TransAlta Renewables Inc
TSX:RNW
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TransAlta Renewables Inc
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Good morning. At this time, I would like to welcome everyone to TransAlta Corporation's First Quarter 2023 Results Conference Call. [Operator Instructions]
Thank you. Ms. Valentini, you may begin your conference.
Great. Thank you, Sergio. Good morning, everyone, and welcome to TransAlta's First Quarter 2023 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 in the phone lines to view the supporting slides that are posted on our website. A replay of the call will be available later today, and the transcript will be posted to our website shortly thereafter.
All the information provided during this conference call is subject to the forward-looking statement qualification set out here on Slide 2, and detailed further in our MD&A and incorporated in full for the purposes of this -- of today's call. All amounts referenced during the call are in Canadian currency unless otherwise noted.
The non-IFRS terminology used, including adjusted EBITDA, funds from operations, and free cash flow are 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, and after these remarks, we will open the call for questions. And with that, let me turn the call over to John.
Thank you, Chiara. Good morning, everyone, and thank you for joining our first quarter results call for 2023.
As part of our commitment towards reconciliation, I want to begin by acknowledging that TransAlta's head office, where we are today, is located in the traditional territories of the Niitsitapi, the people of the Treaty 7 Region in Southern Alberta, which includes the Siksika, the Piikani, the Kainai, the Tsuut'ina, and the Stoney Nakoda First Nations, as well as the home of Metis Nation Region 3.
TransAlta had an exceptional first quarter. We're proud of the overall performance of our company and our employees. We delivered $503 million of adjusted EBITDA, a 94% increase over our Q1 2022 results; and free cash flow of $263 million, or $0.98 per share, a 145% increase over Q1 2022 results on a per share basis. Both metrics beat our expectations for the quarter.
Overall, our benefited from continuing strong power prices in Alberta and Mid-C, complemented by strong operational performance from our fleet and the success of our asset optimization and hedging strategies.
The Alberta market was impacted by stronger power prices in adjacent markets, which lowered net imports into Alberta, encouraged exports of power from Alberta to the Pacific Northwest and, together with increased outages in the province, allowed us to increase overall production from our Alberta gas fleet by 40%, as compared to the same quarter last year.
Our higher capacity factors in the gas fleet, coupled with lower realized gas prices, delivered higher gross margins for our portfolio, compared to Q1 2022. Our Alberta hydro and gas merchant portfolio also benefited from our large and calculated power hedge positions in the quarter.
Our overall availability was strong at 92% despite our ongoing outage at Kent Hills and was driven by the great performance of our Alberta gas fleet, which achieved 96% availability, highly important for delivering on our peaking capacity strategy within the Alberta market. Apart from Kent Hills, our performance was partially offset by weaker availability in our wind fleet due to a lengthy outage at Windrise from a transformer failure due to a manufacturing defect, while snow storms in Hydro One transmission outages impacted our Ontario wind fleet.
During the quarter, we delivered on a number of key priorities. On the growth side, our development team continues to expand our pipeline, adding another 286 megawatts of renewables growth projects. The rehabilitation of Kent Hills is progressing well, with 13 towers fully reassembled and two-thirds of the foundations poured and completed, and I'm pleased to be able to say that commissioning activities have now commenced, with the first turbine energized and currently in its final stages of commissioning.
During the quarter, we returned $36 million of capital back to shareholders through the buyback of 3.2 million shares. We continued to buy back shares in April, returning an additional $29 million of capital back to our shareholders. In late March, we entered into an automatic share purchase plan to facilitate additional purchases under our normal course issuer bid.
This channel now allows us to take advantage of market opportunities, especially in period when the company is in blackout. Our current NCIB program is set to expire in May, and we intend to renew the program with the TSX before it matures. And finally, with another quarter of strong cash flow, our balance sheet position is strong, with excellent liquidity and cash on hand to fund our growth projects.
Turning to our Clean Electricity Growth Plan, to date, we've secured 800 megawatts of growth projects across Canada, the US, and Australia, representing 40% of our 2 gigawatt target by 2025. We currently have 678 megawatts of projects in the construction phase, all of which are expected to be online by the end of 2023. These projects will contribute approximately $149 million in contracted EBITDA once fully operational, or approximately 47% of our five-year incremental annual EBITDA target of $315 million.
Here in Alberta, our 130 megawatt Garden Plain wind farm is nearing completion. All 26 of the turbines have been assembled and over half the units are in operation today. We expect to finalize commissioning of the last turbines and achieve COD later this month. We expect the wind farm to contribute $15 million of contracted EBITDA annually and, so far, we're pleased with the turbine performance. In collaboration with Siemens, we've applied many learnings from the startup of Windrise to the project to ensure that turbine availability meets our expectations right out of the gate.
Our Northern Goldfields project is also reaching final completion. Solar panel installation is complete and interconnection of the facility into our remote network is underway. The team is now installing the battery system and setting up the control system and expects to move into the energization and commissioning phase over the next few weeks. We're aiming to reach commercial operation by the end of the second quarter. This project will deliver approximately $9 million of adjusted EBITDA.
And our two Oklahoma wind projects also continue to progress well, and we expect them to reach final completion by the end of this year. All of the turbine components have been delivered for both projects and at Horizon Hill, we have completed the collector system and foundation work and have started to assemble turbines.
At White Rock, over half the foundations have been completed and the collector system installation is well advanced. We've just started to erect turbines at this site as well. These projects will contribute adjusted EBITDA of over $100 million annually.
Our Mount Keith 132kV expansion project is also well underway. Construction activities have commenced and are on track to be completed in the latter half of 2023. This project will contribute approximately $6 million of adjusted EBITDA annually.
As you know, we're targeting to reach investment decisions on 500 megawatts of growth this year through a combination of greenfield and potential M&A activities. Within our development pipeline, we currently have 374 megawatts of advanced-stage generation and transmission projects that we're advancing towards final investment decisions as we progress through the year. They represent additional growth capital of approximately $600 million.
Our 94 megawatt Southern Cross capacity and transmission expansion projects in Western Australia are advancing well, and we expect to make final decisions together with our customer BHP Nickel West later this year. Our 180 megawatt WaterCharger battery storage project in Alberta also continues to advance and with the recently announced federal budget, we see opportunities under various programs, together with our indigenous partners, to pursue new funding channels to support the project as we work towards making a final investment decision. And finally, our 100 megawatt Tempest Wind project in Alberta is also making progress. We're actively marketing this opportunity with multiple corporate customers.
