expected, was significantly lower than the average price of $142 for the first quarter of 2023. Weather conditions in Q1 were relatively mild compared to the first quarter of 2023, which had multiple periods of extremely cold weather. In Q1, our Hydro fleet in Alberta continued to significantly outperform with an average realized price of $152 per megawatt hour, a notable 53% premium to spot price. Our Gas fleet in Alberta also exceeded expectations, operating with strong availability and capturing peak pricing throughout the quarter of $118 per megawatt hour, which was 19% above the spot price. In the quarter, the Gas fleet in Alberta also benefited from higher production levels during peak pricing as well as higher-priced power hedges, which partially offset the impact of lower Alberta spot pricing. Our merchant Wind fleet realized an average price of $51 per megawatt hour, which was in line with our expectations. In addition to strong realized spot pricing, our hedging program was able to further mitigate the impact of the extended periods of lower power prices experienced in the quarter. During Q1, we had hedged production of 1,900 gigawatt hours at an average price of $88. Looking at the balance of the year, we have approximately 6,400 gigawatt hours of gas generation hedged in Alberta, at an average price of $85. And we've hedged roughly 64% of our required natural gas volumes at an average price of $2.80 per GJ. We're comfortable with our current natural gas hedge level and believe natural gas prices in Alberta will remain soft for the balance of the year due to the significant supply and storage levels. Gas prices through the end of the year are projected to be below $2 per GJ, which will provide the opportunity for higher margins from the Gas fleet. For 2025 and 2026, our team has hedged production at an average price of $80 per megawatt hour, which is above the current forward curve levels for both years. We will continue to lock in opportunistic hedges to secure cash flow and limit the downside impact of lower power prices in the next two years. These hedges are supportive of cash flows in future years and provide a base for our Alberta fleet, based on our hedge levels and our price outlook for 2025, our early estimates of cash flows for 2025, which are broadly in line with our 2024 free cash flow outlook. Looking at the first quarter, we had very strong results, which were led by our Hydro and Gas segments and we're extremely pleased with how the portfolio performed. As we predicted through our forecast, we were fully expecting that the year-over-year performance across all of our merchant assets would be impacted by lower Alberta power prices. In the quarter, the Gas segment delivered adjusted EBITDA of $134 million. Strong performance was driven by high availability, strong production, and higher realized prices from merchant sales and our hedging activities. Adjusted EBITDA at Hydro delivered a stronger than expected contribution of $87 million. Given the strong performance in the first quarter, the Hydro segment is tracking towards adjusted EBITDA for the full year 2024 of $250 million to $300 million. The Energy Transition segment delivered $26 million of adjusted EBITDA, which decreased year-over-year due to outages at Centralia and increased economic dispatch as a result of lower market prices. The Wind and Solar segment delivered EBITDA of $89 million. Lower results were in line with our performance from last year. They were below our expectations for the quarter and we expect to see a stronger contribution in Q2. In Q1, the segment benefited from the addition of Garden Plain, Northern Goldfield Solar and return to service of Kent Hills. However, the segment was impacted by lower realized prices and lower wind resource from the Alberta fleet. In Q2, the segment will benefit from contributions from the new White Rock and Horizon Hill Wind facilities. And finally, our Energy Marketing segment delivered adjusted EBITDA of $20 million, which was slightly below expectations and primarily due to lower realized trades during the quarter in comparison to the prior year. Energy Marketing results remain within our gross margin guidance for 2024 and we expect more trades to settle in the coming quarters. Overall, the first quarter of 2024 was strong, delivering free cash flow of $206 million, or $0.67 per share, which by itself is approximately 40% of the midpoint of our 2024 guidance of $525 million. Focusing on hydro, our hydro assets have continued to achieve strong realized pricing and production during peak hours, as evidenced by significant outperformance relative to spot prices in the quarter. We expect this strength to carry on for the rest of the year and are optimistic about the long-term trends of our fleet. Energy production and ancillary service volumes have remained largely consistent quarter-over-quarter, with slight changes in production that balance out over time. This consistency provides long-term predictability and a stable cash flow base that is distinctive for this asset class. TransAlta has been operating the hydro system in Alberta for over a century. Each year, we manage the balance of filling reservoirs when water is available, ensuring acceptable minimum flows throughout the year, and optimizing generation and ancillary services based on water availability. For 2024, we anticipate our water levels in Alberta will align with what we experienced in 2023, as both snowpack and rainfall significantly contribute to reservoir levels, and we are just beginning the rainy season in Alberta. Currently, we are confident in the fleet's capacity to achieve its long-term average production levels. Realized pricing in hydro remains robust, with a premium to spot electricity prices averaging about 28% over the past three years, and ancillary services earning, on average, 50% of spot prices. Looking ahead, we expect the segment to continue to enjoy a premium over spot pricing and to perform within our guidance expectations for 2024.

