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Good morning. My name is Sylvie, and I will be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation's Second Quarter 2021 Results Conference Call. [Operator Instructions] And I would like to turn the conference over to Chiara Valentini, Managing Director, Strategic Finance and Investor Relations. Please go ahead.
Great. Thank you, Sylvie. Good morning, everyone, and welcome to TransAlta's Second 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 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 Slide 2, details 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 stated. 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 the year. 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 second quarter call. As part of our commitment towards reconciliation, I want to begin by acknowledging the TransAlta's head office, where I am today, is located in the traditional territories of the Niitsitapi, the people of the Treaty 7 region in Southern Alberta, which includes the Siksika, the Piikani, the Kainai, the Tsuut'ina and the Stoney-Nakoda First Nations as well as the home of Metis Nation Region 3.We've had another outstanding quarter. I'm extremely pleased with the performance of our company and the progress that we have made in advancing our priorities. In Q2, we delivered a 39% increase in comparable EBITDA, which has resulted in a 55% increase in free cash flow per share quarter-over-quarter. And year-to-date, we have generated a 40% increase in comparable EBITDA, which has resulted in a 38% increase in free cash flow per share year-over-year.Based on our strong year-to-date performance, along with our expectations for the balance of the year, we're pleased to increase our EBITDA and free cash flow guidance for 2021 by 13% and 22%, respectively, at the midpoint compared to the original guidance we provided for 2021. Todd will provide more details on our revised guidance later in the call. Our access to liquidity remains strong, and we're able to fully fund our remaining conversion to gas at Keephills 3 as well as our growth pipeline, and we continue to achieve improved safety performance year-over-year. Our performance this quarter was driven by operational and optimization excellence across the fleet, which enabled us to capture the higher prices experienced in Alberta. The Alberta team has developed key operating strategies that ensure our fleet has high availability during periods of increased demand so that we're able to provide reliable power when it is most needed. For the second quarter in a row, our Alberta hydro and thermal segments have demonstrated the underlying value of our diversified Alberta fleet. Energy marketing also had an excellent quarter with strong trading results on our -- across our U.S. power and natural gas desks. During the quarter, we also progressed a number of our key priorities. In late July, we announced that we had reached an agreement to provide BHP Nickel West with a 48-megawatt hybrid solar and battery energy storage solution. The project will reduce BHP's greenhouse gas emissions at Leinster and Mt. Keith in Western Australia by 540,000 tons of CO2 over the first 10 years of operation.This project is a concrete example of TransAlta supporting our customers' drive to achieve their ESG goals. In early May, we announced our 130-megawatt Garden Plain wind project, which is contracted to Pembina Pipeline and is another example of how we're focused on enabling our customers to achieve their ESG goals. We advanced construction of our 207-megawatt wind rise project. As of June 30, the facility was 88% complete, and we expect to achieve COD during the fall of 2021. In Q2, we completed a contract extension at Sarnia with an anchor and long-standing customer. We continue to advance recontracting discussions with our other industrial customers with whom we expect to execute contracts later in the year.In July, the ISO released draft details for the procurement of capacity in Ontario for 2026 and beyond. We're participating in the consultation process with the ISO seeking to secure a contract renewal for the facility. At the end of June, we closed the previously announced sale of the Pioneer Pipeline to ADCO, which provided $128 million of proceeds to TransAlta. These funds will be redeployed to our renewables growth program. Our coal to gas conversion of Keephills 2 began during the quarter and was successfully completed in July. The conversion of Keephills 2 reduces our carbon emissions by more than half of that unit. And this is another significant milestone for TransAlta as we transition off coal.Sheerness 1 and 2 are now fully off coal and have been registered as gas-fired steam generation assets with the ISO. We advanced our preparations for our Keephills 3 coal-to-gas conversion, which will start in September. With the completion of this conversion and the closure of the Highvale Mine effective December 31, all our Alberta facilities will be generating on lower carbon natural gas at year-end. We continue our evaluation of the Sundance 5 repowering in light of the higher costs, the changing supply and demand dynamics of the Alberta market as well as the evolving regulatory environment. In Q2, we completed an additional competitive tendering process for the engineering, procurement and construction contract, and we are now reviewing those bid results as well as the overall Sundance 5 repowering project costs.To date, we've delivered over 26 million tons of annual greenhouse gas reductions, representing approximately 8% of Canada's goal of reducing between 292 million and 329 million tons of CO2 from 2005 levels by 2030. On the renewables front, we progressed our 300-megawatt White Rock East and West and 200-megawatt Horizon Hill wind projects to an advanced stage and are actively seeking and discussing contracting opportunities to move them into construction.We also added 500 megawatts of renewables to our growth pipeline, which is a continuing focus for our company. And finally, TransAlta Renewables was named to the Best 50 Corporate Citizens list, a proud achievement for our team. We are pleased to be able to announce our new Northern Goldfields solar and storage project with BHP. The project is the first renewable energy project to be developed under the power purchase agreement we extended with BHP back in October 2020 and initiates the growth of our renewables fleet in Australia. The project comprises 2 solar farms, totaling 38 megawatts, and