Good morning, ladies and gentlemen. My name is Michelle, and 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. All lines have been placed on mute to prevent any background noise, and after the speaker's remarks, there will be a question and answer session. If you would like to ask a question during that time, simply press star, then one on your telephone keypad. If you would like to withdraw your question, please press star followed by two. 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 qualifications set out here on our slide two, 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. 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 that TransAlta's head office, where we are today, is located in the traditional territories of the Niitsitapi, the people of the Treaty Seven region in southern Alberta, which includes the Siksika, the Piikani, the Kainai, the Tsuut'ina, and the Stoney Nakoda First Nations, as well as the home of Métis Nation Region 3. 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 CAD 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 CAD 993 million in comparable EBITDA, a 43% increase over 2020 results, resulting in free cash flow per share of CAD 1.68, a 52% increase year- over- year. We also announced the common share dividend increase of 11% during the quarter, representing an annualized dividend of CAD 0.20 per share. 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 CAD 100 million and CAD 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 GW 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-MW North Carolina solar portfolio. We advanced the construction of our 206-MW 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 MW 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 this final 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 at the COP26 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 a tower collapse at our Kent Hills 2 wind facility at the end of the quarter. The remaining turbines at Kent Hills 1 and Kent 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-MW 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 projects 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 $9 million in EBITDA annually. Construction of Windrise is complete, with all 43 turbines complete. We now expect to achieve COD later this month. The 206 MW 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 10th wind facility in Alberta and will be the first project to reach commercial operation out of the eight projects awarded by the AESO through the second and third rounds of the renewable energy procurement process in December 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-MW Garden Plain project, supported by an 18-year agreement with Pembina Pipeline for 100 MW of the capacity and associated environmental attributes. We've advanced the developments 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 MW and are aiming to fully contract the facility by the end of this year. We expect the project to deliver between CAD 14 million and CAD 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 spent 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 MW 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 GW 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 CAD 3 billion capital investment target. I 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 CAD 381 million of comparable EBITDA and CAD 189 million or CAD 0.70 per share of free cash flow. On a year-to-date basis, the company has generated CAD 993 million of EBITDA and CAD 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 nine months of 2021 have now exceeded the full-year performance achieved in 2020.
On the net earnings front, with the decision to suspend the Sundance 5 repowering project and retire Keephills 1 and Sundance 4, the company did recognize a number of non-cash asset impairments and other related penalties in Q3 totaling CAD 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 and 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 CAD 28 million in 2020 to CAD 82 million this year.
Similarly, EBITDA from the Alberta Thermal segment more than doubled year- over- year from CAD 47 million in 2020 to CAD 104 million this year. Wind and solar EBITDA was also higher, increasing from CAD 36 million in 2020 to CAD 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 CAD 58 million in EBITDA as compared to an also outstanding result of CAD 49 million in 2020. Overall, TransAlta has delivered three 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 business in more detail. Our Alberta wind, hydro, and thermal facilities are dispatched as a portfolio to benefit from base load and peaking energy sales. During the quarter, the Alberta portfolio generated over 3,300 GWh of production, an increase of 6% over the same period last year, and realized CAD 381 million in revenue. The strong pricing throughout the quarter contributed to the average full price for Q3 settling at CAD 100 per MWh compared to CAD 44 in Q3 of 2020. In the quarter, the Alberta thermal fleet generated approximately 2,500 GWh with an average realized price of CAD 101 per MWh.
In the quarter, we had hedged just under 1,900 GWh of base load capacity, or approximately 74% of our expected thermal production at an average price of CAD 76. The combination of our hedged 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 GWh, of which 1,400 GWh 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 CAD 114/MWh, 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 CAD 95-CAD 105 per MWh. 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 CAD 6 million, largely due to the addition of the Ada and Skookumchuck facilities. Cash available for distribution for the quarter decreased by CAD 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 CAD 450 million and CAD 480 million and CAFD to be between CAD 250 million and CAD 270 million. We continue to have strong liquidity at RNW. In addition to our CAD 700 million committed credit facility, we had over CAD 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 two-thirds of the 2 GW clean electricity growth plan could be candidates for drop down to RNW. Overall, TransAlta has had exceptional year-to-date performance. 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 CAD 1.2 billion and CAD 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 CAD 500 million and CAD 560 million.