We continue to advance our growth pipeline in 2023. As you recall, in 2022, we added almost 2 gigawatts to our renewables development pipeline across our regions, providing significant progress towards our longer-term goal of having 5 gigawatts of projects in the pipeline. For 2023, we have an in-year stated goal of adding another 1,500 megawatts of new sites to our pipeline to replenish our growth in the longer term. And so far, we've added 286 megawatts toward this goal.
Notably, in the first quarter, we acquired a 50% interest in the 320 megawatt Tent Mountain pumped hydro energy storage project. This project provides us with a unique opportunity to supply 15 hours of long duration and zero-emission energy storage capabilities for the Alberta market, which will help to address the increasing intermittency that we believe will be experienced with the growth of renewable generation in the province.
Since our last update, we see continuing strength in power prices in Alberta and the Pacific Northwest. In Alberta, forward power prices for the balance of the year are trading higher as a result of, among other things, the relatively strong price results in the year-to-date, transmission import restrictions into the province, and delays in new supply additions.
With our strong results this quarter and improved market expectations for the rest of the year, we're pleased to increase our financial guidance for 2023's adjusted EBITDA by approximately $250 million. We're now expecting Alberta power prices to settle the year $15 per megawatt hour higher than our initial guidance, between $125 to $145 per megawatt hour. Higher pricing and production are expected to increase adjusted EBITDA to the range of $1.45 billion to $1.55 billion, representing an increase of 19% at the midpoint of our prior guidance.
Free cash flow is expected to be in the range of $650 million to $750 million, an increase of 15% at the midpoint compared to our prior guidance; and energy marketing gross margin is expected to be in the range of $130 million to $150 million, an increase of 40% at the midpoint of prior guidance.
I'll now turn it over to Todd for further discussion on the quarter's financial results.
Thank you, John, and good morning, everyone.
I'll kick off my comments, as I always do, with a more detailed overview of our Alberta portfolio performance. When we announced our guidance in December, our outlook was based on Alberta power prices ranging between $105 to $135 per megawatt hour.
Looking at the first quarter of 2023, the spot price in the quarter settled significantly stronger at $142 per megawatt hour, compared to last year's settle of $90. Overall, we realized higher merchant power pricing for energy across the Alberta fleet due to higher market prices and optimization of our available capacity across all fuel types.
The ability of our hydro fleet to capture peak pricing was demonstrated throughout the first quarter, with a realized energy price of $168 per megawatt hour, which represents an 18% premium over the average spot price. In addition, we enhanced revenue further through opportunistic hedging, which generated an incremental $24 million of gross margin, which resulted in a blended realized price of $258 per megawatt hour.
Similarly, our gas fleet also captured peak pricing throughout the quarter, with a realized merchant price of $156 per megawatt hour, which represents a 10% premium to the average spot price. Including hedges, the gas fleet realized an average power price of $136 per megawatt hour, which represents a 62% increase over Q1 2022. Our merchant wind fleet also had a great results and realized an average price of $89 per megawatt hour, an increase of 53% to the same period last year.
Looking at the balance of the year for 2023, we have approximately 4,800 gigawatt hours of Alberta gas generation hedged at an average price of $86 per megawatt hour and roughly 90% of our required natural gas volumes have been hedged at attractive prices. Our hedging activities aim to provide downside protection and support for the Alberta gas fleet, and we continue to retain a significant open position in order to realize higher pricing during times of peak market demand.
Our financial results for the first quarter were outstanding. As John noted, we generated $503 million of adjusted EBITDA and $263 million of free cash flow. Our performance in the first quarter was led by the gas fleet, with adjusted EBITDA of $240 million, 129% improvement over last year.
As we noted, the gas segment benefited from stronger production and realized prices in Alberta, lower input natural gas prices, and lower OM&A from further cost reductions from our previously retired coal operations.
Adjusted EBITDA from hydro -- from the hydro segment was $106 million, a 74% increase to the same quarter in 2022. Although the segment experienced lower production caused by unplanned outages and icing, this was more than offset by higher realized spot and hedge prices for energy sales and higher net realized prices for ancillary services, compared to last year. The segment has also started to monetize its inventory of environmental credits and we received $8 million of environmental credit revenues in the quarter and we expect this activity to continue over the course of the year.
The wind and solar segment performed similar to last year quarter-over-quarter. Although we brought on new assets in the period, we experienced lower production due in part to weaker wind resources, compared to the same quarter last year, and lower availability at our sites. Reduced production was offset by higher realized prices and the environmental attribute revenue in Alberta.
Energy marketing continued its trend of above-average performance and, in the quarter, delivered $53 million of gross margin and $39 million of adjusted EBITDA, a 129% increase over the same quarter in 2022, exceeding our target expectations.
The Centralia facility within our energy transition segment also had a terrific quarter. Adjusted EBITDA for the quarter increased by $49 million, compared to the same period in 2022. We realized higher merchant prices in Mid-C, along with higher production resulting from tighter supply conditions in the region and better availability, compared to the extended outage we incurred last year.
Corporate costs increased by $6 million, primarily due to the insurance recoveries that were realized last year and were also impacted by higher spending on strategic and growth initiatives and from the impact of inflationary pressures on labor costs. Overall, TransAlta's results again exceeded our expectations and delivered a great start to 2023.
Shareholders continue to benefit from the strong performance of our hydro fleet. In the first quarter alone, the hydro assets generated over $100 million of adjusted EBITDA, and we are well on track to deliver roughly $400 million this year. This compares to over $500 million in 2022 and over $300 million in 2021.
Production for both energy and ancillary services were lower this year, driven by a low water resource, lower availability and -- at some sites, and operating restrictions due to icing conditions. Although production varies quarterly, it remains consistent on an annual basis, providing long-term predictability and a floor to cash flows that is unique to this asset class. Realized pricing continues to be strong with a premium on spot energy sales of roughly 20%.
