TransAlta Corp
TSX:TA
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TransAlta Corp
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Good morning. My name is Sylvie, and I will be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation's Third Quarter 2022 Results Conference Call. [Operator Instructions].
Ms. Tomte, you may begin the conference.
Thank you, Sylvie. Good morning, everyone, and welcome to TransAlta's third quarter 2022 conference call. With me today are: John Kousinioris, President and Chief Executive Officer; Todd Stack, EVP Finance and Chief Financial Officer; and Kerry O'Reilly Wilks, EVP, Legal Commercial and External Affairs.
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, 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 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.
With that, let me turn the call over to John.
Thank you, Holly. Good morning, everyone, and thank you for joining our third quarter results call for 2022. 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 Stony-Nakoda First Nations as well as the home of Metis Nation Region 3.
TransAlta had an exceptional third quarter. I'm extremely pleased with the performance of our company. We delivered $555 million of adjusted EBITDA, a 38% increase over the prior period with performance significantly above expectations from our Alberta electricity portfolio. The results demonstrate the value of our strategically diversified fleet in Alberta. Our performance was driven by our ability to optimize our fleet, adjust our portfolio position to respond to changing market conditions, and deliver operational performance, which enabled us to capture the higher prices experienced in Alberta.
As a result, our financial results were ahead of expectations for the quarter. We generated free cash flow of $393 million or $1.45 per share, an 87% increase quarter-over-quarter. On a year-to-date basis, we have generated $1.1 billion in adjusted EBITDA, a 5% increase over 2021 results and free cash flow per share of $2.38, a 28% increase year-over-year.
With this performance across the fleet and our continuing positive outlook on market expectations for the balance of the year, we've revised our 2022 financial guidance upwards, increasing our adjusted EBITDA and free cash flow guidance by $295 million and $245 million, respectively, at the midpoint compared to our original guidance for 2022. We also announced that our Board of Directors approved a common share dividend increase of 10%, representing our fourth consecutive annual increase. The common share dividend will increase by $0.02 to an annualized rate of $0.22 per share, starting in January 2023.
On the growth side, our development team has added approximately 550 megawatts of development opportunities to our growth pipeline during the quarter, bringing our total development pipeline to between 3.5 gigawatts to 4.7 gigawatts. I remain confident in our ability to deliver on the remainder of our 2 gigawatt clean electricity growth plan. We have over 300 megawatts of advanced stage growth that we're working to secure in the upcoming quarters.
Switching to our recontracting activities. We are pleased to announce the award of new 5-year ISO capacity contracts at our Sarnia cogeneration, and Melancthon wind facilities in Ontario. Together with the industrial customer contract extensions we executed earlier this year at Sarnia, the ISO capacity contract extends the life of the Sarnia facility and permits us to continue to serve our industrial customers in the region.
And finally, we were active during the quarter with our normal course issuer bid. We returned another $16 million to our shareholders through the buyback of 1.3 million common shares. We've completed $34 million in share buybacks so far in 2022, and expect to continue to do so in light of the company's current share price, which we view as being undervalued.
We're proud of the progress made on the execution of our clean electricity growth plan. We've secured 800 megawatts of growth projects across Canada, the U.S. and Australia, representing 40% of our 2 gigawatt target by 2025. These projects will contribute approximately $149 million in EBITDA once fully operational, providing 59% of our 5-year incremental annual EBITDA target of $250 million. And as I mentioned earlier, we have over 300 megawatts of advanced stage generation and transmission growth opportunities in development, representing additional growth of approximately $500 million.
With the recent Inflation Reduction Act, we've increased our EBITDA estimates for Horizon Hill and White Rock to now reflect 100% qualification for production tax credits. The capital cost for these projects will also increase as bonus payments are now payable to the turbine supplier tied to the higher PTC qualification.
Turning to the U.S. We've made great progress toward our goal of expanding our development pipeline in support of achieving our 5-year growth targets. Our new projects there include 225 megawatt Trapper Valley site, an expansion of our existing Wyoming wind facility, a 152 megawatt Monument Road wind site in Nebraska, the 242 megawatt Dos Rios site in Oklahoma, and a 100 megawatt solar project, which is also located in Oklahoma.
In Canada, we continue to remain disciplined on growth. Our Tempest and WaterCharger projects are at an advanced stage of development, and we've added the 100 megawatt Red Rock wind site in Alberta to our development pipeline. We're presently reviewing the tax credits announced in the recent fall economic statement to assess how they might support our Canadian growth. In general, we view the pronouncements under the economic statement to be positive for our business.
And we're also seeing growing opportunities in Western Australia in support of our remote mining customers. We're targeting to reach a final investment decision on additional projects with BHP, and we've increased the expected size of the Gold Fields and the Southern Cross energy expansion projects in Western Australia.
I'll now turn it over to Todd to take us through our financial results for the quarter.
Thank you, John, and good morning, everyone. In Alberta, our hydro, gas and wind facilities are dispatched as a portfolio in order to benefit from baseload and peaking energy sales. And in the third quarter, the fleet generated just under 2,900 gigawatt hours of electricity.
Over the past 2 years, we've positioned our fleet to firm renewables and provide capacity and energy when needed by the grid. During the quarter, the province experienced high electricity demand driven by record-setting heat, particularly in August and early September. During the same period, planned and unplanned outages at several generators as well as outages on the transmission time lines, reduced overall supply capacity. These factors contributed to strong pricing throughout the quarter, with the average pool price for Q3 settling at $221 per megawatt hour compared to $100 per megawatt hour in Q3 of 2021.
