Manawa Energy Limited (MNW) Earnings Call Transcript & Summary

Okay. Thank you, I think we'll get started now. I see that there are still people joining us. But as I said earlier, welcome, everyone, to our second final results announcement as Manawa Energy. My name is David Prentice. I'm the Chief Executive. And to my left, your right, is Philip Wiltshire, who is our GM Corporate Services. We'll go to a presentation that we'll step through this morning. Hopefully, as quickly as we can. There's a few slides that we obviously need to get through a lot of information in there, but we obviously do want to leave enough time for prefer to ask a question. So we'll aim to get through this and maybe half an hour to 35 minutes, which should give enough time, as I said, for questions. [Operator Instructions] So without any further ado, we'll get kicked into the presentation. So Phil. So just as a very much a high level kind of summary, year-end review. As I said, this is our second annual results announcement as Manawa, but it's really our first full year as Manawa Energy. It's been a fascinating, interesting, exciting, frustrating year certainly for us, but very much a solid foundational year as we move from being a vertically integrated generator retailer to now the largest independent generator -- in New Zealand, generator, developer, of course, C&I business model that we now run. And of course, that has involved our huge amount of work right across the organization, which we'll talk about in slides to follow this, but which includes the development and rollout of a new strategic plan. Our purpose, vision, mission, values, a new remuneration format, a new performance framework, all of which contribute to foundational activities right across the organization. And of course, in the past -- at the same time of doing that, we have successfully accelerated our new development pipeline. After 2 years, as I said, focus on the sale of the mass market retail business. So it's exciting to finally start to announce some of the opportunities that we've got in front of us. We also approved a record level of investment across our existing hydro fleet, which we signaled at our 6 monthly results 6 months ago. And again, I'll go into that in a little bit more detail and give you a heads up on that. At the same time, hopefully, most of you on the call will be -- will agree that we're navigating some fairly volatile hydrological and market conditions over the past year, certainly, some of the most volatile we've seen in a long time, and at the same time, manage significant weather events safely with our people safety at the heart of everything we do. So it certainly wasn't a rainfall year. So in terms of some of the highlights, look, I wouldn't dwell on this slide too much. Phil will talk in a little bit more detail in terms of some of our key financial metrics. So we'll maybe move on from on that Phil, and I'll let you talk to that a little bit later on. But maybe just on park and look at a bit more detail in terms of our kind of strategic update. So our strategic plan is really effectively focused on 2 or 3 things -- 3 things. We no longer have the complication or the competing factor of our retail business to Mercury last year. So we've got a very simple strategy, and that is simply to develop new generation projects to enhance the existing assets that we've got and to maximize the value that we've got -- that we can generate from existing hedge that we have with Mercury, which we sold in parallel with our retail business. Of course, we can't do all of that without having kind of key enablers across the organization, whether that technology and innovation, whether it's culture and capability or whether it's just baseline -- what we call baseline excellence around sustainability, health and safety, reputation and brand and really important iwi relationships. And why are we different to anybody else out in the market there? Well, we believe we are for those reasons listed down to the left. But primarily, we have retained and, in fact, brought in more quite significant capability in terms of wind development, which we see as a distinct advantage over many of the other developers out there. And most importantly, and this is why we put a kind of key focus on to developing a clear strategy, is we have our focused team with a clear line of sight to what we are trying to achieve as a business so that everybody in the business knows how they can contribute to what we are trying to achieve with respect to our aspirations and our goals. So how have we actually done in terms of progress against that strategic plan? Well, again, I won't go through this in detail, but perhaps pick out 2 or 3 highlights there. First line along the top, we're pretty pleased, if I'm being brutally honest to say, that we have now secured 920 -- roundabout 920 megawatts of solar and wind projects with either landholder or option agreement in place with a further 420 in advanced stages of negotiation. And again, as a reminder, that's very much from a standing start from roughly 2.5 years ago. So very pleased with the progress that the team has made. I'll come on to some 2 key projects that I'll unpack in a little bit more detail just in a minute. As I mentioned earlier, we had a quite significant large wave of CapEx across our existing generation fleet that we announced at our half yearly results. And again, more detail on that in terms of a bit of an update, but that's very much a key level -- a key area of focus for us across the organization in terms of delivering all of those projects on time, on budget and with the required quality. So as I said, I just wanted to kind of highlight those 2 areas there. There are many, many other aspects that I mentioned just earlier in terms of the overarching summary. But needless to say, it's been a very, very busy and very successful year from our perspective. So in terms of that kind of major asset investment that I alluded to there, we've actually got 26 schemes across -- right across the country. And historically, we spent around about $10 million of CapEx on those schemes. We developed our targeted and prioritized focus to look at enhancing those schemes about 3 years ago now with a focus on our large value assets in terms of giving them quite significant upgrades. So we're only kind of towards the start of that program of what has been a record