Before I turn things back to John, I'll turn to TransAlta Renewables. In the quarter TransAlta Renewables delivered adjusted EBITDA of $128 million. This represents a decrease of $11 million compared to the same period in 2022. The decrease was a result of number of factors including a lower wind resource, the timing of environmental credit sales, lower availability at several sites, and higher OM&A expenses due to higher insurance costs and escalation on long-term service agreements.
As John mentioned earlier, our construction program at Kent Hills and in Australia are progressing well, and we expect contributions from these assets to start in the second half of 2023. As we move forward, we continue to focus on identifying opportunities to extend our tax -- our cash tax horizon that we currently expect to impact results in 2024.
With that, I'll turn the call back over to John.
Thanks, Todd.
As I look at our strategic priorities for 2023, our primary goal is to continue delivering clean power solutions to and be the supplier of choice for customers that are focused on sustainable growth and decarbonization.
In 2023, we're focused on progressing the following key goals. Reaching final investment decisions on the equivalent of 500 megawatts of additional clean energy projects across Canada, the United States, and Australia and delivering $75 million to $100 million in incremental EBITDA; achieving COD on the Garden Plain wind, Northern Goldfields solar, White Rock wind, Horizon Hill wind, and Mount Keith transmission projects; expanding our development pipeline by adding 1,500 megawatts of development sites with a focus on renewables and storage; completing the rehabilitation of Kent Hills wind; advancing a new technology roadmap that aligns with our Clean Electricity Growth Plan; advancing the long-term contractedness of our Alberta energy portfolio; delivering permanent financing for our growth projects; achieving EBITDA and free cash flow within our increased guidance ranges; and advancing our ESG objectives, which include furthering reclamation work at Highvale and Centralia; providing indigenous cultural awareness training to all of our US and Australian employees; and achieving at least 40% female employees by 2023.
I'd like to close by what I think makes TransAlta a highly attractive investment and a great value opportunity. First, our cash flows are robust and underpinned by a high quality and highly diversified portfolio. Our business is driven by our contracted wind and solar portfolio; our unique, reliable, and perpetual hydro portfolio; and our efficient gas portfolio, all of which are complemented by our world class asset optimization and energy marketing capabilities.
Second, we're a clean electricity leader with a focus on tangible greenhouse gas emissions reductions. This year, we adopted a more ambitious CO2 emissions reduction target of 75% by 2026 from 2015 levels, and our Board has recently approved our commitment to net-zero by 2045.
Third, we have a diversified and growing development pipeline and a talented development team, focused on realizing its value. Fourth, our company has a sound financial foundation. Our balance sheet is strong, and we have ample liquidity to pursue and deliver growth. Finally, our people, our people are our greatest asset, and I want to thank all of our employees and contractors for the excellent work they've done to deliver our outstanding quarter.
Thank you. I'll turn the call back over to Chiara.
Thank you, John. Sergio, would you please open the call for questions from the analysts and media?
Thank you [Operator Instructions] One moment please, for your first question. Your first question comes from Rob Hope from Scotiabank. Please go ahead.
Good morning, everyone. Just first question is on the updated guidance. So, you expected Alberta spot price goes up, we call it $20 EBITDA goes up $200 million, $250 million. That's significantly above kind of the sensitivity ranges that you have provided previously, and understand like, energy marketing did well. But when we take a look at the gas portfolio and your hydro portfolio, should we think that there is some asymmetric upside in terms of your ability to capture margin when pricing is strong and then - what you typically don't bake into your guidance or your sensitivities?
Good morning, Rob. I think the answer to that question is, yes, we do think that there is asymmetry to the upside. That's actually the language that we use internally when we speak with our optimization team, when we do our internal reviews. And look, when we began the year and we were looking at what, we expected pricing to be sort of in the back three quarters of the year, and we see where it is today, it's a significant difference from what our expectations were to where it is now.
So that lift in the floor, so to speak, coupled with the ability of the fleet to flex when the pathways in the marketplace permitted to really - permits us to have that asymmetry to the upside. And I think, that's really what you saw in the first quarter too.
Right appreciate that. And then just in terms of kind of use of capital, your cash balance is now significantly higher than what we would characterize as run rate. You are buying back a little bit of shares here. But when you take a look at capital allocation priorities, how do you balance strengthening the balance sheet, investing in new projects versus returning cash to shareholders?
Yes - look, we - as you know, we have a framework that we use on capital allocation and 40% to 50% of our deconsolidated FFO is focused on growth capital, debt reductions, and share buybacks. You're right, the balance sheet is strong. We're still doing a significant amount of growth. It's in the hundreds of millions of dollars of spend. We do have just under, 400 megawatts of advanced-stage stage projects that we're looking on pushing forward.
And again, that's a significant dollar amount to be able to invest and see that forward. And as you've seen, we've been very much focused on share buybacks over the quarter and actually into April, I think, Todd, we've collectively done over the last few months something $65 million of share buybacks.
I mean - so, right now, the two major levers that we're pulling on would be share buybacks, given where the share price is trading, and also making sure that we're positioned well for growth as it comes in.
I appreciate the color. Thank you.
Sure. Thanks.
Thank you. Your next question comes from John Mould from TD. Please go ahead.
Thanks. Good morning, everybody. Maybe just digging into the hydro hedging a little more, you don't typically hedge your hydro, but clearly, did you benefit this past quarter. Can you provide a little more context to your broader approach to hedging these assets and locking in upside? Is this something you look to do whenever you have real price diverges with near-term forwards and the liquidities there the transactions?
Yes, good morning, John. I think you've actually got it. I think that's exactly right. When we were in Q4 of last year and we saw kind of what the forward curve, which had okay liquidity, was kind of showing in terms of pricing for the first quarter of 2023, and we were looking at what our fundamental view was and where pricing would be, we just thought it was appropriate to layer in hedges, including in that sort of exceptional circumstance, when we see that level of a divergence for our hydro fleet.
As you know, we would typically leave hydro more open than our gas fleet. We tend to think of our gas fleet as being more, I'd say, Todd what we're focused on from a hedging perspective. But as we went into the quarter, just opportunistically, it just made sense. And really, that's what we expect our asset optimization team to do. Todd, I don't know if you want to add anymore color.
Yes. I would just say, look, the forward curve was trading north of $250 for Q1 as we came out of December just based on concerns of a really, really cold winter and some volatile prices. And the team looked at it and said, we think there is a portion there that's fully valued, and decided to lock off some of that risk.
