TransAlta Corporation (NYSE:TAC) Q2 2023 Earnings Conference Call August 4, 2023 11:00 AM ET
Chiara Valentini – Investor Relations
John Kousinioris – President and Chief Executive Officer
Todd Stack – EVP, Finance and Chief Financial Officer
Conference Call Participants
Dariusz Lozny – Bank of America
Mark Jarvi – CIBC
Ben Pham – BMO Capital Markets
Rob Hope – Scotiabank
Andrew Kuske – Credit Suisse
Naji Baydoun – iA Capital Markets
Patrick Kenny – National Bank Financial
Chris Varcoe – Calgary Herald
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. [Operator Instructions] 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 Metis 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, 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 renewables 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 the 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 compliment. 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 [indiscernible] 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 prices — 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.
I’ll now turn it over to Todd for further discussion on the quarter’s financial results.
Thank you, John, and good morning, everyone.
I’ll kick off my comments with a more detailed note — 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 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] (ph) 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 share 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.
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. [Operator Instructions] 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 project 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 renewables 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 — I guess, 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 constraint where you can cite 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 sort of 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] (ph) 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 coming 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 gigawatt, $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 guys seem you guys are 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 taught 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 is square against some of the other projects that are in the advanced stage?
Yes. I mean, look, we look at it as — we assess each projects in light of the sort of risk elements associated with the projects. So we’ve got like an overall sort of hurdle rate that we tend to target for the company and then it either goes down or it goes up depending on the characteristics specifically that the project has, including whether or not you can put debt financing on it, how easy it is to actually construct it, how confident we are the data, what the contracting strategy is. So it is a — you put a sort of lining scale in terms of the way we look at it.
Certainly, projects like our WaterCharger, Pinnacle type projects would be higher returning projects than kind of contracted renewables. They need to be, candidly, given that there’s a merchant component to what they have. So our focus in those projects would be to get our capital out of this quickly as we possibly can. So we expect much higher returns, whereas if you have a project that you’ve contracted for 15 or 20 years and gives you that stability of cash flow and the ability to put project financing or other debt against it, it’s a different assessment. So I don’t know if that gives you the kind of color that you need, but we do look at it from a broad portfolio perspective, I’d say.
Todd, I don’t know if you have anything else to add to that.
Well, I was just going to add look, 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 turns 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. Well, north yes.
Your next question comes from Ben Pham with BMO Capital Markets. Please go ahead.
Maybe just start of 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 Health?
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 gigs 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?
And John, so you said there was — Ben was commenting on specific issues around Horizon Hill and White Rock delays in capital cost creep in there. I think, Ben — and so as John updated in the call, that the construction of the turbines facility is going extremely well, lots of progress there and it really is the transmission interconnections I think on both sites that are really critical path in driving delays, and there’s just some equipment supply in there and then the final interactions that need to be done.
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 is the — I know there’s snow pack in Alberta, it’s helping out that side, but we’re seeing mostly drought conditions elsewhere. Is it just more regional difference? And then maybe just any comments on, how do you think about the resource projections you have in engineers with Q2 being quite soft? And how that feeds into even how you underwrite projects as well?
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 — just reporting where energy was generated from the fleet rather than ancillary services, but our gas fleet picked up the slack on the AS side.
Maybe just one last one, if I may. You mentioned in response to the question around the 2025 target, RNW being quite a significant transaction. Are you maybe suggesting that you really — like when you think about RNW on a proportionate basis, you’ve effectively met your 2025 targets in a sense, because it always was some sort of M&A in it? And then, can you confirm you mentioned around Investor Day there’s going to be probably no change in methodology. Is it going to be still going on a gross basis that guidance, or you may want to relook at that?
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, broad 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.
Just one for me. I want to think — I want to ask about conceptually, how you’re thinking about the peaker plant at Keephills. As we see Kineticor and Cascade and the Suncor project center service, is the expectation that kind of your coal to gas conversions could be seeing less utilization and won’t have that ramping capacity that will be required in a renewable heavy environment, so that this peaker investment is allowing you to use existing infrastructures and then interconnection to better meet the more volatile pricing environment?