Pool prices were also impacted by higher natural gas prices as compared to last year. Our fleet operated exceptionally well in the quarter and supplied increased electricity when it was needed most. Our strong financial performance in Q3 was underpinned by high availability at our hydro and gas facilities, which tracked at just under 98%.
Production from our gas fleet was approximately 84% hedged at $80 per megawatt hour, and the remaining merchant production realized a price of $264 per megawatt hour. Combined, the Alberta gas fleet generated $290 million of revenue, which equated to a blended realized price of $146.
The ability of our hydro fleet to capture peak pricing was once again demonstrated in the quarter with realized merchant prices of $246 per megawatt hour, which represented an 11% premium over the average spot price.
Realized price for ancillary services also increased over 2021 from $46 per megawatt hour in Q3 of last year to $128 per megawatt hour this quarter. Our merchant fleet in Alberta also benefited from strong on and off peak pricing, realizing an average merchant price of $136 per megawatt hour.
Looking at the balance of 2022, we have 1,850 gigawatt hours of Alberta gas generation hedged at an average price of $95 per megawatt hour, and our fuel requirements are fully hedged with 19 million GJs of natural gas locked in at approximately $3.60. In addition to our contracted production, we continue to retain a significant open position in order to realize higher pricing during times of peak market demand. And we see forward prices for the balance of the year in the range of $140 to $150 per megawatt hour.
Our performance in Q3 was led by the hydro fleet, which delivered nearly a threefold increase in adjusted EBITDA from $82 million in the third quarter of 2021 to $245 million this quarter. As we described earlier, the increase was driven by a combination of stronger realized pricing and higher volumes for both energy and ancillary services. Adjusted EBITDA from the Gas segment, which includes our contracted assets as well as our Alberta merchant fleet was up 26%, primarily due to high availability and stronger merchant pricing in Alberta.
Adjusted EBITDA from the Energy Transition segment decreased by $4 million year-over-year due to the retirement of the Keephills Unit 1 and Sundance Unit 4. This was partially offset by adjusted EBITDA from our Centralia facility, which improved by $20 million or 54%. Our energy marketing team's results again exceeded our expectations for the segment with $53 million in realized EBITDA.
Overall, we're very pleased with TransAlta results, which exceeded our expectations. I want to thank all of our employees for their performance in delivering one of the best quarters in TransAlta's history.
As I mentioned earlier, our results were led by our Alberta hydro fleet. Year-to-date, the hydro segment generated $394 million of adjusted EBITDA, with full year expectations in the range of $475 million to $500 million. Production from the hydro fleet was up 20% over 2021 results for both electricity volumes and for ancillary service volumes. Electricity production increased by 101 gigawatt hours and ancillary services volumes increased by 140 gigawatt hours compared with the same period in 2021.
Ancillary services volumes since the first quarter of 2021 have averaged approximately 750 GJs per quarter -- sorry, gigawatt hours per quarter, and the realized prices averaged 52% of the spot price. Energy volumes in the same periods have averaged approximately 420 gigawatt hours per quarter, with a realized premium of 18% to the spot price. While volumes and realized prices may vary somewhat period-to-period, the long-term value of hydro is significant for our shareholders.
I'm going to turn now to highlight our longer-term trends for free cash flow and EBITDA performance and the continuing financial strength of the company. Year-to-date, we've delivered adjusted EBITDA of $1.1 billion and free cash flow of $646 million or $2.38 per share. These are exceptional results, which have exceeded our original expectations, and allow us to increase full year guidance. We are well positioned to refinancing our upcoming November debt maturity. We have hedges for a significant portion of the underlying rates, and expect to complete an offering when we see a constructive opening in the bond markets.
During the quarter, we closed a $400 million 2-year term facility that we will use to support construction of the Oklahoma growth projects ahead of our permanent funding. The facility will also be used to support other funding needs as they arise.
Despite the ongoing volatility in energy markets, our balance sheet and liquidity remained very strong. We closed the quarter with $2.3 billion of liquidity, including approximately $800 million in available cash. This positions us extremely well to fund our future growth pipeline, including our 680 megawatts of projects under construction. As we've indicated previously, our 2 gigawatt clean electricity growth plan is fully funded, and we don't see the need to issue common equity to complete the program.
As John mentioned earlier in the call, with our exceptional year-to-date results and our expectations for the fourth quarter, we're pleased to increase our adjusted EBITDA and free cash flow guidance for 2022. We're now estimating our adjusted EBITDA to be between $1.38 billion and $1.46 billion, representing a 26% increase at the midpoint of the range versus our original guidance. We are also now estimating our free cash flow guidance range to be between $725 million and $775 million, representing a 49% increase at the midpoint of the range versus our original guidance. This equates to a free cash flow per share of $2.77 at the midpoint.
In addition to our estimates for adjusted EBITDA and free cash flow, we've revised our power price outlook for Alberta and Mid-C for the full year, and we've increased our outlook for gross margin in the energy marketing segment to approximately $155 million at the midpoint.
Before I turn things back to John, I'll turn to TransAlta Renewables. Our operating wind and solar assets as well as the majority of our contracted gas assets are held within TransAlta Renewables and are fully consolidated in TransAlta results. For the third quarter, TransAlta Renewables delivered $88 million of adjusted EBITDA and cash available for distribution of $46 million. Results were below expectations, driven primarily by low wind resource across all regions, the extended outage at Kent Hills 1 and 2 wind facilities and the timing of the environmental credit sales. Based on our year-to-date results, we expect R&W's full year CAFD to track towards the lower end of our 2022 guidance range.
