Contact Energy Limited (CEN) Earnings Call Transcript & Summary

Welcome to Contact Energy's Full Year Results Presentation for FY '24. Today, we're joined by Mike Fuge, our CEO; and Dorian Kevin Devers, our CFO. Over to you, Mike.

Yes. Good day, everyone, and welcome. Welcome to the FY '24 results. If we move quickly into it. Just, sorry, pause at the photo, a photo of the new cohort plant up and operating, which we'll talk about through the presentation. If we go to the next slide. The usual disclaimers, which everyone should note. And then how it's going to play this morning. I'll go through the highlights and a bit of an update on the market. Dorian will then take you through the details of the financial results and what the outlook is. And then I'll give you a little bit of an update on the progress on strategy. And as usual, there is an abundance of supporting materials to help. So the overriding story of this year is that it is a solid increase in the EBITDAF level and profit. But the thing to note on this chart that I would ask you to look at is that our net profit underlying was around $230 million to $235 million. And the amount of capital going into the company at the moment was $470 million, double our net profit levels, which shows exactly where the company is now in its strategy. We are deep in execution. This year, we saw the first fruits of that execution with Tauhara coming online and Te Huka 3 expected before the end of the calendar year. And it's important to note that, as well, we signaled the increase in the dividend, $0.37 per share, and the ROIC has also lifted in that period. It's a period where we would be remiss if we didn't comment on the market conditions where the combination of extreme low hydrology with a low wind in July plus the challenges in gas supply have led to a very tight market over August, in particular. The market has responded and responded appropriately, and you've seen a tempering of those very high prices of 2 weeks ago to something more sustainable over the short to medium term. And we expect that the overriding message is continue to invest in new renewable generation if we want to see these prices soften to what we have signaled the long-term price path on that slide, $115 to $125 per megawatt-hour noting it is 2024 real terms. We remain committed to the closure of TCC, not because TCC itself we have managed to extend the hours, but quite simply we need the gas next year if we are to keep it running. But we do have both peakers expect to be available at the end of the year to step into the gap left plus, of course, Tauhara and Te Huka 3 being online and operating well. In terms of highlights, of course, we also had the commitment to 2 new forms of renewable energy technology, the commitment to the Glenbrook battery in June this year and the commitment to Kowhai Park that we announced on Friday, both of which we expect to be on in calendar '26. What's clear, particularly in the events of the last 2 weeks, in particular, is gas storage remains very important because that flexibility in gas and supporting the transition is critical not to just to us but the whole nation. If we go to the next slide, this is just the scorecard around the strategy that we publish every year and our progress on that. It's fair to say that delivery and execution and delivery on promises made remains a core focus within the company. And the only read that you'll see there is Tauhara coming online, but that masks what I think is the real story of 2024 is the way that the steam plant was going to have problems and it was rebuilt within the space of 90 days with people working literally 18 hours a day, 7 days a week, including over the Christmas, New Year period. Obviously, there are some other highlights in there, the FID on the battery. We've talked about Kowhai Park, us moving to the staged execution of the Wairakei replacement in terms of Te Mihi 2 and Te Mihi 3 and also how the customer business has also progressed in engaging ordinary kiwi homes in that decarbonization journey. Moving to the next slide. It's worth pausing just to look at what the what has been delivered. If you walk around Tauhara, you cannot fail but be impressed with the quality of the build and the complexity of what has been undertaken. It is a fantastic piece of engineering and a credit to the team. We have one small issue to resolve in the IP section of the plant, which is a vibration issue, but we have tested it reliably at 152 megawatts and we have pushed the plant up to 174. So those [indiscernible] are very much in front of us. And if you look on today, you'll see the plant is indeed operating at 152 megawatts during the day and we're delighted it came on at such a period of scarcity in the market. Te Huka 3, demonstrating we have learnt. It remains on track. We've achieved first steam and we expect live commissioning of the power plant to commence in the next 2 weeks or so and for the plant to be online before the end of the calendar year. What that means is that when we have Tauhara and Te Huka 3 at full capacity, we will have delivered