Look, I think the way you characterized it is sort of an appropriate one as we see the evolution of the fleet. When you look at our coal to gas units, now we tend to describe them, I think you’ve heard us describe them as kind of Alberta peaking units. There’ll be periods of time where they’ll be running at relatively high-capacity factors, and there will be other periods of time that we will need them as much. But I think you’ve hit the nail on the head when you’re looking at not just Pinnacle 1 and 2, but even WaterCharger, for example, those are products that will be oriented towards meeting what we anticipate will be increasing intermittency in the grid and more significant volatility in terms of price movement. So having fast response products will be critical, I think, going forward, both to meet the reliability that the grid is going to need, but also from our own perspective to create value for our shareholders.
Different products under each of the different assets, some of them are more, what I would call, energy arbitrage assets. Some will be able to provide more ancillary services support, but we’re very much looking as it relates to Alberta kind of two pathways. One would be an overall renewable build out in time as the province continues to make its transition to decarbonization. And secondly, what are those kind of reliability, fast responding — sorry, capacity products that the province is going to need to ensure the stability of the grid. So those are the two pathways that we’re looking at from an investment perspective.
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 multiyear business which 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 an 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 think, Andrew, you’ve captured it sort of exactly right. That is the mindset. What’s interesting is, in the past, when we’ve talked about average hours, they were really meaningful, at least from my own perspective, because there was — the standard deviation around that was a little bit tighter, if you see what I’m saying, whereas now the path to the average is, what’s really going to matter. I think if you go to ’24, ’25, ’26, we’ve had these kind of discussions, I know with you in the past and others. So I think you’ve got it exactly right. It’s how do you, kind of derisk the base and create that senses of predictability and that is both a revenue item at a cost item with the gas that we’re procuring to kind of lock in margins as we go forward and then making sure that you’ve got fast responding length to be able to take advantage of the volatility when it comes and candidly, to create reliability for the grid here in the province of 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.
That’s the goal.
That’s a good goal to have.
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 RMW?
Yes, we can talk about that.
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 [indiscernible] 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?
Well, we’ve — so I think you’re right, your memory is right, Naji. I think when we were first thinking about the post-PPA period and we were thinking of our hydro performance. I think it was actually around $240 million that we were thinking the hydro run rate was going to be, and that was a little bit of a guess. We’ve seen it, I think, in ’21, it was around $300 million, and ’22, it was just a little bit over $5 million. And look, we’re tracking to another, let’s call it, $500 million here on the hydro fleet.
But we’ve had really elevated pricing, I would say, in the province of Alberta over the course of at least the last two years. If you were to sort of ask me what I think kind of the normal run rate is, I mean, we’ll see how the markets develop in ’24 and ’25. We would expect sort of average pricing to come down a little bit, but we would also expect volatility to be pretty meaningful. So the ability, I think, of the hydro fleet to capture those economic rents, I think, will remain high. Will they be $500 million? That’s a big number. But the low $200 million-s feels low-ish, I think, from my perspective as we go forward.
Yes. I think when we put those numbers out there in the $200 million-s, 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.
And Naji, I think as the grid change has been evolved with more renewables coming in, I think the value of hydro and the kind of reliability and ancillary services support that it provides in the marketplace will actually — my view is it should increase over time. So I think we’re really well positioned with the fleet.
Your next question comes from Patrick Kenny with National Bank Financial. Please go ahead.
John, I know you’ve had a whole day to think about it, but assuming there is a slowdown in renewables in Alberta beyond the six-month period here, how might this change or how much — how would you think about the commercial tension surrounding the next phase of corporate PPAs in Alberta? And do you think there might be an opportunity over the six-month period to strike while the iron is hot related to 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 provinces 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. In terms of the renewable buildout coming into the province, I mean, I think — so first of all, I would say, we have a lot to be proud of here in the province in terms, how much we decarbonize the grid. And I think that journey continues. I think if you go back, oh gosh, like probably even five years ago, certainly 10 years ago, our engines per megawatt generated in the province were probably more than double what they are today. So a tremendous amount has been accomplished and a lot of that was on the back of kind of the ship from coal to natural gas. We have seen significant renewables build-out in the province. That isn’t surprising to us given kind of the state of the marketplace here in Alberta. And as a deregulated market, particularly given corporate ESG requirements, I think there was a rush that I think continues to be demand for renewables in the marketplace.
