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Good morning, ladies and gentlemen, and welcome. My apologies. Good morning, ladies and gentlemen. My name is Michelle. I will be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation's Third Quarter 2021 Results Conference Call. [Operator Instructions] I would now like to turn the conference over to Chiara Valentini. Please go ahead.
Thank you, Michelle. Good morning, everyone, and welcome to TransAlta's Third Quarter 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 of the information provided during this conference call is subject to the forward-looking statement qualification set out here on our 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 comparable EBITDA, funds from operations and free cash flow are also reconciled in the MD&A for your reference. On today's call, John and Todd will provide an overview of the quarter's results along with our expectations for the balance of 2021. After these remarks, we will open the call for questions. And with that, let me turn the call over to John.
Thank you, Chiara. Good morning, everyone, and thank you for joining our third quarter call. 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 Nitsitapi, the people of the Treaty 7 region in Southern Alberta, which includes the Siksika, the Pikani, the Kini, the Tsuut'ina, and the Stony Nakoda First Nations as well as the home of Mati Nation Region 3. We've had another exceptional quarter, and I'm extremely pleased with the performance of our company and the progress that we have made in advancing our priorities. In Q3, we delivered $381 million of comparable EBITDA, a 49% increase over the prior period, leading to a 79% increase in free cash flow per share quarter-over-quarter. On a year-to-date basis, we have generated $993 million in comparable EBITDA, a 43% increase over 2020 results, resulting in free cash flow per share of $1.68, a 52% increase year-over-year. We also announced a common share dividend increase of 11% during the quarter, representing an annualized dividend of $0.20 per share, and our liquidity remains strong. We're positioned to fully fund our renewable growth pipeline. Given our strong year-to-date performance, and our expectations for the balance of the year, we were pleased to announce earlier today a further increase to our EBITDA and free cash flow guidance for 2021, up by another $100 million and $50 million, respectively, at the midpoints compared to the guidance we provided in our Q2 report. Our performance this quarter was driven by our ability to optimize our fleet and deliver operational performance that enabled us to capture the higher prices experienced in Alberta, demonstrating the underlying value of our diversified fleet. Energy Marketing also had an excellent quarter, with strong trading results across our U.S. power and natural gas desks, which capitalized on our deep knowledge of North American power markets and ability to capture market opportunities. We're also on our way to delivering on the 2 gigawatts of incremental renewables in support of our clean electricity growth plan, which we announced at our Investor Day. During the quarter, we progressed a number of our key priorities. We announced the closing of the acquisition of our 122-megawatt North Carolina solar portfolio. We advanced the construction of our 206-megawatt Windrise project. Construction is now complete, and we expect the wind farm to reach COD later this month. We issued full notice to proceed to our EPC contractor on the Northern Goldfields solar and storage project, with construction expected to begin in the first quarter of 2022. We commenced construction of our 130-megawatt Garden Plain wind project here in Alberta. We began the coal to gas conversion of Keephills 3, which is now expected to be completed later this month as it's now undergoing commissioning and testing. With the completion of the spinal conversion, and the closure of the Highvale Mine effective December 31, all of our Alberta facilities will be generating on lower carbon emitting natural gas. We also announced our decision to suspend the Sundance 5 repowering project and retire our remaining Canadian coal units, Keephills Unit 1 at the end of this year and Sundance Unit 4 early in 2022. Finally, we were proud to be recognized that the COP 26 Powering The World Past Coal event as the world takes action to address climate change. TransAlta's decision to join the 165 member alliance, given our success to date as a leader in energy transition, was a natural extension of our commitment to delivering clean energy solutions for our customers, strong returns for our investors and reliable energy for the communities we serve. Unfortunately, we experienced the tower collapse at our Kent Hills 2 wind facility at the end of the quarter. The remaining turbines at Kent Hills 1 and Ken Hills 2 wind facilities have been taken offline and are undergoing engineering and safety assessments. Initial findings have identified subsurface crack propagation at several of the foundations, indicating that a significant number of foundations will need repair or replacement. As you would expect, we're engaged in discussions with New Brunswick Power about the incident and appreciate the support they have provided us to date. We will share additional information on our return to service plan as it becomes available. Turning now to growth. We are pleased to announce the closing of the acquisition of our 122-megawatt North Carolina solar portfolio. The portfolio consists of 20 operating facilities across North Carolina, all of which have long-term contracts with subsidiaries of Duke Energy. The project will be held by TransAlta Renewables through an economic interest. This portfolio expands our solar footprint in the United States and has a high-quality customer in a region where we see significant growth opportunities given North Carolina's transition away from coal. The portfolio is expected to contribute approximately USD 9 million in EBITDA annually. Construction of Windrise is complete, with all 49 turbines complete, 43-story turbines complete. We now expect to achieve COD later this month. The 206-megawatt project is under a 20-year PPA with the Alberta Electric System operator and will extend the life of our contracted portfolio at TransAlta Renewables. This is TransAlta's tenth wind facility in Alberta and will be the first project to reach commercial operation out of the 8 projects awarded by the ISO through the second and third rounds of the renewable energy procurement process in December of 2018. The completion of Windrise ahead of our peers demonstrates TransAlta's execution capabilities and commitment to supporting our customer needs for clean energy. As you know, earlier this year, we launched the 130-megawatt Garden Plan project, supported by an 18-year agreement with Pembina Pipeline for 100 megawatts of the capacity and associated environmental attributes. We've advanced