Mercury NZ Limited (MCY) Earnings Call Transcript & Summary

Thank you all for standing by, and welcome to the Mercury Interim Results Analyst Briefing for 2022. [Operator Instructions] I'd now like to hand the conference over to Chief Executive, Mr. Vince Hawksworth. Thank you. Please go ahead.

Kia ora tatou, and welcome to Mercury's Half-Year 2022 results. I'm Vince Hawksworth, and I'm joined by our Chief Financial Officer, William Meek. If I turn to Slide 3 on the pack. Half year '22 reflects significant change for Mercury and creates a platform for future growth. We've seen major events occur. Completion of the Tilt New Zealand acquisition, where we have acquired the 5 operating wind farms, which when you combine that with Turitea North make Mercury, New Zealand's largest wind generator. Turitea North now in full operating mode with all 33 turbines generating. And the Southern section with civil works well advanced now, looking at a completion in mid-calendar '23. Of course, the half year also saw us move through the acquisition process of Trustpower. We are getting close to the completion of that deal. The high court decision being positive. And now we're in the giving-effect-to phase, which should see us complete in the second quarter of cal '22. All of these things when put together provide that really important platform for the decarbonization of New Zealand. At an EBITDAF level, the $242 million result was obviously down. It reflects a number of moving parts, which we will go into in some more detail shortly. But lower hydro generation, the outage at Kawerau and the impacts of the retirement of the Norske Skog plant all had impacts, of course, with some offset by the added wind generation. Importantly, in a period of extremely low hydro inflows, we were able to maintain our lake storage to be able to deal for lower -- higher prices and lower inflows in the second half. And that's a notable change from last year. We talk about Thrive as our evolving culture in the way we want to work. But importantly, it also delivers financially. And we are on target for our $30 million made up of both revenue and cost elements. The important thing will be sustaining that changing way of work through future years. We're really pleased to be able to confirm guidance at $570 million EBITDAF for the full year. And that includes the hydrology conditions that we have set out later in the pack and the Tilt and Trustpower acquisition accounting. It does not include the -- any settlement for the Kawerau insurance claim. We're confirming $0.08 per share interim dividend and offering guidance of $0.20 per share for the year. Importantly, we have also turned our minds to capital management and are announcing today a dividend reinvestment plan with the intention to underwrite for the interim dividend. And we'll go into more detail on that shortly. So really busy first half to the year, but really laying important foundations for the future. I'm going to hand to William now to take us through some of the numbers, and I'll be back to talk some of the strategic issues shortly. William?

