Transalta Corp Q2 FY2023 Earnings Call

Good morning. My name is Joelle, and I will be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation's Second Quarter 2023 Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. Thank you. Ms. Valentini, you may begin your conference.

Great. Thank you, Michelle. Good morning, everyone, and welcome to TransAlta's second quarter 2023 conference call. With me today are John Kousinioris, President and Chief Executive Officer; and Todd Stack, EVP, Finance and Chief Financial Officer. 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. It's detailed further in our MD&A and incorporated in full for the purposes of today's call. All amounts referenced during the call are in Canadian currency, unless otherwise noted. The non-IFRS terminology used, including adjusted EBITDA, funds from operations, and free cash flow are also reconciled in the MD&A for your reference. On today's call, John and Todd will provide an overview of the quarter's results. After these remarks, we will open the call for questions. And with that, let me turn the call over to John.

Thank you, Chiara. Good morning, everyone, and thank you for joining our second quarter results call for 2023. As part of our commitment towards reconciliation, I want to begin by acknowledging that TransAlta's head office, where we are today, is located in the traditional territories of the Niitsitapi, the people of the Treaty 7 Region in Southern Alberta, which includes the Siksika, the Piikani, the Kainai, the Tsuut'ina, and the Stoney-Nakoda First Nations, as well as the home of Métis Nation Region 3. TransAlta had another exceptional quarter. We're proud of the overall performance of our company and our employees. We delivered $387 million of adjusted EBITDA, a 39% increase over our Q2 2022 results, and free cash flow of $278 million or $1.05 per share, a 94% increase over Q2 2022 results on a per share basis. Both metrics beat our expectations for the quarter. Our results benefited from continuing strong power prices in Alberta and Mid-C, lower natural gas commodity prices, and the success of our asset optimization and hedging strategies. Overall, the Alberta market was impacted by tighter supply conditions resulting from transmission constraints, which limited imports from adjacent markets, supportive power prices in adjacent markets, which also lowered net imports into Alberta and encouraged exports of power from Alberta to the Pacific Northwest, periods of overlapping outages, and lower-than-normal wind resources which impacted renewable generation. We also saw significantly lower fuel costs compared to last year given lower overall commodity prices and the impact of our hedging program. The higher realized prices, coupled with lower realized gas prices, delivered higher gross margins for our portfolio compared to Q2 2022. Our overall availability was 85%. Apart from our ongoing outage at Kent Hills, our performance had weaker availability due to higher planned outages in the hydro and gas segments, which was partially offset by better performance at Centralia compared to last year. During the quarter, we delivered on a number of key priorities. Beginning with the proposed acquisition of TransAlta Renewables by TransAlta Corporation. This transaction will not only simplify our corporate structure, it will enhance our strategic position and provide alignment within our Clean Electricity Growth Plan in a manner that we believe will create value for all our shareholders. The combination will also deliver capital efficiencies and enhance cash flow predictability and diversification for both sets of shareholders while preserving the combined company's ability to realize future growth. On the growth side, our development team continues to expand our pipeline, adding another 344 megawatts of growth projects, 300 megawatts of which are renewable projects based in the U.S. and Australia, and 44 megawatts relate to a new peaker initiative that we have here in Alberta and that I'll be speaking about shortly. The rehabilitation of Kent Hills is progressing well with 27 of 50 turbines fully reassembled. Turbines are being returned to service, commissioning activities are completed, and to date, 10 turbines have been fully placed back into operation and are earning revenues from New Brunswick Power. We are now anticipating that the repair costs will increase to about $140 million as we have opportunistically expanded the scope of work to include certain blade repairs which will permit us to defer or avoid future maintenance at the site. We completed $35 million in share buybacks during the second quarter, bringing our total capital return to shareholders during the first half of the year to $71 million through the repurchase of 6.1 million common shares at an average purchase price of $11.62. Our current NCIB program was renewed in May, and we see it as a capital allocation alternative that will help us continue to enhance long-term shareholder value. And finally, with another quarter of strong cash flow, our balance sheet position is strong with excellent liquidity and cash on hand to fund our recently announced transaction with TransAlta Renewables as well as our growth projects. As you all know, a key priority for the company for 2023 is completing the construction of our contracted renewables projects. We currently have 678 megawatts of projects in the construction phase, representing an investment of $1.4 billion with approximately $1.1 billion spent to date and $300 million left to go. Our 130 megawatt Garden Plain wind farm here in Alberta is nearing completion. All 26 turbines have been assembled and we're pleased to announce that 23 units are in operation today and available to generate electricity to the grid. We expect to finalize commissioning and declare commercial operations in a week or so following resolution of an outstanding issue with the three remaining turbines. We expect the wind farm to contribute $15 million of contracted EBITDA annually, and so far, we're pleased with the performance of the turbines at the site. Our Northern Goldfields solar project in Australia is also reaching its final stages of completion. All major equipment has been installed and construction work is largely complete. Energization and testing processes have commenced. The solar facility is beginning to generate electricity and is expected to achieve full commercial operations in the second half of 2023. This project will deliver approximately $9 million of adjusted EBITDA annually. Construction at the Horizon Hill wind project in Oklahoma is also advancing well, and all major equipment has now been delivered to site. Turbine erection activities are underway, and we're pleased to report that 27 of the 34 wind turbines are fully assembled. Construction of the transmission interconnection is also underway. Although our turbine erection activities are progressing, the critical path to our schedule is the completion of the transmission line, which unfortunately is seeing some delay. As a result, we're now expecting to reach commercial operations during the first half of 2024. At our White Rock East and West projects, equipment deliveries are well advanced and the final blade sets are due to arrive in August. In the meantime, tower assembly has commenced along with the construction of the transmission interconnection. Horizon Hill and White Rock will contribute adjusted EBITDA of over $100 million annually to our company. Finally, our Mount Keith 132kV expansion project is also making progress, with the gas insulated switchgear being installed in August. The project will achieve commercial operations in the second half of 2023 and contribute approximately $7 million of adjusted EBITDA annually. These projects, along with the Kent Hills' rehabilitation, constitute the largest construction program that TransAlta has taken on in recent memory. Given the economic and construction environment we're facing, we're overall pleased with how our projects are tracking. We're only slightly above budget on our two U.S. projects and we're broadly on track with our timing for all other projects. Within our development pipeline, we currently have 418 megawatts of advanced stage generation and transmission projects that we're advancing towards final investment decisions. They represent additional growth capital of approximately $730 million. They range from wind generation at Tempest to battery storage at WaterCharger. I'm pleased to share that we've added our Pinnacle 1 and 2 projects to our advanced stage development pipeline. Pinnacle 1 and 2 will be a highly flexible and quick-ramping peaking facility in Alberta, designed to respond to volatile price environments. As renewables' penetration advances over time in the province, our expectation is that demand for fast-ramping, highly responsive, flexible supply will be needed as a complement. Our Pinnacle 1 and 2 projects will leverage our existing infrastructure and interconnection at Keephills to deliver exactly this type of capacity. The project comprises four 11 megawatt gas generating units. The engines will be connected in pairs with each pair linked to the grid independently. We expect approvals and permits to be issued in Q4 with a potential in-service date in the second half of 2025. We also continue to advance our growth pipeline. As you recall, in 2022, we added almost 2 gigawatts to our renewable development pipeline across all our regions, providing significant progress towards our longer-term goal of having 5 gigawatts of projects in the pipeline. For 2023, we have an in-year stated goal of adding another 1,500 megawatts of new sites to our pipeline to replenish our growth in the longer term. In the quarter, we added an additional 344 megawatts of future development opportunities, and so far this year, we've added 630 megawatts or about 42% of our goal. Notably, in the second quarter, we acquired a 50% interest in the 320 megawatt Tent Mountain pumped hydro energy storage project here in Alberta and a combined 300 megawatts of wind prospects in the U.S. and Australia. We see continuing strength in power prices in Alberta and Pacific Northwest. In Alberta, forward power prices for the balance of the year are trading higher as a result of continuing conditions of tighter supply, resulting from generation outages, delays in new asset entry and persisting transmission constraints that are limiting imports. We also continue to see supportive prices in adjacent markets, which are experiencing lower-than-normal hydrology. With our strong results this quarter and improved market expectations for the rest of the year, we are once again pleased to increase our financial guidance for 2023. We're now expecting Alberta power prices to settle the year between $150 to $170 per megawatt hour, about $25 per megawatt hour higher than our guidance in Q1. We're raising our expectations for adjusted EBITDA to a range of $1.7 billion to $1.8 billion, representing an increase of 17% over the midpoint of our prior guidance, and free cash flow is now expected to be in the range of $850 million to $950 million, an increase of 29% at the midpoint compared to our guidance at Q1.

