TransAlta Corporation (NYSE:TAC) Q3 2022 Earnings Conference Call November 8, 2022 11:00 AM ET
Company Participants
Holly Tomte – Manager of Investor Relations
John Kousinioris – President and Chief Executive Officer
Todd Stack – Executive Vice President of Finance and Chief Financial Officer
Kerry O’Reilly Wilks – Executive Vice President of Legal, Commercial, and External Affairs
Conference Call Participants
Robert Hope – Scotiabank
Mark Darby – CIBC Capital Markets
Dariusz Lozny – Bank of America
Maurice Choy – RBC Capital Markets
Andrew Kuske – Credit Suisse
John Mould – TD Securities
Naji Baydoun – IA Capital Markets
Patrick Kenny – National Bank Financial
Chris Varcoe – The Calgary Herald
Operator
Good morning. My name is Suvi 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. 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]. Ms. Tomte, you may begin the conference.
Holly Tomte
Thank you, Suvi. 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 we have posted on our website. A replay of the call will be available later today and the transcript will be posted to our site shortly thereafter. All of 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 purpose of today’s call. All amounts are 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 quarters result. After these remarks, we will open the call for questions. With that, let me turn the call over to John.
John Kousinioris
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 the 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 home to the Métis 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 midpoints 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 shared 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 two 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 re-contracting activities. We’re pleased to announce the award of new five 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 we 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 two gigawatt target by 2025. These projects will contribute approximately $149 million in EBITDA once fully operational, providing 59% of our five-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 and 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 costs 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 five year growth targets. Our new projects there include 225 megawatt Trapper Valley site, an expansion of our existing Wyoming wind facility, 152 megawatt Monument Road wind site in Nebraska, the 242 megawatt Dos Rios site in Oklahoma, and 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.
Todd Stack
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 two 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 timelines, 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 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 lead 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 version 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 90 million GJs of natural gas locked in at approximately $3.60. In addition to our contract in 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 three-fold 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 teams 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, or 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. Well, volumes in 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’re 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 the $400 million, two-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 two 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 on 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 RNWs full-year CIF-T 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 three quarters 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 Kent 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 our MW 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.
John Kousinioris
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 Hills wind, achieving EBITDA and free cash flow within our revised guidance ranges, and advancing our ESG objectives, which includes reclamation work at High Vale 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 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 businesses 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 reductions 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 a 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. Turns out as 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.
Question-and-Answer Session
Operator
Thank you, John. [Operator Instructions]. And your first question will be from Rob Hope at Scotiabank. Please go ahead.
Robert Hope
Good morning, everyone. First questions just on allocation of capital. We’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 buybacks, some dividend increase? Could we see the rest to pay down debt further accelerate their growth profile? Or could we see incremental returns to shareholders through a larger buyback?
John Kousinioris
Yes, good morning, Rob. Great question. We allocate the way we look at sort of the allocation of capital in the company on a D consolidated basis. You’re right, we are seeing a higher cash flow over the course of the year. We’ve have increased our dividend, we do have a significant growth profile that’s ongoing. It’s almost a billion and a half dollars 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 will 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?
Todd Stack
Look, I would just add that Rob, the dividends 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 with the company. 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 that we think it’s an attractive purchase.
John Kousinioris
And Robert, 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.
Robert Hope
All right. Appreciate the color there. And then maybe taking a look at 2023. Just looking at where the forward curve is, we’ve seen you. We’ve seen you had 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 in the market?
John Kousinioris
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 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 that the company will continue to perform in a 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 three or four months. It’s been a circumstance driven by heat by gas pricing by some of the constraints, you know, some of the outages, we’ve had inter ties. So the company has performed well, but I think you have to take a long-term view on where power prices are from an entry 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 is 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 costs 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 you know, so that’s a lever that they can pull and that’s something that we’ve been encouraging folks to at least think about.
Robert Hope
That’s it for me. Thank you.
Operator
Thank you.
Robert Hope
Thanks Rob.
Operator
Thanks, Ron. Next question will be from Mark Darby at CIBC Capital Markets. Please go ahead.
Mark Darby
Thanks, John, when you look at the growth pipeline, you know, we show 59% of your target EBIT. In hand here, you’ve got Tempest and a few other projects, which could get you closer to 80%. 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’ll lean on to get you to that 2025 targets?
John Kousinioris
Good morning, Mark. I’d say really two 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, may be 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 kind of adjust going upwards. So that’s, that’s something that we’re working to provide clarity. And that’s something I think, Todd that when we come up with their guidance, we’ll do a little bit of a refresh in terms of the way we see numbers going forward.