on about 1.8, 1.9 terawatt hours of additional generation into the market or 225 megawatts. It is reliable baseload and it will go a long way to alleviating some of the supply constraints that we've seen. In addition to that, it's worth also pausing on the Glenbrook factory investment, 100 megawatts, and we expect it to enhance our EBITDAF in terms of taking advantage of the volatility we see in the market of between $15 million to $20 million per annum. It's a project, which stands on its own right. It's not a strategic investment. It's not getting a free ride. It had to pass our own internal hurdles, and we expect it to earn in the order of 9% to 10% internal rate of return. And we expect that they have it online by quarter 1 calendar '26. So not too long to get built. And as we speak today, the bulldozers have already moved on-site and are clearing the site, getting ready for installation. And the last one, the investment in Kowhai Park and partnership with Lightsource bp, 150 megawatts in Christchurch. 80% of the PPA is under contract to us. It is an innovative nonrecourse project finance capital structure. The PPA price is less than $90 real terms, we're delighted with that. And the project costs we expect to be in the order of $273 million. And it's important for us because we have other solar projects, obviously, in the pipeline: Glorit, North Auckland near Helensville; and at Stratford itself, which points to the opportunity at Stratford in terms of [ relifing ] the area and taking advantage of both the transmission and connection and the consent in site we have available there. In terms of the market, so stepping outside the drama over the last couple of weeks, demand has been up in FY '23. It's been good to see that finally after years saying that it's going to be increased, it has actually turned up and start to increase 2% year-on-year. We have seen also this year, obviously, that dry sequence. Also don't forget that many of the factors that's causing that delay were the closure of the refinery in Taranaki, the Pan Pac plant going offline post the floods, all that's come back now, and we expect that demand growth to continue. The low hydro has impacted the generation mix. We've had to run a lot of thermal this year, but you can see in that graph on the left, geothermal Tauhara already in the 4 or 5 weeks it was able to run in FY '25 starting to make a real difference. And on the right there, you see how absolutely unusual the hydrology that we're in right now is, and we expect that to turn and correct. Notwithstanding that, it's not just low hydrology that's been an issue. Gas decline, the decline in gas deliverability, has also [ slid in market ] conditions and that will only be solved as we build more renewable generation and as the gas market upstream resolves its shortage issues. The deal that we did with Methanex points to a potential way forward where we introduced increasing demand side flex just as we did with the smelter, the smelter deal, and we look forward to more of those types of arrangements in the go-forward. The other factors, and this is a diagram we present to you every year, demand is obviously up 2% year-on-year. Hydrology. This is a dry year. Thermal coal prices are actually lower, but the gas shortage itself hasn't helped. Carbon is steady. And methanol remains -- it's up in price. But obviously, we were able to get the fleet in the Methanex plant, which we're delighted with. All of which equates to an increasing volatile graph on the right-hand side. But the long term, we expect to be in the order of that $115 to $125 real terms per megawatt hour. In terms of retail, it's evident that there are different strategies now playing out in the retail market. We're delighted with the performance of our retail business. We now have 100,000 kiwi homes on the -- some form of demand flex, whether it's good night, it's good weekends, good charge. And the latest product, the hot water sorter, which makes use of the ripple control for ordinary kiwi homes to take the pressure off peak times. Tier 2s, obviously, they've had a bit of a mixed year. And you've seen our energy connections just grow slightly. What we have been delighted with is the growth in our telco business with the broadband going past 100,000 connections and the successful launch of mobile, which is now running at about 10,000 connections. And what that leads to is that increase in multiproduct customers where customers do reward us with a lower churn rate if we're able to take the stress out of their everyday lives by simplifying the billing arrangements. You can see also there on the bottom line the relative increases in tariff charges, which is around 3% and just at or below the rate of inflation in the same period. Now in terms of what's happening, regulation is obviously a hot topic at the moment. Fuel security. Obviously, the events of the last week have heightened the degree of interest and potential regulatory reform. We continue to be a strong advocate that the market will resolve itself. And indeed, what's happened in the week following