the development of the wind farm through our procurement processes and secured all regulatory permits and approvals. Initial construction activities have started, and we expect to reach commercial operation during the latter part of 2022. A significant portion of the project costs have been fixed, which limits our exposure to any inflationary pressures being experienced in the marketplace. We continue to actively market the remaining 30 megawatts and are aiming to fully contract the facility by the end of this year. We expect the project to deliver between $14 million and $18 million in comparable EBITDA on a full year basis. The highly contracted nature of the Garden Plain project makes it a strong candidate for drop-down to TransAlta Renewables. We spend a lot of time discussing our development pipeline and growth targets at our Investor Day in September, so I won't spend a lot of time repeating that today. I would like to highlight that we continue to progress the development activities on the 500 megawatts of advanced stage wind projects at Horizon Hill and White Rock East and West, all of which are located in Oklahoma. We're engaged in exclusive discussions to contract the output from the facilities and are targeting to reach the final investment decisions in relation to these projects over the coming few months. We remain disciplined on growth in Canada, including here in Alberta. We've shifted away from merchant baseload gas generation, and are now exploring opportunities to maximize the value of our hydro and wind fleets with a new focus on battery storage and solar. In Australia, we're delivering customized clean power solutions to meet our customers' ESG objectives in the most cost-effective manner, with a focus on advancing several opportunities in Western Australia in support of our remote mining customers. Overall, we have approximately 3 gigawatts of development opportunities in various geographies and with various technologies, including wind, solar, hydro and storage. Our development teams in Canada, Australia and the United States are working hard to deliver on our $3 billion capital investment target. 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. As John discussed, we had another great quarter, and our diversified fleet continued to deliver excellent results with $381 million of comparable EBITDA and $189 million or $0.70 per share of free cash flow. On a year-to-date basis, the company has generated $993 million of EBITDA and $456 million of free cash flow. We are extremely pleased with our financial results so far this year as EBITDA and free cash flow in the first 9 months of 2021 have now exceeded the full year performance achieved in 2020. On the net earnings front, with the decision to spend the Sundance 5 repowering project and retire Keephills 1 and Sundance 4, the company did recognize a number of noncash asset impairments and other related penalties in Q3 totaling $575 million. These impacts are extraordinary due to our shift in strategy and are not reflective of ongoing operations and are not included in our comparable EBITDA results. With the expiry of the PPAs and recovery in demand, both our hydro and Alberta Thermal segments benefited from strong pricing in the Alberta market as well as from the great work of our asset optimization and operations teams. EBITDA from our hydro fleet continued to significantly outperform this quarter, realizing a nearly threefold increase from $28 million in 2020 to $82 million this year. Similarly, EBITDA from the Alberta Thermal segment more than doubled year-over-year from $47 million in 2020 to $104 million this year. Wind and solar EBITDA was also higher, increasing from $36 million in 2020 to $55 million this year, benefiting from higher realized prices in Alberta and the addition of the Skookumchuck wind facility, which was acquired in the fourth quarter of last year. Our energy marketing team delivered another consecutive quarter of superior performance, delivering $58 million in EBITDA as compared to an also outstanding result of $49 million in 2020. Overall, TransAlta has delivered 3 exceptional quarters this year, and we are very pleased with both the results across our diversified fleet and the realization of the potential of our Alberta generating portfolio. I want to thank our employees again for their contributions in achieving these results. I'll turn to Slide 14 to look at our Alberta Thermal Alberta business in more detail. Our Alberta wind, hydro and thermal facilities are dispatched as a portfolio to benefit from baseload and peaking energy sales. During the quarter, the Alberta portfolio generated over 3,300 gigawatt hours of production, an increase of 6% over the same period last year, and realized $381 million in revenue. The strong pricing throughout the quarter contributed to the average pool price for Q3 settling at $100 per megawatt hour compared to $44 in Q3 of 2020. In the quarter, the Alberta Thermal fleet generated approximately 2,500 gigawatt hours, with an average realized price of $101 per megawatt hour. In the quarter, we had hedged just under 1,900 gigawatt hours of baseload capacity or approximately 74% of our expected thermal production at an average price of $76. The combination of our hedge revenues and our peaking sales resulted in revenues at Alberta Thermal being significantly higher than 2020. We expect similar total production from the thermal assets in the fourth quarter of 2021 of approximately 2,300 gigawatt hours, of which 1,400 gigawatt hours or 60% is currently hedged. We continue to see strong forward prices for the balance of the year and into 2022, and the Alberta Thermal segment continues to retain significant open capacity in order to realize potential higher pricing during times of peak market demand. Over the last quarter, natural gas prices have increased significantly, and we expect this will continue to put upward pressure on power prices in Q4 and into 2022. Our fuel position is well managed, and our gas hedges cover roughly 70% of our expected production for Q4 and approximately half of our 2022 production. Turning to hydro. The ability of hydro to capture peak pricing was again demonstrated in Q3, with average realized prices of $114 per megawatt hour, which represents a 14% premium over the average spot price. Ancillary volumes were broadly in line with expectations for the quarter. Overall, hydro gross revenues benefited from strong realized pricing and exceeded our expectations for the quarter. For the balance of the year, we expect Alberta spot prices to settle in the range of $95 to $105 per megawatt hour. I'd like to provide an update on our subsidiary, TransAlta Renewables. As you're aware, 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's results. As John mentioned, we are pleased to announce the closing of the North Carolina Solar acquisition by RNW as well as the completion of construction at Windrise. Comparable EBITDA for the quarter