Thank you, John, and good morning, everyone. I'll kick off my comments with a more detailed overview of our Alberta portfolio performance. When we announced our guidance in December, our outlook was based on Alberta power prices ranging between $105 to $135 per megawatt hour. Spot prices in the second quarter of 2023 continued to exceed our expectations, settling at $160 per megawatt hour versus $122 in 2022. Year-to-date, pricing through the first half of the year has been stronger than expected at $151 per megawatt hour, and we expect this strength to continue through the end of the year. As John noted, we now expect spot prices to average between $150 to $170 for the full year. Overall, we continue to realize higher merchant power pricing for energy and ancillary services across the merchant fleet in the first six months of the year and were able to optimize our available capacity across all fuel types. The ability of our hydro fleet to capture peak pricing was demonstrated throughout the second quarter with a realized energy price of $199 per megawatt hour, which represented a 25% premium over the average spot price and delivered a 53% stronger realized price versus 2022. Similarly, our gas fleet exceeded our expectations, capturing peak pricing throughout the quarter, with a realized merchant price of $202 per megawatt hour, which represented a 27% premium to the average spot price. Our merchant wind fleet realized an average price of $75 per megawatt hour, which is below the average price of $96 we saw last year. But on a year-to-date basis, the merchant wind fleet has realized an average price of $83 per megawatt hour, which is tracking 11% higher than what the wind fleet realized in the first half of 2022. Looking at the balance of the year for 2023, we have approximately 3,600 gigawatt hours of Alberta gas generation hedged at an average price of $102 per megawatt hour, and roughly 88% of our required natural gas volumes are hedged at an attractive price of $2.27 per gigajoule. Our hedging activities aim to mitigate the impact of unfavorable market pricing on the Alberta gas fleet, and we continue to retain a significant open position in order to realize higher pricing during times of peak market demand, which was demonstrated in our strong Q2 and year-to-date results. Our financial results for the second quarter were strong. As John noted, we generated $387 million of adjusted EBITDA and an exceptional $278 million of free cash flow. Our performance in the second quarter was led by the gas fleet with adjusted EBITDA of $166 million, a 155% improvement over last year. The gas segment benefited from expanding gross margins in the Alberta fleet through higher realized prices and lower input costs as hedged and market prices for natural gas declined significantly from last year. The hydro segment also outperformed with an adjusted EBITDA of $147 million, a 67% increase to the same quarter in 2022. Hydro benefited from strong realized pricing as well as from a 20% increase in production over 2022 levels due to higher water resources in the quarter. Higher water resources were driven by timing of the seasonal runoff and higher precipitation. The wind and solar segment underperformed quarter-over-quarter. Although we brought on new production from the Garden Plain facility, we experienced lower overall production due to pervasive weaker wind and solar resources in all regions compared to the same quarter last year. We also experienced lower realized merchant pricing in Alberta and lower environmental attribute revenue. Quarterly variability in wind resources is expected, and we remain confident in our fleet's ability to realize its long-term average production levels. Energy marketing had similar performance to last year, and in the quarter, delivered $49 million of gross margin and $43 million of adjusted EBITDA, which is another great result for the segment. Corporate costs increased by $9 million, primarily due to higher incentive accruals, reflecting our strong performance and were also impacted by higher spending on strategic and growth initiatives and from the impact of inflationary pressures. Overall, TransAlta's results again exceeded our expectations and delivered a great first half of 2023. The strong performance of our hydro fleet continues to benefit our shareholders. In the second quarter, the hydro assets generated $147 million of EBITDA and are well on track to deliver over $500 million this year. This compares to over $500 million of EBITDA in 2022 and over $300 million in 2021. Although energy production and ancillary service volumes vary quarterly, they remain largely consistent on an annual basis. This provides long-term predictability and a floor to cash flows that is unique to this asset class. In Q2, while the strong water flows increased our energy sales, it did at times limit our ability to provide ancillary services into the market from these units. This resulted in lower ancillary sales from the hydro segment year-over-year. When this occurs, we are able to backstop the ancillary service sales with our gas fleet, which we did in Q2. During the quarter, we sold approximately 200 gigawatt hours of ancillary services from the gas fleet. Realized pricing continues to be strong with a premium on spot electricity prices of roughly 25% and with ancillary services earning approximately 50% of spot prices. Together, the higher realized prices on both energy and ancillary services and higher energy flows more than offset the impact of lower ancillary service volume in the hydro segment. Before I turn things back to John, I'll turn to TransAlta Renewables to highlight key details of our acquisition announcement. As John mentioned, we are pleased to announce a path forward on our simplification efforts. We've entered into a definitive agreement where TransAlta will acquire all the issued and outstanding publicly held common shares of TransAlta Renewables. The $13 offer from TransAlta represents an 18.3% premium to TransAlta Renewables' closing share price at July 10, 2023, and a 13.6% premium based on the prior 20-day volume weighted average price of the TransAlta Renewables common shares. Each TransAlta Renewables shareholder will have the ability to elect to receive $13 in cash for TransAlta Renewables shares or 1.0337 TransAlta shares per TransAlta Renewables share or a combination of cash and shares. In each case, consideration is subject to proration, with the maximum cash consideration being fixed at $800 million and the maximum share consideration being equal to 46.4 million TransAlta shares. Upon closing of the transaction, the pro forma ownership of the combined company will be approximately 85% held by current TransAlta shareholders and 15% held by current TransAlta Renewables shareholders. The Board of Directors of each company has independently determined that the transaction is in the best interest of their company and fair to their shareholders. The transaction was also unanimously approved by the independent members of the TransAlta Renewables Board, and they have unanimously recommended that RNW shareholders vote in favor of the transaction. In terms of next steps, we expect to obtain an interim order from the Alberta Court of King's Bench, establishing the process for TransAlta Renewables shareholder approval and will mail out the Management Information Circular to TransAlta Renewables shareholders on or about August 25. The special meeting of TransAlta Renewables shareholders to consider the arrangement is expected to take place on or about September 26. The arrangement must be approved by at least two-thirds of the votes cast by TransAlta Renewables shareholders represented at the meeting and by a simple majority of the minority of public shareholders of TransAlta Renewables represented at the meeting. The transaction is subject to regulatory approvals and other customary closing conditions and is expected to close in early October. And with that, I'll turn the call back over to John.