it indicates our market working and working well in ensuring security of supply. MBIE had undertaken that security of supply study, and there has been the reversal of the oil and gas exploration ban as well as potential studies into the import of LNG. We continue to advocate that gas is an important transition fuel, but what will really solve this is further investment in reliable sources of renewable energy, particularly geothermal. Our gas storage facility also continues to provide value in the transition. In terms of lines assets and regulations, we do see going forward, obviously, the Commerce Commission decision around the new price path, which will lead to an average increase of Commerce Commission signaled of $15 per month for the average consumer. It's important that these revenues -- that this investment happens because those lines and transmission investments are the key enabler of renewable energy investment, which will bring stability and fair prices in the longer term. And resource management, look, I cannot speak highly enough of the efforts to put into the Fast-track reform, but quite frankly it is not happening fast enough. And in itself, has become mired in bureaucracy. It's important that if we are to deliver the 40-or-so power stations required by 2035 that we find a way of consenting these projects quickly because they're the right thing to do for the country and they're the right thing to do for the planet. And somehow, we have to cut through the paper chase and red tape to make this happen and happen quickly. And with that, I'll hand over to Dorian.

Thank you, Mike. So as usual, I'll start off by highlighting some of the key themes that are going to come out as I go through the performance for FY '24. A couple of reporting topics to start off with. As usual, our reported financials are impacted by the AGS onerous contract provision, and as usual, I'll talk about the numbers on an underlying basis, so excluding the effects of that, that make it clear how you bridge from one to the other. We've also got $50 million of write-offs in these results. So that you don't need to normalize the numbers for these. We now actually report write-offs and impairments outside of EBITDAF, which aligns more to how others report. Biggest component of that is $36 million linked to Tauhara and the rework after the steam hammer event. It's a noncash topic. The cash element of that was announced with a high CapEx for the project some time ago and we did sort of signal at the half year that this was likely to be our approach. Next topic, the broader energy system is stepping up to support the market as we see an acceleration in the decline of domestic natural gas. This reflects all the sort of innovative work the electricity industry has done in the recent months around developing new demand response solutions. It does demonstrate that the energy transition is working. It's being tested in an extreme scenario at the moment with a very dry sequence and there's no security-of-supply issues, which is fantastic. However, it is leading to more expensive risk management products in the marketplace. And therefore, we do expect prices in the medium term to be higher than our longer-term view of pricing, which Mike mentioned earlier, and that is we now got these demand response solutions offsetting natural gas at a faster rate than we were expecting. Next topic. There's a shift in the fuel mix nationally moving away from thermal into intermittent renewables, and that's leading to a more pronounced shift between summer and winter pricing. This is likely, in our view, to increase the risk aversion of hydro generators, which will lead to higher autumn prices because as they hold legs higher going into the winter because they won't want to be caught short into those higher pricing. And it does mean though that when you're modeling our business' performance now, you can't just look at annualized volumes and pricing, you actually need to do it by season. Higher near-term pricing is a feature of the energy transition. You need the higher pricing to be able to encourage investments into more innovative technologies such as batteries, such as biofuels, such as deep duration storage options like some of the demand response that's being looked at. This, coupled with the fact that we're still seeing an escalation in the cost of building renewables, both at home and internationally, means that we're still comfortable with that price that Mike mentioned, midpoint $120 real in 2024 terms for our long-term view of pricing. We introduced this topic a couple of years ago. Wasn't the most revolutionary topic, it was basically just saying that electricity pricing need to move with electricity class. And since we introduced that topic, most market participants and commentators have come up with their own view as to where long-term pricing is going, reflecting the reality of what's happening around us. Last topic is just around our FY '25 EBITDAF, based on mean hydrology we've announced that $770 million, up on our expected normalized for FY '24 that we guided this time