Thank you, Vince, and welcome to those on the call. So we're now on Slide 4, and I'll just talk -- take us through some of the financial highlights of the year. We did, as Vince said, the period reflected significant changes for Mercury. And some of these changes include some priority complex accounting for some of these transactions. So again, starting with the Energy margin, you see it down from $361 million to $321 million, again largely explained by those factors, lower hydro generation, so 25% of inflows into the Waikato catchment, sort of 20 days of Kawerau outage in July and the Norske Skog transaction, which saw us buy out the remaining term of the foundation hedge with Norske and acquire their portfolio of hedges on sold to other customers. So that energy margin decrease flowed through to EBITDAF and also into our free cash flow results, which were again down on the prior period. OpEx stepped up from $91 million to $106 million. Again, there's a pretty clear bridge in the next slide, but really largely driven by the addition of your wind farms, so on the back of the Tilt transaction and the commencement of generation at Turitea, some outage costs predominantly related to the Kawerau outage and then some increases in ICT and SaaS-related impacts there. NPAT, very strong increase, up almost $300 million from last year's results. Again, fully explained by the gain on the sale of the Tilt shares back in August. So once you back that through, our effective tax rate rises back to 28%. Probably commenting on same business CapEx broadly in line with the prior period. And then obviously, growth investment almost heading $700 million, again, reflecting the purchase of the ex Tilt wind farms and then just under $50 million related to construction costs at Turitea. And Vince has touched on our interim declared dividend of $0.08 and $109 million, which will be subject to a tender to be underwritten through that DRP. Turning to the EBITDAF bridge on Slide 5. Again, fairly complex bridge, which I'll quickly run through. It's worth commenting spot prices for the period were lower than the prior comparable period. They started off in July and August quite high. Then we saw some very strong inflows into the South Island through that June-September period and a pretty, pretty long lockdown, which saw prices fall away through September through December. So you can see the spot price from generation. So that's -- when we talk about spot generation, we're talking about our hydros and our geothermal. And we've broken out the wind portfolio into Turitea, which is essentially the spot wind revenue generation. And then the external assets, which are all subject to either PPAs or CfDs and the -- relation to Waipipi. So obviously, Turitea and the ex Tilt wind farms adding $36 million to that bridge. Our purchase costs, again, benefiting from the lower price, quite strong yield uplift, particularly in C&I, so up 12%. So those were -- those we shared with the market with our upstep release in January and a 2.5% yield increase across our mass market businesses. So again, that C&I yield assisted by the exit and termination of that Norske contract. You can see the Norske contract. So the termination of the 15-year contract, which had about 2-and-a-bit years to run, was done at a -- struck at a price of $65 million. So that is immediately recognized to P&L. So you can see that bridge there at negative $65 million. Derivative settlements were also decreased, given we've got a net short book and spot prices were lower by $24 million. A strong carbon trading revenue gain, so up $15 million given the series of carbon auctions and a rising carbon price, which is now trading at about $82 and then the impact of accounting. So the acquisition amortizations, which are detailed in the appendices, between the Norske and Tilt transactions total $20 million. So again, we're seeing some differences between the accounting and the EBITDA and actually underlying cash flow treatment. Other income was down $8 million and that's largely attributable to the reduction in Tilt share of profits because we no longer -- one, don't own that, and we're not recognizing as an associate anymore. We've touched on OpEx, giving us that bridge from our half year '21 at $290 million through to this year's result at $242 million. Now turning to the market. So again, this is a familiar chart. We produce this each reporting period. So it's worth just summarizing some of this market situation that was occurring. So this graph's the North Island catchment. And as I said, I think, received about a 26% whole inflow event for the half year and in contrast to the South Island, which was very, very wet. So the South Island had monthly inflows between June and September, over 90 percentile in each month. And I'll come back to that. Cycle on [ Dovey ], which came through a couple of weeks ago, saw us lift the lake by about 100 gigawatt hours, and we're currently sitting at about 125% of average for this time of year. Again, putting us in a good position for the typically drier months as we head through autumn and into early winter. I will call out the difference there and probably the bottom table with the spot prices and futures. So the futures prices are -- or the market expected spot to trade at 3 months ahead. And you can certainly see the impact. The market was predicting much higher futures prices through July, August and September or pretty much almost the whole year. And again, it's that inability to forecast extreme weather into South Island catchments, but worthy of note is prices in May and June were in the high 200s. So there were certainly periods there where prices were elevated. And then we came out of Christmas and again, the futures price 3 months earlier was indicating a price of $105, and we've seen prices rally quite strongly in spot to $163 with futures productions, again, quite close to month-to-date pricing in February $147 versus $157. Turning the page. Again, we sort on this slide around the high wholesale price environment, and obviously, that feeding through into futures and C&I-type pricing, a series of charts here. We'll start with the coal price. Again, not surprising, coal prices at record highs. Sort of close, almost up to $300 a ton. Obviously, that affects the price of running the Rankin units at Huntley on coal. Carbon prices have been steadily rising strongly since April '21. And currently trading at $82, again, influencing the generation cost of both coal and gas. Gas production, again, we're still -- clearly, the market is much lower than where it was 2 or 3 years ago. TCC hasn't run since August, so that's really again a reflection of the current gas state. And right here right now, 2 Rankins are online, e3p, P40 which is Huntly 6 online. Strapped peakers are running, Junction road and McKee. So you're actually seeing quite a lot of similar commitment, which takes us back to the first chart, thermal generation and price, and you can certainly see a very strong correlation in spot prices to the level of thermal commitment. If we look back in July '21, we saw spot prices then of $191 certainly, as we extrapolate forward to winter this year, we expect a similar level of thermal commitment and the futures prices for July '22 are indicating pricing of $190. So a lot of that wholesale price can be explained by underlying thermal costs. But certainly, with elevated prices, the portfolio risk for hydro generators are also amplified. And so that potentially leads to that inherently conservative operation to avoid the short squeeze under high prices and the potential for what we saw through the first half. If inflows are strong, then essentially spot prices will fall away as the commitments drop and you'll get a divergence there between futures expectations and spot prices. Now turning to Slide 8 and the retail market. It certainly remains competitive. We certainly have seen with the high wholesale price that, that's certainly creating some challenges for some of the independents in the market. But certainly, we're seeing transactions over a longer period to actually supply hedges to independent retailers. From Mercury's perspective, our sales position has been relatively consistent on a half year basis, so sitting around a 3,000 gigawatt hour sales mark. We can certainly see the mix shifting there from mass market to C&I. So that's a pretty long running trend, again, coinciding with this phenomenon of elevated prices, which is clearly indicated in the channel yield chart to the right. Certainly, we saw our ICP volumes stabilized in this half with essentially losses over the 6 months of only 1,000 customers. So that certainly attenuated strongly from the trends we had seen in prior periods and certainly looking forward to that Trustpower transaction concluding and becoming New Zealand's #1 energy retailer. I'll hand back to Vince.