a 10-megawatt battery energy storage system. Total construction capital is estimated between $64 million and $68 million. This is another concrete example of our customer-centric solution strategy at work. Our goal is to be the supplier of choice for customers who are focused on sustainable growth and decarbonization. The project will be integrated into our Southern Cross remote network in Western Australia. It is our first hybrid solar battery project that integrates our customers' desire for lower carbon intensity alongside the need for reliable power to ensure effective and more sustainable mining operations. Once completed, the project will be one of the world's largest off-grid hybrid network supporting mining operations and further improves BHP's position as one of the lowest carbon nickel miners in the world. The project is expected to be completed during the second half of 2022 and will generate incremental EBITDA between $8 million and $9 million annually.On May 3, we launched the Garden Plain project and are extremely excited to have Pembina Pipeline as a new customer. Working with customers like Pembina to develop low-cost, reliable energy solutions in support of their sustainability goals is a cornerstone of our strategy. As we've announced, the project will have 130 megawatts of capacity and is supported by an 18-year agreement with Pembina for 100 megawatts of the capacity and the associated environmental attributes. We expect the project to deliver between $14 million and $18 million in comparable EBITDA on a full year basis.We have executed the turbine supply agreement for the project and are scheduled to commence construction later this year. We expect the wind facility to reach commercial operation during the latter part of 2022. We remain customer centered on growth, focused on delivering customized clean power solutions to meet our customers' ESG objectives in the most cost-effective manner. A key element of this goal is expanding our renewables business with the objective of advancing a wind project out of our U.S. wind development portfolio this year. We currently have 500 megawatts of advanced stage wind project in our growth pipeline, which have the potential to become commercial in the 2023 to 2024 time frame. We're progressing development activities on Horizon Hill and White Rock East and West, which are located in Oklahoma and are engaged in exclusive discussions and processes regarding opportunities to contract the output from the facilities. We now have over 2.5 gigawatts of earlier stage opportunities in various geographies with the focus on renewables. Our development team is keeping busy in Canada, Australia and the United States.I'll now turn it over to Todd to take us through our financial results for the quarter.
Thanks, John. We had an outstanding quarter, and our diversified fleet continued to deliver strong results with $302 million of comparable EBITDA, driven by robust results in our Alberta electricity portfolio and our energy marketing business. Strong EBITDA results are reflected in our free cash flow numbers for Q2.In the quarter, we generated $138 million or $0.51 per share of free cash flow. On a year-to-date basis, the company has generated $612 million of EBITDA and $267 million of free cash flow. We are extremely pleased with our performance so far this year. With the expiry of the PPAs, both our Alberta hydro and Alberta Thermal segments benefited from strong pricing in the Alberta market as well as from the great work of our asset management and optimization teams. EBITDA, from our hydro fleet, continued to significantly outperform this quarter, realizing an over threefold increase from $29 million in 2020 to $96 million this year. EBITDA, from the Alberta Thermal segment, also significantly increased year-over-year from $30 million in 2020 to $85 million this year. Although I note that realized cash flow at Alberta Thermal continues to be impacted by the planned sustaining capital expenditures related to our conversions to gas.Our energy marketing team delivered another strong quarter, in line with excellent results delivered in Q2 of 2020. Production from our wind and solar segment was lower than 2020 due to lower wind resources across all regions. This impact of lower wind resource was partially offset by the addition of the Skookumchuck facility. Results from the North American gas segments -- segment were below expectations due to unexpected outages at our Sarnia facility. The decrease in EBITDA was partially offset by the addition of the ADA facility and higher realized pricing in Alberta at the Fort Saskatchewan plant. Centralia's EBITDA decreased by $13 million compared to the same period in 2020, mainly due to the retirement of Centralia Unit 1 at the end of 2020 as well as planned and unplanned outages, which necessitated power purchases during high merchant pricing to meet contractual obligations.Cash flow decreased by $16 million compared to the same period in 2020 as a result of the timing of planned major maintenance as we are setting up the plant for its final run to retirement at the end of 2025. Overall, TransAlta delivered outstanding back-to-back quarters, and we are very pleased with both the results across our diversified fleet and the realization of the potential of our Alberta generating fleet. I want to thank all of our employees for their contributions in achieving these results. I'm going to spend a few minutes on the next slides to discuss 2 of our core businesses, our Alberta electricity portfolio and TransAlta Renewables.Turning to Slide 11. Our Alberta wind, hydro and thermal facilities are dispatches a portfolio to benefit from base load and peaking energy sales. During the quarter, our Alberta portfolio generated over 3,000 gigawatt hours of production and realized $352 million in revenue, including our Alberta wind fleet. Power prices in Alberta and in other Western regions were significantly impacted by the warmer weather experienced in Q2. As is typical during periods of extreme weather patterns in Alberta, wind production was significantly reduced. This reduction of supply during peak demand periods was anticipated, and our teams ensured that our dispatchable capacity was available to meet the increased provincial load. In June, with temperature soaring and extreme heat, power prices averaged $141 per megawatt hour. The strong pricing in June contributed to the average pool price for Q2 settling at $105. In the quarter, the Alberta Thermal fleet generated