increased by $6 million, largely due to the addition of the Ada and Skookumchuck facilities. Cash available for distribution for the quarter decreased by $19 million compared to the same period in 2020. The decrease in CAFD was primarily due to higher interest expense attributed to the financing at South Hedland and higher sustaining capital driven by a spare engine purchase for the South Hedland facility. As a result of continuing lower-than-expected wind resource year-to-date, and the unexpected suspension of operations at Kent Hills, we are now forecasting key 2021 financial targets at RNW to be slightly lower relative to our previous guidance range. We now expect TransAlta Renewables comparable EBITDA to be between $450 million and $480 million and CAFD to be between $250 million and $270 million. We continue to have strong liquidity at RNW. In addition to our $700 million committed credit facility, we had over $200 million of cash at the end of Q3. As we mentioned in our Investor Day presentation, we see additional growth opportunities for TransAlta Renewables, and we anticipate that roughly 2/3 of the 2-gigawatt clean electricity growth plan could be candidates for drop-down to RNW. Overall, TransAlta has had exceptional year-to-date performance. And together with our expectations for the fourth quarter, we are pleased to, once again, increase our EBITDA and free cash flow guidance for 2021. We are now estimating comparable EBITDA to be between $1.2 billion and $1.3 billion, representing an additional 9% increase at the midpoint of the range versus our previous guidance at Q2. This EBITDA expectation allows us to increase our free cash flow guidance range to be between $500 million to $560 million. This equates to free cash flow per share of $1.96 at the midpoint, representing an additional 11% increase over our previous Q2 guidance. In addition to our estimates for consolidated EBITDA and free cash flow, we have revised our power price outlook. First, we are adjusting our full year annual price outlook for Alberta to be between $95 to $105 per megawatt hour. And second, we are adjusting our annual price outlook for Mid-C to be between $50 to $60 per megawatt hour. And finally, based on strong year-to-date results, our outlook for gross margin at the Energy Marketing segment has increased to $195 million to $210 million. I'm going to close my remarks on Slide 17, and highlight our trend of strong free cash flow performance and the continuing financial strength of the company. In the 9 months ended September 30, free cash flow has exceeded our 2020 annual results by 27% with 3 months of 2021 remaining. Our balance sheet and liquidity remain incredibly strong. We closed the quarter with $2.3 billion in liquidity, including $1.1 billion of total cash. This positions us extremely well to fund our future growth pipeline, including our 500 megawatts of advanced stage projects. With that, I'll turn the call back over to John.
Thanks, Todd. As I review our 2021 balance of year priorities, we continue to focus on progressing our key goals, including securing a growth project in the United States, completing the commissioning of Windrise, completing the Keephills 3 coal-to-gas conversion, completing the recontracting of our remaining industrial customers at the Sarnia facility, advancing our organizational health and equity diversity and inclusion initiatives, and delivering 2021 EBITDA and free cash flow on the basis of our revised guidance. I'd like to close by highlighting, as I always do, what I think makes TransAlta a highly attractive investment and a great value opportunity. First, our cash flows are resilient and are supported by a high-quality and highly diversified portfolio. Our business is driven by our contracted wind portfolio, our unique, reliable and perpetual hydro portfolio, and our efficient thermal 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 emission reductions. Our decarbonization journey has resulted in greenhouse gas reductions that represent close to 8% of Canada's 2030 target. In addition, our focus on removing systemic barriers through our commitment to equity, diversity and inclusion and good governance, places us well ahead as a leader in ESG. Third, we have an extensive and diversified set of growth opportunities, which includes a pipeline of advanced stage projects and a talented development team focused on realizing its value. Fourth, our company has a strong financial foundation. Our balance sheet is in great shape and has ample liquidity to pursue growth. Finally, our people. Our people are our greatest asset, and I want to thank all our employees and contractors for the work that they have done to deliver the exceptional results this past quarter. We're committed to a company culture where everyone belongs and can bring their best and authentic selves to deliver great results for our company. TransAlta is at an exciting time in its development, and we're well positioned for the future as a leader in low-cost, reliable and clean electricity generation focused on serving and meeting the needs of our customers. Thank you. I'll turn the call back over to Chiara.
Thank you, John. Michelle, would you please open the call for questions from the analysts and media?
[Operator Instructions] Your first question comes from Rob Hope of Scotiabank.
First question is just on the outlook for 2022 and your hedging profile. It looks like you added quite a bit of hedges in 2022 and depending on the utilization, you think, for your facility, maybe your 60% covered of -- on your Alberta thermal units. Could we see you or opportunistically increase that? Or are you just taking advantage of what is good pricing in the forward curve right now?
Yes, Robert, thank you for that question. I think you have it about right in terms of where we're sort of triangulating to I think it's currently our intention, and I know that the team is continuing to work at adding, I think, some more hedges to basically our position for 2022. I mean as you know, we look at what our expectations are from a pricing perspective on a month-by-month basis, and we are still seeing opportunities in 2022 to add some hedges that to result in locking in prices that are better than potentially where we might expect supply and demand fundamentals to actually land in any particular period. and with the forward curve kind of being in that low $90 range or so, it just makes sense that we would continue to feather in some additional hedges to sort of backstop our performance for 2022.
I appreciate that. And then just switching over to New Brunswick. In the prepared remarks, you mentioned that New Brunswick Power has been a a good partner in this process so far. As you go through evaluating the issues at Kent Hill, are you going to engage the government to see if there is an opportunity to kind of do a blend and extend. And if you do have to rebuild some bases, maybe lock that in with a bit of a longer-term contract?