Thanks, William. So turning to those sort of regulatory and policy areas. The context for all of this, of course, is 2050 and net carbon 0 and really requires us all to focus on joined-up policy and regulatory responses. In the period, we're discussing the advice from the electricity authority that effectively wholesale market volatility wasn't part of a gentailer initiative, but does reflect the underlying issues that William has touched on, that is more generation is required as thermal fuel costs rise and New Zealand moves to decarbonize. So the question has to be in that context is what's the industry doing about that? And it's already responding to those price signals with both Turitea, ourselves, had a package by Meridian and Tauhara by contact. And that will bring on new renewable generation and will start the further exit of thermal fuels. Of course, it's really important, though, that in order to continue that journey, more investment occurs. And the most important thing to occur really there is to have clarity around future policy. When we look at the emissions reductions plans that came out of the climate commissions work, it is a big lift that needs to occur. And those economy-wide changes that are in that plan, including transport and process heads also require the electricity sector to do some heavy lifting. The regulatory focus on that transition has to focus on 100% renewable energy as opposed to just 100% renewable electricity. That's where we have to be traveling towards. The New Zealand Battery Project is an interesting piece of development in that space. And we note that the recent OECD report cautions that it could undermine lease cost abatement. In the really near term, though, the transition from the RMA to the NBEA, the Natural and Built Environment Act is essential if we're going to support rapid deployment of new generation build. One of the things that we know is that delays in the consenting process change the economics of projects really quickly. And one only has to look at the current inflationary pressures around steel, aluminum, copper and other supply chain issues associated with build to know and understand that. And that then leads me to what Mercury is doing, which is this next slide. As I said at the start, the Tilt transaction puts Mercury in a position to really respond to the decarbonization challenges. We have since that transaction completed, continued to work hard to bring some of the pipeline to fruition. With Puketoi, which we already owned, we have extended the consent period to 2031. And we're active in understanding the constructability and consent enhancements required to progress the project. We're taking the learnings of the Turitea project another -- which was also a big project, and applying those to our thinking on Puketoi. Kaiwaikawe. The recent resource consent hearing is completed, and there's a decision pending. As everybody knows, we have a PPA with Genesis. And we're advancing all of the, I guess, investigation work around -- and the procurement chain to be able to move that project forward. We have 200 -- we have 160 megawatts, sorry, Mahinerangi Stage II. Kaiwera Down Stage 1, which is 40 megawatts, we're into constructability work there as well, with a further 200 megawatts consented at that project. We've also started exploration and initial feasibility work for a fifth unit at Ngatamariki. That would add a further 35 megawatts to that site. So when you look at that, we are really active, and what we need to be able to respond to the challenge is to get those projects to a point of final investment decision. The challenge in final investment will be procurement and construction cost pressure. I don't need to explain all of those to you and the appropriate policy settings. We are very active in pushing for a coordinated response with government. Turning to -- now to the strategic framework, which we shared last year. Many of you are familiar with our 2030 longer-term horizons where we consider the pillars of customer, commercial, people, kaitiakitanga and partnerships. And clearly, some of the things that we have done over the last 18 months, both with Tilt, Trustpower, Turitea and Thrive all lend themselves to a platform for that destination. Our 3-year objectives though try to give focus to us and our people, thriving today and shaping tomorrow. We believe we're well positioned to achieved a $700 million EBITDAF in -- as set out in our 3-year objectives. And the work we're doing on people transformation and systems and enhancing our license to operate working with stakeholders sets us up well. The goal of shaping tomorrow and playing the leading role in New Zealand's transition to a low-carbon economy is incredibly important. And the execution of the options for growth that I just described will help support that destination. Of course, as we've all learned through the last 2 years of COVID, being adaptable and resilient is critical to success. And I'm really pleased with the way that our culture is developing and our engagement with our team on our challenges is improving. The next slide gives a bit of detail on the action of that. So importantly, our safety performance