Manawa Energy Limited (MNW) Earnings Call Transcript & Summary

My name is Clayton Delmarter, I'm the Chief Executive of Manawa Energy and I'm joined by Phil Wiltshire, our Chief Financial Officer. Perhaps if I could get a thumbs-up from someone online, just to confirm they can hear everything okay. Grant, thank you very much. Much appreciated. Right. Just a bit of outline of how we'll tackle today's presentation. You can ask questions or type in questions through the Q&A facility. At the end of the presentation, we will talk through those, and you'll also be able to unmute yourself and ask us those questions over the microphone, if that's easier. Right. We'll get underway. Phil, I'll hand over to you to take us through the first few slides, please.

Thanks, Clayton, and good morning, everybody. We're pleased to report today a very solid earnings result for FY '24 with EBITDAF up 6% on the prior year and that is in line with the revised guidance that we provided in mid-March. You will see that the Board has lifted our final dividend to $0.11, bringing the FY '24 total dividend to $0.19, and we'll talk about that a bit later in the presentation. If I can take you to the next slide, I'll talk through the financials in a little bit more detail. As I said, EBITDAF from continuing operations, up $8 million on the prior year. And pleasingly, I guess that was despite the loss of the ACOT revenue stream that we've now -- 100% of that revenue is excluded from FY '24 based on the new TPM regulations that came into place on the 1st of April '23. So that contributed $17 million in the prior year and contributed to this current year result. Our net profit after tax of $24 million was impacted by a $46 million non-cash unfavorable movement in the fair value of financial instruments. And we have seen quite large swings in those that fair value in the last couple of years and we will continue to see that just the way the accounting rules work for the Mercury hedge. The prior year number of $444 million included the one-off sale of the mass market retail business. It also included a $63 million favorable movement last year and the fair value of those financial instruments. CapEx this year of $69 million was up on the prior year, significantly up, up $28 million on the prior year and that's well up on the long-term average. And as a result of our major asset refurbishment program that we will talk more about in the coming slides. You can also see there, our total investment in the new development pipeline of $19.7 million that's made up of a number of things. It's the OpEx costs of progressing that pipeline. There's also some CapEx items in there this year in terms of some land purchases and investment in the joint venture with Pioneer for our Kaihiku Wind Farm. Looking at the next slide, looks at just the movement in EBITDAF in a bit more detail. As you'll see, EBITDAF was up $8.3 million on the prior year. And as I mentioned, the first 2 items on the bridge chart there are non-recurring items. So, we have the loss of the ACOT revenue impacting this year by $17 million. We have a gain in FY '24 of $2.4 million on sales of carbon units. That's a $6 million swing from the prior year. And now we have now divested all of our carbon units, so there will be no carbon impact going forward. In terms of the energy margin, our energy margin was up $14.5 million compared to the prior period. That's a strong result due to higher average electricity spot prices in the wholesale market, good hydro volumes and good wind volumes through the wind that we procure through our PPAs as well as increases in sales prices and particularly the inflation adjustment on the Mercury hedge. Our generation asset and maintenance costs, which is the maintenance spend, the OpEx maintenance spend that we -- on the generation assets, that was up $4 million on the prior year. That's largely a result of us bringing forward some routine maintenance to coincide with the outage we had at our Waipori site. There was also some general [ inflation ] in there and some remediation work we did at 2 of our sites to sort of remediate from some weather events that we had during the year. Our new development OpEx up -- sorry, it was down $2.6 million on the prior year. That does tend to be a little bit lumpy year-on-year just depending on where we -- what stage the projects are at and progressing the pipeline. And pleasingly, our other OpEx, which is our corporate overheads and the majority of our employee costs were $4.5 million, favorable compared to the prior year. And that's really a result of some of the changes and some of the efficiencies we're seeing in our operating model as part of our -- as we transition to an IPP model. There is also some -- we've provided some more breakdown and some more detail on those sort of our operating expenses in the appendix to this presentation for those who would like to see a bit more detail on that. The other movement there was again a non-recurring one, which was around some insurance proceeds that we received during the year and that provided [Technical Difficulty] year-on-year of $2 million. Looking -- the next slide just looks at that $69.5 million of CapEx in the year. As we've previously signaled, we are partway through a major asset refurbishment program. In FY '24, this included major works at some of our larger sites, particularly Waipori, Arnold, Highbank, Coleridge and Matahina. The capital investment program provides long-term revenue protection on what are very long-life'ed hydro assets. Many of the components we're replacing during this refurbishment program are well over 50 years old. And it provides -- the new units will provide revenue protection and reliable generation for well into the future and for 50-plus years. A number of the projects also deliver production improvements or additional output. And we've previously flagged that we are -- that the investment program will deliver an additional 78 gigawatt hours of production output and we'll provide some more detail on the status of those projects and where we're at on the 78 gigawatt hours a bit later in the presentation. And I'll hand back to Clayton to talk a bit more about our strategic plan and progress made to date.