Yes, Rob. Look, I'd be speculating if I sort of try to let give people a sense of where we actually thought any of our discussions with New Brunswick Power would land. I can tell you that our focus on discussions with them, and we've had discussions with them at the highest levels on multiple times over the course of the last few weeks. It's really been around making sure that they understand kind of where we are in the moment on the evaluations that we're doing of the wind farm, having them understand directionally where we might be going from a remediation perspective and really just focused on giving them comfort that we've secured the site, that we're prioritizing safety as we go forward. We need to really better understand in the coming weeks, kind of the status of the wind farm and what it really means for us from a go-forward plan on the foundations before we really open up any discussions with NB Power about what a potential solution or outcome might be this a win-win for everybody.
Your next question comes from Ben Pham of BMO.
I'm just wondering with your your maintenance CapEx outlook, $200 million or so this year, and you're showing down on a couple of plants. Like how do you see that shaking out over time? I mean they actually look like at like is moving lower, but can you provide a sense of magnitude of how low will it go?
Ben, you were breaking up a little bit, so I'll try to answer the the questions as well as I can. So for sure, I think we're looking at 2021 as being, at least from a TransAlta perspective, I'd say, Todd, kind of a heavier sustaining capital year. Really, as we look at the fourth quarter, for example, we're still seeing about $80 million or so of spend. A lot of that is oriented around the Keephills 3 coal-to-gas conversion. And we've done some hydro work this year as well, which has increased our capital spending. Over time, we would expect that to moderate in terms of what the overall spend would be. I don't think that we've sort of set any specific guidelines in terms of what we would expect it to be going forward. But we would view kind of capital spending in the $180 million to $200 million a year as being high compared to where we would be going forward. I think what you can expect to see from us is a little bit more in the way of dam safety spending going forward, which is something that, I think, until now, we probably haven't seen as much of as we go forward. Todd, I don't know if you want to add any color to that.
I think, John, you've covered it, we did highlight that we would see a step down as the CTG conversions were completed through this year. But as John mentioned, we are looking at allocating capital through other portions of our fleet in hydro, definitely an extremely highly valuable asset that we want to make sure that we're putting the appropriate capital to sustain its ongoing performance.
And I would just say that next year, Ben, Sarnia, we're looking at doing a bunch of work there as we're setting up the plant for its next 10-year run effectively. So that will be an area that we'll be spending some capital, I think, in 2022.
Okay. Great. You also mentioned you're looking to maybe adding more hedges for 2022. And I'm wondering like what's -- what's your general philosophy on just the hedges? Like do you have a certain percentage you'd like to be at to derisk your guidance? Do you just look at your expectations internally versus where the forward curves are? Like how do you think about that risk reward to head into next year?
Yes. I'll maybe start, Ben, and happy to turn it over to Todd to add some color. We meet -- we've got a team that meets monthly effectively, and we meet even more frequently than that to basically assess our hedge position. And when we think of our hedge position, it isn't just on the power that we're expecting to sell. It also includes our input costs like natural gas as we go through the year. So we do tend to look at both. We do fundamental modeling throughout the year. And frankly, it's a multiyear modeling that we do. So, at any point in time, we have an internal view as to where we think prices should be landing in any given quarter, frankly, in any given month as we go forward. We assess where the forward curve is in that period and kind of from a probabilities perspective, where that lands in terms of what the internal view. And in general, we tend to be focused certainly from our thermal fleet perspective. We don't really think of a hydro fleet as being something that we're focusing on. We tend to think about depending on our market view and pricing view, directionally trying to lock in the outcome for our more base-loaded units. So traditionally, at least even going forward, that would be sort of K3 for us in terms of where we would be going forward. So hopefully, that gives you a bit of a sense. Todd, I don't know if you want to add anything to that? Todd is also on the committee, along with a few of our colleagues that looks at this every few weeks.
Ben, I just want to add a bit more just a bit more to what John said. It's something we've talked about in the past is that liquidity continues to be a bit of a challenge for executing the exact hedging program that you want to do. And similar to prior periods, a higher weighting of our hedging level is more into the Q1 period and then into Q2 and less so in the back half of the year. And it's an interesting dynamic between last year and this year. When we were coming into 2021 at this time last year, as John mentioned, our our marketing team, our optimization team was looking at the forward prices and saying, we don't think that fairly represents where it should be. So we came into 2021, what I would say, with low level of hedges.
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Whereas this year, we're seeing, as John mentioned, the full forward curve is in the $90 range, low $90 range. and the Q1 prices are relatively strong. And so the team sees that as being fairly valued and willing to lock in more of that volume in Q1.
Okay. That's great. And maybe one more cleanup on Sarnia. You mentioned that maintenance going up a little bit next year. Do you think that you need to spend maybe a bigger CapEx amount to secure a contract -- or sorry, an extension of the contract? Or you can just elevate maintenance a little bit the next few years into that potential new contract?
Yes. It -- I don't think that the capital expenditures are really tied particularly to the extensions that we're looking at doing. And we've landed one extension, and we're working hard to to wrap up the remaining 3 there in fairly short order. It's more just from a time and operations perspective, We're at a point in time where we need to do an appropriate number of inspections for the plant, and it just so happens to be triangulating to 2022. I think there will be a little bit of CapEx potentially even in 2023 as we set up the plant to really run from a time perspective over the course of the ensuing kind of 10-year period. The maintenance is more driven kind of where we are in terms of the historical performance of the plant and where we need it to be to kind of run forward as opposed to it being specifically tied to any of the recontracting that we've done, if that makes sense.
And again, the ISO contract runs through to the end of 2025. So there's maintenance required to get us through to that period as well as beyond.
Your next question comes from Maurice Choy of RBC Capital Markets.