continues to improve. We all know that we're only one incident away from that turning back. So culture is incredibly important in this space. We have been talking with stakeholders and our stakeholder audit tells us that we are making good progress and we need to keep up the work on communication. We've talked a lot this morning already about value creation. And whilst the shareholder returns have seen some headwinds, maintaining our dividend and growing our base through Tilt has set us up well for the future. Our culture index has improved and our culture program is paying dividends. So as we look into the future, we've described the challenge of meeting New Zealand's transition to a low-carbon economy, and we've described how we are progressing that, including, I might add, the trial reinjection of CO2 at Ngatamariki, which will bring down our own generation of carbon dioxide. So I guess, when I look forward for the options for new growth, the platform is in place, we now need to push to further execution. Part of that execution is completing Turitea. We've already noted the situation with Turitea North. The picture there shows what it looks like on a beautiful day in the Turitea. And I think we can be really proud of what's been achieved by the collective team. Of course, we still have challenges. The challenges are to complete Turitea South. It's -- I think the picture there at the bottom of the page, really gives focus to the civil challenges. So there's a lot of dirt to move. We are well advanced, though, as that picture shows. We have some commercial issues to resolve, and those conversations are ongoing. But we remain convinced that we end up with a project in mid-calendar year '23 that really everybody involved can be proud of. Trustpower Retail acquisition is clearly the next step in the journey. We're nearly there, as they say, and we expect to complete in Quarter 4 of the financial year. The time that we've been waiting has not been wasted. There has been a massive amount of work done by both the people who will be joining us from Trustpower from both Tauranga and Omamari. But also work on the Trustpower side so that we can make that change seamlessly. And we're pretty excited about the fact that as we make that change, it releases a whole bunch of capability to deliver for customers on an integrated system and technology stack, and we get the benefits of joint capability. The fact that we've been able to deliver all of this in a virtual environment, I think there's been perhaps only 1 or 2 face-to-face meetings between the 2 teams, also puts us in a great position for new ways of working. And we note the contribution and likely accounting effects. We talk about -- a lot about continuous improvement through our Thrive and thriving programs at Mercury. The fact that we have been able to make real progress despite all of our Auckland staff being locked down for something like 4 months in this half year says a lot for our resilience and purposeful attitude towards this development. In fact, it's all about the Mercury attitudes of curious and original, share and connect and commit and own it. We've built more commercial capability. We are supporting people to make better decisions. We're leveraging our data and we have seen real improvements in the way that we think about deployment of assets on the Waikato River. We've also seen real improvements in the way that we communicate with our customers with significant automation and data insights driving better customer communications. We've also discovered that if you can get everybody to lift through improved ways of working, you build sustainable change. And we are intending to invest in ways of working over the second 6 months and through into the next year. So a couple of other issues that we should just talk to before I hand back to William. One of the things that's really important when you're a geothermal operator is your drilling campaigns and the renewal of your geothermal resource. One of the reflections that we've had over the last year or 2 is that a just-in-time approach rather than having certainty and clarity about your program is not the way to go. We've done considerable thinking about how we approach building capability and also dealing with stressed procurement chains and inflationary pressures. And that's resulted in us determining to have an 8-well program across FY '23 and '24 with the associated stay-in-business CapEx. It does allow us though to plan purposefully and not be buffeted by the change of a more just-in-time approach. We also note that we expect partial payment of the insurance claim on Kawerau. That is excluded from FY '22 guidance just due to the exact timing and exact amount. However, we remain positive that, that will occur. And we note here as well that part of the consequence of all of that is we will have an outage in calendar year '23 to put the new parts in that will have arrived as part of the refurbishment of Kawerau after the event last year. So lots going on. And in order to fund that, of course, we need a capital structure that is flexible and I'm going to hand to William who's going to talk about our initiatives in that space.