level of investment. So as I said, historically, we spent about $10 million on our assets. Moving forward in FY '23, we spend circa $40 million to $45 million. We'll be spending slightly over that in '24 before we start to see that level of investment start to tailor from FY '26 onwards. And I've got a graph in a couple of slides time that will probably better illustrate that. So as I said, most of the focus up until now has been on what we believe are our high-value assets. So that's Coleridge, Matahina, Waipori Branch, Cobb and Highbank, as you can see on there. And for those 6 schemes there, what you've got is an update both in terms of cost, the value of the work and in terms of some of the time frames as well as the actual work that we're doing. But in each of those top 6 cases, we are actually focusing an enhancement in terms of an increased output from that level of investment that we are putting into the strategic assets. In parallel to that, we've obviously got a comprehensive dam safety program that we run right across our portfolio. And this financial year, the Board approved a significant circa $15.6 million investment into dam strengthening works at Arnold dam down in the West Coast. But as I said, these are purely 7 of our more strategic assets. We've still got quite significant, basically, BAU that will continue in all our other assets around the country. So just in terms of those enhancements. So we've effectively -- since we started the program, as I said, about 2.5, maybe 3 years ago, we've now currently delivered 30 gigawatt hours uplift in terms of output. We've got another 50 that is either scoped or certainly has been approved, and there's another 30 that is currently in the process of being scoped. So as you can see, we've got another kind of 80 gigawatt hours planned or being scoped as a result of those enhancement projects, and we will continue to provide updates on our full year and half year results as those projects start to mature. It's fair to say, as I said earlier, again, just as a reminder, there is an intense focus from right across the organization in terms of delivery now that we've -- these have been approved. We've gone out to the market because there is an intense focus in terms of delivering on time, on budget and with the required quality. So moving on to our new development pipeline. As I said earlier, we've secured now roundabout 920 megawatts of solar and wind projects. And that graph, the 2 graphs at the bottom on slide, provide a little bit more of a breakdown of those slides -- sorry, of those projects. Look, I think it's fair to say we're not expecting all of the options to be viable developments, but our aspiration remains to develop 500 megawatts of new projects by 2030. We have a rigorous way of prioritizing projects, we believe, in the New Zealand stock, and we put a lot of effort into ensuring that the opportunities that we bring up to the management team and also up to the Board for approval, meet all the key project fundamentals in terms of good wind resource and cost proximity to transmission. So we're, in a nutshell, very happy with progress to date. Key point is that we're now moving from very much our ideation phase to more of a prioritization and execution phase. So we'll start to provide more color and context as what that looks like, which is probably a mix, a good segue on to the next slide, and this is probably a level of information that we haven't provided in the past. So hopefully, it will be of interest to those listening on. Obviously, where we've put TBC, we're not able to provide any more details because we're bound by confidentiality. But these are all options where we have, as I said earlier, land secured either through purchase or options with landholders. Where we are able to announce projects, we obviously announced project at Huriwaka, which is a large wind project 2 or 3 weeks ago. We're announcing today another albeit smaller scale solar farm in Marlborough, which is adjacent to our Argyle Power Station. And we've previously announced Maungatapere in Northland and Hawke's Bay Airport, which is a joint venture that we've got with the airport there. So as you can see, a lot of projects, which add up to that kind of circa 920 megawatts. We will continue to work through those, whether it's in monitoring, but certainly high-level progress in our design and consenting underway for most of them. As I mentioned, we announced, I think, roughly 2 weeks ago, a very large-scale wind project, Huriwaka 230-megawatt capacity proposed wind farm in the Central North Island. We'd expect to kind of angle out a roundabout 800 gigawatt hours, which will roughly power about 100,000 homes. Importantly, this is a very long-standing, well-established mature site with a highly-regarded, long-term wind monitoring data convenient access to transmission. And importantly, it has been previously consented. So I think it's fair to say, we're pretty excited about this as an opportunity. We've got the consultation consenting and connection underway, and that consent application has also been accepted by Transpower. And just that last slide at the bottom just provides a little bit of an update in terms of where we see a likely time frame with respect to taking that through to a financial investment decision and the construction beyond that. Obviously, lots of caveats and lots of assumptions underpin that, but at least it gives you a flavor for how -- for the kind of the time frames that we are looking at. Moving on to Argyle Solar Farm. This is a new project we're announcing here today. As I said, it's relatively small scale. But again, we are pretty pleased with this because again the project fundamentals stack up quite well both in terms of the solar resource. But I think importantly, in this case, the close proximity to the Argyle grid injection point that we've got with our Argyle hydro farm down in Marlborough. Again, this is very much at the early stage. We're really a high-level design. We certainly haven't -- we're just kind of working through consenting now. So there's a lot of water to go under the bridge, pardon me, very inappropriate pun. But certainly, as I said earlier, it just is another project that adds to the portfolio that we'll continue to work through. Moving on to C&I and wholesale electricity. Look, the one comment that I would make here is that with the wage -- sorry, with the hedge that we sold to Mercury as part of the retail business, the first 250 gigawatt hours tranche starts to roll off from October 2024. So next October, we will have an additional 250 gigawatt hours per year for the next 5 years as those wages start to roll off. So we've got a very, very interesting opportunity in front of us in terms of how we maximize the value of that additional output through whatever channels are available to that. And whether that's through C&I, whether lots through PPAs or whether that's through any other potential channels out there, we will be working through that as a key priority for us next year. Reconsenting is something that we haven't spoken about before, but it is definitely something that we've been focused on as an exec for the last while. We've -- our reconsenting work has ramped up considerably over the last year. And we've now got 6 schemes up for reconsent over the next 3 years, which is quite significant, especially when you consider that the legislative environment has changed considerably since we last consented a scheme. And some of the proposals are going to come on to that slide at the end. Some of the proposals, particularly through the new RMA, which is on the NBEA part of that, could have further significant implications for us. So there's no doubt that reconsenting is something we are actively focused on both in terms of the volume of activity that will be increasing with our existing hydro portfolio. And then, of course, hopefully, we actually want to see significant, significant work that's going to be required to consent new development going forward as well. So we will continue to give you an update on reconsenting as we move forward from here, which is probably a nice segue into some of the -- this is a bit of a summary, both in terms of kind of priority regulatory policy issues that we'll continue to navigate at present. And I think that top sentence, and I won't read it out, but I think that very nicely and succinctly outlines certainly our position. But just 2 kind of areas I do want to focus in on, and that is on the New Zealand battery project. And I think you'll find that we have been quite active in our views, and we will continue to advocate that Lake Onslow is a poor option, and it continues to cause significant investment uncertainty. And the sooner that we get a degree of certainty around that and that, that project has stopped, I think the benefit will be for our industry, and we are firm believers in that. Likewise, as I said earlier, some of the proposed changes to the RMA that is coming through the new Natural and Built Environment Act. And in particular, where there is a proposal in there to reduce the consent period from 35 years down to 10 years for non-grid connected generation, which would have a significant impact on us. And ultimately, what it would do was would create many, many, many tens of millions of dollars of additional costs, which ultimately would go on to the consumer and the community. And we think that is both wrong and both unfair. So we are -- we have submitted to the select committee, as have many others who will be impacted by this proposed change, and we're simply asking that there is a level playing field for water-related consent. So we wait with great interest and bated breath for the outcomes of that. Of course, we have a key social license to operate, especially as a renewable generator. Our first materiality assessment as Manawa Energy is in progress. And we will report on that, hopefully, at our 6 monthly results announcement. But 2 key areas that I just want to just pull out from this slide, which will be key focus areas for us moving forward this year, is the development of our inaugural sustainability strategy, which we'll be looking at our emission reduction plan on our targets. And again, we will be upfront transparent around that. And that we are currently in the process of resetting our approach to health and safety and effectively developing a new strategy that will really increase the focus on the capacity of our systems and our people. So there's a lot of work underway on that at present as well. And of course, as I said earlier, kind of to state an overused cliche, there's no point having these strategic targets unless we've got the people and the capacity to actually deliver on our strategic ambitions. So we need to create the right culture, the right context that enables people to get the best out of them. And that comes from creating a strategy and a vision that inspires and motivates our people and creates that line of sight to what we're actually trying to achieve. And I think importantly, another key focus for -- sorry, another key focus area for us going forward in this particular space will be to have a very clear focus on diversity and inclusion because I think it's fair to say that at Manawa. But to be honest, our sector in general, I think there's a lot of work that we need to do in terms of that space. So it's something that I personally very, very excited about. So finally, you probably heard enough from me, and you probably want to talk and hear from Phil to talk about the numbers. But just in terms of our strategic priorities going forward for this year, and you'll continue to hear us talk about these strategic priorities. So I'll just pull out the 6 key areas that will be a focus area for us. So number one, continue to progress our new development options and continue the great progress that we've made today. Number two, as I said earlier, deliver on our major assets program on time, on budget with the required quality. Number three, minimize unplanned outages and drive efficiency of our operating fleet. Number four, deliver on our strategy for placing our increasing portfolio line, as I mentioned earlier. Number five, our consenting pipeline. We need to work very closely and understand what the implications of that are. Make sure we've got the right capability, the right engagement models in place so that we minimize risk and maximize value from that consenting pipeline going forward. And finally, as I mentioned just in, continue to work on our foundational cultural activities right across the organization with a particular, particular focus on diversity and inclusion. So that's probably enough from me. I'll hand over to Phil now to talk a little bit more about the financial results.