My first question is, I don't want to come back to hedging again, but if I compare your hedge position in Q2 versus what you have right now, you've clearly increased your power production hedges at a pace that is faster than what you've secured on gas volumes sequentially. So how would you characterize this difference in pace? Is it a case where you under hedged on one versus the other? Or is it a case where you have a difference in outlook on power price versus Eco moving forward? Or, to your point, is it a liquidity?
Yes, Maurice, it's a great question. I don't think I've got a perfect answer for you, to be honest. I mean I can tell you, and maybe I'll try to deal with it discretely, I'll try to deal with the gas position first, and then I'll try to deal with the power position subsequently. We made the decision to lock up some of the gas based on, again, our fundamental view of where we thought gas prices were going to go. So we did it, obviously, with an expectation of what we thought our production would be certainly for the balance of this year and going into 2022. But we had an expectation that we would see the spike up in natural gas prices. So it was important to us to lock in as much gas or a reasonable amount of gas that we -- that -- for our expected, broadly speaking, production profile in 2022 early, which resulted in us getting kind of an average price for gas into 2020 to at sort of in that $2.70, $2.75 range. That was ahead of the hedging position that we had on power. -- in part because, as Todd said before, there isn't a lot of liquidity in the market, right? We tend to think of it as sort of a rolling 6 months forward, whereas on the gas side, there is a lot of liquidity in the market. So as the forward curve has strengthened from a gas perspective -- sorry, from a power perspective, and we've been updating kind of our fundamental view on where pricing was going to be as we see now the ability to be hedging in sort of that north of $90 for 2022 and depending on the period even higher than that, the team has been layering in hedges just because, from a fundamental perspective, we think that, that's broadly speaking, a fair price as we go into the year. So it was -- although we do tend to look at the demand for fuel on an anticipated production basis, we're not afraid to kind of decouple our decisions on the 2 and do what we think is sort of appropriate from an economic perspective going forward. So hopefully, that gives you a bit of a sense on how we think of it.
Differently. And maybe as a follow-up to that. By not securing as much gas hedges for next year because you have early hedged it, what does that say to what you expect AECO prices to go from this point onwards?
Yes. I mean, I think, as I mentioned, that we expect gas prices in North America to stay elevated from what we've seen over the past prior years, and our marketing team and our optimization team have had this view for a fair while that there's been lack of investment in some of the drilling. Now that will turn around and has already started to turn around. But we expect to see elevated gas prices. But -- When we thought about hedging the base load, it's more around against those hedges. When we think about the remainder of the peaking power that we're going to need, there's really not a correlation between gas price and power prices when you move into that peaking. And so we -- our view is that we can absorb the higher gas prices for that peaking because we'll be receiving a premium price on the power that we're selling in those periods.
But I'd say, Todd, in terms of just sort of where you're seeing prices for 2022 and look, it moves around. I mean, we're looking at kind of prices, at least if you were to look at where things are today at sort of $0.65 on kind of the dollar in terms of what the cost would be. So we're pretty happy with our cost position going into the year. I think we're pretty nicely set up.
Great. And just a final one, hopefully, a simple one. I want to ask when the market should expect you to share your 2022 guidance? Obviously, in the past, there were times when you were in December and in January and then last year, you shared as part of our Q4 results. I suppose, visibility this time runs better than last year when there was uncertainty with regards to balancing pool PPAs. What are some of the uncertainties that you're still working on before you can be comfortable releasing your guidance?
Yes, Maurice, thanks for that. It's interesting. This is exactly the discussion we were having yesterday, Todd and I, so we're both smiling a little bit here in the room. Look, we tend to be focused on landing our budgeting process in kind of a December time frame, generally speaking. There are some uncertainties. One of the uncertainties, obviously, Kent Hills, as we continue to do the work to understand that better. I'd say, Todd, that's probably the biggest uncertainty that we have in terms of putting a pin in terms of where the numbers are. We haven't set a specific date yet in terms of whether our guidance would come out in December, it would come out early in the first quarter, but if we can lock it down, I think our general, at least our initial preference would be to get it out to the market if we have a sense of where it is. So that's what we're trying to work towards doing.
Your next question comes from Mark Jarvi of CIBC.
John, you made a comment at the end about one of your targets for the balance of the year just to get one contract in the U.S. Is there a potential to get more than one contract on those U.S. wind projects in Oklahoma? Or is it more likely 1 this year and then maybe 2 next year?
Yes. I think it's more likely that we would see 1 this year and 1 or 2 next year just in terms of -- from a timing perspective. It -- the discussions are ongoing there. And we're working hard to really lock down our prices, which -- where there is some volatility right from an asset pricing perspective, and frankly, even from a delivery perspective, just from the supply chain. And just from our perspective, we need to derisk that and absolutely derisk sort of the time frame for delivering the project. And then, I think, we'd be able to proceed fairly, I think, expeditiously to be able to get some contracting done.
Okay. And then can you guys give us any update on South Hedland in terms of -- it sounds like you guys are close to a settlement. When we might get that? And then I mean you do have in your pipeline of solar project in there. Can you maybe just kind of walk us through some of the different options or whether or not how we can think about EBITDA once you do settle the contract dispute with FMG?
Yes. I might ask Kerry Mark, just to kind of address that one in terms of kind of where our state of play is with FMG.
Perfect. Thanks, John. Yes, we're in the final stages of approvals with respect to the settlement. So nothing to disclose to the market at this point, but we expect that we can do imminently.
I think we're pretty close, Mark. And I suspect, I mean, Kerry, it's probably fair to say -- I mean, certainly before Christmas, we'd expect to have it done. And it would be nice to have FMG come back into the fold as a customer there.