Thanks, Vince. We're on Slide 17 now. As it says there, we're expecting our debt-to-EBITDA ratios to peak this financial year, following the acquisition of the Trustpower Retail business for $440 million. So we closed the period with net debt at $1.61 billion. So it's certainly high, but as S&P confirmed back in November, certainly within our current rating targets of 2x to 3x debt to EBITDA. We've got the capacity to fund those transactions. But looking forward in terms of those generation development options, and Mercury being very keen to support the decarbonization of New Zealand, wanting to ensure we've got a balance sheet that essentially enables the funding of further generation development. So as flagged by Vince. We have announced a DRP effective for this interim dividend. We plan for that DRP to be underwritten also, and we are considering a capital bond issue, and that obviously would attract 50% equity credit. So the majority of the Trustpower transaction costs would essentially be paid for by equity-type instruments versus debt, which is certainly helpful to strengthen those credit metrics. So just a little bit more on the DRP. So an $0.08 fully imputed dividend declared, up 18% from the prior period. So it's about $109 million of cash. We have indicated a discount of 2.5% for the DRP. It will be underwritten. So essentially, share is not taken up by existing shareholders will be placed with an underwriter on identical terms. And those shares will be sourced from treasury stock currently held slightly north of 37 million shares of treasury shares held. So key takes in that table on Slide 18 with dividend paid by 1st of April. Finally, guidance for the full year. So we guided $570 million on -- in January with the release of our operating stats. Guidance remains unchanged at $570 million, although the construction is slightly different. Hydro forecast below average at 3,750 gigawatt hours. Clearly, hydro is quite volatile, and we've been in a dry series up until very, very recently. The ordinary dividend guidance of $0.20. So again, unchanged, and we hold our stay-in-business capital guidance at $70 million. So the bridge there for guidance from our initial guidance at the start of the year at $590 million down to $570 million. Probably the key call out there is the impacts of the acquisition accounting relating to Tilt, which we expect to be $15 million positive for the year, again, noncash. And then I call out there on the Trustpower acquisition accounting. So assuming that transaction concludes with a few months to run we're looking at an adjustment there negative of $25 million. The appendix does flag a pretty hefty discount or amortization in FY '23 of over $100 million, and again, that will be dependent on the forward curve on the day the deal is ultimately struck. So essentially, what's happening is the embedded -- the indebted CfD with Trustpower Mangahewa as essentially fair value on our books. It's clearly in the money, and that amortizes through time. Then amortization largely taking place over the next 3 years. So quite a significant divergence there between accounting and cash flows of that transaction. And with that, I'll -- we'll open the phones for Q&A. Thank you.