approximately 2,400 gigawatt hours with an average realized price of $93 per megawatt hour. Our realized price was slightly lower than the average settled pool price due to the impact of our hedging program. In the quarter, we had hedged approximately 1,700 gigawatt hours of baseload capacity or approximately 71% of our expected thermal production at an average price of $62 per megawatt. The combination of our hedge revenues and our peaking sales from periods of high market demand and disruption resulted in revenues at Alberta Thermal being significantly higher than 2020.For the balance of the year, we expect similar total production of approximately 2,300 gigawatt hours in each of Q3 and Q4. With hedges more heavily weighted to the near term, we have approximately 1,800 gigawatt hours hedged in Q3 and 800 gigawatt hours hedged in Q4. We continue to see strong forward prices for the balance of the year, and the Alberta Thermal segment continues to retain significant open capacity in order to realize potential higher pricing experienced during times of peak market demand. As we complete the transition of our thermal fleet to gas, we expect to see significant reductions in our carbon compliance costs. In Q2, roughly 40% of our production at Alberta Thermal was from coal firing at our unconverted units. Currently, our coal generation carries a carbon burden of about $27 per megawatt hour. By contrast, the carbon burden on a fully converted gas unit is significantly less at about $8 per megawatt hour. In Q2, we incurred a total carbon compliance cost at Alberta Thermal of $37 million. Had the conversion program been fully completed, the same production would have incurred approximately 50% of the compliance costs. Turning to hydro. The ability of hydro to capture peak pricing was again demonstrated in Q2, with average realized prices of $133 per megawatt hour, which represented a 27% premium over the average spot price. This premium was consistent with the premiums realized in Q1 as well as in high price periods in 2019 and 2020. Energy and ancillary volumes at Hydro were broadly in line with expectations for the quarter, but 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 at approximately the $80 level. The higher average prices experienced year-to-date have largely been a result of market disruptions, higher demand stemming from extreme weather, unplanned generator outages, tie-line line outages and a low wind resource.I'd now 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. On April 1, we completed the transfer of the economic interest in the Skookumchuck Wind and the Ada cogeneration facilities from TransAlta to TransAlta Renewables. The economic benefit of these transactions was effective as of January 1, and the year-to-date results of these facilities are included in the Q2 results. Comparable EBITDA for the quarter and full year expectations were impacted by a number of factors, including unplanned outages at Sarnia, which impacted steam supply to our customers and lower wind production due to variability in wind resource. Although steam supply disruptions of this nature are atypical and infrequent, these interruptions resulted in a provision for liquidated damages, which we expect to resolve later this year.In addition, wind production in the first half of the year was at 92% of long-term average, with lower wind resource experienced across all operating regions. We also took the decision to accelerate the acquisition of a critical spare at South Hedland to ensure reliability for customers, which will impact our full year sustaining capital. In light of these events, the company is revising our previously issued guidance for TransAlta Renewables for the 2021 fiscal year. Comparable EBITDA for 2021 is now estimated to be between $470 million and $500 million, and cash available for distribution to be in the $260 million to $290 million range due to the lower EBITDA and the planned acceleration of the acquisition of a spare turbine for the South Hedland facility.In terms of growth, we expect TransAlta Renewables to acquire an economic interest in the recently announced BHP Solar project, referenced earlier, as TransAlta Renewables has the right to invest in any expansion project related to its current assets. The Northern Goldfields solar and storage project investment was approved by the TransAlta Renewables independent Board members and the company looks forward to adding the first renewable generation assets to the Australian fleet. We also anticipate that the Garden Plain project that John also referenced earlier would make an excellent drop-down candidate for TransAlta Renewables in the near future given it's anchored by a long-term PPA and a strong counterparty.We also continue to seek additional renewables projects to add to our fleet through M&A and TransAlta's development pipeline. Overall, TransAlta Corp. has had an outstanding year-to-date performance, which, when considered with our expectations for the balance of the year, permits us to increase our EBITDA and free cash flow guidance for 2021. We are now estimating comparable EBITDA to be between $1.1 billion and $1.2 billion, representing a 13% increase at the midpoint of the range versus our previous guidance.This EBITDA expectation allows us to increase our free cash flow guidance range to $440 million to $515 million. This equates to a free cash flow per share of $1.77 at the midpoint, which represents a 22% increase over our previous guidance. Our free cash flow yield at the midpoint of our revised guidance using our current trading price of approximately $13 represents a consolidated free cash flow yield of about 13%. In addition to our estimates for consolidated EBITDA and free cash flow, we have revised several other areas of our outlook. First, we are increasing our outlook for gross margin at the Energy Marketing segment to a range of $170 million to $200 million. Second, we have increased our expectations on sustaining capital to $200 million to $225 million.The increase in sustaining capital is driven by the acceleration of a spare engine purchase for South Hedland facility in Q3, higher sustaining and maintenance capital at our hydro fleet and slightly increased costs for major maintenance at Keephills 2 and Keephills 3, largely driven by enhanced COVID-19 safety protocols. And third, we're adjusting our annual price outlook for Alberta to $80 to $100 per megawatt hour. This reflects the balance of year estimate Alberta price of about $80 per megawatt