Thanks, Todd. As I look at our strategic priorities for 2023, our primary goal is to continue delivering clean power solutions to and be the supplier of choice for customers that are focused on sustainable growth and decarbonization. In 2023, we're focused on progressing the following key goals: reaching final investment decisions on the equivalent of 500 megawatts of additional clean energy projects across Canada, the United States and Australia, and delivering $75 million to $100 million in incremental EBITDA; achieving COD on the Garden Plain wind, Northern Goldfield solar and Mount Keith transmission projects while progressing the White Rock wind and Horizon Hill wind projects to completion early in 2024; expanding our development pipeline by 1,500 megawatts with a focus on renewables and storage; completing the rehabilitation of Kent Hills wind; advancing the long-term contractiveness of our Alberta electricity portfolio; delivering permanent financing for our Oklahoma growth projects; and achieving EBITDA and free cash flow within our increased guidance ranges. I'd like to close by highlighting what I think makes TransAlta a highly attractive investment and a great value opportunity. First, our cash flows are robust and underpinned by a high quality and highly diversified portfolio. Our business is driven by our contracted wind and solar portfolio, our unique, reliable and perpetual hydro portfolio, and our efficient gas portfolio, all of which are complemented by our world-class asset optimization and energy marketing capabilities. The acquisition of TransAlta Renewables will further diversify and increase the contractedness of our cash flows. Second, we're a clean electricity leader with a focus on tangible greenhouse gas emissions reductions. This year, we adopted a more ambitious CO2 emissions reductions target of 75% by 2026 from 2015 levels and our Board has recently approved our commitment to net zero by 2045. Third, as noted earlier, we have a diversified and growing development pipeline and a talented development team focused on realizing its value. And fourth, our company has a sound financial foundation. Our balance sheet is strong and we have ample liquidity to pursue and deliver growth. Finally, our people: our people are our greatest asset, and I want to thank all our employees and contractors for the excellent work they have done to deliver our exceptional quarter. Thank you. I'll turn the call back over to Chiara.