With respect to Kent Hills, rehabilitation is well underway, including turbine disassembly and foundation demolition. About or 3/4 of the towers have been fully disassembled and over half of the foundations have been removed. Construction of new foundations has begun with the first concrete pours completed and the new wind turbine components have been delivered to replace the unit that was damaged. We're targeting the rehabilitation to be completed by the second half of 2023. Each turbine at Ken Hills 1 and 2 wind facilities will return to service as soon as its foundation is replaced and the turbine is reassembled and tested.
Liquidity remains strong at R&W for the upcoming funding needs. In addition to our $700 million committed credit facility, we had $229 million of cash at the end of the quarter.
And with that, I'll turn the call back over to John.
Thanks, Todd. As I look at our strategic priorities for 2022, our goal is to continue delivering clean electricity solutions to our customers and to be the supplier of choice for customers that are focused on sustainable growth and decarbonization.
In 2022, we're focused on progressing the following key goals. reaching final investment decisions on the equivalent of 400 megawatts of clean electricity projects in Canada, the United States and Australia. We're on track to securing another 200 megawatts in addition to the 200 megawatts already announced so far this year, with over 300 megawatts of advanced stage projects in development, achieving COD on the Garden Plain wind and Northern Goldfields solar projects, progressing construction on our U.S. wind projects at White Rock and Horizon Hill, and advancing our Mount Keith transmission expansion project in Western Australia, expanding our development pipeline with a focus on renewables and storage, progressing the rehabilitation of Kent Hill's wind, achieving EBITDA and free cash flow within our revised guidance ranges, and advancing our ESG objectives, which includes reclamation work at Highvale and Centralia, the provision of indigenous cultural awareness training to all our employees, and achieving at least 40% female employees by 2030.
I'd like to close by highlighting what I think makes TransAlta an attractive investment and a great value opportunity. First, our cash flows are resilient and are supported by a high-quality and highly diversified portfolio, as evidenced by our exceptional results in the quarter. Our business is driven by our unique, reliable and perpetual hydro portfolio, our clean wind and solar portfolio and our efficient gas portfolio, all of which are complemented by our world-class asset optimization and energy marketing capabilities.
Second, we're a clean electricity leader with a focus on tangible greenhouse gas emissions reductions. Earlier this year, we were recognized by MSCI for this leadership with an A rating. We have adopted a more ambitious CO2 emissions reduction target of 75% by 2026 from 2015 levels, and are committed to setting a science-based emissions reduction target. In addition, our focus on removing systemic barriers through our commitment to equity, diversity and inclusion and good governance shows our commitment to leadership across all dimensions of ESG performance.
Third, we have an extensive and diversified set of growth opportunities, expanding our renewable development pipeline by nearly 1 gigawatt so far this year, with a talented development team focused on realizing its value. Our execution is on track. We've delivered on that growth pipeline in 2021, and we're continuing to deliver on it in 2022.
Fourth, our company has a sound financial foundation. Our balance sheet remains strong, and we have ample liquidity to fund our growth plan.
Finally, our people. Our people are our greatest asset, and I want to thank all of our employees and contractors for the work that they have done to deliver our exceptional results this quarter.
TransAlta is an exciting point in its evolution. We focus each and every day on meeting and exceeding the targets that we set for ourselves as a leader in affordable, reliable and clean electricity generation, focused on meeting the needs of our customers. Thank you.
I'll turn the call back over to Holly.
Thank you, John. Sylvie, would you please open the call up for questions from analysts and media.
[Operator Instructions] And your first question will be from Rob Hope at Scotiabank.
First question just on allocation of capital. You've seen a significant step up in cash flow this year. How are you thinking about allocating it? We've seen a little bit on the buyback, some dividend increase. Could we see the rest to pay down debt, further accelerate the growth profile? Or could we see incremental returns to shareholders through a larger buyback?
Great question. We allocate -- the way we look at sort of the allocation of capital in the company on a deconsolidated basis. You're right. We are seeing a higher cash flow over the course of the year. We have increased our dividend. We do have a significant growth profile that's ongoing. It's almost $1.5 billion of construction, which is ongoing. And as I mentioned in the call, we continue to look opportunistically to increase the share buybacks. That's something that I expect we'll continue to do certainly into this quarter. And, again, you would expect that to be a reasonably substantial sum that we would be looking to do in terms of share buybacks.
Todd, I don't know if you want to add anything to that?
Look, I would just add that, Rob, the dividend is really focused on what I would say more fundamental long-term projections of the stability of the company, not really just the one time or the one quarter's results. So that's really just about the future sustainability of the company. As John said, we have a lot of room left on our NCIB program. And so I think certainly at the prices that we've seen over the last couple of months here, we think it's an attractive purchase.
And Rob, I'd say we're pretty comfortable with where our debt levels are. I mean, I think the credit facility we put in place and kind of our focus on refinancing the bond, we're pretty happy there.
And then maybe taking a look at 2023, just looking at where the forward curve is. We've seen you add some additional hedges out for that year. When you take a look at pricing and the dynamics in 2023, do you have a bias upwards or downwards in terms of the Alberta power market?
And I guess secondly, are you worried about any political interference of the market?