I will now pass it back to Todd to discuss our 2024 guidance and balance of your priorities. Thanks, Todd. Looking at full year 2024, we continue to be confident that we will meet our guidance. Our results in the first quarter show the value of our optimization and hedging strategies and diversified fleet. We have prepared extensively for weakening market conditions in Alberta. First, we have a relatively high hedge position, which was also reflected in our first quarter results. Hedges have been executed both financially and through our commercial and industrial business and mitigate the downside impact of the significant new gas-fired supply additions and evolving market conditions. We have hedged positions that are above current forward prices and have secured attractive hedge positions for 2025 and 2026. Second, we expect the impact of the interim regulations in Alberta to be muted on our company. Third, we're confident in the ability of our hydro fleet to deliver strong results which it has shown so far this year. Our outlook includes the adjusted EBITDA contributions for the year from the Mount Keith transmission project in Australia, as well as the recently commissioned White Rock East and West and soon to be commissioned Horizon Hill facilities in Oklahoma. The contribution from assets to our guidance is significant and they provide long-term predictable contracted cash flows. We have commenced our preparations for 2025, both from an operating and optimization perspective. Based on our early look work, we currently expect our results in 2025 to be broadly in line with our results in 2024. We're confident in our assets and our employees' capabilities to deliver. Considering the changes to our growth plan and the affirmation of our guidance, we remain committed to our capital allocation priorities and returning value to our shareholders. We continue to believe our enhanced common share repurchase program for 2024 of up to $150 million is an appropriate use of free cash flow to return capital to our shareholders. We were very active in the market through the first four months of the year and year-to-date have returned $53 million or approximately 35% of our 2024 target, resulting in a reduction of almost 6 million of our common shares. In fact, since January of last year, we've completed $140 million in share buybacks resulting in the repurchase of over 13 million common shares. We will be renewing our normal course issuer bid later this month and will continue to repurchase shares given our current share price, which we believe to be undervalued. We believe our share repurchase plan is an appropriate and balanced use of our capital. Our liquidity still permits us to pursue opportunistic growth with returns that meet our strict thresholds while maintaining our balance sheet strength and resilience. With that, I'd like to update you on where we are with our 2024 priorities. As I look at our remaining strategic priorities for 2024, we're focused on progressing the following key goals: first, improving our leading safety performance while achieving strong fleet availability of 93.1%; achieving EBITDA and free cash flow within our guidance ranges; proceeding with our enhanced common share repurchase program for 2024; and advancing our ESG programs. We also look forward to closing and integrating the Heartland Generation transaction subject to the satisfactory review of the transaction by the Competition Bureau. On this slide, you will notice that there is a box around our 2024 growth target. We remind everyone that this target was aspirational, as we will continue to be prudent and disciplined in our growth plan. Given that we have paused over 300 megawatts of advanced stage projects in Alberta, we do not expect to reach our 400-megawatt growth target from our Greenfield Development Program in 2024. Our growth team will turn their attention to our development pipeline to advance high-quality and attractive return projects in other regions. Our return thresholds continue to be strict, and we will continue to aggressively repurchase shares as that is where we are currently seeing the best value for our shareholders. Our Clean Electricity Growth Plan targets extend to 2028, and we will be patient in deploying capital and will balance what is best for our shareholders in both the near and long term. I would like to close by highlighting what I think makes TransAlta a highly attractive investment and a great value opportunity. First, our cash flows are strong and underpinned by a growing, high-quality, and diversified portfolio. Our business is driven by our unique, reliable, and perpetual hydro portfolio, our contracted wind and solar portfolio, and our efficient gas portfolio, all of which are complemented by our world-class asset optimization and energy marketing capabilities. Second, we are a clean electricity leader with a focus on tangible greenhouse gas emissions reductions. We remain on track to achieve our ambitious CO2 emissions reduction targets and remain committed to net zero by 2045. Third, we have a diversified development pipeline and a talented development team focused on realizing its value. We see appropriate returns to achieve our Clean Electricity Growth Plan ambitions. And fourth, our company has a sound financial foundation. Our balance sheet is strong, and we have ample liquidity to return cash flow to our shareholders to share repurchases, close the Heartland acquisition, and pursue and deliver growth when returns meet our thresholds. Finally, we have our people. Our people are our greatest asset, and I want to thank all our employees and contractors for the outstanding work they have done to deliver strong results in the first quarter and set the company up for success for the rest of the year. Thank you. I'll turn the call back over to Chiara.