Thank you, David, and good morning, everybody. We've produced a solid first year financial result despite a very high level of volatility in the inflows that we've seen during the year and in the wholesale electricity prices. The replacement of the mass market retail business with the Mercury hitch has provided us with cash flow stability through that period of wholesale pricing volatility. Our generation volumes, as you can see -- sorry, I'll just move to the right side, sorry. Our generation volumes, as you can see on this slide, were 1,917 gigawatt hours for the year, which was only 1% down on the long-run average, which is 1,942 gigawatt hours. However, it was very much a year of 2 halves. The year started with very dry conditions, which resulted here very low inflows and high average prices. And at the half year, we were [ 135 ] gigawatts below long-run average. But by year-end, we've recovered we're only 25 gigawatts down or 1% down on that long run volume average. Then in Q3, we saw average prices dropped to below $50 per megawatt hour, and that was followed in Q4 by a period of very strong inflows and the significant weather events that we had in that period and also with strong prices. And as a result, we had a very strong finish to the year. Those Q4 weather conditions also meant that our storage lakes finished the year at 124% of average. In terms of EBITDAF results, our FY '23 total EBITDAF was $140 million, and that was at the top end of our October '22 guidance range. And our continuing EBITDAF was $137 million. This bridge shows the year-on-year movement in continuing EBITDAF. And then as you can see, our net wholesale revenue, which includes our C&I business and our hedging, was up $7 million on the FY '22 number. However, the result was negatively impacted by the revaluation of our carbon units, which were down $3.5 million in FY '23 after an $8.5 million gain in the previous year, so a $12 million swing. Our new generation development OpEx was $6 million higher than the prior year. This includes land option costs, consenting and transmission feasibility work, as well as a larger in-house development team working on the pipeline of projects in that area. ACoT revenue was down $2 million on the prior year. And many of you will remember from previous presentations, FY '23, our FY '23 ACoT revenue was $17 million, and this will be the last year that Manawa earns ACoT revenue with the revised transmission pricing rules commencing from 1 April 2023. In the corporate costs, there is a difference between the costs that were previously allocated to the discontinued operations in FY '22 and the actual reduction in corporate costs in FY '23. This variance was anticipated following the sale of the retail business. In the prior year, you can see there in the notes in the prior year, $27 million of costs were allocated to retail, and this compares with the actual cost reduction achieved this year of $22 million. And finally, we did incur some $4.7 million of nonrecurring costs in FY '23. This included things like the legal fees in relation to the TPM changes. A little bit more on CapEx. FY '23 saw our capital expenditure increased to $41 million as we're investing more in our existing hydro assets, as David alluded to earlier. That includes enhancements, which deliver additional generation volume, the dam safety work that's underway and also asset replacements. Of the $41 million, $33 million was spent on existing generation assets with $5.7 million spent on new generation development. That new generation development CapEx is in addition to the generation development OpEx that I referred to earlier, and that brings sort of our total spend across the business in that new generation development area for the year to $12 million. Looking at our balance sheet. Our balance sheet is in a solid position as we go into a period of elevated capital expenditure, and we completed the $150 million bond issue in September 2022. $127 million of those funds were used to repay the bond that matured in December 2022. And we've recently also finalized the refinancing of all of our bank facilities with $305 million of new 2-year and 5-year facilities. That refinance will close on 31 May. And following the refinance, we'll have in excess of $200 million of unutilized facilities and won't be doing any more refinancing in the next 2 years. Looking ahead, this chart just provides a little bit more color on our longer-term CapEx outlook. It is important to note that this excludes new generation development CapEx, so we're looking at our spend on our existing assets. And we're forecasting spend in excess of $200 million on our existing assets over the next 5 years. This includes enhancement projects, the end-of-life asset replacements and some reconsenting costs and those dam safety projects that we referred to earlier. And we're forecasting this to peak in FY '24 at between $55 million and $65 million and then taper off over the next 5 years to a long run sort of business as usual level of between $20 million to $30 million of total CapEx spend. And finally, our FY '24 guidance is unchanged from the information we provided in March. We expect FY '24 EBITDAF to be between $120 million and $140 million. A key change in FY '24 is that Manawa will no longer be an ACoT revenue, and this reduces FY '24 EBITDAF by a net amount of $15 million compared to prior year. That's made up of $17 million of ACoT revenue that was earned in FY '23 and a $2 million saving in connection costs under the new TPM regime. Our generation volumes are forecast to be $195 million, which is flat on FY '23. And we are forecasting a lift in average wholesale prices in FY '24. And finally, we are -- our OpEx costs at our King Country Energy subsidiary will be approximately $4 million higher in FY '24 as a result of a major dam safety project that is considered to be OpEx for accounting purposes. So those are the key movements from '23 to '24 and are included in the guidance that we've provided. So I will wrap up there, and we'll take any questions. I think there are a few that have come through on the chat.

