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? Great. 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 2024, 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 NZD 0.11, bringing the FY 2024 total dividend to NZD 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 NZD 8 million on the prior year, and, 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 2024 based on the new TPM regulations that came into place on the 1st of April 2023. So that contributed NZD 17 million in the prior year and didn't contribute to this current year result. Our net profit after tax of NZD 24 million was impacted by a NZD 46 million non-cash unfavorable movement in the fair value of financial instruments. And we have seen, you know, quite large swings in those, that fair value in the last two 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 NZD 444 million included the one-off sale of the mass market retail business. It also included a NZD 63 million favorable movement last year in the fair value of those financial instruments. CapEx this year of NZD 69 million was up on the prior year. Significantly up, up NZD 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 NZD 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 an investment in the joint venture with Pioneer for our Kaihiku Wind Farm. The next slide looks at just the movement in EBITDAF in a bit more detail. As you'll see, EBITDAF was up NZD 8.3 million on the prior year. And as I mentioned, the first two items on the bridge chart there are non-recurring items. So we have the loss of the ACOT revenue impacting this year by NZD 17 million. We have a gain in FY 2024 of NZD 2.4 million on sales of carbon units. That's a NZD 6 million swing from the prior year. And now, we have now divested all of our carbon units, so there'll be no carbon impact going forward. In terms of the energy margin, our energy margin was up NZD 14.5 million compared to the prior period. That's a, that's a you know, 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 maintenance costs, which is the maintenance spend, the OpEx maintenance spend that we on the generation assets, that was up NZD 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 two of our sites, to sort of remediate from some weather events, that we had during the year. Our new development OpEx, so it was down NZD 2.6 million on the prior year. That does tend to be a little bit lumpy year-on-year, just depending on what stage the projects are at in progressing the pipeline. And pleasingly, our other OpEx, which is our corporate overheads, and the majority of our employee costs, were NZD 4.5 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 more breakdown and some more detail on those sort of our operating expenses in the appendix to this presentation, for those that'd 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 a favorable variance year-on-year of NZD 2 million. Looking at the next slide just looks at that NZD 69.5 million of CapEx in the year. As previously, as we've previously signaled, you know, we are partway through a major asset refurbishment program. In FY 2024, this included major works at, some of our larger sites, particularly Waipori, Arnold, Highbank, Coleridge and Matahina. The capital investment program provides, you know, long-term revenue protection on what are very long-lived 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, you know, revenue protection and reliable generation for well into the future and, and for 50+ years. A number of the projects also deliver, production improvements or additional output. And we've previously flagged that we are, that, that the investment program will deliver an additional 78 GWh of, production output. We'll provide some more detail on the status of those projects and where we're at on the 78 GWh a bit later in the presentation. I'll hand back to Clayton to talk a bit more about our strategic plan and progress made to date. Yeah, thanks, Phil. So on this slide, we've really just outlined the three 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 is very much first and foremost about, excuse me, protecting the value from our existing portfolio of renewable assets. And so in that first tranche there or row, 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 GWh per annum uplift. We've completed a couple of generator replacements. One of those fell into FY 2024 at Waipori 3 station, with Waipori 4 the year prior.t We have made really good progress with Matahina, replacing the two runners on those units. They're our biggest single generating assets in the fleet at 40 MW each, and we will be wet commissioning the first of those units in the coming days and hope to have that completed in the next month or two, 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 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 that outage commencing in September. And we've also made really good progress with our re-consenting of our existing portfolio. Obviously, with a number of assets we have around the country, we do face a reasonable program of re-consenting 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. 