This equates to free cash flow per share of CAD 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 CAD 95-CAD 105 per MWh. Second, we are adjusting our annual price outlook for Mid-C to be between CAD 50-CAD 60 per MWh. Finally, based on strong year-to-date results, our outlook for gross margin at the energy marketing segment has increased to CAD 195 million-CAD 210 million. I'm gonna 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 nine months ended September 30, free cash flow has exceeded our 2020 annual results by 27%, with three months of 2021 remaining. Our balance sheet and liquidity remain incredibly strong. We closed the quarter with CAD 2.3 billion in liquidity, including CAD 1.1 billion of total cash. This positions us extremely well to fund our future growth pipeline, including our 500 MW 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?
Thank you. Ladies and gentlemen, we will now begin the question and answer session. If you would like to ask a question, please press the star followed by the one on your telephone keypad. To withdraw your question, please press the star followed by the two. One moment please, for your first question. Your first question comes from Rob Hope of Scotiabank. Please go ahead.
Morning, everyone. First question is just on the outlook for 2022 and your hedging profile. Looks like you added quite a bit of hedges in 2022. Depending on the utilization, you think for your facility, maybe you're 60% covered off on your Alberta thermal units. Could we see you optimistic or opportunistically increase that? Or are you just, you know, taking advantage of what is good pricing in the forward curve right now?
Yeah, Robert, thank you for that, 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. We are still seeing opportunities in 2022 to add some hedges that, you know, 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. With the forward curve kind of being in that low CAD 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. Just switching over to New Brunswick. In the prepared remarks, you mentioned that New Brunswick Power has been a good partner in this process so far. You know, as you go through evaluating, you know, the issues at Kent Hills, are you going to engage the government to see if there is an opportunity to kind of do a blend and extend? You know, if you do have to rebuild some bases, maybe lock that in with a bit of a longer-term contract?
Yeah, Rob, I'd be speculating if I sort of, you know, 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, has 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, you know, 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 that's a win-win for everybody.
All right. I appreciate the color. Thank you. I'll hop back. Thank you.
Thanks a lot.
Your next question comes from Ben Pham of BMO. Please go ahead.
All right. Thanks. Morning. I'm just wondering what your maintenance CapEx outlook, CAD 200 million or so this year, and you're shutting down a couple plants. Like how do you see that shaking out over time? I mean, direction looks like it's moving lower, but can you provide a sense of magnitude of how low would it go?
Hey, Ben, good morning. You were breaking up a little bit, so I'll try to answer the question as well as I can. 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 CAD 80 million or so of spend. A lot of that is oriented around the Keephills 3 coal to gas conversion. We've done some hydro work this year as well, which has increased our capital spending. Over time, you know, 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, you know, we would expect it to be going forward. We would view kind of capital spending in the CAD 180 million-CAD 200 million a year as being high compared to where, you know, 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, you 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.
Yeah. 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 and hydro, definitely an extremely highly valuable asset that we want to make sure that we're putting the appropriate capital in to sustain its ongoing performance.
I would just say that next year, Ben, you know, Sarnia, we're looking at doing a bunch of work there as we're setting up the plant for, you know, its next 10-year run effectively. That'll be an area that we'll be spending some capital, I think, in 2022.
Okay, great. You also mentioned you're looking to maybe add in more hedges for 2022. I'm wondering, like, what's your general philosophy on just the hedges? Like, do you have a certain percentage you like to be at to de-risk your guidance? Do you just look at, you know, your expectations internally versus where the forward curves are? Like, how do you think about that risk reward heading to next year?