Thank you, Phil. There's a few that's come from the chat, and I saw that Andrew raised his hand as well. So maybe should we do, Andrew, first. If that works for you, Andrew. Are you there?

Try again. Can you hear me now?

Yes, I can hear you, Andrew.

Yes, a couple of questions from me. First of all, I guess, on the Argyle solar development that you've talked about today, the $55 million to $60 million cost. I think we're excited around about $2 million a megawatt, which I just felt reasonably high. I was just hoping you could give a little bit more color in terms of, I guess, how much of that is kind of locked down versus a view on where current costs are versus where current costs might go. And also in terms of the CapEx spend that you talk about of the -- I think it's $21 million -- sorry, $13 million to $16 million this year. I mean does some of that CapEx kind of end up in that $55 million to $60 million estimate. So a couple of questions in there. I hope that second part makes sense.

I'll take the first part of that, Andrew. The CapEx running a relatively small portion being -- is actually, I would say, locked down at this stage. We've still got probably at least 12 months perhaps a bit longer to get to FID on that. Generally, with solar, we are seeing, I guess, procurement prices ease slightly from where they were 12 to 18 months ago. So we will obviously be updating that CapEx projection as we get closer to FID. But in general, we are seeing solar prices on the main components ease as opposed to wind prices. We see procurement we are seeing remain sort of at -- we're not seeing those.

And maybe just to add -- that's right. I agree with what Phil just said and just to kind of add a couple of points to that, Andrew. I think I actually addresses one of the questions that's come up to the chart. But there's no doubt that scale plays a part as well. So the larger the kind of footprint, particularly when it comes to solar, the lower you can get the cost per megawatt down. So -- but as I said, we're looking at very, very high level at present, but you're about right. You've done your calcs right, roundabout 2 million per megawatt. But if there's anything, we would expect that either through costs coming down. Our expectation is that costs will come down or if there are other opportunities to scale that project up, which will bring the net cost down as well. And sorry, just one other point. Sorry, before Phil answers your second point. That does also then play into -- we put a lot of effort into trying to find projects that make quite -- and we've got kind of strong views around investment criteria and basic project fundamentals, whether that's wind resource or solar resource, whether it's proximity Transocean pipelines because all of those things then play into what return you could possibly get as you work through FID. So it's important for us to make sure that we get the right project to start with.