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 consents for the first portion of the Argyle Solar project in Marlborough, located adjacent to our Branch River Hydro Scheme. We have lodged consent for an expansion to that site and expect to secure those consents in the coming months, and that's circa 65 MW-70 MW AC opportunity in that part of the world. Have also made really good progress with a couple of key wind farm projects in our portfolio that we expect to lodge consents for in FY 2025, 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 MW now with several hundred more MW 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. I think all of those points flow into our FY 2025 goals and targets, which is really, you know, 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've flagged that we expect to have the Argyle Solar project in that position during FY 2025. Perhaps, Phil, if we go on to have a quick chat about the development pipeline. As flagged, you know, we've now progressed this to in excess of 1.2 GWh, 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, circa 100 MW, and another 200 MW AC project in the Mackenzie Basin. Again, as we like to point out, I think all of these projects in our view have very strong fundamentals and should realize competitive LCOEs going forward. Obviously, a number of them are at different stages, and I've talked 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 in November 2023. 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 access 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 re-consenting efforts with our existing hydro fleet. As I said, I'll touch on that a little bit more later. 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 four or five financial years, and we're targeting, you know, significant growth out to FY 2030. Just a bit of an update on some of the more recent projects we've announced. As flagged, we when we provided our revised guidance in March 2024, 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 proximate or 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 intraday, 8-10-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, while 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 timelines, 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, you know, that makes up an 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, you know, 50+ years, 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. And we do see increased production from most of these assets going forward. What we're, what we're really seeing from this, and we'll talk to it a little bit later in the presentation, is that by FY 2027, we expect that our annual generation long run production will be above our current baseline of circa 1,940 GWh. So we have a reduction this financial year, similar number next year of about 1,880 GWh, 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, to minimizing the impact on the portfolio, like the Pumps as Turbines project at Highbank. Thanks, Phil. In terms of how this is going, I think we're, 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 full 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 MW 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 2023. And as I say, we're right on the cusp of commissioning that 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 this 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 price 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 2025, so not too far away. Thanks, Phil. Highbank, as I noted, is the other big unit replacement for us. This is really part of an integrated set of assets for us in Canterbury, and I think, one of the other contributors to our FY 2024 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, this machine, is being basically broken out from the concrete out, at the, the very base of the turbine. We're replacing the full unit. We expect to get about an 8% production uplift. We're circa 100 GWh a year, typically from this machine. And Highbank is one of the, I think, key projects that has had an impact on our FY 2025 production volumes as we outlined, again, offset by the Pumps as Turbines project that will be commissioned in the next couple of months ahead of that unit being taken out in September 2024. 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 the future. Perhaps, Phil, you can have a chat to this one. Yeah, thanks, Clayton. As we've said, the capital investment program is on track to deliver 78 GWh of production uplift. We've completed 29 GWh already, has already been achieved, and another 12 GWh - Mm-hmm. will be completed in FY 2025. 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 four or five years. You can see there that, for the next two years, those outages do result in us being lower than our long-term production volumes, so at 1,880 GWh for FY 2025 and 1,878 GWh for FY 2026. And then by FY 2027, we see the benefit of the enhancements and that we are through the major outages by then, so we are starting to get well above the current long-term average of 1,942 GWh, and we get up to 1,990 GWh sort of by FY 2029. So we'll talk a little bit more about that again when we come to talking about FY 2025 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, and I think one thing just to note here is that in July, Manawa will be releasing its climate statement and much more comprehensive information about climate-related disclosures. But just touching on a few highlights here, everyone will understand obviously we're 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 very pleased to, roll out a, for Manawa, a fairly comprehensive parental support policy, that we think will really, you know, bring us in line with many others in the market, and I think it help attracting, people to work at Manawa. We're very, very pleased also during the financial year, to move into our new building after a, 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 elsewhere, 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 consents. 