[Operator Instructions] Our first question comes from Grant Swanepoel at Jarden.

First question, just on Norske Skog. Is that about a 100 gigawatt hour contract you guys exited?

It was actually an 80-megawatt CFD, so much larger than that.

Okay. So can you give some sort of idea of what a normalized 1H would have looked like if it hadn't had that exit including this $242 million adjusted for C&I uplift and knock off the initial hit from Norske Skog?

Yes. It's a good question. I'm just trying to find the appendix because there's some sort of quantity data in there. So on Slide 21, you can see some information. You can see there's essentially the net effect of terminating the CFD and picking up their sales portfolio you've got a 375 gigawatt hour reduction in 500 next year and then a stub period of 160 and 24. So that the -- all those contracts have essentially got us somewhat a strike price of circa $80. So you'd essentially see a baseload 80-megawatt contract, let's say at 640 gigs. Water stayed at the spot price. I haven't done the calc, and you typically halved that. So essentially, for a net proceeds of $32 million were essentially gone longer by those quantities in '22, '23 and '24.

Second and final question, just on Trustpower acquisition. So your assumption is that a couple of months, only 2 months that you're using there in terms of $10 million of EBITDA generated. And have you shifted any of your plans around separate IT systems for 2 years before you do IT overhaul? And any ideas on what that IT overhaul would cost Mercury?

Yes. So we've worked through -- when we undertook the transaction, we gave indications to the market around sort of core EBITDA, which is around $4 million to $5 million a month. The amortization is laid out here. So it's pretty hefty, you can see in '23 related to that CFD, which has got at the moment, based on the forward curve of $260 million asset value. We guided integration costs of $50 million. So embedded in that would be the cost of implementing the IT changes, amongst other things. And then synergy realization of $30 million, and essentially a 3-year program to deliver synergies and that integration.

So well, does that $50 million integration cost, does that cover moving to a single IT system over time?

Yes, that was the intent. So that work is still in progress, obviously, with -- the transaction has taken probably a little bit longer than we thought. And we do need to have some pretty serious engagement with the other side before those decisions are made, but certainly been doing a lot of background work around some of the options and what that might look like in terms of ultimately IT stack. But again, there's certainly a lot of duplication across the 2 businesses, particularly in terms of IT and rationalizing that onto a common platform is a huge part of that synergy.

Our next question comes from Andrew Harvey-Green at Forsyth Barr.

A couple of questions from me. First of all, just in terms of the guidance around maintenance CapEx for FY '23, FY '24. So I'm right in thinking that $65 million is in addition to current, I guess, maintenance CapEx. So when we add on the Trustpower transaction as well, are we sort of looking at $140 million, $150 million all up for stay-in-business CapEx for those 2 years?

Yes.

Great. Next couple of questions just in terms of your outlook on the development pipeline. The Ngatamariki units that you're looking at, do you -- have seen additional steam resource consented or are you able to use, I guess, existing steam consent and you've got capacity and you just need to plant on top to sort of take advantage of those existing consents?

No, you'll require additional steam take, which will require a consent.

Yes. Okay. And secondly, in terms of the Mahinerangi Kiera Downs, the megawatts that you're talking about there. I'm just going back to the -- sort of the Trustpower days when they were on the books. Of those megawatts, does that assume new turbines? Or is that based on the old sort of plans and there's potential for uplift as if you think about sort of technology changes over the last decade?