Yes. Sorry, Andrew, could you just ask the second part of your question again?

Yes, I might rephrase it a little bit. So you talked about, I think, for FY '24, there's $13 million to $16 million of new development CapEx. I guess I just wanted to understand whether that if Argyle were to go to the head that $55 million to $60 million, is that incremental on top of that $13 million to $16 million? Or is some of those costs that you're capitalizing right now going to end up in those estimates of project costs?

Yes. There are certainly some Argyle costs in that $13 million to $16 million that we've included in FY '24 guidance.

Yes. Okay. A second question, if I can ask is just around this clearly, I know it's very small, but what was your sort of current thinking is that going to come back. And in terms of the potential impact there if you decide not to repair that?

So was that 2 parts in terms of the time to get it back up and running again, Andrew?

Yes. Well, I guess the question is, are you planning to do that or not? What's the current thinking?

Yes, we are. I mean it's very, very early stages. I mean to kind of put it in perspective. We haven't really been able to properly even get into the site yet. I mean you all appreciate the level of destruction that occurred in the Esk Valley in general. So what we have done is we've approved some initial funds, which will actually get new access way into the site so that we can properly assess the level of damage. But at a very, very high level, at a very high level, we estimate from what we have been able to see up until now, we estimate that it could be kind of around about 12 months before we get that scheme up and running again. And it was approximately generating somewhere north of $1 million per year prior to the event. So kind of gives you an idea of scale. But certainly, our intention is very much to get it back up and running again.

Yes. Okay. And last question just in terms of dividends and just thinking about FY '24 and beyond. I realize you've got your policy there, but no guidance at this stage in terms of what you might be looking at.

No, Andrew. No guidance at this stage, but we -- we just reiterated the policy. We do want to balance paying a stable dividend over time with also being able to invest in the growth of new development.

Thanks, Andrew. Let me go back to the -- again, if anybody wants to ask a question, please use the Raise Your Hand function, but we'll maybe go back to the questions we got there. I think we've answered the first one because that's similar to Andrew's questions on kind of cost of wind and solar, I think we have. So approximate level of length in portfolio. Phil, do you want to answer that?

If I interpret the question correctly, yes, with the Mercury hedge in place, we have sort of a net length position at the moment of sort of between 200, 300 gigawatt hours per year. And we -- that is a -- includes a level of cushion that is part of our energy trading policy and risk management policy. I hope that answers the question.

I'm sure they'll type in. But if it doesn't, but you can maybe -- you can go on for Lisa.

The question here around one-off costs because it's recurring costs. And can you clarify the operating cost run rate you should be thinking about going forward, specifically other operating expenses at P&L? Look, I think we've tried to clearly identify the one-off cost factors. And I think if you adjust for the one-off costs that we've included in then the information and things like carbon on the revenue side, then you'll get to the appropriate cost run rate. There aren't any other sort of one-off costs that we haven't highlighted. Stephen Hudson, thanks. Three questions. Realized emission unit trading gain to offset the $4 million compared this year. We did sell a small number of units during the year. And I can get back to you, Stephen, with the exact numbers on that. But there was, yes, a small number traded during the year. Volume guidance looks conservative given 35 gigawatt hours start of your storage position. A lot of things go into sort of volume, including outages, and we have got outages at this and for during the year as well as late level start of year, end of year and assumptions around hydrology. So I think we believe we -- the guidance gives -- the volume is appropriate based on where we sit at the moment. I wouldn't call it particularly conservative or aggressive. Why is your [ DevEx ] so high versus larger players? Yes, the land purchases are CapEx. But land options, and we have a number of land options, are OpEx. I think that's sort of where the question is coming from, Stephen. And we just apply an accounting policy, which is for it to be CapEx, it needs to be probable that it will generate future economic benefits. And until our projects get to FID, a lot of the costs are in development OpEx rather than CapEx.