hour.With respect to our expectations for the Hydro segment, our initial guidance was based on hydro EBITDA being in the $200 million to $225 million range. Based on strong performance to date, combined with our outlook for the balance of the year, we are now expecting the hydro segment to generate EBITDA closer to $300 million. The hydro assets provide TransAlta shareholders a unique opportunity to participate in renewable and reliable capacity in the Alberta market. I'm going to close my remarks on Slide 14 and highlight our trend of strong free cash flow performance and the continuing financial strength of the company.In the 6 months ended June 30, free cash flow has exceeded the 75% mark of our 2020 annual results with 6 months of 2021 remaining. Our balance sheet and liquidity remain incredibly strong. We closed the quarter with $2 billion in liquidity, including approximately $650 million of cash. This positions us extremely well to fund future growth. Our senior corporate debt level has been reduced to $1.1 billion, which is below our targeted level and at the lowest level in over 5 years. When we net off the impact of cash held at TransAlta, our deconsolidated net senior debt is about $700 million. This results in an adjusted debt to comparable EBITDA of 3.1x, giving us a robust financial position as we continue through 2021.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 construction of Windrise, completing the Keephills 3 coal-to-gas conversion, completing the recontracting of our 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 what I think makes TransAlta a highly attractive investment and a great value opportunity. First, our cash flows are resilient and supported by a high-quality and highly diversified portfolio as evidenced by our year-to-date results. 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 as well as good governance, places 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 are our greatest asset and I want to thank all our employees and contractors for the work that they have done to deliver our results this past quarter. We're committed to a company culture where everyone belongs and can bring their best in authentic cells to deliver great results for our company. TransAlta has had an exciting time in its development, and we are 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.As I mentioned in the last quarterly update call, we will be hosting our 2021 Virtual Investor Day on September 28. At that time, we'll explore with you our strategic plans for 2022 and beyond. With that, I'll turn the call back over to Chiara.
Thank you, John. Sylvie, would you please open the call up for questions from analysts.
[Operator Instructions] And your first question will be from Mark Jarvi at CIBC Capital Markets.
I just wanted to go to the Sun 5 repowering and this commentary about evaluating. I just wanted to see what your sort of implying there around cost when you're out there looking for, again, the updated bids? Are you implying that the costs can go up from the $900 million to $950 million. And then the second part would be, if you don't like what the costs are and questions around supply dynamic, what are the options? It seems like you've retired the asset effectively. So that can't -- maybe can do employer conversions? Or is it simply just or nothing in terms of the repowering for Sun 5?
Yes. Mark, thanks for the question. So on Sundance 5, so there's a number of questions that you had in that. In terms of what we were signaling in terms of the increase in costs we were seeing in the unit, we continue to be broadly aligned there. We went out and did another tender process to make sure that we were getting the best possible cost that we could for the project. We continue to evaluate going forward. We've made no decisions on finally proceeding with the project. We're for sure looking at kind of the evolution of supply in the province over the course of the coming decade and thinking about everything on when it would make sense to bring the unit, which might be exactly as currently planned and also continuing to assess kind of the regulatory environment in terms of the implications of the federal government approach to carbon pricing for new combined cycle gas plants. So that's all in the mix, and that remains live in terms of the assessment that we're doing for that project. In terms of the mothball, I think it was on July 28, we made the announcement to basically end the mothball. So the unit will not be returning on November 1. Remember, it hasn't been converted to a gas unit. It would have been required to run on coal-fired generation. And as you know, we're shutting down the mine at the end of the year. So really for us, this is -- it's almost an administrative kind of approach where we're parking the unit at this point in time, no plans to bring it back prior to making a decision on Sundance 5 and certainly not making any decision to bring it back on coal nor having made any decision to do a coal-to-gas conversion there either.
But just to be clear, you still could go to a plan B and do a simple conversion like you did for the Keephills units and Sun 6, if you so to...
That would be possible to do there, yes.
And with the time line of the first half of 2024, to stick to that target completion day, if that's what you intended. When would you have to make a formal decision on Sun 5 of whether or not to go ahead?
I think just going from memory, it would be sometime later this year, Mark.
Okay. And then can you guys provide a bit more context on the Sarnia issues with the steam interruption in terms of whether or not there's any cost still to bear and liquidate damages or essentially what we saw as a hit to the Q2 numbers is all done and there's no forward impact.
Yes, Mark -- so we had 3 very unusual for us, very typical. I think as Todd said in his comments, we had 3 outages. And I think, Todd, it was over the course of about 3 weeks. It was very unusual in terms of steam interruptions there. The plant is up and running. We're not expecting any sort of significant sort of sustaining capital or other capital costs associated with the outages. The liquidated damages are effectively as shown in the financial statement. So effectively, the event, which was unusual is contained from our perspective, and we're really proud of the way that we were able to work with our customers in Sarnia to kind of bring them through the channels that we were facing and be as responsive as we could to their needs.