Thank you, John. Michelle, would you please open the call for questions from the analysts and media?

Thank you. Your first question comes from Dariusz Lozny with Bank of America. Please go ahead.

Hey, guys. Good morning. Thank you for taking my question. Maybe just at the outset, I was wondering if I could get your thoughts on the announcement yesterday from the Alberta Commission that put a pause on new applications for wind and solar. I don't believe there should be much of a material impact to your pending projects in the pipeline, but maybe if you can comment on that? And maybe more broadly, how do you see this sort of impacting your longer-term plans as far as where to concentrate your development pipeline? Thank you.

Good morning, Darius, and thanks for that question. I mean, look, the impact of the announcement yesterday will be limiting, at least for a period of time, the advancement of renewable projects in the province for that six-month period while there's consideration being given to the pathways going forward. I have to say that from our own perspective, we have raised in the past the importance of making sure that we have a balanced approach to the growth that we're seeing in renewables in the province. I think if people have heard me say this before, it's like a three-legged stool, and it's critical that the grid is clean, but also reliable and affordable. And I think spending a bit of time to review, how the system maintains affordability and reliability as we begin to transition towards the lower emitting grid is critical. So, we're looking forward to that consultation process that we'll be having, that will involve the Alberta Utilities Commission. We take a long-term view on our development pipeline in Alberta, and I can tell you, it's business as usual for us in terms of trying to advance our projects here. In specific response to a couple of your questions, we don't really see it having a significant impact on our advanced stage projects. WaterCharger and Tempest have Alberta Utilities Commission approval, and we continue to advance those forward and are working hard to get them completed and announced this year. Pinnacle 1 and 2, which we've just announced, would be gas investments in the province. So again, they wouldn't be impacted by the halt. As we understand it, that is being put in place as a result of the Alberta Utilities Commission decision. In terms of where we're thinking overall in Alberta, I would say that we continue to be committed to all of our decarbonization and net zero targets. We continue to see demand for renewables in the province. We expect kind of renewable growth to continue once this review is completed in the province. We are, though, for sure, I would say, turning our minds to what other attributes the system will require in Alberta as it evolves in the coming decade and having fast response battery and some peaking capacity that can create that reliability and stability that the market will need periodically is also something we're looking at. And that's really what Pinnacle 1 and 2 are all about, along with WaterCharger.

If I could ask one more on the updated guidance for the full year. Obviously, very robust results, $200 million more on free cash flow. To the extent that the balance of the year continues to come in above expectations, is there any possibility of perhaps raising the cash contribution in the RNW buy-in? Or is it more or less set as you guys announced earlier in July, and that's how you plan on proceeding?

Yes. No. So the transaction with TransAlta Renewables is fixed. There is, from our perspective, no prospect of any change in the composition of the consideration to that transaction.

I'd just say that we are conscious that when the transaction closes, there might be some movement in shareholder interests from TransAlta Renewables' side. And so you'll notice that we did reinstate our NCIB program back in May, and so we're very much able to go out and support the stock if there is some churn.

Your next question comes from Mark Jarvi with CIBC. Please go ahead.

So just coming back to more to a couple of other questions. One, do you think this will have any impact on, I guess, the outlook for pricing or ancillary services here, if there is a little bit of a slowdown in the penetration ramp up in renewables? And then just maybe clarify, you said nothing, no impact on Tempest, WaterCharger. What about some of the, I guess, the next stage of projects like Riplinger, SunHills? And I guess the last little question would be, if they do constrain where you can site new projects, can you talk a little bit about the ability to build on existing sites, whether it's your thermal sites or legacy wind sites?

Yes, Mark, maybe I'll start with the back half of your question. Look, as we were progressing our development pipeline, the projects that were sort of next up in terms of moving through the process for us would have been Riplinger and SunHills Solar. And I think generally, we would have been looking to begin advancing approvals for those projects kind of in the back half of this year and the early part of next year. So, I would say that those projects, which we continue to work on would be a little bit delayed in terms of being in the permitting queue to get them completed. We'll see how the consultation progresses. I think there's a strong desire on part of the province to ensure reliability in the grid, which makes sense for us. That's something that we've been speaking to. And also, the notion of making sure that various stakeholders and rural parts of the province that are being impacted by the dramatic renewables growth that we've seen have been addressed. You also have to remember that our development pipeline also has an extensive exposure to projects in the United States and Australia. And we're able to accelerate and kind of move the focus of the growth that we have in the different jurisdictions. But from a long-term perspective, I don't think we're expecting much in the way of change. It's sort of business as usual. On your question on pricing, when we look at sort of 2024, the balance of 2023 and into probably even 2025, I would say, Todd, I'm not sure that we think that the announcements would have much in the way of a significant impact. There's plenty of projects that are under construction. There are some large gas plants that are looking to come in, most notably Kineticor and also the Suncor plant at the tail end of next year. So the slowdown would be projects that are still a number of years away from being able to see the light of day. So I think in terms of our near-term view, I'd say, very little impact.

And then just, when you think about some of your growth objectives or the main growth objective sort of 2 gigawatts, $3.6 billion, and you're seeing things like this maybe delay in Alberta, still some constraints on supply chain and costs, how would you frame that now in terms of your path-forward on that? If it takes a bit more time, I guess you guys seem comfortable with that. How would you sort of frame your, I guess, willingness to stick to that timeline versus just continue to be disciplined and you've got excess cash to use for the buyback? Just sort of your updated views in terms of how aggressively you push those goals, right now?