Mark Darby
And then just to follow-up on that comment, you talked about higher EBITDA on the PTC sharing some of that with the suppliers. It does look like the EVD EBITDA multiples on the build costs have come down a little bit, but obviously, it’s a bit long moving parts here with tax equity, whatnot. So net-net, are the returns on those projects, increasing, or as you said, they just holding flat and you’re passing through the higher costs?
John Kousinioris
Yes, Mark, I’d say they’re largely holding flat at the end of the day, really just the 100 100% 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.
Mark Darby
Okay. And then just last question for me, it just around, we’re getting closer to some at some outcome on the review of Tier and a CS just updated views and impact on the markets where you guys operate?
John Kousinioris
Yes, I mean, the — we’re waiting, and I think we’ll be hearing shortly, actually, in terms of where the tier outcome is that I know that the provincial governments 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 — excuse me how it might decline over time. I — these are all things that that our expectation is that they will land broadly in the middle of a fairway in terms of what our forecasting would see. We’re not expecting any surprises on those.
Todd Stack
Yes, and I just like to say like, we’ve over the last couple of years tried to what I would say is somewhat immunize or soften the impacts of any tier, any changes to tier or the environmental criteria. One of the upsides that that I think we’re kind of encouraged by or potentially may come out of some of the values of our renewable energy credit portfolio. And what do you think underrated? Let’s generate off the wind and hydro fleets, which may have actually more value than what we were previously thinking. So we’re waiting eagerly.
Mark Darby
Can you just expand on that last comment Todd in terms of see more value from the credits?
Todd Stack
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 than we see upside and value.
John Kousinioris
I think there’s the 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.
Mark Darby
Okay. Thanks, John. Thanks.
Operator
Thank you. Next question will be from Dariusz Lozny at the Bank of America. Please go ahead.
Dariusz Lozny
Hey guys, good morning. Thank you for taking my question. Just maybe a little bit more high level. I was wondering if you could comment on thoughts on the carbon capture and storage opportunity in Alberta? Obviously, nothing in your pipeline at present. But just curious where you are taking about that long-term?
John Kousinioris
Yes, I — look, I think in order for the province to get to a place where you know, 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 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 governments to make sure that they take balance 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 had 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’ll help us with our glide path.
Dariusz Lozny
Great, thank you for that. One more, if I can. This one is on RNW that you guys had a couple of nice milestones in the quarter, you got Sarnia re-contracted, I was wondering if you could maybe just touch upon, what are the next milestones that you see whether that be re-contracting or 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?
John Kousinioris
Yes, maybe I’ll start on that, Darius. 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 foundations. So that’s priority number one. 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 mid-year, 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 timeframes in 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.
Todd Stack
I think optimizing is the key word 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.
John Kousinioris
And then I think also for RNW in terms of growth, I think some of the Australian projects that we’re working on with BHP would be another avenue that 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.
Dariusz Lozny
Okay, great. Thank you guys very much. I’ll turn it back here.
John Kousinioris
Thanks so much.
Operator
Our next question will be from Maurice Choy, RBC Capital Markets. Please go ahead.
Maurice Choy
Thanks and good morning. Maybe just sticking with the RNW theme here. John, you mentioned in the last call that you’d be looking to provide clarity on status of these two entities. Maybe just an update on how you view this, the two working together to in terms of growth, or when should we expect that clarity moving forward?
John Kousinioris
Yes, no, Maurice. Good morning. 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 two. 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 a view to potentially doing that in kind of a December timeframe, 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 two companies going forward so that investors both have a better line of sight to how the future may look.
Maurice Choy
That’s great. 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 RNW like what assets will go?
John Kousinioris
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, the [indiscernible] RNW and we’ll look to provide clarity on that.
Todd Stack
I think the answer is yes.
Maurice Choy
My second question is about Slide 12, which is the strong performance that you have in Hydro. And particularly I want to talk about the realized reservice pricing that you have, you’ve got 58% average over the last seven quarters. And if my calculations right this quarter in Q3, you have had strong just under 60% realized pricing, sharp contrast to Q2, which is sub 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?
John Kousinioris
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, 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, if you have any color on that, but at least that’s the way I think.
Todd Stack
No, it is all predicated on actual volatility, $120 prices can 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 in the higher prices. And you see it in the ancillary services market, as well as in the energy market for hydro.
John Kousinioris
And you saw it in terms of the demand in the quarter, I would say, Maurice is well aware, we had 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 550 gigawatt hours. Less than that, typically, I think over time, more than that 750 range, I think, Todd, you even mentioned that in your notes.
Todd Stack
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 to $50, $60 minimum in that period, and so that that volatility around the renewables is just going to be getting, get bigger over time.
John Kousinioris
So I’d say it’s directionally positive for the need for AS and the value of the hydro fleet, Maurice.