Yes. Thanks, Phil. So, on this slide, I've really just outlined the 3 core pillars of our strategy. Simplicity in a strategy is a good thing. And I think it's clear for us as an independent generator that that's very much first and foremost about protecting the value from our existing portfolio of renewable assets. And so in that first tranche there or [ ROE ] it's really looking at how we went this year. And I think, as Phil outlined previously, we made good progress across the portfolio. We saw some of those enhancement opportunities realized like Branch, for example, at an intake gallery, which gives us a 10 gigawatt hour per annum uplift. We've completed a couple of generator replacements. One of those fell into FY '24 at Waipori 3 Station with Waipori 4, the year prior. We have made really good progress with Matahina, replacing the 2 runners on those units. They are our biggest single generating assets in the fleet at 40 megawatts each and we will be commissioning the first of those units in the coming days and hope to have that completed in the next month or 2, with the second unit going into its replacement works later this calendar year. We're making good progress at Arnold Dam. We've quite a significant dam strengthening project underway there on the West Coast. And one of our bigger unit replacements also at the Highbank scheme, which will get underway later this year. We've outlined and we can talk to a little bit more of the impact that has on our annual production volumes this year. But pleasingly, I think the team in terms of coming up with an innovative project where we're converting the existing pumps to turbines, the generation volume that we get from that project does provide us with an offset to the lost generation as we look to do a complete unit replacement on the Highbank scheme or Highbank machine over the next 18 months or so with our outage commencing in September. And we've also made really good progress with our reconsenting of our existing portfolio. Obviously, with a number of assets we have around the country, we do face a reasonable program of reconsenting efforts over the coming years. And it's pleasing to see that progressing. In terms of other progress made this year, one of the other pillars for us is really around our contracting strategy and our revenue strategy. We continue to have really good engagement with a number of interested parties. I think, again, for us, it is very unique that we are able to offer a product, if you like, to the market from our diverse fleet of hydro assets across the country, different catchments, different geographic locations, a degree of storage from some of our more strategic assets in the portfolio. And I think the unique product offering we can make supported by those assets that will complement our future development portfolio is really helpful for us as we look to progress that strategy, which ultimately will allow us to have a good look at our capital structure in the not-too-distant future. The development pipeline has also made good progress this year. You will have seen that we secured consent for the first portion of the Argyle Solar project in Marlborough located adjacent to our Branch hydro scheme. We have launched consent for an expansion to that site and expect to secure those consents in the coming months, and that's circa 65 to 70 megawatt AC opportunity in that part of the world and have also made really good progress with a couple of key wind farm projects in our portfolio that we expect to launch consents for in FY '25, and that includes Huriwaka in the Central North Island and Kaihiku, which is the project we're developing in partnership with Pioneer Energy near Balclutha in the Otago region. So -- and I think another great thing about the portfolio in terms of the development portfolio that is really just expanding that portfolio. It's close to 1,300 megawatts an hour with several hundred more megawatts in active discussions. And I think we've got a really good mix of technology and geographic diversity on that portfolio that will allow us to bring those projects to the market at the right time. And I think all of those points flow into our FY '25 goals and targets, which is really nailing the major capital works enhancement program that we have currently underway and executing on that very well and efficiently. Obviously, in terms of the portfolio, that will be very much about securing a cornerstone PPA and really shoring up that volume for the longer term, which, as discussed, really flows through to our ability to revise our capital structure, and then, of course, moving our development pipeline towards shovel-ready or investment-ready decisions, and we flagged that we expect to have the Argyle Solar project in that position during FY '25. Perhaps then if we go on to have a quick chat about the development pipeline. As flagged, we've now progressed this to in excess of 1.2 gigawatts, a good range of diversity in terms of location and technology. We continue to enjoy developing solar projects and have added a few more to the portfolio. The recently announced Marlborough project, [ super ] 100 megawatts and another 200 megawatt AC project in the Mackenzie Basin. Again, as we like to point out, I think all of these projects are now have very strong fundamentals and should realize competitive LCOEs going forward. Obviously, a number of them are at different stages, and I'll talk through some of the more advanced opportunities we have in the pipeline, but we'll continue to move all of these as efficiently as we can through the development process in the coming months and years. The next slide provides a bit more detail. This is fairly similar to the half year or the interim results released on November '23. We're continuing to see these projects move as anticipated. I think we've flagged that a number of our projects where we have land, actually secured, we have all of those in the Transpower queue. Obviously, securing network connections for these projects is also on the critical path along with the resource consenting activities. We certainly do see and I'll touch on this a little bit later that some of the resource management reforms proposed by the coalition government are quite supportive of more rapid progression of some of these resource consenting opportunities in our pipeline as well as also supporting our reconsenting efforts with our existing hydro fleet. And as I said, I'll touch on that a little bit more later. But overall, you can see, again, I think we've got a reasonable look ahead to be able to bring projects to market should conditions suit and should they meet our investment hurdle over the next 4 or 5 financial years and we are targeting significant growth out to FY '30. Just a bit of an update on some of the more recent projects we've announced. As flagged when we provided our revised guidance in March '24, indicated we'd secured development rights to a wind farm opportunity near -- in the Marlborough region, not too far from Blenheim. That's