Yes. Look, I'll begin by saying that the TransAlta-TransAlta Renewables acquisition is, at least from our own perspective, a pretty significant acquisition of generation. I mean, we're acquiring kind of the economic interest in that balance, 1.2 gig essentially of generation that we didn't effectively own as a result of the structure that was there. But in terms of the incremental projects going forward, look, we're remaining super disciplined. We won't do projects until we've derisked them as much as we possibly can and are comfortable with the contractual terms. When you're looking at projects like WaterCharger that our optimization team is ready to go in terms of what they will be doing to create value for our shareholder in those projects. So, we think our targets are appropriate ones. We continue to advance them. We like our 418 megawatts of advanced stage projects that we're seeing get through. I think for us, we're just going to remain super disciplined on our capital expenditures. We're not going to pull the trigger on projects unless we're getting the kind of returns that we need for them. And we think the appropriate contingency that we have, we think prices have stabilized, I would say. I think over the last little bit, what used to be about $1.5 million a megawatt for development has inched up, I'd say closer to $2 million, but it's kind of staying around $2 million. On the wind side, we're a little bit concerned about the supply chain and kind of 25-ish, 26-ish. There's a lot of wind development that is going in place, and there's work to do for the OEMs to be able to supply all of that. But it's pretty much steady as she goes from a TransAlta perspective and always with a view of making sure, we're creating value for our shareholders. We will be at our Investor Day in November, looking to update our targets broadly speaking to the end of the decade. It's amazing how quickly time goes by. So stay tuned for that, but I don't think there'll be any surprises in terms of what our approach is going forward.

And just a follow-up that you talked about maintaining good returns. How would you frame the returns on the advanced stage projects now that you have in front as you come to a final investment decision? And I'm particularly interested to see how the returns on something like Pinnacle 1 and 2 square against some of the other projects that are in the advanced stage?

Yes. We assess each project based on the associated risk factors. We have a target hurdle rate for the company, which may adjust up or down depending on the project's specific characteristics, such as the potential for debt financing, ease of construction, data confidence, and contracting strategy. There is a scale in how we evaluate projects. For instance, our WaterCharger and Pinnacle projects are expected to yield higher returns compared to contracted renewables. This is necessary due to the merchant aspect of these projects, and our goal is to recoup our capital as quickly as possible, which leads to much higher returns. On the other hand, a project contracted for 15 or 20 years provides stability in cash flow and easier access to project financing or other debt, requiring a different assessment. I'm not sure if that provides the insight you need, but we approach it from a broad portfolio perspective. Todd, feel free to add anything else.

Well, I was just going to add look, clearly, clearly inflation is higher, underlying rates are higher. Taking that into consideration even on what would I would call the standard fully contracted wind facility on our return expectations. So I would say that return expectations are inching up and John really dove into the detail about merchant is really a whole different spectrum of return expectations.

No, that makes sense and good to hear the returns are inching up. What would you say would be the premium required? Can you quantify in terms of basis points or percentage-wise for that merchant exposure?

Let's put it this way, it's several hundred basis points higher than it would be for contracted renewables from a TransAlta perspective. So well north of 10%, put it that way.

Your next question comes from Ben Pham with BMO Capital Markets. Please go ahead.

Maybe just start on the clean electricity growth plan. Can you talk about some of the moving parts on White Rock Horizon? You talk about the timing being revised. Maybe context on the CapEx movement and a little bit of movement on the EBITDA for Horizon Hill?

Yes, Ben, you came across as pretty muted, but I think I caught the gist of what you were asking. I mean in terms of the timing on the plan, look, our advanced stage projects are probably about another 25% to 30% of the targeted EBITDA that we want. We do expect to be bringing some of those forward. We like the fact that they're in multiple jurisdictions, there's an Alberta feel to them, but also a feel in Australia, where we continue to progress things going forward. We remain confident in hitting our target in terms of getting financial investment decisions on the 2 gigawatts by the end of 2025. We are seeing appropriate returns, I think, for the projects generally. But given the inflationary environment that we see, like we're even being more cautious than usual in terms of buttoning out the cost of developing the projects and derisking them as much as possible. So that's generally the approach. Todd?

John mentioned that Ben commented on the specific issues related to delays and cost increases at Horizon Hill and White Rock. As John updated during the call, the construction of the turbines facility is progressing very well. The main challenges causing delays are related to the transmission interconnections at both sites, alongside some equipment supply issues and final interactions that still need to be addressed.

Yes. Sorry, Ben. I didn't quite catch.

No, that's okay. It's good to hear the broader view first too on that. Can you also comment on why there is snow pack in Alberta helping out that side, while we are seeing mostly drought conditions elsewhere? Is it just more of a regional difference? Additionally, could you provide some insights on how you view the resource projections given that Q2 has been quite soft, and how that impacts your approach to underwriting projects?

Well, I think we did see an early melt this year and a lot of water came through in Q2 versus some that often spills into July in our Q3 results. We saw a lot of the melts come in Q2. But we did see high precipitation in the period as well. Long term, I mean, clearly, if the melt comes in Q2, we'll have less production in Q3. But as we kind of talk through there, even though we got the extra energy in the water in Q2, it did impact our ancillary services sales. So if we get a little bit less water in Q3, then we have the opportunity to offer more into the ancillary market from the facility. Longer term, we're still confident in the long-run hydrology there and really no concerns on the long-run average production that we get from those facilities.