In terms of 2023, I'd say, right now, our view is that it looks to be a constructive year. I think the forward curve, the average price for the year is kind of in that $119 range, and Q1 looks strong. I think, Todd, the average price is nudging up towards $200 in that period with January and February being particularly strong and Q3 also looks good. So we expect another good year, I would say, in 2023. So we're optimistic that the company will continue to perform in a strong manner going forward.
In terms of political intervention or interference, we tend to think of things in terms of -- I think you have to take a long-term view of where pricing is in the marketplace rather than kind of looking at some of the strength that we've seen in pricing over the course of the last 3 or 4 months. It's been a circumstance driven by heat, by gas pricing, by some of the constraints, some of the outages we've had, interties. So the company has performed well. But I think you have to take a long-term view on where power prices are from a government perspective, and that's our message to the government.
I think the energy-only market works and has worked over the course of the year. And when we look at the cost of delivered power to consumers, it's as much the cost of transmission and distribution as it is the electrons.
The other thing I would say is, it is open for certainly commercial and industrial customers and even consumers at home to enter into contracts where they can kind of fix their cost for power at levels that are significantly below, I would say, where some of the wholesale prices have cleared over the course of the last few months. And so that's a lever that they can pull and that's something that we've been encouraging folks to at least to think about.
Next question will be from Mark Jarvi at CIBC Capital Markets.
John, when you look at the growth pipeline, I know you show 59% of your target EBITDA in hand here, you've got 10% in a few other projects, which could get you closer to 80%. So when you think about getting to your target in 2025, is the expectation that the internal development pipeline will get you there? Or do you think M&A is something that you lean on to get you to that 2025 targets?
I'd say really 2 answers to that question. I think we're pretty confident that it's our internal development pipeline that's going to get us there. The M&A side would be helpful. I mean, candidly, I'm encouraging the team from an M&A perspective to be more focused on transactions that would supplement our growth pipeline rather than bringing in assets to be able to achieve the result.
The other thing I would say is, look, we're reevaluating our targets as we go forward. We're very comfortable with our 2 gigawatt target. What we are seeing is the cost of construction is increasing a bit. So that $3 billion target as a practical matter, maybe drifting upwards a bit. But we are seeing returns stay in with the expectation levels that we have. So you might see the EBITDA number also in a commensurate way kind of adjust going upwards. So that's something that we're working to provide clarity. And that's something, I think, Todd, that when we come up with our guidance, we'll do a little bit of a refresh in terms of the way we see numbers going forward.
And then just a follow-up on that comment. You talked about higher EBITDA around the PTC, sharing some of that with the suppliers. It does look like the EBIT to EBITDA multiples on the build costs have come down a little bit. But obviously, it's a bit of moving parts there with tax equity and what not. So net-net, are the returns on those projects increasing? Or as you said, they're just holding flat and you're passing through the higher costs?
Mark, I'd say they're largely holding flat at the end of the day. Really just the 100% PTC treatment did get a bit of a pickup for the projects, but we did commit to share some of that upside -- potential upside, with the turbine supplier, as we mentioned.
And then just last question for me is just around, we're getting closer to or maybe some outcome on the review of tier and the CES, just updated views and impact on the markets where you guys operate?
Yes. I mean, we're waiting, and I think we'll be hearing shortly actually, in terms of where the tier outcome is, and I know that the provincial government has been working hard to land that and is in a dialogue with the [ Feds ] to be able to land that. I don't think we're expecting to see any surprises. I think we're seeing the carbon price trajectory to continue to increase certainly in 2023 into that mid-$60 range.
There is a discussion about the performance standard and how it might decline over time. These are all things that -- our expectation is that they will land broadly in the middle of the fairway in terms of what our forecasting would see. We're not expecting any surprises on those.
Yes. And I'd just like to say, like we've, over the last couple of years, tried to what I would say is somewhat immunized or soften the impacts of any tier. Any changes to tier or the environmental criteria. One of the upsides that I think we're kind of encouraged by or potentially may come out is some of the values of our renewable energy credit portfolio and what is generated off the wind and hydro fleets, which may have actually more value than what we were previously thinking. So we're waiting eagerly.
Can you just expand on that last comment, Todd, in terms of seeing more value from the credits?
Yes. Just the ability-- the potential ability, to use more renewable energy credits to offset carbon liabilities from carbon emitting facilities. And so if there's a larger demand for those credits, then we see upside in the value.
I think there is a notion that the amount of credits that could be procured to basically offset the carbon price might be enhanced or lifted a bit to create more of a balance in the demand and supply of those attributes in the marketplace, which I think, gives us uniquely an opportunity to monetize some of our inventory, so to speak, over the course of the coming years, I would say, Mark.
Next question will be from Dariusz Lozny at Bank of America.
Just maybe a little bit more high level. I was wondering if you could comment on your thoughts on carbon capture and storage opportunity in Alberta. Obviously nothing in your pipeline at present. But I'm just curious if you're thinking about that long term.
Yes. Look, I think in order for the province to get to a place where our governments are targeting it, to get to a place in terms of the decarbonization of the grid, I think we're going to need all of the above solution, which I think is going to include CCS. So that's something, I think, that's developing from a government policy perspective. We think it makes sense that they would be focusing energies around that.