a circa 100 megawatt project really taking into account the project characteristics and available transmission capacity, et cetera, in a region with very strong wind resource and a part of the country that could do with some additional generation. So we're quite pleased to bring that one into the pipeline as well as the project on the right, which is a polygon really showing you the proposed solar array, again, with transmission very proximal passing through the proposed development area. So, both of those projects, we're now progressing through environmental assessments, resource monitoring, et cetera, and getting them well and truly progressed through our various development milestones as we look to balance them in terms of our overall portfolio mix in the development space. Thanks, Phil. Just a quick update here on Argyle. I think I touched on this earlier that we're planning to be in a position to consider an investment opportunity in this project in the current financial year. One of the things we like about this project is that proximity to the existing Branch River hydro scheme and the advantages that brings with it is really -- we've got existing connection infrastructure, which is dedicated to our existing hydro assets. So, we think a relatively cost-effective connection solution for that site. And also, we do have a degree of storage, sort of intra-day 8- to 10-hour storage from those hydro assets, which we do think will be beneficial in terms of just balancing wind and solar resource on any given day. And have generally seen whilst there's inevitably continued -- and there's no doubt there's continued pressure on supply chain costs overall, we do think that the site looks quite prospective. We've seen module prices improve quite materially in recent months and a little bit of easing in supply chain time lines, which we perhaps can talk a little bit about later. But this is certainly our most advanced and prospective solar opportunity in the Manawa development portfolio at the moment. I'll just turn to the major asset refurbishment program. As we've noted, this is the most significant program of investment in our existing asset base in the company's history, including obviously from the Trustpower years, targeting our most strategic assets across Matahina, Coleridge, Waipori, Highbank and Arnold, that makes up in excess of 40% of the volume on an annual basis from our portfolio. As Phil noted, these refurbishments not only, of course, improve the overall condition rating of these assets and bring them back in line with our expectations for the next many decades, 50 years plus. But as you would expect, with modern machine replacements, we see a bit more copper in the winding, a bit more efficiency from the [ wet end ] or the turbine or the runner from these machines that we do see increased production from most of these assets going forward. And what we're really seeing from this and we'll talk to a little bit later in the presentation is that by FY '27, we expect that our annual generation long-run production will be above our current baseline of circa 1,940 gigawatt hours. So we have a reduction, this financial year, similar number, next year of about 80 gigawatt hours, which is really as a result primarily of having to obviously take some of these machines out while we do these major CapEx works. But as indicated, we have been able to find solutions to minimizing the impact on the portfolio like the pumps to turbines project at Highbank. Thanks, Phil. In terms of how this is going, I think we're pretty happy with the way the enhancement and refurbishment program is rolling out. You'll note we've obviously completed a number of projects on the list there, including most recently the Waipori generator replacement in the Otago region. As noted, we're about to go into commissioning of the first of the new turbines at Matahina, with the second to follow later this year and into next. And the Highbank all unit replacement that outage will commence in September this year. So, I think the team has done a great job of continuing to look for opportunities to do better than the baseline. We have found a bit of an opportunity to bring forward the first unit at Coleridge into winter next year and that will certainly help particularly with the elevated sort of futures pricing we continue to see in the market, given the overall supply demand equation. Thanks, Phil. So, just a bit of a case study. As noted, for Manawa, these are very significant projects, Matahina, which is in the Bay of Plenty, not too far from HQ here comprises 80 megawatts in our portfolio. It's our sort of single largest asset by annual production and megawatt capacity. The units are 57 years old. We expect to get a similar life out of these replacements and we commenced taking the machine apart in simple terms in November '23. And as I say, we're right on the cusp of commissioning that to new runner. It's also been designed to take advantage of the hydrological flow or the patterns that we see. Obviously, particularly through the summer months, we tend to get lower inflows and the first runner will give us a higher degree of efficiency at that flow range. with the second runner and machine really giving us that peaking capacity to take advantage of higher priced periods and greater demand in the market. So that's progressing well. There's a few pictures there, obviously. And as noted, we expect to have completed the second unit by mid-calendar '25. So, not too far away. Thanks, Phil. Highbank, as I noted, is the other big unit replacement for us. This is really part of the -- an integrated set of assets for us in Canterbury, and I think one of the other contributors to our FY '24 performance was we had very strong irrigation demand out of the Canterbury region. So strong demand for both pumping through the Highbank pumping scheme, but also for our stored water releases from Lake Coleridge to the downstream irrigators and that was certainly another good contributor to our earnings throughout the year and we certainly anticipate that in future years, of course. And so this machine has been basically broken out from the concrete out at the very base of the turbine. We're replacing the full unit. We expect to get about an 8% production uplift with circa 100 gigawatt hours a year typically from this machine. And Highbank is one of the, I think, key projects that has had an impact on our FY '25 production volumes, as we outlined, again, offset by the pumps as turbine project that will be commissioned in the next couple of months ahead of that unit being taken out on September '24. So again, a circa World War II vintage machine. 1946, the scheme was commissioned. So we've got 80-odd years out of this unit to date, just reinforcing the long-life nature of these assets. And as we'll talk to on the next couple of slides, once we're through this major capital program, I think the portfolio is very well set up for all the future. Perhaps, Phil, you can have a chat on this one.