Got it. And then just coming back to Kent Hills, your discussion with New Brunswick Power, are there like obligations for you in terms of delivery like liquidated damages? Or do you think if there was -- those would be all covered by insurance? Or maybe it's just too early to make any comment on that?
Yes. It is a bit early to make a comment on that. I can tell you that when you have an interruption like the one that we have there, the contractual regime that we have does give us time to provide a remedial plan for it that we would work through with NB Power to put into place. So it we're going to be short of meeting kind of the contracted generation output that we have under the agreement this year, but there are pathways in the actual agreement that permit us to kind of explain the situation and develop a plan with an appropriate time period to be able to address the shortfall. So we're not, at this point in time, concerned about the PPA that we have with NB Power.
Got it. And then maybe one last one for Todd. I mean your leverage metrics are in really great shape and your EBITDA numbers are great. You're deleveraging a lot of free cash flow generation. You do have the maturity next year. Any updated thoughts in terms of what you do with that? Whether or not you just kind of delay that and you just pay it with the cash you've generated excess cash, just updated views on the 2020 debt maturity?
Yes. I think you're absolutely right. I mean, we're looking at all of those options. We had actually thought about making hold the fund ahead of time. The economics just don't don't work and don't make sense. So we're going to watch and push the growth team to get those projects committed, and then we'll have a better idea of how much liquidity we have in 2022, and particularly when that bond comes to mature. But you're absolutely right, we have a lot of flexibility in how we address that bond.
And given you said really great results, like how do you think about like the go-forward sort of consolidated deconsolidated leverage? Like do you just treat the most recent results as sort of maybe anomaly you can't bank on that going forward? Or just how do you think about this sort of, I guess, cushion you feel like you have right now at least?
Yes. I think -- look, like we've said, is that we really want to put that cushion that we have to work. We really want to get those growth projects moving as quickly as we can to get them producing. As far as leverage, and I think I've talked about it before, it's really focusing on that corporate debt level amount and to keep that corporate debt level amount in around that $1 billion level, and that's really how we think about it. But exactly as you mentioned, right now, if we're if we're flush with cash that may go down as that maturity comes due. But again, really pushing the growth team to get the capital that we have to work as opposed to paying down debt.
Your next question comes from John Mok of TD Securities.
Maybe just like to start with the corporate PPA market in Alberta and the lay of the land here you've remarked in the past that can be tough to contract a full facility just based on the relative scale of the market, but we've seen a lot of activity there over the last few months. But have you seen any changes in that market from your perspective, just given maybe a broader push towards more decarbonization and maybe in tandem with the strong pricing that we've seen so far this year and the outlook for the next couple of years, any thoughts there?
Yes. So maybe 2 responses to it. I mean given the kind of pricing that we've seen in the province, I think -- We have seen a bit of an uptick. I think it's fair to say in just C&I interest, just having some people sort of contract and deal with their electricity requirements over the upcoming period as opposed to maybe being more open than they might have otherwise been. And that's just kind of a generalized sort of comment, and that's creating opportunities for us from a contracting perspective. On the renewable side, from a PPA perspective, we're still seeing, I think, kind of the size of the offtakes for the PPAs being certainly smaller than you would typically see in the United States in terms of the size that people would be willing to contract for, although not universally. I mean, there have been -- I mean I even look at our Garden Plain PPA, where you've got 100 megawatts. There are large offtakes that are available. I would say, though, that the number of players that are in the market looking for PPAs remains robust. And we've had pretty good experience, you heard in my sort of comments, as we're really focused on trying to contract that balance of Garden Plan, which is 30 megawatts. I mean that's -- there is definite interest for things of that size and certainly larger at what we think are really competitive pricing. So the market remains a good one. I think, Todd, I think you probably agree like we -- it's steady.
Yes. And I think our primary focus, as you mentioned, is on the Garden Plain and recontracting that last portion of capacity there.
For us, John, where we're focused on is when you look at our Ripplinger project, which is a large project, 300 megawatts in Southwestern Alberta, there's cost benefits to that given the scale and the size of that project. Finding a 300-megawatt offtake is not a typical thing to do. So that's a project that's going to require us to bring a bit of creativity and some partners to see it through, if you see what I'm saying.
Yes. No, absolutely. That's helpful. And then just a clarification on your Oklahoma wind pipeline, and apologies if I missed this, but can you just remind us where those projects are in terms of the interconnection process? And does -- are there any potential constraints on timing once you do get those projects contracted that just could come out of the interconnection queue there?
No. I think we're actually feeling pretty confident about kind of permitting all of the regulatory approvals that we need to get. Not all of the approvals are received at the time that you would sign a PPA. Some of them would -- you'd secure over the course of the ensuing kind of 9-month period. And just to give you an example of that, the Bureau of [indiscernible], just in terms of the -- the sites of the transmission on the actual wind farms require some consultation, and we're focused on kind of disserving the affected land as little as we possibly can. But in general, I don't think that we would view permitting to be a critical path item. I think we're at an advanced stage of what the costs associated with interconnection would be. How it would be done and advanced discussions with equipment suppliers, advanced discussions with EPC contractors, actually working out the time frames, the schedule for the actual construction. And as I mentioned in my comments, in exclusive discussions really for potential offtakes of the entire 500 megawatts in the region that we have in an advanced stage. So pretty advanced, I'd say.
Okay. Great. And maybe one -- just one last question on how you think about energy marketing guidance? Your objective on the gross margin side there, I think, has about doubled from where it was in your original guidance, and I can appreciate there's been some weather volatility and unit volatility that may have supported that. But is there -- is there a path to maybe not a reset is the wrong way to phrase it, but has your expectation around kind of the base performance level of that business increased at all for future years just based on what you've seen this so far this year? Or is that really event-driven, and you want to be conservative on how you think about it going into the year?