Our major discussion point with the government is to make sure that they take a balanced and kind of a technology agnostic approach to the various kinds of -- or various types of generation that could facilitate the evolution of the marketplace from storage to even hydro, frankly, wind or combinations of those things. And I think they're listening to that, and we've seen that with the fall economic statement that came out and have been encouraged by what seems to be an all of the above approach in terms of incentivizing development going forward.
So the one thing with CCS that we continue to kind of assess, it's just the cost associated with it and just the technological certainty around it. So I know folks are working on those things. And hopefully, it results in something that can be realized. I think it will help us with our glide path.
One more, if I can. This one is on R&W. You guys had a couple of nice milestones in the quarter. You got Sarnia recontracted. I was wondering if you could maybe just touch upon what are the next milestones that you see, whether that be recontracting or other otherwise? And appreciate the update on Kent Hills. I was wondering if you could expand on that just a little bit. And if you have one, provide an update as to when you might actually start to turn some of those repaired turbines back on?
Yes. Maybe I'll start on the, Dariusz. Clearly, the highest priority of TransAlta Renewables is getting those Kent Hills facilities turbines back up and running. Happy with the progress so far of disassembling. The next big milestone we'll see as they start putting turbines back together and reconnecting them to the grid with new foundation. So that's priority #1. I don't think that we'll see -- although we've been having some discussions, but the intent is to disassemble and report all of the foundations and then bring in the reassembly and recommissioning.
I don't think you'll see that until close to midyear next year of when the first turbine start to come back online.
Although I would say the team is actively looking at, is there a way to kind of change the rehabilitation process to actually accelerate the time frame at which some come on, even though it might mean kind of delaying the rehabilitation of some of the turbines into the balance of the year. So we're continuing to work on optimizing that, I would say, Todd.
I think optimizing is the keyword. Like we have been focused on cost for the whole project. But if we can bring some of the turbines back on earlier, that may -- if we need to [ rejig ] the schedule, that may be the most efficient thing to do.
And then I think also for R&W in terms of growth, I think some of the Australian projects that we're working on with BHP would be another avenue that we're looking at for them. And that's something the team is working on both in Calgary and in Perth to get across the goal line.
Next question will be from Maurice Choy of RBC Capital Markets.
Maybe just sticking with the RNW theme here. John, you mentioned on the last call that you'd be looking to provide clarity on the strategies of these 2 entities. Maybe just an update on how you view this, the 2 working together in terms of growth? Or when should we expect that clarity moving forward?
No, Maurice. We are actively working on that. I had good sessions with the boards of both companies in terms of trying to provide just a greater sense of clarity going forward between the 2. And it's our expectation that we'll do so at the time that we provide guidance for both companies, which we're trying to actually accelerate with the view to potentially doing that in kind of a December time frame, I would say, Todd, which is something that we're focused on doing, Maurice. So certainly, before the end of the year, we would look to provide just clarity in terms of the positioning of the 2 companies going forward so that investors both have a better line of sight to how the future may look.
And we look forward to that. Maybe just a quick follow-up to that. Will that update also provide visibility of the drop-downs from TA to RNW? Like what assets will go?
Yes. I think it will -- there are a number of, what we're calling ROFR projects within TransAlta Renewables expansions and projects down in Australia that belong to RNW, and we'll look to provide clarity on that.
I think the answer is yes, Maurice.
And my second question is about Slide 12, which is the strong performance that you have in hydro. And in particular, I want to talk about the realized ancillary service pricing that you have. You've got 58% average over the last 7 quarters. And if my calculation is right, this quarter, our Q3 has to be strong, just under 60% realized pricing. Sharp contrast to Q2, which was up 40%. Can you speak to some of the dynamics in the quarter that saw you had this favorable capture pricing that you didn't see in Q2? And your thoughts on whether or not these dynamics will continue.
Yes. So Maurice, I think when we look at kind of what has happened over the course of the year, I'd say I'm not surprised by how we've seen the AS proceed in terms of the average price that's been realized kind of in that, call it, 50% to 60% range. I think in times where like we experienced in Q3, you had high levels of volatility, we would expect there to be a greater percentage, I would say, Todd, a higher lift in terms of the difference between the energy price and the AS price.
And at times when there is less volatility, even though the average price might be reasonably high, you'd expect it to be -- you think of a sliding scale more on the left side of the scale as opposed to the higher right side of the scale. I think the relationship holds, and it's primarily, I think, driven from a volatility perspective. When the market is tight, I think AS is super valuable, and we'll see it swing that way.
Todd, I don't know if you have any color on that, but at least that's the way I think of.
No. It is all predicated on actual volatility. $120 prices be derived in a couple of ways. It could be prices between $100 and $140 average out to $120, or it could be prices between 50 and…
$250, that's right.
And in that latter case, that's when you really get to pick off the volatility and the higher prices, and you see it in the ancillary services market as well as in the energy market for hydro.
And you saw it in terms of the demand in the quarter, I would say, Maurice, as well, where just about, I think it was 800 gigawatt hours of AS that was basically delivered by the company, whereas our I think, a more typical run rate would have been about 50 gigawatt hours, less than that, typically, I think, over time, more in that $750 million range. I think, Todd, you even mentioned that in your notes.
Right. And maybe just one more thing is that we've seen it pan out over the course of the summer and even here into Q4 where the renewables are having a massive impact on that volatility where if it's sunny and windy, prices are trading in that $60 to $80 range. And as soon as we start to see the sun disappear or the wind drop off, prices jump up $50, $60 minimum in that period. And so that volatility around the renewables is just going to get bigger over time.