Okay. That's good to hear. And last question, this is for Todd. Just in terms of the hybrid solar project in Australia, the economics that you guys have shown from the CapEx and EBITDA projections, I assume, is sort of like to TransAlta core, how would we adjust those numbers to think through in terms of what that might look like at the TransAlta Renewables level in terms of either development premium or associated costs in terms of bringing that asset online just in terms of what that could look like in terms of EBITDA net to TransAlta renewals.
Yes, Mark, I would say any development fee, is modest. Those economics effectively roll up to TransAlta renewables.
Next question will be from Dariusz Lozny at Bank of America.
Just wanted to touch on the unplanned outage at [indiscernible]. Can you just speak to that in a little bit more detail, please? I know the queue kind of referenced that there were 3 separate events. So just curious if you could give a little bit more clarity as far as how those went.
We had -- I'm not sure that there's a lot more that I can give you Dariusz. We had sort of 3 technical issues, which occurred, I think 2 of them occurred pretty proximate to each other. And then we had a third one that occurred subsequently. They weren't related events. They were very much sort of stand-alone events, and the facility is back up and running at this point in time. Todd, I don't know if you can add more color...
Maybe I'll just add a bit more color. I mean steam interruptions are extremely infrequent and rare in these facilities. As you know, the [indiscernible] facility, especially Sarnia is designed with a lot of N minus 1 duplication reliability in order to maintain that steam supply to customers. In this particular case, the first outage occurred. And while they were in the process, they did restore steam supply, but not fully restore all of the redundancies in the plant. And while they were in that process, another event that normally would have been covered through redundancy. Unfortunately, all of the redundant systems were not back up and running, which triggered another outage. And so they were just into a bit of a catch-up game of trying to get the plant fully restored to all of its N minus 1 reliability, which is why a couple of these events triggered. But as John mentioned, they were unrelated. And it is an extremely rare event. And it's just unfortunate that all of the redundancies weren't actually available for the second and third events.
Okay. And one more just on the R&W updated guidance, if I could. Just you referenced some lower-than-average wind performance for the first half of the year. Can you speak to sort of what's embedded in your expectations for the balance of the year at the wind assets and also broadly across the portfolio?
Yes. Unfortunately, in wind, you can't say that the first half was at 90% and the second half will be at 110. So our balance of year forecast is based on a P50 results, so basically an average second half wind result. Again, we did see a lot of heat in July. So July as well was a weak wind resource. But the back half of the forecast is based on sort of average production.
Yes. we were, I think, 92% in the first half.
In the first half.
Next question will be from Rob Hope at Scotiabank.
I want to circle back on Sun 5 and kind of the evaluation of that project. One point of clarification. The offtake block with Shell from the Kineticor turbine, if you were not to proceed with Sun 5, could you port those over to your other portfolio?
Yes, Rob, that's a great question. So we do not view the -- the arrangement with Shell as being contingent on any specific units. So our view is that we would be able to allocate them to other areas of the portfolio of generation in the province.
And then I guess just more fulsome in terms of kind of the capital allocation question. Sun 5, if the costs further increase, there is quite a bit of a capital spend for a good amount of merchant capacity there. When you take a look at the suite of projects that you have under the umbrella, are we increasingly seeing better opportunities on the renewable side? And if Sun 5 doesn't go forward, could we see increased investment in renewables as well as a potential acceleration of the share buyback?
Yes, Rob, that's a great question. So when we look at sort of Sun 5 and we look at sort of the development pipeline that we have, we tend to look at them kind of at an equivalent level in terms of how they compete for capital, allocation in the company. So when we look at our renewables fleet, which, to your point, would be more bite-size pieces, more contracted probably, in some respects, lower risk, it just factors into the way that we're looking at the capital allocation between the 2. And in the event that we weren't to proceed with Sun 5 or it ends up being developed in a different kind of manner, there would potentially be more capital to accelerate kind of the renewable side of the equation.In terms of share buybacks, I mean, Todd, you can comment about that, too. But we're very much focused on doing that when we think it makes sense based on the trading price of the shares. And we've typically bought them at prices sort of at a sub-$10 level. And given where we're trading right now, the share buybacks aren't -- I don't want to put words in Todd's mouth kind of a priority for us.
Actually, I think that's a fair characterization that we see a lot of good opportunities to deploy capital. Certainly, our capacity buyback shares is there to support the stock and buy it back at opportunistic prices.
Okay. And then just one follow-up question. The Hedland settlement that was struck in May, any updates there in terms of progress and well as potential outlooks in EBITDA?
Sure. I might -- Rob, I might turn that over to Kerry. Hopefully, you can hear her here.
Rob, nice to hear from you. We're still in the process of finalizing the settlement, and we should do so in the imminent -- in the coming weeks.
Next question will be from Maurice Choy at RBC Capital Markets.
My first question is just also another follow-up on Sundance 5. It sounds like everything is -- remains on the table, including a boiler conversion like Sun 6. But within your list of options that are in front of you, is there any contemplation to repower the project using newer and more efficient technology instead of the ones -- instead of turbines from Kineticor. And to that end, how marketable is it to sell the Kineticor turbines that you bought back in 2019?