last year by $170 million. That reflects Tauhara and Te Huka coming online. When we actually announced this, it was lower than I think some in the marketplace we're expecting and just explaining, I think, what some of those differences were. I'm not sure the market has probably taken into account some of the temporal headwinds we have in FY '25, such as the outage that we have at Te Mihi and relatively no news about slightly lower volumes of Tauhara in the near term. Also, we have 0.7 terawatt hours of volumes linked to those Tauhara PPAs kicking in and also a bit more volume going to Tiwai. All of that sort of slightly lower price point that you can get selling through other channels, although very strategically important. And then risk management for us is getting more skewed towards acquired generation with TCC shutting at the end of 2024 and there being less domestic gas. And as I previously talked about, the cost of risk management is going up significantly. So on to the overall financials. As I said, the profit after tax impacted by the AGS onerous contract provision to the tune of $84 million in the prior corresponding period and $5 million favorably in FY '24. If you adjust for that, profit after tax is up by $90 million. EBITDAF on an underlying basis is $663 million. And we've got -- that's up $90 million on the prior corresponding period, and we've got the usual waterfall chart there and I'll talk you through that. So it has been very dry, you would have noticed that. So hydro was lower. That was mitigated to a degree by us because you had Tauhara coming online towards the end of the financial year, which meant our renewable volumes were only down 88 gigs, and on a fuel replacement basis, that cost us about $11 million. As we guided to, we stepped up our volumes by 1.5 terawatt hours. We sold the expected Tauhara volumes because we were comfortable in our fuel position going into FY '24 to do that. We've also seen market pricing bounce back after it was quite depressed in FY '23, and that allowed us to run more thermal responding to market conditions. Unfortunately, with that delay of Tauhara, most of those sales were backed by thermal fuel and we only saw a $5 million benefit from them. However, the fact that we were -- even though we had delivery risk on Tauhara going into FY '24, we were able to place those sales into the market was good, reflected our fuel and the diversification of our asset because that gave us exposure to that $63 million increase in market channel pricing. As I say, CFD pricing bounced back after being depressed in FY '23 because of all the water that we had nationally in that year. We've seen $61 million of increased pricing across long-term channels. That's largely the retail channel pricing up closer to the wholesale market. Importantly, it does that as, specifically Mike mentioned, we've got those kind of network costs that are going to be coming through going forward. We've seen improved thermal efficiency of $19 million. Two drivers of that. We shut our least efficient thermal plant, which is Te Rapa, and we've also run TCC at a very high capacity factor, which improves its efficiency. The other benefit we get at that is it becomes more carbon efficient. So the carbon intensity of thermal for us has dropped from 0.8 tonnes to 0.4 tonnes per megawatt hour. And it's quite a nice story here about the thermal assets stepping up to support energy security, but doing it in the most carbon-effective way possible. Our other income was adverse $23 million. We had some big headwinds actually going into FY '24. We lost the steam revenue of $32 million linked to Te Rapa. And also, we've made some profit on disposal of assets linked to Te Rapa in the prior corresponding period. Some of that headwind was offset by premium that we made on the swaption that we sold to Meridian and improved margins across our retail adjacencies. And then fixed costs have stepped up $24 million. $20 million of that is higher OpEx, which is in line with our expectations. And then you've got the usual increases in the escalations linked to transmission and gas storage. So that's the overall EBITDAF story. Going back to profit after tax, depreciation is higher by $31 million. We're running thermal assets harder so you get more depreciation. And also, remember, we talked about this at the half year, we reduced the lives of some of the components of our peakers because we're going to replace them more frequently to improve reliability and that pushes up depreciation, too. Interest expense is down $3 million on an underlying basis. It's a little bit perverse because, obviously, our debt levels were up and our interest rates were up, but this is a function that we capitalize all of the interest on the debt that links to these big projects that we're building whilst they're in the construction phase. It does make sense. But because when you think about business-as-usual, so strip that bit out, the operating free cash flow is higher than the dividend, so business-as-usual debt is actually reducing. Fair value of financial instruments is