Yes, I'd say it's directionally positive for the need for AS and the value of the hydro fleet, Maurice.
Sounds like the 52% average over 7 quarters. That's probably something that is quite sustainable moving forward, although I appreciate…
That would be our view.
Next question will be from Andrew Kuske at Credit Suisse.
Maybe a kind of narrow question, but a broad question at the same time. Could you maybe give a refresh on just the terms of the Brookfield deal as it relates to the percentage of ownership on the hydro plants? I asked just in part given the hydro performance that you put up this quarter. And I think at the time of the transaction, there was a cap at 49%, but you're predicating everything really on a 30% to 33% ownership stake.
And now I've got to go back into the depth of memory for all of that. But effectively, the way the transaction works is our hydro fleet is valued on the basis of 13x EBITDA with a fixed amount of sustaining capital deducted from that, which, if memory serves, is $15 million a year in terms of the set price that we've done. And we do a 3-year average to figure out what they would get. So they're $750 million investment.
What percentage of $750 million of that 13x that 3-year average EBITDA of the hydro performance over time. And then they do have essentially 2 top-up rate. One is a 10% top-up rate, provided TransAlta's VWAP at the time is over $14 a share, and they do have the ability to increase that ownership stake up to 49% if TransAlta is trading over $17 a share at that time. I think there's also the ability to be able to go up to 25% in the event that their ownership stake is significantly below that. They wanted to be able to have a meaningful ownership stake if it fell to a relatively de minimis level.
So I think that's in a nutshell, I think, all of the levers that kind of surround the transaction. Does that help? Sorry, go ahead, Todd.
Yes. Andrew, you mentioned the 30% level. That was really predicated on EBITDA from the hydro facility potentially being in that $200 million to $250 million or $225 million to $250 million range. This year is a year that sort of goes towards that 3-year average, and we'll be pushing $500 million of EBITDA this year. So that percentage ratio will change accordingly should they choose to exercise their option.
If I could maybe ask a follow-up question just on the government economic update that came out last week. And if you had a hypothetical facility with the same returns on both sides of the border, the Canada-U.S. border, what legislative framework do you think you would allocate capital into? Would it really be IRA, or is there enough sort of meat on the bone in Canada now to attract capital?
Yes. I -- look, I think the economic update that the federal government did was really constructive. And I do think it was directed at basically levelizing the playing field. So what really drives us right now is really the opportunity set, I would say. I would say the drag, let's say, on a Canadian investment has largely been kind of taken away. The other thing I would say is that -- and folks sometimes forget this, we tend to view the policy environment in both countries now as being something that is oriented at increasing demand more than actually at the end of the day, helping our returns, and I'll explain what I mean by that.
A lot of people just kind of think -- the ITCs come in, that's a gain that the company gets. I think sophisticated buyers understand what that means for the returns of the developer, and then they recalibrate the PPA prices to assess with that at an appropriate level of return given the risk that's being taken. So I think people shouldn't be thinking of it in terms of a windfall that people will be getting. I think it's more oriented to ensuring that there's a continuing drive and appetite to bring the renewables on or whatever program they're developing, if that makes sense.
Next question will be from John Mould at TD Securities.
Maybe just going back to your priority slide and the reference to securing long-term contracts for the Alberta merchant fleet. Can you just clarify, is that more a reference to the mid-term customer contracts that form part of your hedging number or more kind of one-off merchant wind PPAs like what you did with [ Exshaw ] or some mix in between?
It's actually both. John.. I'm glad you raised that. It is actually both. We do -- as you know, the market in Alberta, the forward market in Alberta has limited liquidity. So when we think of our C&I business and we think of our total hedging levels, a pretty big component of that is based on our C&I business, especially the fixed price component rather than the flow component of the C&I business, which tends to be, Todd, probably 2 to 3 years would be kind of the average tenor of those.
In tandem with that, as you know, we've got quite a bit of merchant win, for example, in Alberta. And even at times, we have discussions with people on hydro, if there would be something that we would be willing to do to help shape on hydro that would provide kind of medium term or even longer-term contracts like you saw with Lafarge, that we would have done earlier in the year. So it's really both. We do see a critical component of our hedging program in Alberta as requiring what I would call outside of financial market hedging. So it is both. And the team has targets around both. We drive them from a gold perspective in terms of what they're trying to do.
And maybe just to follow up on that quickly because you mentioned hydro. I mean is some sort of offtake for hydro really achievable, just given the benefit that you got in quarters like the past one where between AS and energy -- I guess, maybe AS you would still pretty be -- but there's exceptional benefit for TransAlta, that PPA price would have to be pretty high for that deal to get done. Is that a fair way to think about it?
I think it is. I think people kind of gravitate -- the ask often gravitates to the hydro ,and the response is typically, you have to understand that is a premium product given the relative scarcity and the role that it plays here in the province. So the way to think of it is exactly the way you've articulated, and it's part of the portfolio that we try to keep open, frankly, for exactly the reason that we saw in the last quarter.
And then maybe just pivoting into Ontario. The [ ISO ] is going to procure 4 gigawatts of capacity, including up to 1.5 gigawatts of gas, you qualified for the first long-term RFP not that expedited round, I believe. What investments are you considering? Are you looking at batteries? Would you look at any investments in gas beyond batteries such as enhancements of [ uprates ] or maybe even new units just given that 1.5 gigawatt slice? Or are you really not looking at new capital in meaningful, I should say, new capital in gas at this point?