In terms of impact, look, we’ve been talking for quite a while to here in Alberta, frankly, everywhere, because it’s similar challenges we’re seeing everywhere that we operate, about the importance of kind of aligning the importance of having clean generation with affordability and reliability. And what we’re seeing with the renewables is more, I would say, a few things. So when it’s a windy day or a super sunny day, you’ve got a lot of renewable generation that is actually in the marketplace. And then if all of a sudden the wind dies down or all of a sudden we’re getting to dusk and that we’re getting into the evening, the solar just goes away. And it’s not like it’s 50 megawatts, it’s large amounts of generation that are online offline, if you see what I’m saying. So that increases the kind of volatility that you’re seeing in the marketplace, and really, from an Alberta perspective, that’s up to our gas and I’m saying gas because a little bit of coal, we have left is going to be converted to gas to backstop that, and make sure that, that is there and in a way that is reliable and affordable for Alberta.
I think the other element with the renewable build-out is I think it does create pressure on transmission. We have more dispersed generation coming across the province and kind of building out that transmission that you need to be able to take the power where it’s being generated and move it to the populated areas or the industrial areas of the province is an incremental cost burden that we need to be mindful of.
And finally, just from a regulatory, permitting, supply chain, making sure that stakeholders in parts of the province that have seen quite a bit of development are being heard is another third factor that I think needs to be addressed.
So there’s a lot of change. It’s come relatively quickly. And we’re seeing some of the impacts of that, and I think the province is trying to just make sure that we have thoughtful pathways going forward and that the pace, I think, is an appropriate pace to maintain that three-legged stool of clean, reliable and affordable for our province.
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. I think from a stakeholders’ perspective, I think it’s very, very diverse. I don’t think there is — at least our experience would be that there isn’t a single voice or a singular view on what we’re seeing when we’re out there getting things developed. I think there is a significant group of individuals that are welcoming of the development that’s taking place in the sense of creating revenue streams for them and creating economic opportunities for people in those jurisdictions. I think of our operations in Southern Alberta and now even Central Alberta, for sure, there’s jobs that are being created and opportunity for some of the landowners to create revenue.
I think folks that have concerns, they are legitimate concerns, and we listen to them and it has everything to do with impact to birds and bird migration, bats to sidelines candidly in terms of being able to see. We live in a beautiful part of the world. So being able to have that view that you’ve always had in an appropriate way, I think, is an appropriate view and people express it. And with our responsibility to hear that out, it does impact how we cite things. It impacts where we cite them.
And I can tell you, we take the reclamation obligations that we have when it’s all done very, very seriously. And we’ve actually reclaimed the first wind farm that was built in Alberta. So we have a sense of what that’s about and returning the land to the state that it was in. We also have, as you know, years and years, candidly, decades of experience with mine reclamation. So it is critically important that, that work is done and it’s done from people that are determined to do it in an appropriate way.
So hopefully, that gives you a bit of a flavor. There isn’t a singular point. It’s everything from a spectrum of opportunity to concern about what happens at the end of the life of a wind farm and everything in between.
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?
Look, I think a lot of the companies that I think are in kind of a vanguard of building out new generation in Alberta, also have projects in other jurisdictions. So they look at deploying capital in multiple places in the yard. Look at our company, we’re in Canada, the U.S. and Australia, and the development environment and opportunity sets are relatively similar in all those jurisdictions. So to a certain extent, you’re agnostic about where you go.
I think with respect to this pause that we’re seeing to have the consultation done, it’s just six months. We take a long-term view in terms of our projects. There’s still a lot of projects that are effectively grandfathered and are being built out, including ours, and we’re committed to seeing those through. I think we’ll end up with, I think, a thoughtful response from the Alberta Utilities Commission and the government when the consultation process is done. And I think, we’ll end up being better developers and builders of these assets that they go forward.
I mean I can really speak for our company, and not on other companies, but it’s — we’re staying the course that the project that we would have been putting in the development or in the permitting queue, sort of imminently, we’re continuing to work on and develop with a view to seeing them being realized eventually in the longer term.
[Operator Instructions] 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.