favorable $26 million. That's the bounce back off. We had those unusually high market-making losses in the prior corresponding period. We talked about that $50 million write-off and the Tauhara component. We've also got $8 million linked to the damage we had to the peaker and then $6 million in relation to ICT projects that we started and then stopped because they were increasing in both cost [ and intensity ]. And then taxes up on the higher underlying profits, but also the change of rules around tax depreciation on buildings, it's flowing through here as well. So overall, our profit -- EBITDAF across our 3 operating segments. The wholesale business is up by $114 million. This reflects the repricing of channels it supplies through and also the high volumes. Retail is down by $18 million. This is the price cost recovery issue here where you've got increases in network costs coming through here. We've got that onset of transfer price that goes into the retail business reflecting the higher wholesale market cost, but the tariff increases aren't increasing enough to offset that cost inflation. And then you've got corporate costs, which were up by $6 million. We'll talk about that when we get into the OpEx section, but there's some onetimers and the inflation up there. So on to the wholesale business. Generation costs are up by $186 million as we've sold more volume. When you look at most of that extra sales, it's been backed by thermal generation and risk management and those 2 components of our costs are up by $174 million. This is where the actual impact of Tauhara being latest felt because Tauhara generated in the second half of FY '24. As we'd expected, we would have 0.6 hour more geothermal generation and our fuel bill would have been 40% or $70 million lower than what we reported. But that being said, as market channels [ delivery ] price up again and with the improved thermal efficiency, as you saw in the previous slides, we did make a spread on those sales even though they were backed by thermal fuel. And then the rest of the generation cost increase relates to fixed costs. You're seeing the usual increased escalation around transmission and then we've got higher costs year-on-year of actually operating our assets, too. In terms of the overall asset performance, hydro, where you can say it's been relatively easy. There's only been 3 weather events of note actually in the financial year, but the team did a really good job in making sure we maximized our hydro operating capacity around those events. Geothermal has performed well. It got the benefit of that extra 5,000 tonnes per day of fluid consent. We got the new Wairakei consent there. So that was good. That stepped up our volumes by 50 gigs per year to 3.3 terawatt hours. We've got a bit of extra volume with Tauhara coming on in the year, 127 gigs. And then it dialed back slightly because we had a planned outage at Poihipi. Thermal has been, I guess, the star, stepping up and supporting the energy system with the low hydro. We were down a peaker, we expect to get that back in September. Remember, thermal capacity hasn't been the constraint. It's been thermal fuel, so that hasn't been a problem for us. And then TCC has performed very well and continues to perform very well. GE has signed off the extra 2,500 hours. Our internal engineers have signed up for further 2,500 hours. So we expect to be able to run it until the end of 2024. And with the Methanex deal that we announced last week or a week before last, I forget, we now have enough fuel to run it to the end of 2024. Question whether or not we will because late levels have got very low, so fuel could be quite tight for winter 2025, too. So we'll need to make a judgment call as to how much of that gas we store and how much of that we run. The market will obviously tell us the answer to that. Wholesale contracting revenue was up by $235 million and that reflects a 1 terawatt hour increased volume. The biggest component there was in CFD, which is actually in line with what we guided to at the beginning of the year wherein we presold that Tauhara volumes with the step-up in market pricing. We ran more thermal generation to support the market. Overall channel pricing $146, up $14 on the previous year. C&I volumes and pricing were up marginally, slightly less than we've guided to at the beginning of the year and that reflects fuel risk, and we did constrain this channel from a fuel perspective. Retail channel -- or the retail load, you've probably noticed we'd like to keep that flat and that's because retail load and the shape of it is very expensive to supply into. However, we did see the retail load step up a little bit this year and that will reflected the success of the business with its time-of-use products. You can see the transfer pricing to that business though continuing to go up, reflecting the wholesale market conditions. Strategic fixed price channel saw volumes drop, and again, that was ending at that shutdown of the Te Rapa plant and the associated contract to supply electricity to Fonterra that allowed us to take that volume