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 in excess of NZD 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 re-consent in the coming years, the fact that we have a lot of distributed generation connected assets rather than grid- 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, you know, the time, cost, complexity and risk associated with consenting has, has impacted us in the same way it has many others, and I think there's a real opportunity to, to have that occur on a more streamlined basis. Having said that, you know, well aware that, and, you know, that some of the concerns around things like fast- track consenting are valid and, you know, 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, re-consent 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 on, and again, just make sure that we're focusing on things that impact Manawa, perhaps more uniquely than others, noting that, you know, a lot of others in the sector will be doing quite a lot of heavy lifting. For us, we're frankly, you know, 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 existing pipeline. Thanks, Phil. Thanks. Just looking at our FY 2025 guidance, we expect EBITDA for the year to March 2025 to be in the range of NZD 130 million-NZD 150 million. So a similar range to the result we have seen in FY 2024. That is based on hydro generation volumes of 880 GWh, as we noted on the earlier slide. That is sort of below our long-run average, particularly due to the Highbank instream outage, and some of that outage is required to deliver that major capital investment program. And that guidance is as we do normally, you know, assumes current ASX forward pricing and normal levels of hydrology, which are, you know, hot... Do fluctuate, and we will provide any updates if it's necessary during the year. In terms of capital expenditure, our guidance range is NZD 40 million-NZD 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 costs 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. Maybe just a reminder in terms of questions. There are two 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. Thank you. Grant, you have a question? Yeah, thanks. Good morning. Just two questions. The first is, you have all these options, and a myriad of them, but you haven't gone to FID yet. I know you're talking about FID. What's holding up you going to FID 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? You know, we saw Contact's at a blowout on what they're looking for in geothermal. All your competitors are talking about wind costs going up. Can you give us color on all of that? Thanks. Yeah, thanks, Grant. I wouldn't say there's anything particular holding us up getting to FID. Projects take time, right? You know, 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 well 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 wind LCOEs. I think solar, as everyone knows, panel prices, module prices out of Asia have come off considerably. Not that long ago, they were NZD 0.20-NZD 0.23 a watt, now they're NZD 0.10-NZD 0.12. Even hear stories of single-digit numbers, at scale. But they're a much smaller component of the overall CapEx for those projects, again, as you well 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 DevEx 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. Progressing on, on those, are you thinking about a NZD 100+ wholesale market over the longer term in real terms, or are you still slightly below the NZD 100? I think we're more the former. We do see it as in the higher end of that range that you've indicated. As always, it's interesting just, you know, 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 yeah, generally think it is going to be at the higher end. Thanks. And then, my second question, 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? Yeah. 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. I suppose the focus we have on the IPP terminology, I think it's just helpful for us, both internally and in terms of our external comms, 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? I think it's really important that we are really clear about our strategy. We execute on that really well. That'll turn up in our efficiency, you know, our overall operating model efficiency, which is obviously our OpEx. It'll turn up in how we think about placing our product in the market in a way that helps us to leverage that 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 then 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 NZD 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 higher degree of revenue contracting, a lower degree of revenue risk, which underpins, you know, how they think about their 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 try to describe. Ultimately, for us, it's about efficiency and excellence in execution, and we think, you know, that's what will make us successful and different in terms of that model. ... Thanks. But the NZD 0.19 dividend commentary was a little misleading, in that the reason for the NZD 0.19 was part about going through some new model, et cetera, 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 NZD 0.19, or should we be thinking about a new reset coming from the board? Yeah. Grant, it is a combination of all of those things. It's a combination of- Mm-hmm. You know, a reasonably, reasonably good year. It's a combination of the, some of the, proceeds that we've received from, from divestment. But also, I guess, the board's, comfort that we have a strategy, going forward that will enable, enable us to fund, you know, new developments, and pay a dividend. Now, the way that capital structure looks might, in, in a year or two's time, might be different to the way it looks today. And, and that would necessitate, you know, potentially flows through to, through to, to a slightly different dividend policy, and that's what we've sort of flagged in the release. Yeah, yeah, that's right. As, 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 2023. 