And I think it was prudent to do that, I mean, given where the prices were. And it turned out the quarter was relatively benign from a weather perspective, I would say, and it ended up being the right decision.
Okay, great. Thanks for that. Maybe just turning to the growth side, we have seen some additional renewable PPAs get finalized in Alberta. I'm just wondering if you can comment more broadly on the challenges, I suppose, not just in Alberta, but in your core markets, progressing towards that 500 megawatt target for this year in the current development environment, whether it's equipment costs, securing off-take agreements at appropriate pricing or other factors that make it a bit of a challenge?
Yes. I'd say, when we look at our sort of our advanced-stage projects and we go forward, we're going to be super disciplined. So, we continue to work hard to derisk those projects as much as we possibly can, make sure that we're very, very comfortable with what our pricing is and our cost, more importantly, from a supply chain perspective, because we - given how competitive the world is, we want to make sure that when we go to our Board and we say, here is the project, here is the revenue stream.
We end up locking in the returns that we promised that we were going to be able to lock in. Just to address, John, kind of the more, broader question that you had, look, there is, challenges out there, for sure, and I don't think we're unique in kind of identifying them. I think permitting is taking a little bit longer to get done than it traditionally did. I think the cost of - on the supply chain - I think some of those inflationary pressures have eased a little bit.
But we've seen a considerable increase in just the cost of the steel on the ground, whether it's solar or wind, in terms of getting it forward. Even labor availability for construction has been a bit of a challenge at times, depending on the jurisdiction that you're in. And I think on the PPA side, there has been - I mean, there continues to be robust demand for product, but there still is a little bit, I would say, of a delta between kind of, where costs have gone versus where the market is pricing things in.
And people forget that it is risky to build these things and you need to be very, disciplined that the returns are appropriate from a risk-adjusted perspective. So, when you put the whole thing together, it - look, we're very optimistic about the future, but I think it requires care and a lot of discipline as we go forward, and we're going to stick to that.
Okay, great. Thanks. Maybe just one last one on the RNW release, you again reference the headwinds that RNW is facing on cash taxes, absent any growth. What are the considerations for our RNW in exercising its role for on the advanced-stage projects in Australia, or are you more focused on finding more nearer-term growth that could sooner mitigate those cash tax headwinds?
Todd, you want to take this?
Yes, yes I would say, look, just as far as the cash tax headwinds, I mean, obviously the solar project that's advancing right now will be beneficial for that. That's already looked into our plans. As far as the ROFO projects in Australia, they're all great projects, they're good economics. I would expect RNW to exercise those options going forward. But we are looking for more options, particularly in Canada, to help to defer the tax horizon.
Okay, great. I'll leave it there and thank you very much.
Thanks, John.
Thank you. Your next question comes from Dariusz Lozny from Bank of America. Please go ahead.
Hi, guys good morning. Thank you for taking my question. First one, just on Alberta gas performance in the quarter. Can you clarify whether -- was it most of the elevated output that you attribute to export sales into the Mid-C area or just a portion of it? And then the part B to that question would be, in your updated plan, are you embedding any assumptions about the future kind of - for quarters two through four elevated levels of exports relative to the earlier plan or relative to prior years? Thank you.
Yes. Look, I'll start there, and then John can jump in. And I think the general…
Good morning.
Good morning. The general answer is yes. What we've seen is a bit of shift in dynamic. One is, Mid-C prices are higher than we were thinking originally coming into the year. And so, that's creating more demand to move power out of the province down into the Pacific Northwest when they need it. The other aspect is the ISO here in the province has reduced some of the capacity on imports.
And so, they've restricted down how much power can come into the market during periods of high demand. And so, we're seeing a real shift in dynamics, and that is - it does account for a lot of the differences. The imports in the strong Mid-C pricing, we expect to persist through the year and potentially even into 2024.
Yes and it -- I would say, Dariusz, that we always have kind of viewed it as being a kind of an integrated market, sort of Alberta into the Pac Northwest, and we really see it at the moment in terms of the dynamics between the two jurisdictions.
Great, thank you for that. Appreciate it. Maybe one more, if I can and this is just relative to the Tent Mountain project, that you guys announced. Can you - first of all, assuming that that is not included in your '23 500 megawatt FID target; presumably that decision is maybe a little bit further out, but correct me if I'm wrong.
And is it a little bit, at this point, preliminary to discuss target returns/capital for that project? And then finally, is there anything that you saw in the recent federal budget that gives you perhaps more confidence in being able to finance or otherwise get support for that project? Thank you.
Yes. Thank you for that. It is still pretty early days - for that project. I think right now, I mean - the team is actively working on it. We tend to think of that as being more of a 2026 kind of project and maybe even - sorry, beyond in terms of that coming to fruition. We think it - there will be a time when its unique attributes will be just a huge asset for the way that the marketplace will be evolving in Alberta, given the intermittency that we see occurring as the renewable build-out occurs.
And what I would say is, in general, I think the federal government sort of policy around tax credits and supports - in terms of financial supports is relatively positive in terms of moving it forward. But it's still early days to get into specifics about how that is. We saw an opportunity and we kind of jumped on it and are pretty happy that we did.
Great, thanks for the color. I appreciate it. I'll turn it over here.
Thanks.
Thank you. Your next question comes from Ben Pham from BMO. Please go ahead.
Hi, thanks. I wanted to follow-up on your comment on - I think you mentioned there is a gap between CapEx and there is more on the renewables side CapEx and bridging that with securing a contract or maybe I didn't interpret it the right way. Can you expand, is that more of a U.S. situation? How does some of the budget support items that we've seen flow through impact that thought process? And I just want to make it clear. You're still quite confident around the 500 megawatts section this year?
Yes, good morning, Ben. So yes, we set the target and we do view our targets the stretch targets. We try to motivate our team to move forward and achieve the best that they can do. We're comfortable with our advanced-stage pipeline. They're quality projects and we are advancing them actively. There's - the team is on all of them and we have confidence that we'll be converting those as the year goes by.
I'm not sure about the introductory question that you had. Maybe I'll try to add a little bit of color. I mean, what I was trying to say is that pricing from a renewables perspective and expected returns, at least from a TransAlta perspective, we need to make sure that the returns are appropriate on a risk-adjusted basis, which, I think, there's some time an assumption is that there is no risk associated with construction.