Yeah, I'll maybe start, Ben, and then happy to turn it over to Todd to add some color. We've got a team that meets monthly effectively, and we even meet more frequently than that to basically assess our hedge position. When we think of our hedge position, it isn't just on the power that we're expecting to sell. It also includes, you know, our input costs like natural gas as we go through the year. We do tend to look at both. We do fundamental modeling throughout the year. Frankly, it's a multi-year modeling that we do. 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, you know, 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. In general, we tend to be focused, certainly from our thermal fleet perspective, we don't really think of the hydro fleet as being something that we're focusing on. We tend to think about, you know, depending on our market view and pricing view, directionally trying to lock in, you know, the outcome for our more base loaded units. Traditionally, at least even going forward, that would be sort of Keephills 3 for us in terms of where we would be going forward. Hopefully that gives you a bit of a sense. Todd, I don't know if you want to add anything to that. Todd's 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, and 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. Similar to prior periods, you know, 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. 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 marketing team, our optimization team was looking at the forward prices and saying, we don't think that fairly represents where that should be. We came into 2021, what I would say, with low level of hedges. Yeah. Whereas this year we're seeing, as John mentioned, the full forward curve is in the CAD 90 range, low CAD 90 range. The Q1 prices are relatively strong. The team sees that as being fairly valued and willing to lock in more of that volume in Q1.
Okay, that's great. Maybe one more cleanup on Sarnia. You mentioned the 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?
Yeah, 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 wrap up the remaining three 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'll 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.
Yeah. Again, the AESO contract runs through to the end of 2025. There's, you know, maintenance required to get us through to that period as well as beyond.
That's great. Thank you.
Thank you.
Your next question comes from Maurice Choy of RBC Capital Markets. Please go ahead.
Thank you, and good morning. My first question is, you know, I don't wanna 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. How would you characterize this difference in pace? Is it a case where, you know, you under hedged on one versus the other? Or is it a case where you have a difference in outlook on power price versus AECO moving forward? Or to your point, is it a liquidity thing?
Yeah, 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. Maybe I'll try to deal with it discreetly. 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, you know, lock up some of the gas based on, again, our fundamental view of where we thought gas prices were going to go. 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.
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, you know, for our expected, broadly speaking, production profile in 2022 early, which resulted in us getting kind of an average price for gas into 2022 at sort of in that CAD 2.70-CAD 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 six-month forward, whereas on the gas side, there is a lot of liquidity in the market.
As the forward curve has strengthened 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, you know, the ability to be hedging in sort of that north of CAD 90 for 2022, and depending on the period, even higher than that. The team has been layering in hedges just 'cause from a fundamental perspective, we think that that's, broadly speaking, a fair price, as we go into the year. Although we do tend to look at, you know, the demands for fuel on an anticipated production basis, we're not afraid to kinda decouple our decisions on the two, and do what we think is sort of appropriate from an economic perspective going forward. Hopefully that gives you a bit of a sense on how we think of it.
No, it definitely does. Maybe as a follow-up to that, by not securing as much gas hedges for next year, because you've already hedged it, what does that say to what you expect AECO prices to go from this point onwards?
Oh, yeah. I mean, I think, you know, as I mentioned that we expect gas prices in North America to stay elevated. From what we've seen over the past prior years. Our marketing team and our optimization team have had this view for a fair while, that there's been, you know, 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. 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 price. 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.
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 65 cents on kind of the, you know, the dollar in terms of what the cost would be. We're pretty happy with our cost position going into the year. I think we're pretty nicely set up.
Great. Just a final one, hopefully a simple one. Wanted 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 January, and then last year you shared as part of your Q4 results. I suppose visibility this time around is better than last year when there was uncertainty with regards to balancing pool TPAs. What are some of the uncertainties that you're still working on before you can be comfortable releasing your guidance?
Yeah, 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 timeframe, generally speaking. There are some uncertainties. One of the uncertainties is 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, you know, 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 or would come out early in the first quarter.
You know, if we can lock it down, I think our general, at least my our initial preference would be to get it out to the market if we have a sense of where it is. That's what we're trying to work towards doing.
Fantastic. Thank you very much.
Your next question comes from Mark Jarvi of CIBC. Please go ahead.
Thanks. Good morning, everyone.
Morning.