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 would've certainly helped our overall result. But on balance, the board was comfortable, obviously, to take that position, understanding how the market thinks about certainty around dividends going forward. But obviously, 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. Thanks. That's all for me. Thanks for answering those questions. No problem. Andrew? Morning, guys. Thanks for all that. Good morning. I guess I'll follow on a little bit from Grant's dividend questions. One of the things I did notice, 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 gonna be a policy going forward as well, to maintain fully imputed dividends? Yeah. Hi, Andrew. Whilst we have got sort of a favorable or a positive tax receivable balance, that it wasn't a deliberate strategy to prepay in order to fully impute. It's more a function of just the uplift model we follow for provisional tax payments. But yeah, we are comfortable with being able to fully impute. And Trustpower has in the past, at times, prepaid tax to fully impute, and I wouldn't rule it out. But it's not, yeah, 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, thanks. And just in terms of, again, thinking about what we might expect going forward, I'm assuming that we should be looking at the NZD 0.19 full year dividend as opposed to the NZD 0.11 half year. And going forward, be looking at that NZD 0.19 as a base, as opposed to... I guess traditionally you've done half and half have been pretty similar. But NZD 0.22 sort of feels a little bit on the rich side to be going forward. Yes, correct. Look at the, look at the full year. Indeed. Yeah. I think the board has been. That's the way the board has looked at it. That's right. And in terms of, I guess, giving us some more, you know, a revised policy or whatever you might end up with. 'Cause it does sort of feel we're in a bit of a limbo, not quite exactly sure where you're going with this. When will you be able to provide the market, I guess, with more certainty around the future dividend policy? Yeah, I mean, that's somewhat fair, 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'll be plenty of advance notice around us executing on some of those core elements of our strategy around the portfolio, contracting, et cetera. You know, as I noted, those are reasonably significant and material contracts. Obviously, if you're looking at reasonable volume over a reasonable tenor, you know, clearly there's some other stuff in the market that isn't resolved until it's resolved, where we all expect it to be at some point, in relation to something like Tiwai, for example. So I think that those discussions will unfold and land as they land, and are a precursor to us then looking at how we move to a different capital structure. And 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 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. Sure. Okay, thanks. And last question from me is a little bit of a detailed one, but looking at the other revenue line is a big step up, which is understandably a reasonable chunk is the carbon sales, which I guess the exact total was a wee bit more this year. If I've done my math correctly and back out the carbon sales from FY 2024 and FY 2023, it still looks like a fairly substantial NZD 7 million increase coming through the other revenue line. Are you able to sort of talk to that? 'Cause I noticed there isn't anything in the bridge, which sort of alludes to any sort of change there. ... Yeah, I think there's two things in the other revenue line, Andrew, that's probably you're seeing there. One is some insurance proceeds coming through, and the other is irrigation revenue. We had, as Clayton said earlier, strong irrigation revenue numbers in FY 2024. Okay, that's great. That's all for me. Thanks. Yeah, I mean, we in simple terms had a record season in terms of the volume of irrigation water supplied this year. We also saw, you know, higher cost to serve, for example, from the Highbank pumps, because you're procuring energy at a more elevated price, as you know. But yeah, that was certainly a key contributor to that line item. There's a few questions we have 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. You know, while we've only recently started pulling machines into bits, if you like, obviously there were many, many years of planning and manufacturing and procurement ahead of that. So, you know, 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 somewhat are where we are, and I think have taken the view that we're better to, you know, obviously carry on and complete these projects as efficiently as possible. And as noted, you know, we're not too far off from sort of coming out the other side of that and seeing us, you know, 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, you know, we can, we can get these outages completed. Completion is de-risking, make the machines available to capture what we still see as 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 the above, really. I think, 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 a moderation, if nothing else. And I think we are still confident that in the more medium term, perhaps we will see wind, you know, 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 in 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 at, we will continue to move those. There will be—these numbers will move around. They flow through, as you know, to the LRMC of this plant and the wholesale curve. And, you know, we will take decisions