and reprice it through CFD channels, which was good. Just linked to that, you can see the steam revenue there dropping from $35 million to $3 million. That's what I mentioned earlier, that's linked to Te Rapa, too. Incidentally, relative to the counterfactual, the closing of Te Rapa was the right thing to do financially. And remember, it will all ultimately get displaced from a fuel perspective by Te Huka 3 coming online, which is good in terms of carbon reduction, too. And then our wholesale trading and merchant revenue that was up by $66 million. With wholesale pricing going back above the marginal cost of thermal generation, we saw length -- merchant length increase by $83 million. With the higher market prices, location losses increased naturally $17 million, not as much as you'd expect they should increase though and that's because we saw our percentage location loss reduced with South Island pricing relatively high because of the dry conditions that we saw. In terms of the retail business, its EBITDAF dropped by $18 million to a loss of $32 million. This reflects for the long-term nature of this channel and that pricing is generally increasing by that CPI, which lags the escalations that we've seen in the wholesale market. We've seen tariff -- electricity tariffs increase by 6.5% on average in the year, reflecting those higher wholesale prices and network cost increases. We have previously guided that going forward tariff increases would be aligned to CPI. However, because of the magnitude of the network costs that are being signed off by the Commerce Commission at the moment, we do expect tariff increases to have to be a bit higher than that to pass through those higher network costs. Mike said this that, that's why it's good we've got more customers on this time of use tariffs now, gives them the option to ship their load to save some money to offset some of that tariff increases. We've actually got 27% now of our electricity -- retail electricity book were on those time of use tariffs, which is fantastic. Gas margins were up from $9 million to $17 million, and that actually reflects a netback of $20 a gigajoule, which is comparable to the value that we can make running that gas through a peaker. Big issue for us, obviously, we have no upstream gas positions and we're just a distributor of gas for upstream businesses. It's making sure we can get access to the 2.4 PJs of gas that we need for the year to supply our retail customers. Broadband has performed really well. Connections are up by 27% and margins up by 60%. Some of that margin improvement in the year was recovering some of the under recovery of local fiber company costs, which went up in the prior corresponding period. When you actually look at the performance across the 2 periods, connections were up by 42% and margins were up by a similar percentage, which is good. And then our industry-leading cost to serve continues to be very well controlled. On a per-connection basis, it's up just 2.5% to $123. In absolute terms, it's up by $5 million. That represents wage inflation of 5%, but also $2 million of advertising and spend linked to the launch of our mobile product. That segues neatly onto context -- operating costs or OpEx. It's up 8.5% or $20 million for the year. That's $4 million lower than we were expecting because obviously, with the delay of Tauhara, we didn't incur some of the operating cost to support that, that we were expecting. It is a big percentage increase, though, year-on-year, we recognize that, but it is aligned to what we signaled at the beginning of the year. We've got a net $2 million increase in costs linked to onetime movements between the 2 years and that's because we've got $5 million of onetimers this year. That relates to a restructuring within our Simply Energy business, which will deliver $2 million of sustainable OpEx savings from FY '25 onwards. We've got the tail end of some of the cyclone recovery costs. And we're also starting to think about what happens after our Contact26 strategy and so there's some cost regarding support for that, too. We continue to see the impacts of inflation coming through. That's increased our OpEx by $11 million, although we are starting to see that sort of come off. So we shouldn't see those levels of increases in FY '25. Headwinds of $4 million. We've got $1 million of increased bad debt, which won't surprise anyone based on the economic situation. Just to put that into context, though, Contact's overall bad debt are just $3 million on $3 billion of sales. So they are being very well controlled. The rest of the headwinds are $3 million in relation to ICT and our S4/HANA project. Unfortunately, the CRM system stays on the old version of SAP, so we're still paying 2 lots of license fees now and 2 lots of cloud storage. So whilst this is frustrating, it's a small price to pay, in my view, for avoiding the disruption of doing a CRM upgrade anytime soon. We've also got $5 million of savings. So we have $3 million with Te Rapa shutting and then you've got the usual $2 million of fixed cost leverage that we get as