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 U.S. Is there potential to get more than one contract on those U.S. wind projects in Oklahoma? Or is it more likely one this year and then maybe two next year?
Yeah, I think it's more likely that we would see one this year and one or two next year, just in terms of from a timing perspective. You know, the discussions are ongoing there and you know, we're working hard to really lock down our prices, which you know where there is some volatility, right, from an asset pricing perspective, and frankly, even from a delivery perspective, just from the supply chain. Just from our perspective, we need to de-risk that and absolutely de-risk sort of the timeframe for delivering the project. Then I think we'd be able to proceed fairly, I think, expeditiously to be able to get some contracting done.
Okay. Can you guys give any update on South Hedland in terms of it sounds like you guys are close to a settlement, when we might get that? Then, I mean, you do have in your pipeline a solar project in there. Can you maybe just kind of walk us through some of the different options or, you know, whether or not how we can think about EBITDA once you do settle the contract dispute with FMG?
Yeah, I might ask Carrie, Mark, just to kind of address that one in terms of kind of where our state of play is with FMG.
Perfect. Thanks, John. Yeah. 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 do imminently.
Okay.
I think we're pretty close, Mark, and I suspect, I mean, Carrie, it's probably fair to say we. I mean, certainly before Christmas, we'd expect to have it done. And it'd be nice to have FMG, you know, come back into the fold as a customer there.
Got it. Just coming back to Kent Hills, like, your discussion with NB 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? I mean, or maybe it's just too early to make any comment on that.
Yeah, it is a bit early to make a comment on that. I can tell you that, you know, when you have an interruption like the one that we have there, the contractual regime that we have, you know, 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. You know, we're gonna 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. We're not at this point in time concerned about the PPA that we have with NB Power.
Got it. One last one for Todd. I mean, your leverage metrics are in really great shape. I mean, even the numbers are great. You, you're de-leveraging a lot of free cash flow generation. You do have the maturity next year. Just 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 generated, excess cash? Just updated views on the 2022 debt maturity.
Yeah, I think you're absolutely right. I mean, we're looking at all of those options. We had actually thought about making whole the bond ahead of time. The economics just don't work and don't make sense. We're gonna 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. You're absolutely right. We have a lot of flexibility in how we address that bond.
Given that, you know, you've had, you know, really great results, like how do you think about like the go forward, sort of consolidated and de-consolidated leverage? Like do you just treat the most recent results as sort of maybe an anomaly and you can't bank on that going forward? Or just how do you think about this sort of, you know, I guess, cushion you feel like you have right now, at least?
Yeah, 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, 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 CAD 1 billion level. And that's really how we think about it. Exactly as you mentioned, right now if we're flush with cash, that may go down as that maturity comes due. Again, really pushing the growth team to get the capital that we have to work as opposed to paying down debt.
Got it. Makes sense. Thanks for that.
Thanks, Mark.
Your next question comes from John Mould of TD Securities. Please go ahead.
Morning, everybody. I'd maybe just like to start with the corporate PPA market in Alberta and the lay of the land there. You know, you've remarked in the past that it can be tough to contract a full facility, just based on the relative scale of the market, but, you know, we've seen a lot of activity there the last few months. Have you seen any, you know, changes in that market from your perspective, just given maybe a broader push towards more decarbonization and maybe in tandem with the, you know, strong pricing that we've seen so far this year and the outlook for the next couple of years? Any thoughts there?
Yeah. John, good morning, first of all. So maybe two responses to it. I mean, you know, 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, you know, electricity requirements over the upcoming period, as opposed to maybe being more open than they might have otherwise been. That's just kind of a generalized sort of comment. 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, you know, certainly smaller than you would typically see in the United States in terms of, you know, the size that people would be willing to contract for. Although not universally. I mean, you know, I even look at our Garden Plain PPA where you've got 100 MW. 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. You know, 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 Plain, which is 30 MW. I mean, there is definite interest for things of that size and certainly larger at what we think are really competitive pricing. The market remains a good one, I think. Todd, I think you probably agree. Like, it's steady.