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

Thank you. One moment for our first question, which comes from Mark Jarvi with CIBC. Please proceed.

Yeah. Good morning, everyone. First, all the best to you, Todd, in retirement. It's always a pleasure to get to know you over the last couple of years. John, maybe you are committed to the Heartland deal, but you don't want to pursue things like Pinnacle, which would think to make sense in the new market environment. Maybe reconcile this, and if there is a modest reduction in potential cash flows, is there a price adjustment possible on that deal?

Yeah, Mark, good morning, and I agree with your comments on Todd. He will definitely be missed here in the company. Look, on Heartland, we have re-evaluated the transaction in the context of the changing regulations and the market dynamics that we see in the company. It's based on all of our internal forecasting. The transaction continues to make a lot of sense. One of the key drivers for the transaction for us is our ability to use that kind of significant number of peaking assets that are part of that portfolio, which is a number that our optimization team feels good about. It's at a price that's exceptional—a price that is much lower than the kind of investment that would be required for us to get the Pinnacle asset developed and operating in the province of Alberta. So when we look on balance at the value associated with completing the Heartland acquisition, we think it's going to create a lot of value for our shareholders. We're confident in it going forward. And then just to address your ongoing question on there being an adjustment to the purchase price, we're not contemplating anything at this time under the terms of the agreement. There is a price adjustment mechanism in the sense that the effective date is the end of October of 2023. So the value of the portfolio after that date effectively has the effect of grinding down the purchase price, but we're not renegotiating the transaction or anything like that.

And where are you in the Competition review at this point? Any updated views on timelines for closing that deal?

Yes. We still think that we'll be able to get through that process within the first half of the year. Look, we are dealing with the Competition Bureau regularly. There's a regular cadence of discussion that we have. They've been responsive with us and we continue to address matters and questions that they have as we proceed. So we're guardedly optimistic that we'll be able to have a sort of complete picture on where the competition process within the kind of next month.

Okay. And then turning to the buyback, you commented you see the shares as undervalued here. You're not going to proceed with Tempest, water charger, and projects that would have put capital work this year. Is there an opportunity to push a little more aggressively on the buyback? Do you have Board approvals that go beyond $150 million? And is that something you're contemplating right now?

Yes. Look, we continually review our capital allocation approach with our Board every quarter. We just finished our Board meetings here. Look, it will be a discussion point, I'm sure that we'll be having with our Board as we proceed over the course of the year. Right now we're really comfortable with the allocation that we have. And in part, even though there is a pause on some of those Alberta projects, which were really 2024 projects, we do continue to see some opportunities that we have that we can proceed—candidly, on a contracted basis here in the province of Alberta and even from an M&A perspective. So we continue to be disciplined from a return perspective and we want to make sure that we're balanced and make the right decisions for our shareholders going forward. But we'll look at it every quarter, but we're absolutely committed to the $150 million.

So you – okay, I’ll leave it there for now. Thanks.

Thanks. One moment for our next question please. And it comes from the line of John Mould with TD Securities. Please proceed.

Good morning, everybody. Maybe just reliability is a big theme right now. And so I'd just like to ask a bit about Centralia. I think you've talked before about the gas supply constraints at that site, the fact that it's got a legislated shutdown at the end of 2025. What kind of options are you still looking at for that site right now?