I think it's also saying that if you look at the level of spend then -- and compare that to what Trustpower were spending prior to demerger, then it's actually probably even slightly less than that. But it's certainly on par. So we certainly don't believe it's high in relation to what our strategic ambitions are. Maybe I'll try and answer an excellent level. Good on you for having a crack at that. I would -- look, probability would you place Manawa river schemes being included in the natural NBEA. I honestly don't know the answer to -- how to answer that question, Neville. I mean we've certainly done what we can. We fronted up to the select committee. We put our case forward. The feedback that we got from the select committee at the time was that, that same argument had been put forward very articulately both by us, but many other kind of organizations out there, where it's certainly signal to me that it's been heard loud and clear. So I would only like to think that there's a degree of fragmentism that's involved, but I guess that remains to be seen. So yes, okay. Sorry. So I'm not quite sure I can really answer that question, Neville in terms of putting a particular probability on it, but we remain very hopeful. Sorry, you just some looking to my left there. We need to read out the questions in advance because we haven't realized that people -- not everybody on the call can actually see the questions. So Phil, do you want to answer next one?

Neville, your next question was how is Manawa preparing itself for increased volatility in a high renewables world. Clearly, we have some hydro flexibility and reinvestment underway. Any of this aimed to increase Manawa role providing firming? Thoughts on batteries? And we have so many embedded stations and networks around the country and conventional industrial customers, does Manawa have competitive advantage stabilizing increases within network lower volatility?

You go, and then I'll jump in.

Yes, a number of sort of questions in there. Look, certainly, important part of our strategy is to be able to provide products to customers where we are providing firming on new intermittent generation, and that's something we're talking to customers about and is very much a core part of our strategy. Thoughts on batteries. We're not looking at batteries at the moment.

But there's no doubt. I mean to state the obvious, I mean the technology in batteries is coming down. So batteries will have an incredibly important part to play, especially where they're obviously utilized in conjunction with solar farms. But it's not something that we are investing time or resource in at present.

And your other question, Neville, was carbon price decline this year. What is Manawa's house view on carbon pricing direction from here?

We were just talking about that before the session here this morning.

Good question. I guess outside our in-house view is that they will inevitably increase if we -- the New Zealand economy is going to decarbonize, there will -- we believe there will be an increase in the price of the carbon units. Just when we see that recent trend reverses, there's a little bit unknown, but our view is that they will turn.

And you just need to look at some of the carbon prices overseas to get an idea for some of the levels that they are on, just now. So the carbon price continues to stay at the level it's at just now. And as a country that we're expected to meet our -- to put the right commercial parameters as a result of that, then it quite simply, it doesn't equate as far as we are concerned. So we believe the carbon price will increase up to levels that it's actually going to drive the right types of behaviors to actually fundamentally decarbonize the economy. Whether that's this year or whether that's beyond, we don't know yet. But we're convicted on that.

There's another question from Stephen. Can you remind us what the Mercury [ safety ] volume step downs are by financial year? And what process is for testing market? Early thoughts on sweet spot for you for pricing duration indexation.

That's a great question, Stephen. So as I said earlier, it steps down 250 gigawatt wages from October '24 onwards, and it does that in 5 separate wages. So we've already sold -- I think we gave the market an update. We've already sold a very small initial tranche of 80 gigawatt hours from that first FY '24, which are quite attractive tenures on pricing, and we'll continue to use that as a potential way of testing the market. But early thoughts on the sweet spot, it's a really great question, Stephen. It's a fantastic problem and a fantastic opportunity that we've got, and we will be working through exactly what our strategy is around that and providing more details as we can. So -- but it's a good problem to have.

Another question. I mean any further detail behind the $20 million to $28 million of land sales and carbon credits? I won't provide any more detail, but what I would say is that given we're going into a fairly elevated period of capital expenditure, we have looked down on a piece -- we are looking at, if there are surplus land that doesn't have any future value for us that we could realize to make sure we are being very prudent with our cash flow management. And we are -- we'll also look to -- for opportunities to sell carbon units when the opportunities are there. We are not necessarily a long-term holder of carbon units. So it's really making sure we're just prudent with our cash flow management and that we are realizing sort of any noncore or not valuable pieces of land that we hold over these few years.

I think we've got no more questions at the moment on Q&A. But I think, Grant, did you -- nothing popped up here. Grant did you raise your hand to ask a question?

You guys answered it.

Okay. Well, I'll just wait and see if there's any. None? Okay. Well, we might call it a day. So thank you all very much for listening in this morning. Thanks very much for engaging. Thanks for the questions, and we look forward to catching up with, no doubt, a few of you over the next couple of days. And thanks again, everybody.

Thanks very much.