Maurice Choy
It sounds like the 52% average was seven quarters, that’s probably something that it’s quite sustainable moving forward. Although I appreciate.
John Kousinioris
Yes, that would be our view.
Maurice Choy
Okay. Great. Thank you.
Operator
Next question will be from Andrew Kuske at Credit Suisse. Please go ahead.
Andrew Kuske
Thanks. Good morning, 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 just in 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 were predicating everything really on a 30% to 33% ownership stake?
John Kousinioris
Yes, so good morning, Andrew, happy to do that. And now I’ve got to go back into the depths of my memory for all of that, but effectively the way the transaction works is our Hydro fleet is valued on the basis of 13 times 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 three year average to figure out what they would get.
So $750 million investment is, 700 — what percentage of $750 million of that 13 times that three year average EBITDA of the of the Hydro performance over time, and then they do have essentially two top up rates. One is a 10% top up rate provided to TransAlta’s at the time is over $14 a share. And they do have the ability to increase that ownership stake up to 49% of 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 want it 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 that kind of surround the transaction. Yes, does that help? Sorry, go ahead, Todd.
Todd Stack
Andrew, you mentioned that 30% level that was really predicated on EBITDA from a Hydro facility potentially being in that $200 million to $250 million or $225 million to $250 million range. This year, this year is a year that sort of goes towards that three year average, and will be pushing $500 million of EBITDA this year. So that percentage ratio will change accordingly, should they choose to exercise their option.
Andrew Kuske
Okay, appreciate that color. That was a lot of information out of the resources of your brain. 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 track capital?
John Kousinioris
Yes, 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, 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 ITC has come in, that’s a game 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 what that, what 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 auto or whatever program they’re developing, if that makes sense.
AndrewKuske
Okay, very helpful. Thank you.
Operator
Thank you. Next question will be from John Mould of TD Securities. Please go ahead.
John Mould
Hi, good morning, everyone. 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 reference to the mid-term customer contracts that form part of your hedging number? Or no more kind of one-off merchant PPAs like what you did with Exshaw or some mix in between?
John Kousinioris
It’s actually both. John, good morning. I’m glad you raised that, it is actually both we do. As you know, the market in Alberta, the Ford 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 two to three years would be kind of the average tenure of those. In tandem with that, as you know, we’ve got quite a bit of merchant wind, 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 than 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 goal perspective in terms of what they’re trying to do.
John Mould
Okay, maybe just follow up on that quickly because you mentioned Hydro, is some sort of off take for hydro really achievable, just given the benefit that you get in in quarters like the past one where between AS and energy, I guess maybe AS you would still accrue. But there’s exceptional benefits 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?
John Kousinioris
I think it is, I think people kind of gravitate the, AS often gravitates to the hydro and you know 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 in the Province. So, a good, good 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.
John Mould
Okay, great. And then maybe just pivoting to Ontario, the ISO is going to procure four gigawatts of capacity, including up to 1.5 gigawatts of gas. You qualified for the first long-term RFP, not the expedited round, I believe, but what investments are you considering? Are you looking at batteries? Would you look at any investments in gas beyond batteries, such as enhancements of upgrades or maybe even new units is given that 1.5 gigawatt slice or you really not looking at new capital in meaningful, I should say new capital and gas at this point?
John Kousinioris
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, including the ISO was 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.
John Mould
Okay, I’ll leave it there. Thank you very much.
Operator
Thank you. [Operator Instructions]. And your next question will be from Naji Baydoun at IA Capital Markets. Please go ahead.
Naji Baydoun
Hi, good morning. Just wanted to go back to the topic of capital costs and returns, you mentioned that the returns are relatively fast, given the different moving pieces. I’m just wondering if you can give us a refresh of where you see IRR is in a different markets. And maybe that will kind of help inform where you’d lean to invest a bit more and one jurisdiction more than another?
John Kousinioris
Yes, Naji happy to do that. We look, we continually look at what our hurdle rates are. And we tend to focus on IRR as being one of the key factors that we look at. And frankly, we’ve 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, as the returns are kind of hanging in. And I think, when we think of that, I think Todd, it would be sort of upper single-digit returns that we can get to a double-digit return.
And I’m just talking about that base transaction without us 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 three jurisdictions that we operate in, I don’t think we see a huge difference between sort of Canada or certainly the return environment, I’d say, Todd, Canada, the U.S. and/or Australia — it’s pretty similar.
Todd Stack
They’re all very similar in geographies on unraised returns. And as we kind of talked about a little bit before, we see the best returns coming from the Greenfield and on field development sites that we have, we’re still active in the M&A market, we do look 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’ve seen 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, the Greenfield development side.