Yes. It's a real active discussion right now, I would say, in the company, John. And look, what we've said is we're -- our growth is primarily focused on renewables. But when we see a gas opportunity for an existing client -- and clearly, the ISO is an existing client in the province of Ontario -- it's something that we would consider. So although it's early days, we are turning our minds to what some kind of participation might consist of -- particularly when we look at the footprint that we have kind of in that Sarnia, Windsor area.
So nothing definitive yet, but we're definitely looking at it, I would say.
[Operator Instructions] And your next question will be from Naji Baydoun at IA Capital Markets.
Just wanted to go back to the topic of capital costs and net returns. You mentioned that the returns are relatively flat given the different moving pieces. I'm just wondering if you can give us a refresh of where you see IRRs in the different markets and maybe that would kind of outperform, or you mean to invest a bit more in one jurisdiction more than another?
We -- look, we continually look at what our hurdle rates are and we tend to focus on IRRs being one of the key factors that we look at. And frankly, we really focus on contracted period, IRRs. I think what we're seeing is in terms of the opportunity sets that we're pursuing, notwithstanding some of the, I would say, near-term inflationary headwinds that we're seeing in the marketplace is the returns were kind of hanging in. And I think when we think of that, I think, Todd, it would be sort of upper single-digit returns if we can get to a double-digit return.
And I'm just talking about the base transaction without a fact adding any of the benefits that we can by optimizing it, whether it's everything from an operational perspective to the way that we're financing it to whatever we do, continues to be, broadly speaking, I think what we're looking at. I don't know if that answers your question. Todd, if you have any perspectives.
And I think we're seeing it very similarly -- just the last point. In each of the 3 jurisdictions that we operate in, I don't think we see a huge difference between sort of Canada -- certainly the return environment, I'd say, Todd -- Canada, the U.S. and/or Australia at this point. It's pretty similar.
They're all very similar in geographies on rates of returns. And as we kind of talked about a little bit before, we see the best returns coming from the greenfield field development of field development sites that we have. We're still active in the M&A market. We do look at a lot of transactions. And I would say we haven't actually seen a reduction in prices or multiples being paid for M&A transactions, which seems disconnected from where we've seen the underlying interest rates move and where we can see inflation move. Now maybe that's a short-term issue, and we'll start to see a little bit more rational investing on the M&A side, but that's really what's been leading us towards the greenfield development side.
And just to kind of close the discussion, I mean the way we would look at returns is, we do focus on it from a risk-adjusted perspective. So a very long tenure PPA from a AA-rated offtaker would be viewed differently from the company as something that would be shorter in tenure, has a larger merchant tail in terms of what you're looking at, and has credit worthiness that isn't the same as the other party.
The other area that we look at would be just the market dynamics in terms of where the project is. And that's particularly with the view of the merchant period. Is it constructive and one that is based on supply and demand fundamentals? Or is there some distortion in the market that concerns us? So it's a bit of a judgment call that we make with our Board when we move forward.
And I guess maybe to take that to the next sort of step when you think about updating your sort of the outlook for 2023, you talked about maybe refreshing the strategy for RNW. But just given where you are on your targets, I mean, it would seem like $250 million of incremental EBITDA is very conservative. Is that a number that you think you'd also update shortly?
You mean for balance of 2022?
No [indiscernible].
I think it's -- Yes, the 2 gigawatt growth program, that's targeting $250 million of EBITDA. We're 55% of the way through that. We're at about $150 million of the $250 million. So I'm not sure that's going to be part of our guidance in December that we'll be readdressing that.
No. But -- Naji, sorry, I misunderstood your question. Ideally, I would like to see if we could actually update what we actually think those numbers are going forward. And my current expectation is that 250 number would increase, right, because the returns are holding, yet the cost of capital to build out some of the pipeline is increasing.
So we would expect the return rate to be holding, but both of those numbers to kind of [ lift ] as time goes by if that makes sense.
Yes, exactly. Because I mean, just based on what you've achieved that $300 million would seem more like an achievable target, but we'll wait for that update in due time. I Just wanted to ask more questions. Just on the buybacks, you mentioned maybe being a bit more aggressive on the buybacks in the short term. Is that even with the increase in the share price today? I mean you bought stock at around $12.5. Shares are going to be above that today. Does that change at all your view on buybacks?
Look, we're always opportunistic on our share buybacks when we see the share price trading below. I mean last time, it dropped low $13 level after Q2, and we thought that was a good opportunity to purchase. So look, we'll just play it by year, and we'll look for opportunities to support the shares.
So I take it -- below 13% is a no-brainer and above that it depends on what else is on the table. Just one more question…
I would say, based on where it's currently -- I think based on where the share price is currently trading, I think people can expect us to do more share buybacks.
So just a final question on Garden Plain. Any updates on Pembina's decision to exercise their option there? And is that option, if you can just remind us, is it only exercisable at COD? Or is there a sort of a longer time line associated with that?
No. I think it is basically exercised at COD. And as I recall, it's for 30% of their proportion of the wind farm, 30 megawatts of the 100 megawatts of the 130 megawatts.
It's 50 megawatts of the 100 megawatts that they have the rights to purchase, which works out to about 40% of the facility.
And no update from them in terms of where they are in that process.
Next question will be from Patrick Kenny at National Bank Financial.