Yes. I mean, the kind of variability, we're seeing is kind of within the zone of what our expectations would be and what we've seen over the more than a decade of data that we have. In fact, it goes a lot longer than that. I mean, this year, we had a lot of water in June. I think Ben, as you know, we don't have as much storage as we'd like on our systems here in Alberta. So you can't actually store the water. We've got a spill it and manage the river flows as we go forward. So in light of the overall management that we do there and the constraints that we have in the facilities, to Todd's point, we ran them and there was reporting where energy was generated from the fleet rather than ancillary services, but our gas fleet picked up the slack on the AS side.

Could you clarify your thoughts on the 2025 target regarding RNW being a significant transaction? Are you implying that, on a proportionate basis, RNW has effectively allowed you to meet your 2025 targets since it included some form of M&A? Also, you mentioned during Investor Day that there is likely to be no change in methodology. Will the guidance still be provided on a gross basis or is there a possibility of reevaluating that approach?

Yes. Look, when we talk internally about what we're doing and when you look at the TransAlta Renewables acquisition, I mean, we're spending quite a bit of money for that. It is growth from our perspective. We're preserving cash flows from those assets. We're not sort of explicitly saying that check, we've made the 2-gigawatt target. We continue to advance and trying to add incremental megawatts going forward, and we're confident of moving that forward. The key criteria for us, is just making sure that the projects that we do create value for our shareholders. I mean if all we needed to do is hit 2 gigs, we could do it, but you may not get the kind of projects from the company that you'd want us to have. So we're going to stay disciplined. In terms of Investor Day, you will be seeing sort of gross. We're not proposing to change the methodology or anything like that. It will be very much as we work through it similar to what you're seeing now in terms of a long-range megawatt target, broadly speaking, an annual pathway, EBITDA targets for the company, and kind of our expectations on what the capital spend would be based on the best information we have at the time.

Your next question comes from Rob Hope with Scotiabank. Please go ahead.

I have a question about your thinking on the peaker plant at Keephills. With Kineticor, Cascade, and the Suncor project in service, do you expect that your coal to gas conversions may experience lower utilization and lack the necessary ramping capacity in a renewable-heavy environment? Is the purpose of this peaker investment to utilize existing infrastructure and interconnections to better navigate the more volatile pricing landscape?

I believe the way you've described it is quite accurate as we observe the evolution of our fleet. Our coal to gas units, which we refer to as Alberta peaking units, will operate at high capacity during certain periods, while at other times, their utilization will be lower. You've accurately identified our focus on products like Pinnacle 1 and 2 and WaterCharger, which aim to address the anticipated increase in grid intermittency and significant price volatility. Fast response products are essential for ensuring grid reliability and creating value for our shareholders. We have a range of products across our different assets, some focused on energy arbitrage, while others will offer ancillary services. In Alberta, we are considering two pathways for investment: one involves a gradual renewable build-out as the province moves toward decarbonization, and the other focuses on the necessary fast-responding capacity products to maintain grid stability.

All right. Appreciate that. And actually maybe one follow-up. You did add some hedges in '24 and '25 that looks like to be a good pricing. But overall, how are you thinking about the kind of trade-off of adding hedges in '24 and '25 versus where the forward curve is as well as just maintaining optionality?

Yes. Look, our hedging team is in there and feel, I think that the kind of pricing that we're getting in, and I'll talk mostly about '24 because '25 is a ways away and the market isn't all that liquid. But we're getting, I would say, some reasonable early liquidity in terms of 2024. I think we're seeing prices that are in the high 90s right now that are there. The team is happy with what they're seeing. They're layering on. And just you have to remember, we also have our C&I business, which is a multi-year business that provides hedging that goes out, typically, I think, on average, around three years, I would say, Todd, going forward. So we continue to do what we've always done, and that is look at our internal modeling, where we think the fundamental price is going to be, how do we derisk elements of the fleet at the same time, leaving enough open length in the fleet to be able to capture kind of the volatility that we expect will increase. I think as time goes by, it will become less about what you made in the 60% of the hours in the marketplace, but much more about how you did in that 25%, 30% of stronger hours in the market, and we're really focused on that part of the market and shifting the capabilities of our fleet to be responsive there.

Your next question comes from Andrew Kuske with Credit Suisse. Please go ahead.

I guess the first question is for John and it ties into some of your last comments there. When we look at the Alberta power market, we're having higher highs and lower lows, a very bifurcated market with maybe longer-term prices, sort of average down a bit. Some of that is reflected in your hedging program where '24 for '25, kind of flat on price, but you've got your gas hedges at a greater dollar value. Carbon prices obviously go up each year. All of that imply kind of lower margins. So I guess when you think about all that, is that kind of baseload hedging program to give business stability and certainly on a high degree of the cash flows and then you're trying to capture around it for that sort of 25% of the market where there's maybe greater volatility?

I believe you have captured the essence perfectly. That represents the mindset we have. Historically, when we discussed average hours, they were particularly significant from my perspective due to a tighter standard deviation. However, presently, the route to the average is what truly matters. Looking towards 2024, 2025, and 2026, we've had discussions on this topic with you and others in the past, and I think you have it spot on. It’s about how we can reduce risk in the base and establish predictability. This involves both revenue and cost considerations, including the gas we're buying to secure margins moving forward, along with ensuring we have a responsive structure in place to seize opportunities during market volatility, while also enhancing grid reliability in Alberta.

And then maybe just on Pinnacle 1 and 2, and if I could maybe geek out a little bit on some of the op conditions of those units. It's been a while since I've looked at them. But my recollection is sort of, like two to three minutes to full load on a ramp rate, 10 minutes for efficiency and about 8,000 heat rate. Is that all about broadly right?