John Kousinioris
And just to kind of close the discussion, I mean, we would — the way we would look at returns is we do focus on it from a risk adjusted perspective. So a very long tenor PPA from double A rated, off taker would be viewed differently from the company as something that would be shorter and tender, 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 a view to 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, of a judgment call that we make with our with our board when we move forward.
Naji Baydoun
Okay, guys that’s really helpful. And I guess, maybe 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 NW, but just given where you are on your targets? I mean, it would seem like 250 million of incremental with a very conservative. Is that a number that you think you’d also update shortly?
John Kousinioris
You mean, for balance of 2022?
Naji Baydoun
No, I…
John Kousinioris
Yes, the 2 gigawatt growth program that’s under targeting 250 million of EBITDA were 55% of the way through that we’re at about 200 or about 150 million of the 250. I’m not sure that’s going to be part of our guidance in December that will be readdressing that.
Todd Stack
No, but Naji sorry, I misunderstood your question. It 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.
Naji Baydoun
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 you know, we’ll wait for that update [indiscernible]. 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, that even with the increase in the share price today, you bought stock at around $12.5 shares are going to be above that today that change at all, your view on buybacks?
Todd Stack
We’re always optimistic — opportunistic on our share buybacks when we see the share price trading below. I mean, last time, it dropped below $13 level after Q2, and we thought that was a good opportunity to purchase. So he looked we’ll just play it by year, and we’ll look for opportunities to support the shares.
Naji Baydoun
Okay. So I think it below 13 is a no brainer and above that depends on what else is on the table.
John Kousinioris
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. Yes.
Naji Baydoun
Okay. But just a follow-up question on garden plane. Any updates on [indiscernible] decision to exercise that option there? And is that option, if you can just remind us, is it only exercisable at COD or is there sort of a longer timeline associated with that?
John Kousinioris
No, I think it is basically exercise that COD and as a recall, it’s for 30% of their proportion of the wind farm 30 of the 100 of the 130 megawatts.
Todd Stack
It’s 50 of the 100 that they have the rights to purchase. Yes, which works out to about 40% of the facility.
John Kousinioris
And no update from them in terms of where they are in that process.
Naji Baydoun
Okay. Got it. Thank you very much. Great quarter.
John Kousinioris
Thank you.
Todd Stack
Thanks.
Operator
Next question will be from Patrick Kenny at National Bank Financial. Please go ahead.
Patrick Kenny
Thank you. Good morning. Hey, guys, 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. Does 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 credit worthy counterparties?
John Kousinioris
Sure. Thanks and good morning, Patrick. Todd you want to?
Todd Stack
Well, I was just going to say like the CNI business is actively out there looking for transactions. And John mentioned average terms of two to three years, but we do stretch out into five 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 five 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.
John Kousinioris
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, pretty significant between the two that are much more oriented towards the renewable side than it would be the gas side.
Patrick Kenny
Got it. Okay, that’s helpful. Thank you. And then maybe just to 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 contract basis, or perhaps just selling that 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?
John Kousinioris
Yes, 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 cashflow that’s being generated from the business and sort of the way we’re facing in our clean electricity growth plan. So right now, I don’t think we’re looking at doing anything.
Todd Stack
And it’s very early days. I mean, they have several years yet before the option even just is able to be exercised. So early days.
Patrick Kenny
Okay, that’s great. Thanks. I’ll leave it there.
John Kousinioris
Thank you.
Operator
Thank you. Next question will be from Chris Varcoe at The Calgary Herald. Please go ahead.
Chris Varcoe
Hi, 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 fit in with trans ultimate? I believe with last year, you talked about the potential of or examination of it, at least with regards to Sundance spark?
John Kousinioris
Yes, Chris, good morning. So we made the decision last — not last summer, but the summer of July of 2021 not to proceed with our Sundance five 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 just 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, or our growth focus is far more on our renewables at this point, and particularly wind which is a strength of ours, but storage and solar factor into that will 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.
Chris Varcoe
Thank you. Just a separate question is the COP 27 conferences begun this week? I guess I’m curious, what steps 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 about?
John Kousinioris
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 that we all need to deal with. We’re looking to see that the Federal government continues to have the kind of commitment that has to have in Canada, it’s a carbon reduction 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 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 province and the standard of living that we have here in Alberta. 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 but our real focus is on domestic policy in the U.S. and 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.
Chris Varcoe
Finally, just a follow-up on a question that you 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?
John Kousinioris
I think it definitely makes investments in Canada more competitive with portfolio 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.
Chris Varcoe
Thank you.
John Kousinioris
Thank you.
Operator
Thank you. At this time, we have no further questions, please proceed with your closing remarks.
Holly Tomte
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.
Operator
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.
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