our retail connections grow. And then we've got this $8 million, what I call growth OpEx, again aligned to what we signaled at the beginning of the year, $3 million linked to the retail business with the launch of the mobile offering that I talked about, $1 million of higher rates at Tauhara even though the plant was barely on in FY '24 to help reduce capital that there's an opportunity to increase their revenues. And then we've got $4 million of rightsizing our business for growth and dealing with all of the complexity around ESG. And you can see the sheer number of reports that we're now having to release on the NZX with the financial year-end, how reporting is getting more complex there. But again, as I said at the beginning of FY '24, this is the last year of big OpEx increases for us. FY '25 onwards, our OpEx will be going up with inflation. It will then change based on fixed costs reducing or going up, depending on whether we're shutting or putting new assets online. And then there'll be an overlay of our productivity programs. Operating free cash flow is $470 million, which is a conversion of our EBITDAF of 71%, which is a very strong performance, up on the 49% that we had in the prior year. The cash conversion does swing based on thermal usage. In the prior corresponding period, very low thermal usage, but you still have that gas and carbon that you acquire, which is bad for cash flows. This year, we saw the reverse, very high thermal usage, so we draw down the inventories there, which is good for cash flow. When you look at the performance across the 2 years on average, our cash conversion was 60%, which is actually what we say is normal for Contact. We are expecting questions from different stakeholders about the profit going up year-on-year. In particular, when kiwis are doing it tough, with the economic situation we're in. But if you look at our sources and uses of cash, you can see that every extra bit of cash flow that we are generating is going into building more renewables for the good of the country, both economic and from a climate change perspective. You can also see that in spite of the higher profits year-on-year, our return on invested capital is still only 3.7%. So isn't providing a sufficient return on capital for our investors or capital providers. These are the legacy issues that take some time to turn around. One of the issues here is around thermal assets where they tend not to get the price that's required to cover the level of investment that's happened in them and also the relatively high levels of fixed costs with running them. We will get a kick on this measure in FY '25 when we get the income streams coming through for Tauhara and Te Huka 3, and I can assure you that all of our recent and go-forward investments generate a return of at least our weighted average cost of capital. But what the KPI does demonstrate, though, even though we are seeing higher profits is that we're still not making sufficient returns. This is a fact. The numbers don't lie as opposed to some of the opinions that I'm seeing playing out in the media at the moment, which are trying to tell a different story about excessive profits. And for us, anyway, when you look at this, our profits are a long way from being excessive. This is just the usual slide, we're spending a lot of money on growth capital. So it just lets you know where that's going and that the spend is aligned to what we told the market. And then in terms of our balance sheet, we continued to see high levels of debt as we continued to build out our development pipeline. Very pleased we entered the Australian bond market during FY '24, gives us another option in terms of debt as we -- as our balance sheet grows. Floating rates for us were up by 152 basis points, but you only see our average interest rate going up by 30 basis points, and that's because of -- that's the great work the treasury team have done. They took out fixed interest rate hedging in a lower interest environment in anticipation of our debt levels going up as we build out our renewable development pipeline and that means our fixed interest rate is actually dropping as our debt levels go up, which is offsetting some of that floating rate increase. So very pleased with what they did there. We are expecting to issue more capital bonds. They have a wider margin than normal bonds. But even taking that into account, we don't expect interest rates to go much about where they are at the moment. And with the use of those capital bonds, dividend reinvestment plan, which you'll see in a minute, we've discounted by 2% going forward. And the use of off-balance sheet arrangements for solar, like what we've just announced with Kowhai Park, we expect to continue to build out our development pipeline on balance sheet. So on to dividend, very exciting for me. First time in my Contact career that I've ever been able to announce an increase in our dividend. So it's up by 6% for the full year for $0.37 a share, and that's the final dividend going up by $0.02 from $0.21 to $0.23 per share. The intention is then to increase the