There is no risk associated with evolving dynamics within the marketplace in which the unit - where the facility is being built. And I think it requires care when you're going forward and developing a project, and we owe it to our shareholders to be as disciplined as we can be when we're allocating capital. On the cost side, I mean, just to give you an example, I think - and I'll use the U.S. as an example. I think PPA prices there are up roughly around 10% or so over the course of the last year.
And that's in the context of turbine costs, for example, increasing by 30%, 40%. So, the market is reacting to the increased sort of cost of developing projects, but it isn't exactly the same. And for us, we're going to be very, very disciplined, both in making sure we lock in our economics and making sure that our costs are fully baked before we proceed on anything.
Okay, that's more, clear. Thank you. Not that you weren't clear from the beginning. On the gas procurement side of things, I'm wondering, just looking at the quarter, how you benefited from low gas prices, are you - do you anticipate any changes in how you're procuring gas going forward? And is there any sort of interest in even getting involved in buying a gas field at some point?
Yes, no, thank you for that. We're pretty comfortable. I mean, I think over 90% of our anticipated gas burn is basically locked in for 2023 at very good pricing. I mean, it's sort of low $2 kind of pricing, and 2024 is candidly not much different than that. When we look going forward, we're not contemplating actually buying an interest in any natural gas generation to supply where we are. We're comfortable with our ability to secure natural gas for our assets going forward.
We have sort of a view on where we think natural gas prices are going to be in the kind of near to mid-term, and we're comfortable with where that is. I know it can be volatile. We've seen that over the last little bit. But when we look at sort of '23 and '24 and even into '25, I don't, I honestly, I don't see us actually making - kind of integrating upstream effectively into the supply chain to be able to secure that fuel.
As you said, we do look at it every few years, and I think the conclusion continues to come back every time that the best thing to do with our business, is to just hedge it forward in the financial markets or bilaterally with counterparties.
Yes. I mean, our focus is to stick with things that we do well, and that's the power generation and growth side, rather than oil and gas generation. It's not something that we're in.
Okay got it. Thank you.
Thank you. Your next question comes from Mark Jarvi from CIBC Capital Markets. Please go ahead.
Thanks. You guys mentioned that you'd be looking to renew the NCIB in the coming weeks here. I think it's for about 5% of shares outstanding. Would you take that up when you renew the NCIB in terms of maybe a bit more sort of granular ambition on the buyback?
Yes. Good morning, Mark, first of all. Sorry. Look, we will renew the NCIB, I think, before the end of the month. I think it actually expires on the 30th, I think, it is, Todd. So, we will make sure that we do that this month. In terms of the size of it, I think it - we tend to ask for our entitlement to be up to the maximum amount that we're permitted under the rules to be able to buyback just as a matter, of course.
And I think it's restricted by, I think, the proportion that you're allowed to get of your average kind of daily float that is traded on the exchange. So, we will enable the maximum amount, I think, which I think translates, Todd, to somewhere just a bit over 5% of the total float that we're permitted to repurchase under the NCIB. I'm just going from memory here.
Okay. And then, John, you also brought up M&A as a potential source of growth. I know you guys have been very cautious on that, just given where deal metrics have been over the stronger cash position. Anything change there? How would you characterize that in terms of your interest in looking at deal flow right now and what you're seeing in terms of opportunities and valuations out there?
Yes. So, the team is - I would say the team is busy. It was interesting - we just had our Board meeting for the quarter and we gave an update and it was interesting to see kind of the funnel that we use in terms of what the team looks at and how it progresses through it. So, we do remain active. Two areas for us would be, are there sort of good assets that we think we can add value to and bring into the fold? So, that's one category.
This would be operating existing assets that we could bring into the fold. The second area that we're actually spending quite a bit of time on is actually just developer platforms and developers. There's something that we could see there that makes sense to bring into the company to further, I think, strengthen our growth capabilities within the organization. So, those would be the two broad areas that we look at.
We do kick the tires a lot, if I can use that sort of expression, and continue to see if we can opportunistically get something over the goal line. We're going to be disciplined on price, though, I would say, Mark, like, things are still pretty expensive and it's got a -- when we diligence these things, we need to make sure that we're comfortable with what we're getting, given the pricing.
And then just in terms of the operating assets you mentioned, I mean, obviously, there is a concerted effort to shift your portfolio to more contracted renewables. Where would gas or thermal assets fit in, in terms of M&A on operating assets?
Yes. Look, we do see gas opportunities occasionally. I think, certainly, from sort of a priority perspective, we are looking at more of the contracted renewables. But that's not to say that if a gas opportunity came up that was contracted, fit well with the kind of fleet, had - gave us the ability to optimize around it, given the skills that our team has, and permits us to have kind of within the emissions profile that we've set within the company, it is something that we would look at. And we do periodically look at those. So it's not like we won't look at gas at all.
Understood. Last question for me, just given the pricing dynamics and tightness in the Pacific Northwest, any sort of updated views in terms of opportunity sets and how you can extract value from the Centralia site?
Yes. It's an ongoing - Todd just smiled, Mark. It's an ongoing discussion that we end up having here. One of the challenges we have there is our ability to, for example, convert the unit from coal to natural gas to super-constrain, both in terms of volumes of natural gas and actual pipeline capacity. So when we look at the sites, we're looking at it from, is there some solar we could do there, is there battery installation that we could do there, is there even wind that you could do there.
The solar resource isn't the greatest, the wind resource is better east of the Cascades than, certainly, west of the Cascades. We are looking, though, at everything from fusion, we're looking with FFI at the possibility of being involved in their hydrogen prospects there. So, the infrastructure is great. It's in a perfect spot from a transmission perspective. So, we continue to sort of chase all the potential opportunities that we can to see it through. So, we're - stay tuned. I think there is a lot of value in the site. It's just I doubt it will be thermal in nature.
Would you characterize it, in terms of opportunities, becoming more advanced, or seeing something you think that could become more tangible in the near term?
I don't suspect that we'll see anything that will be tangible kind of over the next 12 to 18 months. I think most of the things that we're working on there, Mark, are things that would be sort of, in my own mind, kind of 2025, 2026. I mean, we're into a place where the unit's going to run until the end of 2025 anyway. So it's really kind of the back half of the decade focus.