Yes. Maurice, thanks for that. Look, we are looking at Sundance 5, including sort of the competitiveness of the unit in light of the new build that is being proposed to be added to the province over the course of the next 7 or 8 years or so, which is pretty significant. We're still at an evaluation phase. I wouldn't say that we've made any kind of decisions in terms of replacing the class of turbines that we have, for example, a different class of turbine or turbines that would have a dual fuel capability, for example. So I don't want to speculate in terms of where that would land. And at this point in time, I wouldn't comment on not proceeding with the project and what we'd be able to recoup for the existing equipment there.
Fair enough. And not that I want to tee up the September 20 event, but is it likely that we'll hear more about that on that day in terms of decision making? Or is it more like end-of-year type of decision?
We're working hard to be able to provide more clarity certainly by Investor Day, Maurice.
Great. And just to finish off, I wanted to just come back to energy marketing. Obviously, the guidance has been improved to $170 million to $200 million and that represents an upward trend from $120 million back in 2018, $140 million in 2019. I recognize that some of the stronger performance is some more circumstantial sometimes based on different years. But is there a sign of a more permanent change in the profitability of this segment moving forward?
I'm going to turn that over to my friend, Todd, who oversees the group.
Yes. I'm not sure, like certainly, the floor is well positioned to take advantage of opportunities that present themselves in the market. And really, the regions we're talking about here are, the Western and Eastern, U.S. markets as well as natural gas across North America. And really, what it takes there is market opportunity. And so volatility is one of the key things that they look for, price dislocation and really the opportunity to source power, to source energy in one jurisdiction and move it to another. And that's predominantly how the team looks to generate profits. And that's something that we've seen, whether it's from heat waves in certain areas or cold periods in other parts of times of the year. Even quite frankly, forest fires and other disruptions of transmission and, et cetera, give the teams opportunity to look for margin by moving power around and arranging transport and transmission.So I would say volatility is what creates the opportunity and renewables is a big part of that volatility as well. So I would say we are seeing structural changes that could see an upward shift in that number?
Yes. And I just think as a talk with the increasing heat that we've seen over time in that part of the world and increasing demand, the change of the generation mix, certainly volatility has increased and the [ forthright ] on that.
Your next question will be from John Mould at TD Securities.
Maybe to circle back to Sun 5 again. Looking back at Q1 disclosures, you'd referenced issuing full notice to proceed later this year. So obviously, that language has been pulled back a little bit. I guess -- what's changed since May in your broader outlook for the project either in the power markets, the regulatory outlook, be it maybe a CCUS requirement down the road or build cost picture that's just maybe made you take a bit of a step back this quarter?
Yes. John, I think it's a great question. I think it's a lot of things. So when you look at the project, I mean, we're very much looking at -- and I'll just give you an example, carbon pricing going to $170, seeing the federal government signal that the performance standard for new gas like Sun 5 would actually decline to 0 by a 2030 time period in terms of just directionally where they're going and seeing that being fully exposed to the carbon price as it's increased over the coming years. We're very mindful of load growth in the province and looking at the increase in the amount of proposed generation, both on the gas side and on the renewable side and working to understand the implications of that for generation of the province as we go forward. So it's really a -- it isn't any one thing, John. It's a confluence of things that I think we're prudently looking at in the context of making the right decision for our shareholders.And I would just add that CCS is also a pretty big uncertainty. I mean it is expensive technology. Our assessment would have the cost of CCS, CCUS be at least equal to the cost of the actual repowering of the project. And it isn't necessarily the case that the technology associated with that is [indiscernible] . So I just -- I wanted to sort of give you a bit of a complete picture.
Okay. And then -- turning to Sarnia and the recontracting outlook there, I just wonder about your thoughts on how the recontracting outlook there has been informed at all by the recent annual acquisition report that the ISO published.
Yes, it's a great question. So for us, there's really 3 elements to Sarnia, and I can turn it over to Kerry to add any color if I omit anything. One is, we do have the Blue Water Energy Park there, and we're working hard to actually expand off-takers on the facility, and we're having some success in doing that. Certainly, over the course of the quarter, we're expecting some of the crypto miners to be interested in that, and we're seeing some success in terms of supplementing the cash flows there. Two, as we indicated in the quarter, we are focused on recontracting with our 4 major off-takers there. We have completed one. Discussions are advancing well with the other 3. And it's kind of good just to have one of them done and creating kind of a good template and sort of a benchmark in terms of pricing for the facility as we go forward, and we're pleased with how that has gone and is going.And then finally, it's the ongoing discussions with the ISO. We're actually pretty optimistic about our ability to recontract a chunk of that plant with the ISO. It is located in a part of the province that we understand does have a power need. It's important in terms of backstopping the needs of industry in that particular region. And size of the offtake that at least we understand the ISO was looking at is sufficiently large, given what would be available to participate that we think it creates a good opportunity for us to be competitive in that and actually secure something that underpins the plant going forward. Kerry, I don't know if there's anything else you'd add to that?