Yes. Good morning, John. And actually, I really appreciate the question. It isn't something that we've spent much time talking about to focus in the market. I'm probably more optimistic about Centralia now than I have been over the course of the last two or three years. We're focusing a lot more on the Pacific Northwest, I would say, from a growth perspective. There is an increasing realization, I think, in the region that as they move forward to increase the renewable component of their generation and coal pulls back that there's going to be the need for I would say generation that can provide reliability as the energy transition takes place. So I would say we're probably—although early stages—engaged in more deliberate conversations with potential customers there about potentially reimagining the Centralia site almost as kind of an energy campus. That's sort of the term that I use internally. So imagine a circumstance where you could see a little bit of solar, maybe some storage, maybe some alternative technologies, and potentially even some peaking gas that would help to bridge the gap. This is all very early days but I would say that the momentum is better today than it was I would say six months ago in terms of the kinds of discussions that we're having. So it's not that we're going to have something to announce tomorrow. But we are actively—much more actively working on it, I would say, and more optimistic about the back half of the decade for that area. It's perfectly situated and has excellent transmission interconnections to the region. So it's a really great site.

Thanks for that. And maybe circling up on your comments about the 400 megawatts this year and targeted growth. What do you see as the best opportunities where you could make an FID? I'm just looking at your—the pipeline in your slide deck; there's a lot of potential 2024 FIDs in Australia. Is that kind of a focus? And I guess, not doing greenfield in Alberta right now, what projects are you still looking at, I guess, more on the brownfield side there? And could any of that see an FID this year?

Yes. I would say, look, we have some opportunities that we're pursuing in Alberta; they're definitely not merchant and some of them are of scale. I wish I could talk more about them, but I actually can't at this point in time. But they're not projects that have what I would call sort of merchant exposure or even particularly sort of tail exposure. So they're very much oriented towards serving the needs of industrial customers in the province. In terms of other jurisdictions, Western Australia continues to be important for us. We do have opportunities from an M&A perspective that we're pursuing. Interestingly, we are seeing better returns right now—probably from some of the contracted or actually even better, a mixture of sort of contracted and merchant—and this is not in Alberta, but in other jurisdictions, gas facilities where we end up having the ability to take the expertise that our trade floor has and our optimization team has to kind of extract more value from those assets and create higher returns.

Okay. That's interesting. Thanks a lot. And then on the power market restructuring, you've talked about the need for long-term incentives for investment. I'm wondering what you're thinking about shorter-term incentives for older operating gas. I think it's fair to say the provincial government has been a vocal supporter of gas in the power system. What kind of construct do you think is needed to keep older units online, particularly given the amount of supply we've got coming online this year and the potential for less volatility in the near to midterm?

I'll probably tap Blain, who oversees our Alberta business portfolio to give his perspective, but maybe I'll just start by giving just a few thoughts. Look, our current view is that with the kind of work that's being done from a regulatory perspective to sort of get things right; I think we would agree with the AESO that the penetration of renewables in the province, although positive in the sense of the decarbonization that's occurred, does put pressure on kind of the simple conventional market structure that we had before. I think it's going to take a bit of time for people to get confidence to make investments in the province pending the review. That means, that the assets that we have in the ground today are, from our perspective, worth more. They're actually there; they are, in many respects, de-risked—they've been built. We know how they operate. So there's very much good value there. We also think that there are many circumstances in which their generation will absolutely be needed. I think load is continuing to grow in the province I'd say pretty dramatically. The population inflow is high, industrial activity is high. And we haven't even begun to talk about data centers and AI, which is something that's still in its early days here but could potentially expand the grid. So I think in terms of the legacy assets, if I can put them that way, I think some of them are going to be required. They'll probably have lower capacity factors, but will absolutely be required. I think some of them, and we're encouraging the AESO and even the government to think about this, may require some kind of contracting—almost like an insurance policy—to make sure that they're in the market to ensure that we have reliability when we need it. Blain, I don't know if you want to add any more color to that?

No, I think that's good and it's consistent with the message that we gave at Investor Day last November, where we showed that the units definitely are needed in the market for a reliability type of stance. The work that the AESO has proposed in the short term and with the restructured energy market does have a significant focus on reliability and ensuring that there's always enough capacity in the grid and on the grid to meet load at any time. So we continue to have the discussions on what that can look like for different assets in our mix and portfolio, and we're confident that we'll find something that works for our fleet.