That makes sense. Okay. Thanks for the time today.
Thanks a lot.
Thank you. Your next question comes from Maurice Choy from RBC Capital Markets. Please go ahead.
Thank you, and good morning, everyone. My first question relates to capital availability. Unless I missed it, I believe you continued to be equity self-funded for your 2025 growth targets. And -- but given the growth options that you have, which are clearly abundant, how do you view prospects for bringing in a long-term partner or partners, be that for these growth opportunities and/or for a corporate simplification? And if you do, what would be the top thing that you'd like this partner to bring to the table besides capital?
Yes and so good morning, Maurice, thank you for that. And I think you've actually just touched on it at the end there. So, traditionally, look, we do have some great partnerships, and when I think of the relationship we have, for example, with CKI and even the Heartland folks with Sheerness, I think those are very constructive partnerships and work very well. When we think of bringing others to move things forward, it isn't because we see ourselves as being capital-constrained right now.
So, for us to bring somebody in, one of the key drivers would be, what would they bring to the table that makes it a bigger pie, so to speak, in terms of us being able to collectively participate in kind of accelerating our growth, or are there capabilities there that maybe we don't have or an area - a geographic area of focus that we aren't as strong in that we could bring our expertise in with their expertise to move forward.
So, we do have these kinds of discussions every so often. I don't think there's anything particularly active on that at this particular point in time, I would say. And when we think of partnership, we also think about our customers. So, when I think of partnerships, I think BHP Nickel West, and we do view as kind of being in it with them as they continue to advance their business in Western Australia and we're there kind of shoulder-to-shoulder with them as they move forward. Todd, I don't know if want to add any color.
The only thing I would add is the other thing that I would consider about is risk mitigation.
Right.
As we get large, large capital projects, we start to think about, does it makes sense, given our market cap or our float, should we be thinking about diversifying some of that risk away with a partner just on any individual project. So that's another key consideration.
Thanks for that color. And maybe I could just finish off with the regulation question. The CR or the clean electricity regulation it's obviously seemingly coming the spring, you view to be a good outcome for your Alberta gas fleet, including benchmark or even a number of years in terms of NOI?
Yes - and I might turn it over to Kerry here who is in the room for us to give any color. I think - so, look, we have to wait to see what the fine details are going to be when it is actually published at the end of the day. Our team is very actively involved in the process. I know Kerry and her, team have been consulting on it. In fact, they just filed another submission on it. I think it was just yesterday, I think, Kerry.
And it's around some of the things that you've alluded, to Maurice. It's everything from reliability running, for example, what should, the end of life be, how do we think of smaller units. It's that nature of the flavor of things that we do. So, it's sort of how do you balance decarbonization while ensuring the integrity and the reliability and stability of the systems as we go-forward.
Turning to our units, given the kind of timeframes that they're suggesting in terms the 2035 and the ability to, maybe run longer than that, and I look at what the natural life is of our coal to gas converted units. They aligned pretty well. I would say, so it's not like our CTG units ever going to run into 2050, for example. So I don't know that what is developing is going to have a major impact on how we're operating. Chiari, I don't know if you have any thoughts around that.
No. I think I can fully agree with everything you mentioned, John. The only thing that I would add is that we do understand that it will be delayed until later in the year. And one of the things that we speak with the government about is the importance for clarity, which encourages investment certainty in the province and in the country as well.
So, I think the only point I would add to your comments is additional clarity on cogen and how the cogens will be treated under the CR, but otherwise I think it's moving in the right direction and hopefully we will see it at the latest in the third quarter.
Just to clarify you mentioned that this aligns pretty well with the - I guess the physical characteristics of your fleet. Do you mean that by being a 2035 or do you mean that by a view of what those end of lives maybe when - that's 30 years or not?
No, no. My reference was the 2035 kind of timeframe it. We're not that far and that was actually a conversation piece we were engaged with the government.
Thank you very much
Thanks.
Thank you. Your next question comes from Andrew Kuske from Credit Suisse. Please go ahead.
Thanks, good morning. If you had a hypothetical project in Canada then the U.S. with exactly the same economics. Where would you allocate capital if you start to think about the incentives, the IRA in the U.S. and then the new round of incentives in Canada? And then maybe just to give you a little bit rounded answer are there other factors beyond government incentives that would sort of dictate where the capital would go on such a project?
Yes good morning. Good morning, Andrew. It's interesting if they were - if they were exactly the same and we were in both jurisdictions. Let me try to answer it this way. I think the financial incentives that the governments have on both sides of the border are pretty powerful. And it's interesting. I was recently in Australia and the narrative there is also around how do you respond to the IRA in the United States, because they really do see it as an element of their industrial strategy that they need to be mindful of.
So when you look at the two jurisdictions. There are differences I mean the refund ability of the ITC in Canada is pretty powerful. That was that was unimportant element of the response here from a Canadian perspective. We are looking at a very powerful in the U.S. as well. Transmission is an issue in the U.S. in terms of where you are. And the reason I raise that is probably a differentiator between the two. I would say we're pretty agnostic within the jurisdictions, except for this.
When we do our projects, we're very concerned about the post-PPA merchant period and so for us, the assessment would be how does that look in the market in which we're making the investment in terms of differentiating. Are we more comfortable with Canadian, Australian or U.S. component and what is the contract period IRR in the context of the two. So it's more that all things being the same, it's more what does that backend certainty look like to the extent you can get any and are we comfortable with that.
Okay. That's very helpful. Maybe building upon your comment there got backend of a PPA does that really speak to places where you have existing portfolio concentration on being more likely to draw capital. Is that gives you by default a greater level of comfort and optionality around the asset-base?
Yes. It can. So for us, I think it would be more Andrew around how large is our position in the jurisdiction, how intimately knowledgeable are we about it. Do we have the ability to influence regulatory outcomes within the jurisdiction or not? Do we have ability to re-contract or have any particular sort of customer relationship that makes it a little bit differently?
Does our trade floor have a particular expertise, not just in trading, but also from an intelligence perspective in that jurisdiction? So it's hard - it's a great question but it's a hard one to answer because it truly does depend and it actually evolve overtime.
If I could just sneak in one more, how do you feel about your positioning in the interconnection Qs and I guess mainly in the U.S. you could answer Canada too, but I guess it's mainly in the U.S.?