Yes. Thanks, Clayton. As we've said, the capital investment program is on track to deliver 78 gigawatt hours of production uplift. We've completed 29 gigawatt hours -- has already been achieved and another 12 gigawatt hours will be completed in FY '25. Some of the refurbishment projects do require scheme or unit outages. And on the right-hand chart, we've provided a little bit more detail around what that looks like over the next 4 or 5 years. And we've -- you can see there that for the next 2 years, we will -- those outages do result in us being lower than our long-term production volumes, so 1,880 gigawatt hours for FY '25 and 1,878 for FY '26. And then by FY '27, we see the benefit of the enhancements and that we are through the major outages by the end. So, we are starting to get well above the current long-term average of 1,942, and we get up to 1,990 sort of by FY '29. So, we'll talk a little bit more about that again when we come to talking about FY '25 guidance. But hopefully, that explains the relationship between the investment program, the enhancements and the production volumes over the next couple of years.

So in terms of ESG, I think one thing just to note here is that in July, Manawa will be releasing its climate statement and much more comprehensive information on our climate-related disclosures, but just touching on a few highlights here. Everyone will understand, obviously, we are largely renewable from our portfolio, but for our small diesel peaker at Bream Bay. Emissions that are outlined here is really a baseline of our Scope 1 and 2 emissions with some Scope 3 emissions relating to business travel. I think some of the key things we were able to deliver this year and there's a bit more information in our integrated report, but on the people and culture side, we're were pleased to roll out for Manawa, a fairly comprehensive parental support policy that we think will really bring us in line with many others in the market and I think help attracting people to work at Manawa. We're very pleased also during the financial year to move into our new building after a little bit of a delay like many projects of that nature in recent years. But certainly, that has provided us with a really wonderful working space and a lot of opportunity to get the team collaborating and really focused on nailing our strategy in the coming years. In terms of health and safety, our TRIFR was slightly down this year. We did, as noted, else, we have a slight increase in our LTIs, which was a little bit disappointing and certainly something we'll remain focused on, particularly with a large capital work program continuing for the foreseeable future. We had very good compliance with resource consent. Manawa, again, rather uniquely has over 3,500 resource consent conditions across our portfolio we need to comply with. So, I think the team has once again done a really great job running those assets and making sure we maintain compliance in all material respects with all of those conditions, which was a great result to see. And another key for us was just that ongoing interaction with the community. Again, with our footprint around the country, we were able to distribute an excessive $400,000, supporting some really great community initiatives, which are outlined here on the slide. And again, there's a little bit more detail on the integrated report provided. In terms of the regulatory landscape, again, for us, it's always about just focusing on the stuff that matters. I think given our relative size to other players in the market and some of the unique attributes of our business, just with the geographic footprint we have, the number of assets that we're looking to reconsent in the coming years, the fact that we have a lot of distributed generation connected assets rather than good connected, all of these things sort of play into how we think about the world perhaps a little bit differently to others. I think from our perspective, it's fair to say that the proposed direction of the resource management reforms in particular, are largely supportive of our business, certainly, in terms of developing new renewable generation assets and protecting the value of our existing diverse asset fleet. It's fair to say that the time, cost, complexity and risk associated with consenting has impacted us in the same way it has many others. And I think there's a real opportunity to have that occur on a more streamlined basis. Having said that, well aware that and some of the concerns around things like fast track consenting are valid and it is critical in our view, as it is in many others in the sector to maintain that social license and ensure that we continue to have real engagement and interaction with key stakeholders as we look to progress not only the new projects in our portfolio, but obviously reconsent those existing assets. I think for us more broadly, in terms of the electricity sector, obviously, the Market Development Advisory Group or MDAG proposed quite a number of potential reforms out over a number of years across the market. I think that's something that we will continue to keep an eye and again, just make sure that we're focusing on things that impact Manawa perhaps more uniquely than others, noting that a lot of others in the sector will be doing quite a lot of heavy lifting. For us, we are frankly, our needs and views will be largely aligned. Certainly, the opportunity associated with the low carbon transition is clear, electrification of the economy will only continue to drive the requirement for investment in new renewables and that's obviously very supportive of our very existing pipeline. Thanks, Phil.