Yes, John. I would think of it as it was an exceptional year, exactly as you spoke about, with some really, really interesting market dynamics throughout the U.S. and primarily through the West U.S. between the Mid-Columbia, California and South West Powerpool. So it was really being positioned to take advantage of a market disconnect and make some good opportunities to make some EBITDA in those periods. We'll be thinking about that as we set our 2022 guidance as to what the right level is. But I think the floor of the trade group is set up to deliver that base amount and then opportunistically be able to exceed that when the opportunity presents. But it's not -- it's not like we can predict a number of opportunities. And in fact, over the last couple of months, we've seen some of that -- the market pricing disconnects and flatten. And so we've seen a lot more flat price through the Western U.S. over the last month or so. But as my team tells me, you can never predict what weather event is going to occur or what other market event is going to occur that's going to drive an opportunity. And so that's really what the team is positioned for.
Although I think it's probably fair to say, Todd, that at least over the last years, we've seen more volatility than would have been the case in the prior years, John, is what I would say, particularly in the second and third quarters. And we have, I think, Todd, it's fair to say a general expectation that, that will, to a greater or lesser extent because it requires a couple of -- the confluence of a couple of factors to see it through kind of continue for a period of time now. How long and with what degree of certainty is always challenging. But I think, certainly, our expectations in terms are conservative, but we would expect the floor to be doing a bit better on average, I think, Todd, than it would have been doing 5 years ago, for example, from a metric perspective. So hopefully, that gives you a bit of a sense.
Your next question comes from Andrew Kuske of Credit Suisse.
And I guess the question is really an evolution of your guidance and also your business strategy, if you look back a year ago and the plan that you had in place to where you are now, where you've had guidance revisions, robust market environment overall and, frankly, just execution. How do you think about the capital deployment that occurs into the next year? Can you accelerate some activities? And then a related question, does that start to motivate you to drop assets down on an accelerated basis into RNW?
Yes. Great question, Andrew. I mean we are -- we're focused on a few things. One of them would be, first and foremost, getting the 3 wind farms that we have in Oklahoma under our belt and contracted. That's quite a bit of activity. And I think, Todd, potentially kind of approaching $800 million in capital expenditure from our perspective. The team is already focused on trying to accelerate some of the other wind farms and development opportunities that we have going forward, including potentially some solar and storage activity in Alberta, which we're looking at accelerating. And then the third thing I would say is very much an increased focus on just increasing the size of our pipeline and making sure that it's as robust and certainly larger than it is today. So certainly focused on trying to accelerate things. We do feel, as we said during Investor Day, that we're in a period of time where we're expecting relatively robust, I think, pricing in Alberta, 2021, 2022, 2023. So Andrew, at least the way I think of it is it's kind of a nice period to be using those kind of cash flows that we're expecting to kind of help the transformation of the company and the pivot effectively from a strategic perspective that we've embarked on that we announced to investors. So hopefully, that gives you a bit of a sense.
It does. It's helpful. And I guess maybe the bigger picture perspective on this, if you sort of thought about your internal 5- and 10-year plans, are you -- given the performance you've had this year, you're effectively establishing a much more solid base to be further down the road in those 5- and 10-year plans than you previously thought you were? And then that's the emphasis on the growth pipeline for the future?
I think that's exactly right. We've set the targets that we've set in terms of where we want to get to from a growth perspective. I mean, the team is working hard from an execution and the devil's in the details, right? It's critical that we execute to see if we can reach kind of the targets that we have on an accelerated basis. The one thing I would say, though, Andrew, is we're hyper, hyper focused on just being disciplined, making sure that we get the right returns that we need. We do see return compression in a number of parts of the world and in a number of the technologies, and we're just going to be choosy and we're really, really focused on making sure that we execute well and get the kind of returns that we're targeting for our company.
If I may sneak in one follow-up on I just build on your return comment. Do you have opportunities either adjacent to existing farms or facilities that you've got where you can do extensions or repowering opportunities where you can effectively enhance your returns?
The answer to that is yes, and that is definitely something that we're looking at. So when we think of big timber, for example, in Pennsylvania, which is near our big level wind farm there and also an expansion of our Wyoming Wind, which by another 100 megawatts there, so that is -- I'm glad I actually raised it. That's actually one of the first places we go to, to see whether or not we can use some of that existing infrastructure that we have, expand the footprint of the assets that we have, which permits us to do it on a cost competitive basis. So, for sure, that's the case. And even some of the storage opportunities that we're looking at in Alberta when we're looking at water charger, again, that is oriented towards using -- expanding really the footprint, if I can use that expression of our hydro in the province to extract more value. So for sure, that's a priority.
Your next question comes from Naji Baydoun of IA Capital Markets.
I just wanted to go back to the the cash balance and capital allocation. I appreciate the focus is on the project development ahead of you. But have you -- does this at all change your view on M&A, specifically, I guess, are you still just looking at tuck-ins? Or would you be pursuing any larger opportunities at this point?
Yes, Naji, thank you for that. So we continually look at M&A opportunities, both from a development pipeline perspective and from an asset perspective. We have a separate team that evaluates that, and they're in the process now of evaluating other opportunities that we may be able to move forward that would sort of fit within the objectives that the company has. So that's a never kind of ending process that we have. And I think we're pretty proud of our track record in terms of being able to grow that way and get the kind of returns that we're targeting for the company. So that's a yes, definitely in terms of what we're doing. The other thing I would say that we do periodically is, we do look at share buybacks occasionally. It's something that that is a topic Todd and I continue to discuss and evaluate. And when we look, at least from a deconsolidated cash flow perspective, that bucket that we've allocated for growth, debt repayment and we're pretty happy where we are from a debt perspective. And then share buybacks, it's -- I think it's 30% to 50% of that cash flow segment. So that's another piece of the pie that we continue to assess. Todd, I don't know if you want to add any color?