That's based on what you would call, yes, historical-scale technologies. And bear in mind, Mahinerangi consent was given effect to through the smaller project. And it would require -- if you wanted to use different technology, you would have to look for a consent variation. The Kawerau Downs consent has an envelope that we believe can deliver those projects. There is potential for uplift if we wanted to go through that process.

Yes. Okay. And lastly, I know you haven't given formal numbers at all. But are you able to just give us a sort of a rough ballpark estimate of what we might be looking at around the insurance on the Kawerau geothermal?

Yes. So this is -- in the deck, we're signaling an interim settlement, so that's not a final sentiment. Insurers have accepted there's an insurance claim. And so we're expecting a number in the order of mid-20s after retentions. That will be recognized as other income so it will flow through P&L. Even though most of that will actually be related to property because, obviously, you end up having to buy the replacement gear.

Our next question comes from Adrian Atkins at Morningstar.

Vince, I noticed the cost of the Turitea South development has increased, but by a pretty small amount. Just wondering if that's actually indicative of how much development costs have risen if you were starting a new project? And then just further on that, just wondering, it's not just high commodity prices and labor shortages, but bond yields have also gone up quite significantly in the past year. So is that materially increasing the electricity price needed to justify new wind farms?

So first part, first, Adrian, I think -- yes, so look, I don't think you should make any linkage between the Turitea change and the structural inflationary pressures that we see on a global basis. It's associated with some quite small issues that had to be dealt with. So that's not a linkage. To the second part of your question, we would have to say that everything we're seeing around commodity prices is flowing through into pricing that we're seeing coming from equipment manufacturers. It reflects the lift in steel prices, aluminum, copper, et cetera. And also the other supply chain issues associated with actually transporting is flowing through. So that does put reasonably significant headwinds on investment. And I guess that does lift the sort of pricing that one needs to see to invest. That said, when one looks at the wholesale prices that we're seeing and one looks at the outlook when -- we've seen some commitment from New Zealand Steel. We've seen I think, truly bipartisan commitment to a decarbonized future. We're seeing electric vehicles being taken up and government support for that. You add all of those stuff to add all of those things together, we still believe that there will be projects that can get away. We'll test that as we get to a final investment decision. But in the meantime, you can't test that whilst -- until your project is ready to go. So we are spending money on being ready to go. And yes, so that's the environment we're in. But I think businesses like Mercury have to stand up and be counted.

[Operator Instructions] Our next question comes from Eamon Rood at Energy News.

Going back to Ngatamariki, can you explain what prompted this feasibility study into a potential 1st unit? And can you give any indication of perhaps what the CapEx requirement and development time line might be for that?

Yes. Well, I mean, I guess, the first part of your question is that goes to this long-term decarbonization goal. If we're going to be successful, we believe that New Zealand needs a suite of technologies, and Mercury has, if you like, got itself into a position where we have geothermal, hydro and wind. And we see those technologies as playing long-term roles to get to the outcome. The Ngatamariki site and field seem to have the ability to support further investment. So -- and obviously, in Mercury's portfolio, it builds a bit more baseload as we add the intermittency of wind and the storage and peaking capability of the Waikato River. So it helps keep all of those things balanced as we moved through our growth ambitions. As to capital cost, I think basically too early to say.

Right. Do you have an idea when the study will be wrapping up? Or is it also too early to say?

Look, we're sort of pretty well advanced. But as one of the earlier questions said there will be some there will be some consenting things we need to work through, so -- and I have to say it's one area I never liked to put a time frame on. Experience seems to say, and that goes back to my commentary on regulatory. You put time frames on consenting processes at your peril.

I think what I would say is geothermal development is slightly different to the other technologies in that confirmation of the fuel resource underground is really important. The Ngatamariki commissioned in 2013, so we're 9 years down the track from that. So certainly got a lot of confidence around the sustainability of the resource and the ability of the field to produce sufficient steam. What you don't want to do is commit to assets above ground and then find that essentially the steam fields incapable of supplying the field. So no one wants to know hacker -- hockey, I should say, a scenario where you've got a large plant that's running at seriously derated capacity. So we're still early days. We've got a lot of stakeholder engagement to work through, which we'll do. But certainly, our desktop studies indicate it looks promising.