Thanks. Just looking at our FY '25 guidance, we expect EBITDAF for the year to March '25 to be in the range of $130 million to $150 million. So, a similar range to what we -- the result we have seen in FY '24. That is based on hydrogeneration volumes of 880 (sic) [ 1,880 ] gigawatt hours as we noted on the earlier slide, that is sort of below our long-run average, particularly due to the Highbank scheme outage and some of that outage is required to deliver that major capital investment program. And that guidance as we do normally, it assumes current ASX forward pricing and normal levels of hydrology, which are -- do fluctuate and we will provide any updates. So that's necessary during the year. In terms of capital expenditure, our guidance range is $40 million to $50 million and that's in line with sort of the long-run CapEx projections that we have provided in previous presentations in terms of how that investment program rolls out over the next few years and it includes some modest investment in the new development pipeline, but obviously not actual build cost or construction costs. It's minor capital equipment in the preliminary phase. And with that, I think that brings us to the end of this section of the presentation. And maybe just a reminder in terms of questions, there are 2 ways of answering questions, either using the Q&A function in the Zoom app or if you'd like to ask it verbally, raise your hand in the Zoom app and we can unmute you and answer the question that way.

Sure. Grant, you have a question?

Yes. Just 2 questions. The first is you have all these options or myriad of them. But you haven't now deferred yet? I know you're talking about FID. What's holding up your going to bet on any of these? And could you give some color on what these things might cost in terms of long-run marginal cost or CapEx per megawatt? We saw contact at a blow out on what they are looking for in geothermal. All your competitors are talking about wind costs going up. Can you give some color on all of that?

Yes. Thanks, Grant. I wouldn't say there's anything in particular holding us up, getting to FID. Projects take time, right? Going through the full development continuum, securing land, doing a robust environmental assessment, completing an application, securing a consent, getting good connection. All of these things take a while. I think as you will know, Trustpower had a bit of a hiatus from undertaking development activities for some time, so has been looking to rebuild its development portfolio. I think we're generally quite comfortable with the rate at which these projects are progressing toward an investment decision, noting some of the challenges that you've outlined around long-run marginal costs and where that sits against future views of the wholesale electricity price curve. I don't think we're any different to anyone else in terms of how we're seeing the LRMC for these projects. Look Grant, haven't really seen a lot of softening or improvement in the short-term or expected in the short-term in relation to [indiscernible]. I think solar, as everyone knows, panel prices, module prices out of Asia have come off considerably. Not that long ago, they were USD 0.20 to USD 0.23 a watt, now they're USD 0.10 to USD 0.12. Even hear stories of single-digit numbers at scale. But there are much smaller component of the overall CapEx for those projects, again, as you all know. So I think for us, it's about progressing the pipeline at a sensible rate. We do think carefully about our annual sort of dev-ex budget and keeping the right projects ticking over. Obviously, we've got a number of options in the pipeline now and we'll continue to move those forward. But don't have any particular concerns that things are taking longer than they otherwise should. It's a little bit the nature of the game for us, so.

So progressing on those, are you thinking about a $100-plus wholesale market over the longer term in real terms? Or are you still slightly below the $100?

I think we're more of a former. We do see it as in the higher end of that range that you've indicated. As always, it's interesting just in terms of how we cut our own internal projections and it's obviously very sensitive to assumptions you make around build costs and new entrant costs, et cetera. But generally, think it is going to be at the higher end.

And then second question, I know that was lots of little questions. What's the key difference in your current model against your independent power producer model that you're slowly moving towards? And particularly, how it impacts OpEx and dividends?