Yes. I think in terms of the ramp rates that you have, you've got it pretty much bang on the mark. I think their heat rate is probably a little bit higher. But at least from our own perspective, they'll be running at times when the heat rate isn't going to matter all that much from a pricing perspective, if you see what I mean, Andrew. What really matters is the speed with which they're able to respond, and that's our focus. The other thing I would say is they were an opportunistic purchase that we made probably two years ago now. They became available on the market and in anticipation of the evolution of the market, we picked them up for pennies on the dollar, let's put it that way. So we're shipping them up here now from the Pac Northwest and look forward to advancing them.

So the pennies on the dollar, that sounds like very high ROIs.

Your next question comes from Naji Baydoun with iA Capital Markets.

I just wanted to go back a bit to the topic of growth and CapEx pressures, just seeing a bit of sort of higher dollar investments on the wind side. I guess with things like WaterCharger and Pinnacle and maybe just a function of those specific assets in that specific market, but are you seeing sort of better risk-adjusted returns on the solar storage side maybe versus wind? And if that's the case, what are some of the ways that maybe you can accelerate development on that side of the house seeing that how most of the pipeline today is made up of wind projects?

Yes, good morning, Naji. I would say if you were to kind of draw a spectrum of kind of returns, I would say that we would see probably the lower level of returns more in contracted solar, I would say, higher returns than contracted wind. And look, we have a particular expertise in wind. And for us, that's not a core part of our business. And then it gets higher in the spectrum as you begin moving towards some of the peaking gas capacity that we're looking at and then some of the battery storage that we would be looking. And I would say that even when we look at like Tent Mountain and some of the pump storage that we have, and the kind of returns we would expect for those projects would be significantly higher. We do look at it from a portfolio perspective. There is a finite amount of storage and kind of peaking gas that we would put in because what's critical, I think for those, kind of assets is to have those really strong optimization capabilities that you need to be able to extract value from them. We definitely have that in Alberta. So that is a focus for us. It's not something that is pervasive in terms of all parts of North America. So we continue to focus on, I would say, our investments still oriented towards green. You'll see the company continuing to execute on renewables as we go forward. We'll be opportunistic. I think on natural gas investments that we think we can add value to as a company. And we think that we can get acceptable risk-adjusted returns for all of those types of projects as part of the portfolio that we're building out.

I also wanted to get your thoughts on the sort of emissions credit, be it inventory or annual generation. Does that change at all with the RNW buyout either in terms of the amount or strategy? Just how are you thinking about the sort of emissions credits post-RNW?

Yes, not real big change, Naji. Renewables was typically selling the credits that have produced on an annual basis. And so TransAlta Renewables wasn't actually even carrying an inventory balance. That balance was all developed and held and strategized at the TransAlta Corp. level from both the hydro and the wind assets as well as purchased credits. So, I mean, you'll notice we are carrying a fairly large balance in there. We have a lot of internal discussions about how and when to utilize those credits. You'll see in Q2, we chose not to retire any credits and simply pay the $50 obligation from last year's production, and we'll continue to look to how to optimize that inventory level.

Okay. So no changes to the strategy then. Maybe just one last question for the hydro, again, on track for a very strong year. I think in the past, in a more normalized power price environment, I think you were talking sort of a $200 million-ish run rate EBITDA number for the hydro fleet. Is that still the right number, given what we're seeing in the market now, how the dynamics are playing out or do you think that, that number could be materially higher?

I think you're correct, Naji. Initially, when we were considering the post-PPA period and our hydro performance, we estimated the hydro run rate to be around $240 million, although that was somewhat of a guess. In 2021, it was approximately $300 million, and in 2022, it exceeded $5 million slightly. Currently, we are on track for around $500 million with the hydro fleet. However, pricing has been quite elevated in Alberta for at least the last two years. Looking ahead to 2024 and 2025, while we anticipate average pricing to decrease somewhat, we also expect significant volatility. I believe the hydro fleet will still be able to capture good economic rents. Will it reach $500 million? That’s a substantial figure. But I think the low $200 million estimate feels somewhat low as we move forward.

Yes. I think when we put those numbers out there in the $200 million range, it was really predicated on sort of the last 10 years or 20 years of the average probably in that $60 to $70 price range. I think we see a step change up from there. Carbon impact on power prices in Alberta will have a real impact somewhat through the balance of the decade, but then even into the 2030s, it will be very dramatic on the long-term power price. So, it will go up and down. But I think the trend is definitely for much stronger prices over the next 10 years than we saw in, say, the 2010s.

I believe that as the grid evolves with an increase in renewable energy sources, the value of hydroelectric power, along with its reliability and support for ancillary services in the marketplace, should rise over time. I think we are well positioned with our fleet.

Your next question comes from Patrick Kenny with National Bank Financial. Please go ahead.

John, I know you've had time to consider this, but if there is a slowdown in renewables in Alberta beyond the next six months, how might this affect the commercial dynamics surrounding the next phase of corporate PPAs in the region? Do you think there could be an opportunity in the next six months to capitalize on some of your uncontracted renewable capacity in the province?