I think you were also poking at sort of the size of the M&A that we've been looking at.
Yes.
And typically, we have been looking at the single asset or small portfolio that is the bulk of what the team does review to look for opportunities in regions that we think are attractive or to build out expansion within regions where we're already operating. John, about like larger transactions, again, we do look at it. We look at some opportunities. Quite frankly, we haven't seen anything that would be accretive at this point in time. So our focus really is on, what I'll call that, 100- to maybe 400-megawatt size M&A transaction of single asset or portfolio.
Yes. We tend to think of kind of our floor size in terms of acquisitions to sort of being in that $100 million range, roughly speaking.
Okay. Okay. Great. That's very helpful. And just a clarification question on Sarnia. The -- I guess, the MD&A or the press release, it kind of reads as if the contract with the ISO or the new contract, I should say, would only be secured after the existing one expires? Am I reading that correctly? Or maybe you can just clarify expectations for Sarnia?
Yes. So the recontracting agreements that we have would become effective as soon as they're actually signed. What we're doing is we're kind of putting in a relook effectively into these agreements, just making sure that they remain economic depending on the outcome of the recontracting and just the market evolution in the Ontario marketplace, which we expect to evolve over the course of the kind of ensuing year or so. The facility is contracted until 2025 with the ISO there. And I know our team is engaged in discussions with the ministry and also participating with the ISO there as they begin to plot out kind of the procurement of medium and longer range capacity to meet the needs of Ontario for the balance of the decade.
Your next question comes from Luca Nadol of National Bank.
My first question, I got out early, so it's not a repeat question, but it would be regarding the insurance claim on the Kent Hills property. What could we expect? And what kind of time line should we look for a potential settlement in that regard?
It really is premature for us to really be able to provide you with any sort of reliable guidance on what the insurance recoveries would be. We do have property and business interruption insurance in Kent Hills. We do expect to get some insurance recovery. And obviously, our insurers have been notified of the situation that we're facing there. But it really is early -- too early for us to be able to give any guidance in terms of the scope and scale or even the timing of what the insurance recovery would be there.
Okay. Perfect. And a quick other one. In terms of the -- I don't know if you are able to give any guidance for the timing of the assessment, the engineering on the other like turbines?
Yes. So that's ongoing. Todd, I'd say, our -- at least my best estimate right now is we're probably 6 weeks, maybe 8 weeks away from getting that work done. And the work is really in 2 broad areas. One of them is on a real focus around understanding the current status of the foundations and also a path to the remediation plan. The second bucket is really just the root cause failure. We're trying to understand the causation of the situation we find ourselves in just to better understand how we can move forward. So it's really those 2 key elements, and we've got different players that are involved in those elements as well. But I think a good outcome, from a timing perspective, just being realistic about it, it would be right around the end of the year would be the earliest time I think that we'd get clarity, I think, or better clarity in terms of where we're at.
Your next question comes from Patrick Kenny of National Bank.
I just wanted to come back to Sun 5 here given the robust pricing environment, economic tailwinds in the province. Just assuming we do get clarity over the next year or so that the [ 0.37 ] intensity standard does hold up. And if power demand continues to ramp up, does the repowering project come back onto the front burner at some point? Or are you basically just moving on from a capital allocation standpoint towards renewables at this point?
Yes. I'd say, Patrick, look, we have a pretty strong sort of internal view of how we expect the market to kind of developing in terms of the additions coming in and also kind of demand or load increase over time. Sundance 5, we don't really think, is a project that will come back from a TransAlta perspective, certainly not in the way that it was originally configured to be developed. We're pretty comfortable with our shift and kind of the capital allocation shift that we're seeing. And candidly, we're much more focused in terms of understanding the development of the hydrogen opportunity that we see and some of the technologies there as kind of a leapfrogging of technology going forward rather than really being -- looking to make large kind of merchant bets on sort of gas as we go forward.
That's great. And then just as a related question, John, wanted to get your thoughts on how your relationship with Brookfield might, in essence, give you, perhaps, a first look at certain decarbonization opportunities just given recent developments? Whether it be cogen or waste heat recovery at Inter Pipeline or perhaps accelerating some battery storage opportunities in Western Australia? Again, just curious if you're able to leverage off your direct line with Brookfield there to accelerate your $3 billion investment plan?
Yes. All I can say, Patrick, is, to date, when it comes to sort of opportunity development, we've been pretty arm's length and they've been pretty arm's length from us. So there is, for sure, a focus on kind of the hydro that we have in Alberta and then being involved in understanding the performance of that because that's in essence what they sort of contracted for when we did the transaction a few years ago. But in terms of kind of larger scale cooperation, I mean, never say never, but it hasn't, to date, been a focus for us. And our growth team is very much focused on kind of a stand-alone approach by and large, to kind of landing the transactions and opportunities that we see before us rather than really trying to work in tandem with them.
[Operator Instructions] There are no further questions on the phone line. Please proceed with your closing remarks.
Great. Thank you, Michelle. That concludes our call for today. If you have any further questions, please don't hesitate to reach out to the TransAlta investor team. Investor Relations team. Thank you very much, and have a great day.
Ladies and gentlemen, this does conclude your call for today. We thank you for participating and ask that you please disconnect your lines.