Yes. I mean, I think it's a little bit semantics, Grant in that at the end of the day, when we divested the mass market retail business, we became an independent generator. We became an IPP. I think they're sort of same-same. What I suppose the focus we have on the IPP terminology is I think it's just helpful for us, both internally and in terms of our external comps around differentiating ourselves from the other larger vertically integrated players in the market. IPPs are obviously quite a well-understood construct in other markets. And really, it's just saying, look, we need to be a very focused, very lean, efficient, independent generator if we're going to be competitive. Being an independent generator, frankly, in the New Zealand market is not without its challenges, right? And so I think it's really important that we are really clear about our strategy. We execute on that really well. That will turn up in our efficiency, in our overall operating model efficiency, which is obviously our OpEx. It will turn up in how we think about placing our product in the market in a way that helps us to leverage their portfolio to get a capital structure that supports growth in terms of thinking about the overall debt and equity ask in each case for a new project. Clearly, that's linked in through to how we think about or how the Board thinks about dividends and returns to shareholders. And that's what we've really said is that the Board obviously resolved this year for a full year ordinary dividend of $0.19 per share. I think going forward for us, we've outlined some of the signposts you might see that indicate we are successfully executing on our strategy around some of those offtake discussions, et cetera, that will put us in a position to revise our capital structure to what is probably more a normal IPP model where IPPs typically have a high degree of revenue contracting a lower degree of revenue risk, which underpins how they think about the cost of capital, their overall gearing levels, et cetera. So, this is all stuff that we're continuing to work through. I think we're very well positioned to be able to execute on that in the coming months and years. And that will drive that overall, I guess, IPP construct that we tried to describe. But ultimately, for us, it's about efficiency and excellence in execution. And we think that's what will make us successful and different in terms of that model.

But the $0.19 dividend commentary was a little misleading in that the reason for the $0.19 was part of our going through new [ mobile ], et cetera, but also about one-off benefits of like carbon, et cetera, and sale of land or sale of assets. If you strip that out, are we still at $0.19 or should we be thinking about a new reset coming from the Board?

Yes. Grant, it is a combination of all of those things. It's a combination of a reasonably good year. It's a combination of some of the proceeds that we've received from divestment. But also, I guess the Board's comfort that we have a strategy going forward that will enable us to fund new developments and pay a dividend. Now, the way that capital structure looks might in a year or 2's time might be different to what it looks today. And that would necessitate potentially flows through to a slightly different dividend policy and that's what we sort of flagged in the release.

Yes. Yes, that's right. As Phil said, it's a combination of all of those things. At the end of the day, we did make the revision to our forward CapEx profile. In November '23, there's that confidence in the strategy. You're right, Grant, there were some gains from the sale of carbon and land this year that certainly helped the overall result. But on balance, the Board was comfortable obviously to take their position understanding how the market thinks about certainty around dividends going forward. But also, there is, I think, inevitably going to be an opportunity for the Board to have another look at those settings as we execute on that strategy and consider a revised capital structure down the track. Andrew?

I guess I'll follow on a little bit from Grant's dividend questions. One of the things I did note is, it looks like you've prepaid quite a little bit of tax to make sure it's fully imputed. Are you able to sort of talk through to that? And is that going to be a policy going forward as well if the -- to maintain fully imputed dividends?

Andrew, whilst we have got sort of, overall or positive tax receivable balance on that. It wasn't a deliberate strategy to prepay in order to fully imputed. It's more a function of just the uplift model we follow for provisional tax payments. But we are comfortable with being able to fully impute and Trustpower has in the past at times prepaid tax to fully impute and it wouldn't rule it out, but it's not -- I guess, it's not key to this year's dividend. But we're certainly confident that we will be able to fully impute this year's based on the imputation credit balance.

Okay. And just in terms of, again, thinking about what we might expect going forward, look, I'm assuming that we should look into the $0.19 full year dividend as opposed to $0.11 half year and going forward, be looking at that $0.19 as a base as opposed to, I guess, prediction that you've done half and half have been pretty similar, but $0.22 sort of feels a little bit on the [ average ] side to be going forward?

Yes, correct. Look at the full year. That's the way the Board has looked at it. That's right.

And in terms of, I guess, giving us some more a revised policy or whatever you might end up with because it does sort of feel we're in a bit of a limbo not quite exactly sure where you're going with this. When you will be able to provide the market, I guess, with more certainty around the future dividend policy?

Yes. I mean that's somewhat here, Andrew, I mean I think as I flagged, we've tried to be reasonably clear that there are a few signposts that you will see and there will be plenty of advanced notice around us executing on some of those core elements of our strategy around the portfolio contracting, et cetera. As I noted, those are reasonably significant and material contracts. Obviously, if you're looking at reasonable volume over a reasonable tenure, clearly, there's some other stuff in the market that isn't resolved until which is all where we will expect it to be at some point in relation to something like TY, for example. So I think those discussions will unfold and land as they lend and are a precursor to us then looking at how we move to a different capital structure. I think the dividend policy settings will all be part and parcel of that in due course. So, the exact timing is TBD, but I think even you will get a reasonable sense of when that's likely to drop as you see those other things be successfully executed on, if you like.