Okay, that's great. Thanks for all that color. I'll leave it there. Todd, thanks for all your help and support over the years and wishing you a great retirement. Thank you.

Thanks, John.

One moment for our next question please, it comes from the line of Ben Pham with BMO. Please proceed.

Hi, good morning. I also wanted to send my regards to Todd on your retirement. Thank you. Maybe just—you mentioned data centers and maybe a couple of questions on that. Do you think that there's an opportunity with your hydro in Alberta adding it with renewables to provide something similar to what the Brookfield Renewable Group is doing?

Yes. By the way, good morning, Ben. Look, I think the Brookfield transaction that was just announced is pretty impressive and really shows the kind of momentum that you can see in the sector and also their ability to execute, which again is pretty impressive. For us, our hydro fleet in the province is super high value. I mean, we tend to think of that as a premium price asset. So there's a bit of a disconnect, I think, with the kind of value or the pricing the way we optimize the fleet versus the price-sensitive nature of what we're seeing even in some of the discussions we've had on data centers. So I'm not sure that our hydro fleet is the right way to move forward. Having said that, Blain and I talk all the time about is there a way that we can provide reliable but greener generation—a mixture of our wind tied with maybe some low-emitting natural gas or even some storage to kind of shape a product that makes sense for data centers going forward. We have more work to do on that, candidly, but I think that's the way we're thinking of it at least at this point.

And I would say, Ben, people forget we have our Sarnia facility. So that provides behind-the-fence generation for a number of the industrial players in that part of the world. And that too has been—we actually have a Bitcoin mining operation that is situated there already. So many people have to skip it from the context of Alberta it's also that facility and other facilities that we have that can also be prospective for these kinds of things.

Okay, got it. And I know you announced the White Rock wind farm being commissioned with Amazon as a counterparty. Can you comment because I know I think a few years back, in a year back, you mentioned competitive management dealing with counterparties to secure contracts. Can you talk about just how the relationship with maybe Amazon has been and how you built it? Are they generally happy with the process? Could it lead to other opportunities beyond White Rock?

Yes. No, I think—and Blain, speak to this too. I mean, Amazon is happy, just like Meda as well very happy. I mean, each company has different styles and the extent of the engagement is different with each of them. But no for sure, I would say they're happy. They've got massive needs going forward, I would say Blain, but you can maybe give some color.

I mean we talk to them across the jurisdictions on their needs as they look for geographic diversity as they meet their ESG goals. They're a great counterparty that is collaborative in their approach. And we work with them across various different parts of the business, including the energy marketing group to help them as needed. It's not a one-off discussion. I mean, it's a continuing dialogue we have.

Okay. All right, that's good to hear. And maybe lastly, you've been doing the buybacks. You have the ENHANCE program. Would you consider—are you considering maybe something of a larger scale now where you can work with a deal or do something larger just given maybe a bit of a pullback on Alberta?

Yes, I mean all I can say is that we're very much committed to the plan that we set out—Todd was probably about two months ago now in terms of proceeding at this point going forward. I mean I don't want to speculate on what we do in the future, but we do look at our capital allocation with our Board continuously. And it's a constant conversation that we have with them on what are the opportunities we have, how are we returning capital to our shareholders and what's the right balance. So it's just—it's a constant conversation I would say with our company and our Board.

Thank you. One moment for our next question. It comes from the line of Maurice Choy with RBC Capital Markets. Please proceed.

Thank you, and good morning everyone. I wanted to come back to your prepared remarks that based on your early outlook—free cash flow in 2025 will be broadly in line with 2024. I assume this includes the Heartland generation assets, but can you comment on the production—power production levels that you've assumed for your legacy coal-to-gas assets that you currently own today? Differently, what would the run rate production level be for these assets moving forward?