I think in terms of the - the project timeframes that we have for bringing the assets in right now, if you were to look at kind of what is more ready in terms of our advanced-stage projects. It's more a Canada kind of Australia flavor. The U.S. stuff is kind of a little bit further away in terms of getting forward. We're pretty comfortable in terms of where we are. It is one of the key considerations though, Andrew, to your point and it's becoming an even bigger consideration in the U.S. in terms of what is the actual timeframe.
I mean, some of the timeframes from beginning from initiation of envisioning of a project to the actual realization are exceeding half a decade now and getting longer. So - that is for sure a factor. One of the things about the IRA, is it really incents demand increase and meeting that demand, but it kind of forgot the widest part of the equation which is - which is kind of at least from our own perspective, sort of the missing piece in terms of enablement.
Okay. I appreciate that. Thank you.
Thanks.
Thank you. Your next question comes from Naji Baydoun from AI Capital Markets. Please go ahead.
Hi, good morning and congrats on a great quarter. Just wanted to ask couple of questions around organic growth and capital allocation, it seems like maybe project have opened is taking a bit longer than you'd like. Just any thoughts on what can be done differently to try to accelerate development. And maybe reading between the lines in your opening remarks a bit, do you anticipate maybe backfill some of the sort of megawatts to achieve your target through M&A?
Yes. Good morning, Naji. Thanks for your question this morning. Look the projects have a life of their own. So we're not, it's not like oh goodness it's January and we haven't announced anything this month. That isn't the way we look at it. For us, it's more when are, they ready to go. And if they are ready to go, then there might be cluster in terms of when they come within the organization.
And candidly, we've been really focused on a lot of construction. I mean, in all three countries in which we're active over the last little bit and if. I think, in total about 1.4 billion over the last kind of 18 months or so. So, that's been a big focus of the team going forward. So, we do have things in our development pipeline that we can potentially accelerate to get to that 500 megawatt target that we have.
It is a stretch target we deliberately made it a stretch target when we said it for this year. We're comfortable with the advanced-stage projects that we have. The team continues to work to move more projects the advanced stage and we will be opportunistic on M&A, but we're going to be disciplined like if we don't - if we don't see returns that we like will be patient and we'll will bring the projects on when we think it makes sense for our company and our shareholders.
So, in a scenario where the 500 for this year or 1,200 to reach the two gigawatt target or may be like you said the projects are lumpy. How much M&A would you be comfortable kind of pursuing or none at all if you don't find the right acquisitions?
Yes. I would say it would be none at all if we don't find the right acquisition. I think we're not going to - if the exercise was simply to get to the numerical target of two gigawatts you could - you could achieve it, but you might achieve it in a way that really ends up destroying value rather than actually maintaining value going forward. So for us the overriding factor on our clean electricity growth plan is that we're going to make investments that we think provide value for our shareholders - and that sort of threshold one in terms of moving forward.
We're still confident that we'll meet the targets and the team continues to work forward and we're happy with where we are from a pipeline perspective, and I think we set a 5-gig pipeline target for 2025 and we're over four now, so I mean that I'm very comfortable in terms of the scope of the inventory that we're building effectively to bring forward.
Okay fantastic. That's very clear. And just tied to all of this is it seems like you're doing a bit more buybacks that maybe what you would have talked about it earlier. Again, just given if growth is a bit lumpy, do you think that you'd be allocating more capital to buybacks, like is that a fair a assumption in the short-term? And if the answer is yes, do you have just sort of a maximum envelope for share repurchases that they have months of the year?
Yes, we don't - we don't have a set number of share buybacks that we would do over the course of the year, but look, it is - it is a key factor from a capital allocation perspective. We're mindful that we've got a strong balance sheet right now. We're very mindful of making sure that we -- make sure that we're focused on our shareholders and giving them an appropriate return and we look at that holistically in terms of the dividend and also the share buybacks that we're doing and we also look at kind of where the share price is trading.
And we saw, I think Todd, it's fair to say a little bit of weakness over the last little bit, certainly compared to where management - thinks we should be trading at and opportunistically, we were in buying shares when we see that the value isn't there. Todd. I don't know if you want to add anything.
I just want to say that our tone is still to stay very opportunistic on share buybacks, and certainly, when we saw a drop below $13, below $12, we signaled very strong - that's the time to be in the market. I was going to say that we are sitting on a decent amount of cash. We still have about $400 million, $500 million of construction to go here on the existing projects, but I would say that with rising interest rates, there is maybe a bit more pressure out there on some of our - some other people.
And there may be some more attractive M&A opportunities show-up in the next six months than we've seen over the last several years here with rich return that are probably more acceptable to us. So, I think we're in a great spot. So not only the cash balance, but the amount of liquidity, the strength of the balance sheet, it all points to a spot where the company is in a good spot to really jump on opportunities if they show up.
Yes. What I would say Naji is kind of the optionality we have right now is kind of a nice place for us to be. So when we see an opportunity, we're in a position where we can actually proceed.
Yes. It's a good color. Thank you very much.
Thank you.
Thank you. Your next question comes from Patrick Kenny from National Bank Financial. Please go ahead.
Thank you. Good morning. Just on the heels of the carbon tax here moving up to $65. If you could provide an update on your carbon offset strategy where your credit inventory sits today? Your procurement strategy going, forward and then how this all feeds into your outlook for utilization across your CTG units in Alberta?
Yes. Thanks, Patrick, and good morning. Todd, I don't know - that I don't have those numbers to add Patrick. So that's something we can certainly get back to you. I mean I think we're long - we're fairly long credits I would say, so in terms of being able to manage, I would say the carbon exposure that the company has not just this year, but actually the next few years, we're very in good shape.
Our bigger discussions on the inventory we have of credits is how much do we monetize them and when candidly. So it's more around that rather than the impact that they have on the fleet, Todd, I don't know if you have at a hand.
We can clarify that afterwards. I think we have about 1.7 million.
Something like that it's about $1.7 million.
In the inventory, but we also generate about 750,000 RECs per year annually. And so, we have been monetizing a portion of when we go, but obviously the inventory is built-up and we're just sort of looking there's a little bit of the carbon tax is going up year-after year. Therefore they theoretically should be worth more value going forward. But at some point we want to monetize them. We don't want to be sitting on too big of an inventory and so, we'll will sort of be opportunistic about how - we exercise and use those.