And last question for me is a little bit of a detailed one. But looking at the other revenue line is a big step up, which is I understand it will be a reasonable chunk is the carbon sales, which, I just -- the exact total was even more this year. If I've done my math correctly and back out the carbon sales from FY '24 and FY '23, it still looks like a fairly substantial $7 million increase coming through the other revenue line. Are you able to sort of talk to that because I noticed there wasn't anything in the bridge, which sort of alludes to any sort of change there?

Yes. I think there's 2 things in the other revenue line, Andrew, that you're probably seeing there. One is some insurance proceeds coming through and the other is irrigation revenue. We had -- as Clayton said earlier, we had strong irrigation revenue numbers in FY '24.

Yes. I mean we, in simple terms, had a record season in terms of the volume of irrigation water supplied this year. We also saw higher cost to serve, for example, from the Highbank pumps because you're procuring energy at a more elevated price, as you know. But yes, that was certainly a key contributor to that line item. There's a few questions we have are online here. So, maybe we'll just take those up. The first, Adrian. In relation to high energy prices does it make sense to delay some of our enhancement projects or our major capital projects. Not a bad question. The reality is, given the nature of these projects, there's obviously years of planning goes into the design. Whilst we've only recently started pulling machines into bits, if you like, obviously, there were many years of planning and manufacturing and procurement ahead of it. So, the time to secure the parts, the equipment, the people to undertake these outages is obviously no small challenge as everyone will know, particularly with large-scale projects across the globe recently. So, we're somewhat are where we are. And I think we have taken the view that we're better to obviously carry on and complete these projects as efficiently as possible. And as noted, we're not too far off from sort of coming out the other side of it and seeing us at or above our current baseline. So that's really the factor. I think one of the things, like I mentioned earlier, bringing forward one of the units at Coleridge for example, by a full 12 months is really a case of saying, well, we can get these outages completed. Completion is derisking, make the machines available to capture what we still see is fairly elevated prices for the foreseeable future. We've got a question from Vignesh at UBS. Thanks, Vignesh. What are we seeing from construction cost perspective on new wind and solar beyond Argyle? Directionally, are we seeing these build costs moderate for or continuing to track upwards? A little bit of a mix of all of the above, really. I think wind is still pretty uncertain. We're not seeing -- it's probably more moderate to maybe still slightly tracking up. I think some of the balance of plant costs may be slightly improving. Certainly, lead times, perhaps some of the civil components we hope we will see at least moderation. If nothing else, and I think we are still confident that in the more medium term, perhaps we will see wouldn't continue to improve in terms of its cost, particularly on the OEM side. Solar, I think as we noted, right, we're seeing module prices improve. Other components, maybe less so. The reality is this renewable stuff is still a lot more expensive than it was than the not too distant past, right? So, we will continue to keep an eye on it. I think, again, for us, given the stage that our development portfolio is that we will continue to move those -- there will be -- these numbers will move around. They flow through as you know, to the [indiscernible] of this plant in the wholesale curve and we will take decisions when they make sense. On CapEx, from the $70 million reported today stripping out the other CapEx and new development spend, how much of the $50 million is underlying spend versus hydro in upgrades [indiscernible]? Phil, can talk to it.

Vignesh, thanks. We have indicated previously that we think our long-run BAU CapEx is in the $15 million to $20 million range once we're through this significant investment program. But there's a small amount of that is non-hydro. But if you look at the delta between that and the $50 million that we've shown in FY '24 for the generation assets, that's sort of a split between the current program and the long-run BAU.