Yes. I don't actually—so first of all, Maurice, good morning and thanks for the question. Look, when we think of 2025 and kind of the early look work that we do—and we do a multi-phased budgeting approach in the company. We do an early look, and then we continue to refine it and then we end up improving our budget in the back half of the year, but it's sort of a continual process. There's a number of things that go into that. I can tell you that we're comfortable with the hedge levels that we've got for 2025 which I think is somewhere in the 4500 gigawatt hour range kind of nudging up into that $80 range. We have a sense of what our C&I business is continuing to book and the price at which we're booking those. We're very much mindful of the impact that the new growth is that we've got in the organization, which is over $100 million of EBITDA coming into the company. And then to your point, it does include the benefit of having the Heartland generation transaction come into the company. That would be one of the base assumptions. So, do we continue to see, I would say Todd and Blain kind of capacity factors, nudging downwards? I think we probably do in terms of the generation of the fleet. I think all gas in Alberta, we tend to think of all gas Alberta as being peakers now. We don't really think of them as baseload generating units anymore. But certainly, our team could maybe cycle back with you and see what more color we could share. But we're pretty—when we put everything together and look at all the levers that we can pull, we feel pretty comfortable.

And remember we continually optimize how we actually deliver on an hour-by-hour basis. When we see a large influx of renewables, we're more than happy to use that low-priced market power in order to fulfill all of our customer contracts. So, it will be a blend of megawatts that we produce ourselves and megawatts procured to the market at very attractive prices.

Yes. I didn't talk about it. I think we feel pretty comfortable about how our hydro is expected to perform in subsequent years, both from an AS and energy perspective. It's putting together all of the pieces I think that we have to prepare for.

Maybe as a quick follow-up since you mentioned the dynamics of how some of these hedges or power prices are set. You've been able to hedge at about $80 per megawatt hour despite the recent decline in near-term forward prices. Can you provide some color as to how you think your counterparties are happy signing at premium prices like these—and what it may mean in terms of the true price signal for future years?

Yes. So look, our C&I team reports to Blain. I think people sometimes forget when we talk about our hedges; I think Blain something like 40% of our hedge position is sort of our own book; it's not sort of the financial hedges that we do in the marketplace. We have a variety of customers—it's a multiyear in many respects procurement that customers do. So they don't just necessarily look at one year. I think a typical kind of procurement would be closer to three years in terms of what we do. So people tend to look at pricing over a longer period of time, they factor in what gas prices would be; there's volatility there. I mean, they're relatively inexpensive today, but that can change and we've seen it change. It's reflective of all of the efforts that we've had in previous years in terms of setting that book at prices that we thought made sense in the context of where we thought fundamental pricing was going to be in the market. So it's a bit of an art, I think that we have. I think Blain even recently we're pretty happy with where some of the pricing is coming in our C&I book, notwithstanding, where pricing is in the market.

That's right, John. And when we look at that hedging program and customer base, which is broad and spans a lot of different industries within the province here, we really take a focus with them of being able to provide that price certainty that they need for their business. The same reason that we hedge output of our power plants is really to achieve what they need in their business, which would be—their core business isn't the widget they're producing or the whatever the customers they're serving; they need that certainty, and that's the service that we feel we're providing them.

And the chunks of contracts are from the relatively small to the pretty significant. I mean, everything from like a management hotel business to municipality. So it's quite a broad spectrum of customers that we have.

Understood. And if I could finish off with a question on capital allocation here. You mentioned that you're going to focus on US and Aussie assets versus Alberta greenfield projects. Can you help us compare the returns of these projects versus buying back shares? I know you mentioned that buying back shares is the best value for shareholders there. But maybe more specifically, is the spread between buying back shares and the returns for these projects over and how that has changed over recent months?

Yeah. Look, we think our share price is undervalued, Maurice. I mean, you and I have chatted about that before. I think if you just look at the kind of cash that we're looking at generating this year, and you look at it as a percentage of where our price is, that's a pretty good return for our shareholders right now. So do we have opportunities that are in the teens, sometimes high teens? We do. They're probably more, I would say, on the thermal side than they are on the renewable side. But given where we're trading today, we tend to think that creates a little bit of a mark in terms of I think where our shareholders are expecting us from a capital allocation perspective. So that clearly influences the way that we're thinking about deploying capital to support growth.

Thank you. One moment for the next question please. And it comes in the line of Patrick Kenny with NBF. Please proceed.

Yeah. Good morning, everybody. I guess before the new rule changes take effect here on July 1, are you pursuing any modifications to either the price cap, the supply cushion target, or perhaps any parameters around the reference unit? I'm just wondering if you had any color on what recommendations you might be making to the government before these rules take effect.