Our next question comes from Nevill Gluyas at Jarden.

Two questions from me. First one, just I'm interested in what you had to say about Mercury participation in sort of peaking capacity. I'm interested in sort of what kind of form you thought that might take, whether that's sort of direct investment, sort of contracts, i.e., taking contracts versus options. If you could just sort of add a bit more color to that, that would be great then.

Yes. Well, thanks, Nevill. I think -- I mean, I think in that sense, Mercury has always talked about its use of the Waikato River chain. One of the key things for us is the reinvestment program in that chain which allows to get a few more peaking megawatts by the type of plant change-out we're doing, plus also get a few more gigawatt hours at the right time. And that then leads to the work that we've been doing on -- sort of data investment on the chain and optimizing the use of each machine. So that's entirely within our control, and we all know that hope is not a strategy. Our discussion with other parties is, yes, we're always open for business with respect to swaptions. And we would have -- we've said publicly -- or as I've said publicly and would continue to say publicly that gas does make a good transitionary fuel. We're not going to be investors in gas. That's not our space. But certainly, we would continue to look to support some gas peaking as a transition over the next 15 to 20 years. And in that sense, be a willing purchaser of products that support those investments.

That's great. Very clear. And I'm going to touch a little bit on the potential new investments as well. I think you've kind of given a pretty clear answer about the reliance or the dependence on how the commercial kind of outcomes and consenting outcomes could dictate FID on these projects you've named. I'm just wondering about other factors. I mean, how significant would TY sort of -- whether or not we see heat conversions, whether or not Lake Onslow proceeds or whether there's any sort of major dependence on transmission, do you think would be significant in that sort of FID process as well? Are any of those sort of major roadblocks or enablers?

I think -- look, I think the TY cliff or headwinds or speculations sort of wears a bit thin. I think with the projects we're looking at, we're going to have to sort of muscle up and commit. Obviously, transitions in the EV and process heat space are encouraging. I think the investments that are being made that are beginning to see those changes occur are good. I think the New Zealand Steel announcement is positive. We're not close to the hydrogen thing, but I note that if that were to occur, that would also be net beneficial. I do think the -- I do think there is serious interest in data centers occurring. And I've always had the view that the investors in fiber -- large-scale fiber networks around the globe would see New Zealand as a place where data centers should be housed. And I think there's evidence of that occurring. So I think all of those things are positive. Of course, at the end of the day, it's always a bit trickier in the South Island than it is in the North Island. We'd be the first to acknowledge that. However, I would also say if there was a time for the industry to step up and play its part if we want to get to that decarbonization position, the next 5 to 10 years is the time.

Great. That's useful. Lake Onslow, would that -- if announcement was done tomorrow that they committed to it, do you think that would change your investment decisions for those projects?

Probably my lack of dealing with Lake Onslow has said something about my view of it. But look, I still think it's the wrong tool for the wrong problem and the lack of problem definition. I think it would be -- it's the one thing that it's impossible, I think, for -- to scale around a decision to go ahead. I don't think would come with a clear time line how it would operate in the market, the chances of it being successfully built in that time line. All they do is add massive uncertainty. So that would probably be the one thing that is really difficult to navigate around for all sorts of reasons, which you would understand as much as I do. So I do think, though, that the best response that Mercury can make to Lake Onslow, other than bleating, is to get up and show we're ready to do our bit of share of the heavy lifting.

Thank you, everyone. We have no further questions, so Vince, I'll hand back to you for closing comments.

Thank you. Well, thanks, everyone, for coming on. Thanks for the questions. You all know how to find us, and William and I are always happy to talk to that. And we appreciate your time this morning. Look forward to seeing you all in person at some stage.