No. I would just note that we're very pleased that they've released the guidance. We appreciate that it's still in the design phase. We're also confident given that the amount of megawatts that will be able to be bid into the process is limited to 2 providers that will be coming off contract at the same time at Sarnia. And we're working closely hand in hand as we always do with the Ontario government with the goal that we provide them with the energy that they need and that we are obviously able to contract the facility to provide our shareholders with those returns as well.
Okay. Great. And maybe just one last one on your growth pipeline. Just looking beyond the Oklahoma projects, which I understand you're advancing offtake discussions there. Where are you seeing among your mid-stage pipeline, the best opportunities to secure potential offtake agreements and move those projects forward?
Yes. Thank you for that. So we think it really falls into 3 areas. We do think that there continue to be opportunities to grow in a similar fashion to what we've seen serving our customers in Australia, and our development team there continues to work to land that. And I think that might be a little bit of gas, but also potentially additional solar that we're able to do there and even potentially win, to be honest, in Australia. In Canada, we're pretty excited about the ongoing demand from industry institutions, commercial entities for renewables here. We're working hard to advance our wind farms that are under development in the province here. And I'm thinking of Riplinger and Willow Creek would be just an example of some of the wind farms there. We're also in the early stages of developing solar in the province, both near [ high bill ] and also in the southeastern part of the province, which we also think is something that we could bring forward. And in the U.S. We continue to see a lot of opportunity in Illinois with our Prairie Violet project, and the team is doing a really good job of increasing our opportunity set in PJM, where we continue to see really strong PPA offtake demand. So it's really, John, all 3 jurisdictions. And I'm really pleased with the fact that we now have defined and identifiable projects that we can specifically kind of feather in, in the medium term.
Next question will be from Andrew Kuske at Credit Suisse.
I think in the MD&A, there was a comment that in Alberta, if you were fully converted in your fleet, your carbon compliance costs would be $15 million to $20 million lower. So I guess the question is more of a broad one. on how do you think about the tension in the market of lower carbon compliance costs for some like yourselves in the conversion process versus escalating carbon prices that are happening on a legislative basis. And where do you think clearing prices wind up? Is there an upward bias over time because of the carbon prices increasing, but there's also a generation mix that's changing in the province.
Yes, it's a great question, Andrew. Maybe I'll try to answer it this way. I mean, we do -- so we do think that -- maybe I'll try to answer it this way. So in general, from a trend perspective, the carbon intensity of the provinces has declined, and I think is going to continue to decline. So for sure, I think over time, we will continue to see that happen. The decline, though, is happening at a rate that is a bit lower than the carbon prices increasing. So we do think that when you get to the sort of the mid and back half of the decade, for sure there will continue to be an increase in carbon pricing that will be impacted and showing itself in the price over time. And in part, that's because we're -- at least our company is presently expecting to see that performance standard for new gas decline over time.So we do see a more muted impact, I think, in the near term. But over time, I think it becomes more and more significant as you get into certainly 2028, 2029, 2030 kind of the bigger numbers and are there and it kind of bites into the emissions profile from whatever natural gas generation exists at that time. I don't know if that answers your question, but...
It does. It's helpful color. And then maybe flipping to just another part of your portfolio in Alberta. What opportunities do you see for really structured power deals on a renewable basis and being able to capture premium pricing for 24/7 kind of green power deals. We've seen them in some other jurisdictions, very few players can offer them because you need a portfolio of assets across the ecosystem to do it. You seem to have all those things. So what are you seeing on that front?
So we actually think it's one of the biggest opportunity sets that we actually see, Andrew. I'm glad you raised it. I'm not sure that our off-takers at least today, are quite there in demanding that product in Alberta. That might change over time. And we're actually seeing a greater focus on that with the mining community in Western Australia, where they're very much interested in reducing their emissions but also having an element of reliability. And I think in part, that's just to the remote nature of their operations. So they're not tied into the grid. And as a result, it's more of an acute issue with them. But I do think that it will become more important over time. And I think you're right, between our existing wind fleet and certainly our hydro fleet, we do have the ability to shape. And we're actually looking at some of the opportunities to add a pretty meaningful amount of storage potentially tied to existing renewable assets in the province. And that's not just wind, but potentially our hydro fleet that can also help some of that shaping in addition to maybe helping meet some of the ancillary services need at the province might have in the future as the renewables build-out continues. So hopefully, that gives you a bit of a sense.
Next question will be from Naji Baydoun at IA Capital Markets.
I know you touched on this earlier, but I just wanted to go back to corporate partnerships. So far to see you've got Garden Plain with Pembina, Goldfields with BHP, it sounds like there's another project or more coming from the U.S. Do you really see corporate partnerships becoming the path forward for growing your renewable portfolio? And if so, what are some of the resources or investments seem to make today to capture those opportunities?