Just on your Alberta Gas portfolio, I know you've layered on a few more near-term hedges through 2023. But I'm just curious, given the volatility experienced in the quarter, if you're starting to have more conversations with the industrial power consumers in the province and whether or not there's any increase in appetite with respect to entering into long-term fixed pricing contracts such that you might be able to convert some of your Alberta merchant gas capacity to more of a fixed price, long-term contract with some of these larger high creditworthy counterparties.
Todd, do you want to --?
Well, I was just going to say, look, the C&I business is actively out there looking for transactions. And John mentioned average terms of 2 to 3 years, but we do stretch out into 5 year terms with a number of counterparties for supply. That really forms part of our hedge portfolio. In addition, we do have a long-term contract that starts in November of next year, that was originally intended to go with our Sun 5 projects that we -- it's 200 megawatts, 220 megawatts that we can apply to the CTG units as well. So I think we have a lot of underlying and always looking to add to that portfolio.
But I would say, Patrick, that the bulk of the discussion that we're seeing, I mean, the interest is primarily around the renewables, I would say, much more than it is around the existing natural gas portfolio that we have. And I think that difference in discussion is pretty significant between the 2. They are much more oriented towards the renewable side than it would be the gas side.
And then maybe just a follow-up on the Alberta Hydro question earlier. And assuming Brookfield does end up with only a 25% ownership stake in the assets versus the original expectations of 30% to 35%. Curious if you might lean towards crystallizing that bonus 5% to 10% stake, so to speak, either by selling that portion of the capacity on a long-term contracted basis or perhaps just selling at that equity stake to a buyer looking for environmental attributes, but just either way to shore up the balance sheet further and accelerate other contracted renewable opportunities.
I'd say there's no discussion or contemplation of doing that at this point, Patrick. I think we feel pretty comfortable with kind of our balance sheet strength and the cash flow that's being generated from the business, and sort of the way we're phasing in our clean electricity growth plan. So right now, I don't think we're looking at doing anything.
And it's very early days here. I mean, they have several years yet before the option even is able to be exercised. So early days.
Next question will be from Chris Varcoe of Calgary Herald.
This is a question for John. John, can you give us an update on where the company's examination of carbon capture projects and the potential for it might sit in with TransAlta? I believe last year, you talked about the potential or examination of it at least with regards to Sundance 5.
Yes, Chris. So we made the decision last -- not last summer, but it's the summer of July of 2021 -- not to proceed with our Sundance 5 project at that time. And that was due to a number of reasons, everything from sort of the regulatory directions that we saw going into supply and demand dynamics, increasing costs, and some of the technological uncertainty that we were seeing with carbon capture and storage. So we made the decision not to pursue the Sun 5 repowering. And as a consequence, carbon capture and storage isn't sort of a primary focus for the company going forward.
Our growth focuses far more on renewables at this point and particularly wind, which is a strength of ours, but storage and solar factor into that. We'll be opportunistic on natural gas serving customers that we have. But, although we watch CCS and look to see how it's developing from a technological perspective, it isn't a core focus for our company at this point in time.
Just a separate question is the COP 27 conferences began this week. I guess I'm curious what stance do you want to see the governments of Canada and Alberta take at the Climate Conference? And what, if anything, will you be watching for as a company to come out of that?
Yes, it's interesting. We actually have -- one of our colleagues will be attending and speaking at the conference early next week, I think it is -- Look, we think that climate change is a real factor that we all need to deal with. We're looking to see that the federal government continues to have the kind of commitment it has to have in Canada to reach it. It's carbon production and emissions reductions targets and are more looking at kind of how policy is developing domestically, which is why the pronouncements under the fall economic update were so critical for our industry.
And then from an Alberta perspective, we're looking at how the province is also looking to evolve the generation in the jurisdiction to make sure that the grid is greening as we go through and creating some of the room for the oil and gas development, that is the core for our province and the standard of living that we have here in Alberta.
We -- It's more of something that we're looking at, I think, broad long-term directions and how things are evolving. We're looking at, for example, cross-border credit trading and whether there's alignments around those kinds of things as we move forward because that's something that's of value to us. And when we look at other potentially important business lines that we can go to, it's sort of an early -- it's sort of a precursor to those kinds of things taking place. But our real focus is on domestic policy in the U.S., in Canada and in Australia.
So it's more of a forum where we look to where the future might be going rather than looking at kind of our immediate investment decisions.
Finally, just a follow-up on a question that you'd referenced a little bit earlier. This is regarding the green credits within the fall economic update. And I just want to be clear here. Will -- the provisions that are included in that update, will that impact your spending decisions in Canada versus making a similar kind of investment in Australia or the United States?
I think it definitely makes investments in Canada more competitive with the portfolio of investments that we're looking at in the U.S. and in Australia. I think for our company, we're much more focused on kind of the maturity of the opportunities that we have, Chris. So when I look at kind of our development pipeline and kind of the phasing or the sequencing of those opportunities, it's more Alberta focused right now or Alberta heavy, I would say, right now, and to a lesser extent, Australia focused.
We're working to build a bunch of stuff that we've procured in the U.S. But when I look at kind of our newest projects, that will come to be -- it's really Alberta and to a lesser extent, Australia. And certainly, the government policy is helpful in terms of the way we're looking at things for sure.
Thank you. At this time, we have no further questions. Please proceed with your closing remarks.
Thank you, everyone. That concludes our call for today. If you have any further questions, please don't hesitate to reach out to the TransAlta Investor Relations team.
Thank you. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending. And at this time, we do ask that you please disconnect your lines.