Thanks. A couple of questions from [ Neville ]. Thanks, for putting those through Neville. FY '25 goals include signing a cornerstone PPA, some questions around volume, tenure. Are they likely to be firmed or relatively straightforward generation following? I suppose there's 2 things here, right? From the existing portfolio, as I noted, we have quite a unique set of assets and therefore, sort of generation product from that given the diversity of location, catchments, et cetera, as well as some storage associated with our Cobb/Coleridge and Waipori assets in particular. I think for us, getting all that stuff in the right place is really important. Clearly, we see things like what we call the peaking factor or the GWAP/TWAP ratios of those assets are very different to new build wind and solar. Certainly, we see that only improving for any assets that have any degree of peaking capabilities, such as those assets that I mentioned were some storage. So I think for us, we will think very carefully about the percentage of that portfolio that we look to sell that is complementary with potential new build from wind and solar going forward. I think in terms of where that might end up, to have any meaningful impact on our capital structure, we probably see that in the range of 60% -- to 60% to 70% or thereabouts of our sort of hydro portfolio volume. Now that won't necessarily all be with a single offtake counterparty obviously, but we are talking to people that have interest in a reasonably significant proportion of that volume and reasonable tenure, 10-years plus effectively from that portfolio. So that's how we're thinking about that and building up that portfolio and then in terms of how complementary that is with new build. In terms of the new build, yes, that's the question of the day, right, how firm is firm. Clearly, generation following is relatively straightforward. We do see reasonable interest, particularly coupled with some of the discussions we're having around our existing portfolio for essentially generation following fixed price variable volume PPAs, but to also understand, obviously, that a number of off-takers are looking for something that is more load following on their side. And that's obviously something we think about, particularly when we do have albeit a degree of limited storage from our existing portfolio, how we can supply products that meet their requirements going forward. Neville has also asked our view on medium- to long-run average price. I think without being too specific about that Neville, we responded to Grant earlier about his question about where that sits sort of North versus South of $100. In terms of, is there a useful role for spot sales as Manawa transitions to an IPP. I think the answer to that is absolutely. One of the benefits we have in-house is having their trading capability. And I think for us, a combination of those longer tenure larger volume offtakes coupled with our ability to trade out stuff 2 or 3 years ahead on the ASX as well as manage our overall position on any given day with some more modest stuff really like around the edges on the spot market. All of that is critical to us being able to manage our portfolio risk going forward and try and get there. I hesitate to use the word optimize because that's a bit of an impossible task in the energy market, but just get that in the best place we can to support our overall risk and the Board's risk appetite around earnings volatility, but also position ourselves, frankly, to take advantage of the market on any given day and extract a bit of upside value. And that's certainly something we continue to let our teams explore as how they can do that within that trading function within the business. A question from Steven around the size of the uplift on Mercury CFD as it rolls off, taking into account shape location with 2 terawatt hours. It's the megawatt --hours of megawatt will be a good starting point. And that's a really specific question. Yes. Look, the reality is, as you know, we've got a couple of things, right? There's from October '24, we have a reduction in the volume that we sell to Mercury under the hedge of circa 250 gigs per annum. So, on a financial year basis, you get about 50% of that on a weighted basis. And then a repricing of the construct from October '26, which is a historic ASX-linked look back, if you like, with adjustments for location and peaking. So that the volume that it applies to reduces at the point you get out to that repricing. I think we probably can't say too much in terms of the specifics, but you've obviously got a bit of a look ahead as that price starts to sort of lock-in over that historic period when you get to October '26, given where ASX futures are sitting. And perhaps if there's an opportunity to pick that up tomorrow, Steven or in a subsequent conversation, we can try and come back to you with a bit more detail on that front. Question from [ Cameron ] around geographic diversity and pipeline. Are you looking at battery options. Any info on costs and sizing would be helpful. Yes, it's a good question. I think sort of is the answer. I think batteries are obviously quite an interesting play and clearly provides a capacity solution on a shorter time step to 4 hours tops maybe at this current point in time, given their technology and pricing. And we do have a number of network connections associated with our assets scattered throughout the country. I think just given the nature of our portfolio, batteries maybe make a little bit less sense for us than others in the markets that have currently talked about exploring those, just given the overall volumes and the nature of our business. I think we have seen, although by caveat, this was saying, it's not something we've been very particularly focused on in recent times is that the lead time and the cost for these utility-scale batteries has certainly improved quite markedly in fact, in recent months, which will help and experience from Australia suggests that a lot of players that have been looking at these types of facilities have been more focused on the 1- or 2-hour discharge sort of end of the spectrum versus longer term, but I'm sure that will shift to energy density and cost of storage improves in favor of these solutions, but that's probably about the extent of the insights we can offer at this stage. Do you want to...

I'll take the next one, Cameron. Your question was generation asset maintenance costs up to $31 million. Please remind us of the long-run expectation. Yes, as we looked at earlier, that was up $4 million on the prior year. Then sort of in the near term, looking forward, I would probably expect that to be $1 million to $2 million lower. As I said, we did bring forward some maintenance costs into FY '24 and had some weather-related costs in there as well. And as we complete this asset sort of refurbishment program, there is obviously some benefit there in terms of ongoing maintenance costs with newer, more reliable equipment.

All right. I think we have exhausted all the questions online at least. Just maybe give people another minute or 2 if there's anything else they want to ask over the mic or online. Otherwise, thank you very much for attending. Much appreciate it.

Thanks, everyone.

All right. Thanks, everyone. Have a great day.