Yeah. Good morning, Patrick, and thank you for the question. I would say a couple of things. I'll turn it over to Blain to talk about one of the elements that we have more on the supply cushion regulation, which is something I think that we've been focused on going forward. I do want to—you mentioned the reference plant; we've made it pretty clear, I would say to the AESO that the reference plant that they're using to set the pricing is not at least from our own perspective, broadly reflective of what you could actually do from a commercial perspective in the marketplace today in the sense that I think the returns, the pre-tax returns that they set are lower than would need to be the case, and both the capital costs associated with developing a plant like that are actually lower than needs to be. So from that perspective, even though we don't think that the price limit is going to have any kind of a meaningful or appreciable impact given where fundamental supply and demand is in the province, we think it's low, candidly, and we've told them that. I'm not sure it's going to have any impact in terms of where things will be in terms of the interim regulation, but we think it's low. And then on supply cushion, it is something that we are looking to see if we can actually extract a bit of a change going forward. And Blain maybe I'll turn it over to you because you're in the midst of that.

Yes. So one of the conversations we're in there, Patrick, related around the supply cushion regulation and the reconstitution of pool price if long lead assets are brought online to support reliability, and they're not actually needed due to forecasting error. So it's one that creates some concern because it might reduce the price fidelity signal that we see in the market. We think that's a broadly supported change by the rest of the industry based on the conversations that we've had. And we're optimistic based on the conversations that we could maybe see some change to that one. Again, like John mentioned in his earlier comments, though, given the supply/demand fundamentals and where pricing is over the next few years while those regulations are in place, we don't think that it's a huge impact, but we just want to ensure that if we are better in those situations, the price signal remains what it should be based on the supply/demand fundamentals of the market, and not just for our fleet, but for every generator within the province.

As opposed to a misdiagnosis effectively that results in more generation being online than needed to be if you see what I was saying we're saying.

Okay. That's great. But I guess if the rule changes take effect as is, say without any of your recommendations, would you consider perhaps an early retirement of some of your boiler-converted units over the next two to three-year interim period? Or do you just—is the plan to forge ahead with no change to your maintenance capital program and continuing to keep these units available even if utilization does nudge down and you're not able to capture much in the way of peak pricing going forward?

I'd say, Patrick, we constantly assess kind of the economics associated with each of the plants and kind of the role that they play within the market both in terms of the kind of energy market that we have today and in terms of their potential role is providing reliability services that they could potentially be compensated for the province going forward, which is sort of a new area that we're exploring. Decisions that we make, I think on those plants, I'd say Blain are going to be based fundamentally on supply and demand dynamics that we see in the province and kind of the forward curve pricing—not so much the impact on the interim regulations which we really don't think are going to really influence kind of overall economics or outcomes all that much.

Okay. Makes sense. And then if I could just on the Alberta hydrology here. I'm sorry, if I missed it, but can you just walk us through how the MoU compensates for any opportunity cost or lost revenue related to managing the water supplies in the South? And then if this is sort of a temporary agreement until the reservoir levels are back to normal? Or is this more of a go-forward agreement in the years ahead as well?

So I think—the MoU doesn't really have anything in it that deals with sort of a compensation perspective. It's kind of a—think of it as an agreement to agree or an agreement to work together in a cooperative way to make sure that appropriate decisions are being made. We actually don't think it will impact the ability of our company to operate the manner in which we currently operate the hydro fleet. I think we're part of that agreement primarily because we're the carrier of the water; we are not really a consumer of the water. So I think the province is much more concerned about the consumers of water. And when we think of it, it's more in terms of a populous, sort of, industrialized water basin. It's more of the Bow River sort of in Southern Alberta that flows through Calgary—they're concerned about. There isn't one in place for the North Saskatchewan which is where Abrazo and Bighorn facilities actually are. So it's an agreement to sort of work cooperatively to make sure that as the carrier of the water, we're supportive in whatever manner needs to be the case. In terms of the hydrology, I'd say the soil is probably dry, although I think Patrick you being here in Southern Alberta, we've had a bunch of snow over the last few days. I think today is the first sunny day we've seen in quite a while. The snowpack isn't bad. It's about I would say a bit over 80% of what kind of average would be. It's kind of looking to be at least from a water perspective, broadly the same as 2023 was. And then I think it's also important to remember that the North Saskatchewan is a bit more glacier-fed. So it's challenged by kind of where is the snowpack in the moment. So when we look at kind of the way the water is shaping up in Alberta, I'd say not much different probably than last year and better than we're seeing in Washington State and certainly British Columbia, which are for sure dry, I would say.