when they make sense. On CapEx, from the NZD 70 million reported today, stripping out the other CapEx and new development spend, how much of the NZD 50 million is underlying spend versus hydro and upgrade spend? Yeah. We can talk to that. Vignesh, thanks. We have indicated previously that we think our, you know, our long run BAU CapEx is in the NZD 15 million-NZD 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 NZD 50 million that we've shown on it, in FY 2024 for the generation assets, that's sort of the split between, you know, the current program and the long run BAU. Thanks. Couple of questions from Neville. Thanks for putting those through, Neville. FY 2025 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 two 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 ability, some storage associated with our Cobb, Coleridge, and Waipori assets in particular. I think for us, getting all of that stuff in the right place is really important. Clearly, the... You know, we see things like what we call the peaking factor or the GWAP- to- 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 capability, such as those assets that I mentioned with 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%- 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, you know, 10+ years effectively from that portfolio. So that, that's how we're thinking about that and building up that portfolio. And then in terms of how, 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, you know, essentially generation- following fixed price, variable volume PPAs. But do also understand, obviously, that a number of offtakers 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 NZD 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 that trading capability. I think for us, a combination of, you know, those longer tenure, larger volume offtakes, coupled with our ability to trade out stuff two or three years ahead on the ASX, as well as manage our overall position on any given day with some more modest stuff, if you 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, you know, try and get that at, I hesitate to use the word optimize, 'cause 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, extract a bit of upside value. And that's certainly something we continue to let our teams explore, is how they can do that within that trading function and within the business. A question from Stephen around the size of the uplift on Mercury CFD as it rolls off, taking into account shape, location, with 2 TWh, it's 30 MWh be a good starting point? That's a very specific question. Yeah. Look, the reality is, as you know, we've got a couple of things, right? There's from October 2024, we have a reduction in the volume that we sell to Mercury under that hedge of circa 250 GWh per annum. So on a financial year basis, you get about 50% of that on a weighted basis, and then a repricing of that construct from October 2026, which is a historic ASX, ASX- linked, look- back, if you like, with adjustments for location and peaking. So the, 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, as that price starts to sort of lock in over that historic period when you get to October 2026, given where ASX futures are sitting. And perhaps, if there's an opportunity to pick that up tomorrow, Stephen, or in a subsequent conversation, we can try and come back to you with a bit more detail on that front. A question from Cameron around geographic diversity and pipeline. Are you looking at battery options? Any info on costs and sizing would be helpful. Yeah, it's a good question. I think sort of is the answer. I think batteries are obviously quite an interesting play and clearly provide a capacity solution on a shorter time step to, you know, two-four hours tops, maybe at this current point in time, given that 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 market that have currently talked about exploring those, as I say, just given the overall volumes and the nature of our business. I think we have seen, although I caveat this with saying it's not something we've been very particularly focused on in recent times, is that, you know, the lead- time and the cost for these utility- scale batteries has certainly improved quite markedly, in fact, in recent months, which will help. You know, experience from Australia suggests that a lot of, a lot of players that have been looking at these types of facilities have been more focused on the one- or two-hour discharge, sort of end of the spectrum versus, versus longer term, but I'm sure that will shift as energy density and cost of storage improves in favor of these solutions. But that's, that's probably about the extent of the insights we can offer at this stage. I'll take the next one. Cameron, yeah, your question was generation asset maintenance costs up to NZD 31 million. Please remind us of the long-run expectation. Yes, as we looked at earlier, you know, that was up NZD 4 million on the prior year. In sort of the near term, looking forward, I'd probably expect that to be NZD 1 million-NZD 2 million lower. As I said, we did bring forward some maintenance costs into FY 2024, and had some weather-related costs in there as well. And as we complete this asset refurbishment program, there is obviously some benefit there in terms of ongoing maintenance costs, with newer, more reliable equipment. Right. I think we have exhausted all the questions online at least. Just, maybe give people another minute or two if there's anything else they want to ask either over the mic or, or online. Otherwise, thank you very much for attending. Much appreciated. Thanks, everyone. All right. Thanks, everyone. Have a great day.