Yeah. I think our primary focus, as you mentioned, is on the Garden Plain and recontracting that last portion of capacity there.
For us, John, what we're focused on is when you look at our Ripplinger project, which is a large project, you know, 300 MW in southwestern Alberta, there's cost benefits to that given the scale and the size of that project. You know, finding a 300 MW offtake is not a typical thing to do. That's a project that's gonna require us to, you know, bring a bit of creativity and some partners to see it through. If you see what I'm saying.
Yeah. No, absolutely. That's helpful. Then just a clarification on your Oklahoma wind pipeline, and apologies if I missed this. Can you just remind us where those projects are in terms of the interconnection process and, you know, 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 you'd secure over the course of the ensuing kind of nine-month period. Just to give you an example of that, you know, the Bureau of Indian Affairs, just in terms of the situs of the transmission on the actual wind farms requires some consultation. You know, we're focused on kind of disturbing the affected land as little as we possibly can. In general, you know, 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 you know, advanced discussions with equipment suppliers, advanced discussions with EPC contractors. You know, actually working out you know, the timeframes, the schedule for the actual construction. As I mentioned in my comments, in exclusive discussions really for potential offtakes of the entire 500 MW in the region that we have in an advanced stage. Pretty advanced, I'd say.
Okay. Great. You know, maybe one last question on how you think about energy marketing guidance. Y our objective on the gross margin side there, I think has about doubled from where it was in your original guidance. I can appreciate there's been some weather volatility and unit volatility that you know may have supported that. You know, is there a path. 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 so far this year? Or is that really event driven and you wanna be conservative on how you think about it going into the year?
Yeah, John, I would think of it as it was an exceptional year, exactly as you spoke about with some really you know really interesting market dynamics throughout the U.S. and primarily through the West U.S. between the Mid-Columbia, California and Southwest Power Pool. It was really you know being positioned to take advantage of a market disconnect and make some you know good opportunities to make some dividend in those periods. You know we'll be thinking about that as we set our 2022 guidance as to what the right level is.
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. It's not like we can predict a number of opportunities, and in fact, you know, over the last couple of months, we've seen some of that, the market pricing disconnects flatten. We've seen a lot more flat price through the Western U.S. over the last month or so.
Okay, great. Thanks very much.
As my team tells me, you know, you can never predict what weather event is going to occur or what other market event is gonna occur that's gonna drive an opportunity. You know, 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 two, three years, we've seen, you know, 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. 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, you know, the confluence of a couple of factors to see it through, kinda continue, for a period of time now. You know, how long and with what degree of certainty is always challenging. I think certainly our expectations in terms, you know, 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 five years ago, for example, from a metric perspective. Hopefully that gives you a bit of a sense.
Okay, great. Those are my questions. Thanks very much.
Thanks, John.
Your next question comes from Andrew Kuske of Credit Suisse. Please go ahead.
Thanks. Good morning. I guess my 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, you know, 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? Then a related question, does that start to motivate you to drop assets down on an accelerated basis in the RNW?
Yeah. Great, great question, Andrew. I mean, we're focused on a few things. One of them would be, you know, first and foremost, getting the thre 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, you know, 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.
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, you know, as robust and certainly larger than it is today. You know, 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, you know, 2021, 2022, 2023. 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 kinda help the transformation of the company and the pivot effectively from a strategic perspective that we've embarked on that we announced to investors. Hopefully that gives you a bit of a sense.
It does. It's helpful. I guess maybe the bigger picture perspective on this, if you sort of thought about your internal five- and 10-year plans, you know, are you, given the performance you've had this year, effectively establishing a much solider, so more solid base to be farther down the road in those five- and 10-year plans than you previously thought you were, and then thus the emphasis on the growth pipeline for the future.