Okay. That's great. And yeah, let's hope the wet stuff disappears this weekend. All the best in retirement to Todd. Congratulations.

Well, we like it to stick around for a bit, Patrick.

Thank you. One moment for our next question please. It comes from Chris Varcoe with Calgary Herald. Please proceed.

Good morning. John. On your decision to help the four projects in Alberta, what would it take for TransAlta to bring any of them back? Or are they permanently shelved?

Good morning, Chris, and thank you for the question. So one of them is permanently shelved, which is the Riplinger wind farm, which was a sizable wind farm kind of on the southwestern fringe of the Rockies, and it is within—I think it's a 35-kilometer exclusion zone near the amounts that have been set. So that is a project that we will not be proceeding with. The other projects are on hold; they're not canceled. The team is working to preserve them and make sure that as soon as we get the clarity that we need from the regulatory process; Blain mentioned this earlier in our call, a sense of the fidelity of the price signal as we go forward. There are things that could be resurrected and investments that could be made there; two of them are more novel. One of them is a wind farm, but it does have a merchant component to it after the contract expiry period. The other two projects were peaking gas units, which would supplement what we're looking at doing with Heartland. But the Heartland acquisition, I think, meets the need for us. And then finally, the other one was a very large storage facility west of Calgary, also merchant. We hear potential for certain types of services being procured by the province to help with the stability of the grid that could incent that project being built. But look, we're very careful with our shareholders' money, and we're not going to invest in these kinds of projects unless we have a good level of comfort that our return expectations are going to move that—and it's a little opaque right now.

Two last quick questions. Back in 2021, you mentioned that TransAlta was examining carbon capture and storage for potential adoption at Sundance 5 at some point? And I know that Heartland has the Battle River carbon hub project that is also on the books. I'm wondering right now, what are your current thoughts on the potential of CCUS in Alberta, but also the challenges to them?

Yeah. Look, I think CCUS is going to be a very important tool that our country and other countries are going to need to use to decarbonize emissions. Our view is that the best use for CCUS is in large sort of industrial, whether it's the petrochemical industry, just high emitting, but very large-scale industrial processes where there's a need to reduce emissions and decarbonize, and the kind of scale of investment required makes sense. We're a little bit leery of CCUS investments for sort of conventional power class. We think that's a bit more challenging. I think from an economic perspective—and I don't think our view has changed on that. When we were looking at the Sundance 5 project, which you rightly pointed out, we set aside, we were getting to the point where the cost of the CCUS was going to be significantly greater and also with technological uncertainty than actually the repowering was. So it's just hard to make that work from an economic perspective. There's better uses for CCUS. At least that's our view right now, pending a break subsequent.

Finally, I'm just wondering, given the changes that are going in Alberta right now in the power market, how do you view making investments in Alberta versus the United States or Australia or other parts of Canada?

Yes. I look at it this way: I would say our return expectations or the returns that you see in the markets are broadly similar in all three jurisdictions. So it's not so much because of the objective returns associated with the project; it's more for us a question of opportunity and importantly, certainty. So right now, the markets that we're dealing with in the United States, they're more I would say static and I think we have a bunch of certainty associated with making investments there. In Western Australia, we have very little merchant exposure. I mean typically, all of our assets and the full return of it on capital comes from our customer during the contract period that we have. So we don't have any of that merchant exposure after the contracted period. Is that because the remote sites, there is no other place to sell the power? So you have all of your kind of derisked economics provided during the contract period. Alberta has high growth, high income levels; we're seeing population migration, industry grow. I mean there's a lot of positive things that electrification is impacting all of these jurisdictions. It's just as we are looking to adjust the market structure in the province—it's a bit more uncertain than some of our other markets and we just need to get a bit of clarity, which I expect we will get in the coming year, two years, three years, and then we'll be able to have I think the confidence that we need to reevaluate being in this jurisdiction.

Thank you.

Our perspective is that the market needs some evolution. It's a reasonable opportunity to refine or strengthen our approach.

Great. Thank you, Carmen. 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. Have a great Friday and a great weekend. Thank you.

And this concludes today's conference call. You may now disconnect.