Yes, Naji, great question. So when we think of our renewables growth and frankly, the way we're approaching growth, it is very much customer centered. So our goal is to actually have our development team, and I think this is where we do best to actually be essentially embedded with our customers, our prospective customers, helping them come up with solutions to meet their needs. So do I expect our renewables build out to be largely contracted? I do. Do we expect to see more partnerships along the lines of what we have seen. I think we do. And it's something that we talk about explicitly and are spending a lot of time at the company, making sure that our whole approach to dealing with customers is top of mind. It's actually a real focus internally, and that's everything from the way we interact with customers to the way that we try to standardize our approaches to make it easier for our teams as we integrate our growth going forward.
Okay. That's helpful. And maybe just another question on your development pipeline. It still mostly consist of wind opportunities today, but do you believe you need to maybe diversify or add to your development teams to try to get a bit more into solar and storage? And if that's the case, how do you view solar storage in terms of risk return trade-off versus wind?
Yes. So we do have storage in our portfolio and are actually in the process now of developing incremental storage not just in Australia with what we've just done with BHP, but frankly, in Alberta as we go forward. We think the return equation for storage is becoming better all of the time. And the work that we did with our wind charger opportunity really helped, I think, derisk our own understanding of what we can do with storage in the province and how the economics work. So frankly, we're pretty positive about storage, notwithstanding the fact that the cost of storage remains on the high -- it's a little bit higher than we'd like to see it, but it will trend down.On solar, look, the -- it is a highly competitive space. The returns tend to be compressed, certainly compared to the opportunities that we see from a wind perspective. We are, though, focused on developing our own solar and also canvassing potential acquisition opportunities. On the solar side, we think it's an important technology for our company to have a skill set in, and that remains our focus. It's pretty disruptive candidly, in some parts of the world. And I think as we're looking at the energy transition taking place, it's important that a company like ours has some solar capabilities. So I think you'll see more of a focus than we've traditionally had on solar in our company.
[Operator Instructions] The next question is from Patrick Kenny at National Bank.
Just a couple of follow-ups here. So back on the Alberta hydro results and the healthy realized price achieved relative to spot. I think you touched on it, but can you just clarify how much of a factor the heat wave late in the quarter might have played into elevating the strong performance there? Or did everything play out as expected and that 30% or so realized pricing premium over the spot market is what we should expect from the portfolio going forward, especially as it relates to the seasonally strong second quarter?
Yes. I would say, Patrick -- I would say that I'll try to answer the question maybe in reverse. The kind of premium that we're talking about realizing on the energy side to just sort of the spot price from our hydro is, I would say, Todd, broadly where we would expect our hydro to come in on the energy side. So we would expect it to be broadly having a premium to spot. In terms of kind of the prices that we saw over the quarter for sure, they were in part due to the high temperatures that we experienced. But there were issues with the intertie, there were outages that were pretty significant. Load has come back pretty dramatically in the province. So it was a confluence of a number of events that resulted in kind of strengthened supply and demand kind of fundamentals over the quarter. Todd, I don't know if you want...
I would say nobody expected really high temperatures that we saw in Alberta in June. It was abnormal. As far as the premiums on hydro, it is somewhat correlated to how volatile the power prices are if typically in shoulder months that we would see in like April, May, we would see is more softer prices.
More compression.
More compression, which doesn't give you as much opportunity to realize the peak pricing -- on the super peak pricing in hydro. But certainly, as John mentioned, there was outages, there were tie-line outages and then driven by demand because of the heat, presented all of those opportunities. But we typically do see it in the winter months where we can realize the premiums and then also in the warm summer months of July and August for sure. Yes.
Okay. That's helpful. And then just back to Sun 5. So say it does not allow to proceed. Can you maybe just help us square up your gas supply commitments on Pioneer and NGTL? I believe it's $400-plus million a day starting in 2023. Just square up that commitment with your internal gas consumption forecast under a boiler conversion only scenario across your Sundance and Keephills units? Just want to make sure that you won't be offside with your commitments, if Sun 5 does stay on the shelf for a little while?
Yes. And I wouldn't say that we would be offside any of our commitments. I mean look, Patrick, it's a great question, but I'd be speculating right now in terms of how much gas we would need, depending on the decisions that we end up making with Sundance 5, which could result in a proceeding or not proceeding or proceeding in a different way than we've currently sort of anticipated. In general, we've got more than ample sort of gas supply going forward. As we begin our assessment and evaluation of the plant, we do look at the gas supply equation and the team looks at -- to the extent we have excess supply, what does it mean in terms of us being able to market or remarket those commitments going forward. But hopefully, that gives you a little bit of a flavor, Todd, I don't know if you want to add any...
Yes. I think there's work to be done. But again, like Sun 5 was -- is part of that equation as well. But remember, I mean, we procure gas as well to make sure that we have firm supply for all of the peak days as well. So that does mean by nature, there are going to be days where you're not actually using the entire firm commitment. So I don't see it as a big mismatch or anything at this point in time. And again, no decision has been made on Sun 5.
Thank you. And at this time, gentlemen, we have no further questions. Please proceed.
Great. Thank you, Sylvie. Thank you, everyone. That concludes our call for today. If you have any further questions, please don't hesitate to reach out to the TransAlta Investor Relations team. Thanks, and have a great day.
Thank you. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending. At this time, we do ask that you please disconnect your lines.