Yes, I think, Patrick, and look I think we're on record of saying this. I think there does come a time perhaps late in the decade when there is a bit of decoupling between the carbon price and the value of the RECs like there could be a supply-demand imbalance, candidly in terms of how that proceeds going forward. So we're managing our portfolio in the context of all of that.
Okay. And then, John, I guess stepping back here and as you assess opportunities to simplify the corporate structure overtime. I guess dovetailing in with Todd's comments on the strength of the balance sheet. Curious to get your thoughts on potentially consolidating some other CTG units in the province and perhaps spinning off some sort of high cash flow yielding entity for the portfolio of merchant thermal assets as a play on crystallizing value for shareholders?
Yes. It's - an interesting suggestion that you have and look I would say our Alberta optimization team is one of the great strengths of the company. And if there was an opportunity potentially to kind of expand our portfolio of assets that the team would be able to deal with and that just to give you a sense of that I mean we are focused even on speakers that we're looking at bringing forward. There is a couple of projects that we have that we're actively involved in pushing forward and - just to give you an example, kind of a merchant peaking low capital cost peaking kind of fleet for the province.
So it's not beyond the realm of possibility that we would look at that whether that would say within the organization or would be spun out or I would just be speculating right now, but. If the question is, are you looking at ways to maybe expand the breadth and depth and dynamic of kind of the portfolio we have in the province of Alberta, for example, the answer would be yes. I think.
Okay great. I'll leave it there. Thanks, John.
Thanks so much.
Thank you. [Operator Instructions] Your next question comes from Chris Varcoe from Calgary Herald. Please go ahead.
Hi, John quick question here, regarding the challenges that you see or what challenges maybe more importantly do you see to get to a net zero power grid in Alberta by 2035? And how expensive do you think it might be?
Yes, Chris, and good morning and thanks for calling in. Candidly, I'm not sure anybody knows how much it would cost to get us to that state by 2035. I think you've seen the ISO has come out with a bit of a suggestion in terms of what it would cost to get there on a number of different pathways and I think even the ISOs analysis would show that at the very margin in terms of full decarbonization within the province, it's hard to do.
I don't think - I don't think their paper actually contemplate that they would get right down to zero, so would it be expensive, yes, it would be expensive. And I think the main take away at least from our perspective is that the closer you get to achieving net zero, it's kind of like a geometric increase in what the costs are like sort of exponentially increases and people need to understand the province has already done a tremendous job in decarbonizing.
When I think of what the emissions profile was of the electricity sector in the province of Alberta in terms of mega tons versus where it is today, the progress that's been made has been remarkable. And we're still on a journey of decarbonization. I know One Capital Power has done the work that they are proposing to do it we'll see another step-change in terms of the emissions reductions within the province.
Getting us to that ultimate level is going to be technologically I think challenging and will also be just from a cost perspective challenging. The other thing I think that's important is at least our company we tend to you've heard me talk about this the three-legged stool and I think as we go on the journey to their, the three legs of the stool are one, decarbonization and things being clean, the other two are making sure that things are affordable for both businesses and individual are burdens and also having a reliable system.
Those two things are critical and it doesn't help anybody to just secure the leg of this stool without actually making sure that the other two legs come along in the journey and that you've actually got a proper stool that you can sit on by the time you get to 2025. There's been a lot of discussion about the clean part, hasn't been as much discussion at least in our company's view on both reliability and on the cost.
So what it means for us from a company perspective is, we do have concerns in terms of the reliability of the system. I think the push towards renewables, has been positive in this province. But it does have implications on both the market construct and the reliability of the system and I think the ISO sees that, I think we see that and it's critical that the lights are going to be brownouts or anything like that.
And obviously, costs are important as well. We need to make sure that our economy remains competitive, and that consumers in the province of Alberta are taken care of. So, it's a hard question to answer, but hopefully I've tried to just kind of give you some of the prospectus and the puts and takes that need to go into it. We've been pretty effective to get us a long way away. The last part is going to require everything from technology to support frankly from government to get there.
Just a follow up, what are still the key uncertainties are wildcards that you see between now and 2035, in order to get that net zero target?
I mean, there are many. For example, how many renewables can you bring into the province? What does it mean from a transmission and delivery perspective within the province. What does it mean in terms of the infrastructure we need in our towns and cities and rural areas to permit the electrification of transportation, very challenging I mean, Alberta is in its very early stages of doing all of that. What does it mean in terms of electrification for the oil fans.
One of the great engines of our province and what are the costs associated with that? Will CCSP effective? Not generally, but to the actual levels that are being imposed on by the federal government to move forward. And secondly, we do think that there is going to need to be technological advances to kind of get us there. So its hydrogen ready, it's not right now from our perspective. It's storage where we want it to be from and effectiveness perspective, its not quite ready in terms of where we need it to be.
So it's everything from making sure that existing technologies that we have are as effective as they need to be the renewables that come in come in, in a cost-effective way, given its not just building them. It's all - the transmission and delivery infrastructure that's needed to do that. And then finally, some of the technologies that I think we're kind of banking on candidly to be able to get us there in the 2030s aren't quite ready for prime-time.
And look, we made an investment in an entity called the IP that looks at any new technologies, whether it is battery storage, fusion hydrogen, all of those kinds of things, there is a way to go, and you even heard discussion around SMRs. I mean, from our company's perspective, we've looked at them, not that its core technology for us. But we look at them and we look at the timeframe is required to bring them in and the costs associated with that.
It's many times more than natural gas-fired plants. So who is going to pay for that and how is it going to proceed, so I know that's a lot there, Chris, but I just wanted to give you a bit of a flavor, it isn't any one thing. There is a regulatory piece. There is a affordability piece, and then there is a technological kind of piece in terms of us getting there and it's a bit opaque, right, when you get further out there.
I think we see pathways to get us a good chunk all the way there, but to get us all the way there the way that's affordable and reliable. It's hard for us to predict right now. It's actually something that worries us.
Thank you.
Of course.
Thank you. There are no further questions at this time. You may proceed.
Great and thank you everyone. That concludes our call for today. If you have any further questions please don't hesitate to reach out to the TransAlta Investor Relations team. Thank you very much and have a great day.
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