I think that's exactly right. You know, we've set the targets that we've set in terms of where we wanna 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-focused on just being disciplined, making sure that we get the right, you know, returns that we need. We do see, you know, return compression in a number of parts of the world and a number of the technologies, and we're just gonna be choosy and we're 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 it, just built 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. That is definitely something that we're looking at. You know, 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, you know, by another 100 MW there. I'm glad you actually raised it. That's actually one of the first places we go to see whether or not we can use some of that existing infrastructure that we have, expand the footprints of the assets that we have, which permits us to do it on a cost-competitive basis. For sure that's the case. Even some of the you know, storage opportunities that we're looking at in Alberta, when we're looking at pumped storage, again, that is oriented towards using you know, expanding really the footprint, if I can use that expression, of our hydro in the province to extract more value. For sure, that's a priority.
Very helpful. Thank you.
Your next question comes from Naji Baydoun of iA Capital Markets. Please go ahead.
Hi. Good morning.
Good morning.
Just wanted to go back to the cash balance and capital allocation. You know, I appreciate the focus on the project developments ahead of 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?
Yeah. Naji, thank you for that. 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. That's a never kind of ending process that we have. 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. That's a yes, definitely, in terms of where 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 is a topic Todd and I continue to discuss and evaluate. You know, when we look at least from a deconsolidated cash flow perspective, that bucket that we've allocated for growth, you know, debt repayment, and we're pretty happy where we are from a debt perspective. You know, share buybacks, it's 30%-50% of that cash flow segment. That's another piece of the pie that we continue to assess. Todd, I don't know if you wanna add any color.
I think you were also looking at sort of the size of the M&A that we've been looking at. 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. Our focus really is on what I'll call that, you know, 100 to maybe 400 MW size M&A transaction of single asset or portfolio.
Yeah. We tend to think of kind of our floor size in terms of acquisitions as sort of being in that CAD 100 million range, roughly speaking.
Okay, great. That's very helpful. Just a clarification question on Sarnia. I guess the MD&A or the press release, it kind of reads as if the contract with the AESO 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.
Yeah. 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 you know 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 AESO there, and I know our team is engaged in discussions with the ministry and also participating with the AESO there as they begin to plot out kind of the procurement of medium- and longer-range capacity to meet the needs of Alberta, you know, for the balance of the decade.
Okay. Thanks for the detail.
Thanks.
Your next question comes from Louka Nadeau of National Bank. Please go ahead.
Hi. Good morning. My first question, I cut out early, so I hope 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 timeline should we look for, a potential settlement in that regard?
Yeah. Louka, good morning. It really is premature for us to really be able to provide you with any sort of, you know, 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. 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. Thank you very much. A quick other one. In terms of I don't know if you are able to give any guidance for the timing of the assessment, the engineering on the other, like, turbine?
Yeah. That's ongoing. Todd, I'd say our, at least my best estimate right now is we're probably six weeks, maybe eight weeks, away from getting that work done. The work is really in two 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 a 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. It's really those two key elements and we've got different players that are involved in those elements as well. You know, I think a good outcome from a timing perspective, just being realistic about it would be, you know, 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.
All right. Thank you very much for the color. That's it for me.
Sure.
Your next question comes from Patrick Kenny of National Bank Financial. Please go ahead.
Yeah, good morning, guys. I just wanted to come back to Sundance 5 here and, you know, given the robust pricing environment, economic tailwinds in the province, just assuming we do get clarity over the next year 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?
Yeah, 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. You know, 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.
You know, 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, you know, looking to make large kind of merchant bets on sort of gas as we go forward.
That's great. Thanks for clarifying. Just as a related question, John, wanted to get your thoughts on how your relationship with Brookfield might, in essence, give you a perhaps a first look at certain decarbonization opportunities, just given recent developments, you know, 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 CAD 3 billion investment plan.
Yeah. You know, 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. There is for sure a focus on kind of the hydro that we have in Alberta and them being involved and 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. You know, in terms of kind of larger scale, you know, cooperation, I mean, never say never, but it hasn't to date been a focus for us. You know, our growth team is very much focused on kind of a standalone 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.
Great. I'll leave it there. Thanks, John.
Great. Thank you, Patrick.
Ladies and gentlemen, as a reminder, if you do have a question, please press star one now. There are no further questions on the phone line. Please proceed with your closing remarks.
Great. Thank you. 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 line.