Look, you're right, it's been 24 hours, I think, almost to the hour since the announcement has come up. And look, it's a decision that we know the province of Alberta wouldn't have taken lightly. I think they see some of the pressure points in the province and they're hearing some of the feedback they're getting from folks in parts of the province, and they want to make sure that we do this in a thoughtful way. So we completely understand that. I do think, to your point, that those projects that are through the queue, let's put it that way, like our Tempest project, I think are in a particularly good position now to be able to get PPAs and move on from a contracting perspective given their, I would say, comparative scarcity. I also am hopeful that it means that we can do more like we did with Lafarge on some of the other renewables that we have where we can get longer contracted contracts for some of our merchant renewables fleet, not so much from hydro, but certainly from the wind that we have in Alberta to be able to meet sort of the ESG and environmental goals that third parties have. As you know, Alberta is really the only truly deregulated market in the country. So the good thing about it is that there's people that are trying to meet their needs are coming to Alberta to kind of get the supply that they need to meet them. The challenge is, and I think this is what is reflecting the province's position is that, that incremental build-out isn't necessarily built on fundamental supply and demand balances within the province. And so it's a balancing act in terms of going forward.

And then I guess it's been less than a month since you announced the roll-up transaction. But just given this August performed well, I guess, validating your strategy of simplifying the story, I know the near-term priority is closing RNW here, but are there any other corporate structure optimization opportunities that you might be able to point to that might serve to keep the valuation momentum going beyond cleaning up RNW?

Yes. I mean, look, we're focused on getting the RNW transaction done in that late September, actually early October timeframe. It's a critical thing that we need to do. We're pleased that it's been well received in the marketplace. We're focused on our upcoming Investor Day, where we're going to talk about kind of our pathways going out for the balance of the decade. Our M&A team, we have a small team, but they're a very capable team. They are continually looking at the funnel. It's a very wide funnel of opportunities that arise and they see stuff that ranges from renewables in each of our three jurisdictions to alternative fuels, which is kind of new to even occasionally some natural gas opportunities that might exist. So we're still active from that perspective. Very mindful, Patrick on just the cost of things. We still find assets in the M&A market to be a bit expensive, I would say. That doesn't mean that there aren't opportunities there. I think there are. But we're going to be super disciplined and make sure that if we proceed with something, whatever we pay makes sense for our shareholders.

Your next question comes from Chris Varcoe with Calgary Herald. Please go ahead.

Hi, John. With all of the renewable projects in Alberta that have been proposed over the last couple of years, what impact do you think it's having on the Alberta market? And you talked about reliability concerns and some of the other issues. And I guess just taking a big picture, what are in the broader impact that you're seeing?

Good morning, Chris. Regarding the development of renewable energy in the province, we have a lot to be proud of in terms of decarbonizing the grid, and this journey continues. Looking back five to ten years, our emissions per megawatt generated were over double what they are now, so significant progress has been made, largely due to the transition from coal to natural gas. We have seen substantial renewable energy build-out in the province, which aligns with the current market dynamics in Alberta. As a deregulated market, and with corporate ESG requirements, there has been a strong demand for renewable energy that shows no signs of slowing down. We've been discussing the need to balance clean energy generation with affordability and reliability, particularly in Alberta but also across other areas where we operate, where similar challenges are present. On windy or sunny days, renewable generation is prevalent, but as conditions change—when the wind dies down or at dusk—this generation can drop significantly, creating volatility in the market. In Alberta, the reliance will be on gas, as we are transitioning any remaining coal to gas to ensure reliability and affordability. Furthermore, the growth of renewable energy puts pressure on transmission. Increased dispersed generation across the province necessitates investments in transmission infrastructure to deliver power to populated and industrial areas, which introduces an incremental cost we need to be aware of. Additionally, regulatory issues, permitting, supply chain challenges, and ensuring stakeholder voices are heard in regions experiencing significant development are critical factors to address. There is a lot of change happening quickly, and while we are recognizing the impacts of these developments, the province is working to create thoughtful pathways for the future, ensuring we maintain a balance of clean, reliable, and affordable energy.

Just a follow-up, sort of a two-part question here. Maybe I'll start with the first one, and that is, you mentioned the stakeholders in rural Alberta being impacted. What are you hearing from rural landowners when you're proposing renewable projects? And how are you addressing their concerns?

Yes, from the perspective of our stakeholders, there is a wide range of opinions. Our experience suggests that there isn't a single perspective when we are developing projects. Many individuals are supportive of the development because it generates revenue streams and creates economic opportunities in their areas. For instance, in Southern and Central Alberta, we are creating jobs and helping landowners earn income. The concerns that some people have are valid, particularly regarding the impact on birds and their migration, as well as the aesthetic view of the landscape. We recognize that this part of the world is beautiful, and people value maintaining that view. We take these concerns seriously, and they influence how we site our projects. We are committed to our reclamation responsibilities, having successfully reclaimed the first wind farm in Alberta, and we have decades of experience with mine reclamation. It's essential that this work is carried out properly. So, there's a range of views, from opportunities to concerns regarding the future impact of wind farms, and we aim to address all of them.

And just to ask you, what signal do you think the pause is sending to the industry? Will it impact your investment decisions? Or do you think the industry's investment decisions, such as perhaps looking at other jurisdictions because of the pause?

I believe many companies leading the way in developing the next generation in Alberta also have projects in other regions. They consider investing in multiple locations. Our company operates in Canada, the U.S., and Australia, where the development conditions and opportunities are quite similar. Therefore, location is less critical. Regarding the current pause for consultation, it's only six months. We maintain a long-term perspective on our projects. There are still numerous projects that are effectively secured and are being developed, including ours, and we are dedicated to completing them. I expect that the Alberta Utilities Commission and the government will provide a thoughtful response once the consultation concludes. I believe this will ultimately make us better developers and builders of these assets moving forward. Speaking specifically for our company, we are continuing to work on and develop the projects that were about to enter the development or permitting stage, with the goal of bringing them to realization in the long term.

There are no further questions at this time. Please proceed.

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 later today or furthering up on to next week. Thank you so much.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.