interim dividend of FY '25 by a couple of cents, too, taking FY '25's full year dividend to $0.39 per share. And this increase is driven by the higher operating free cash flows we have due to Tauhara and Te Huka 3 coming on and also lower market risk because of that long-term Tiwai deal that has been done. We continue with a dividend reinvestment program, but we've now discounted it by 2% and that will ensure we continue to get capital recycled back into the company to support our build program. After FY '25, we're expecting to hold dividends whilst we do the first stage of the Wairakei replacement project. Whilst we disclose the CapEx around that project as growth, it really is sustained business CapEx project and [ bold ] means it should probably be going into our operating free cash flow, which then impacts dividends. But because it's such a large project, it's easier just to split it out and show us a growth project, but the quid pro quo is we think it's the right thing to do to hold dividends whilst we're building that project, which then comes online in mid-2027. Our expected and normalized EBITDAF. So mean hydro EBITDAF for FY '25 is $770 million there. As I said earlier, that's up by $170 million on our expected normalized for FY '24. And you can see on the chart that all of that growth is coming from renewable generation, and that's Tauhara and Te Huka 3 being online, that's 8 months of Te Huka 3 in there. So we are a little bit sensitive about people writing about profit and then not actually talking about the investment that's driving that. So remember, that's a $1.2 billion investment that's enabled us to get that $164 million of profit growth there. And also remember, you have to pay 28% tax on that, too. If you actually strip that out, our underlying business, so like-for-like without that investment, is actually staying sort of flat with those higher risk management costs that I've talked about earlier being offset by pricing being a bit higher. The other question that we're being asked a lot is this is mean hydro for FY '25. And clearly, we're not in a mean hydro situation at the moment. So is this forecast still holding? And the answer is yes. We're expecting hydro to be about 300 gigs down and that assumes we revert to mean hydrology in September. We have quite expensive risk management now with the Methanex demand response, the Tiwai demand response and a bit of Taranaki so that -- displacing that water is costing us about $90 million. But going into the year, we had about 500 gigs of uncontracted volume, which we can now contract into higher pricing. So we expect those to offset, leaving us there or thereabouts. Last slide from me. So the Tiwai deal is done. Project Onslow has been kicked into touch. There is cross-party support for building renewable electricities to meet New Zealand's climate change targets. And our electricity market is envied by almost every other country in the world for offering affordable, secure and sustainable electricity. These are very conducive market conditions to invest into. Contact has great strategic optionality with projects across all different types of renewable fuels and flexibility. We actually see this as being quite unique. We don't see anyone else that's actually got the breadth of investment opportunities that we have. Now we need to ensure that we're deploying your capital effectively. And when you look at our next project, which is scheduled to come online, which is Te Huka 3, that project is on time and it's on budget. So now it's the time to build. We have great renewable options and deploying capital is the right thing to do to drive long-term value for our investors.

Thank you, Dorian. Just to -- one thing I didn't bring out on the first one is obviously the signing of the Tiwai deal. As Dorian alluded to there, it's great for both market security, but also pointing the way forward about how large-scale industrials can participate in the investment through demand flex, and we're delighted with the outcome of that negotiation. If we look at the next slide, and at the risk of being boring, this is the same slide we've put up for the last 3 years, which shows that it's not just about making a promise. It's actually delivering on the promise that's really important to us internally at Contact Energy. And that strategy remains very much the same with a focus on decarbonizing the portfolio, growing demand, investing in renewables and taking the rest of New Zealand ordinary kiwi households on that journey of decarbonization. How is that showing up? As we prepare for new investments, you obviously have there the completion of Tauhara and Te Huka 3 in terms of geothermal generation and then we have remaining consented opportunities there both on the Wairakei field with the Te Mihi 2 and 3 and with Tauhara Stage 2, which will lead us eventually by 2031 to 2035 to about 6.3 terawatt hours of [ geothermal ]. In addition to that, we haven't been idle in developing other technologies already with the Kowhai Park announcement of 0.3 terawatt hours. We have a total pipeline of 2 terawatt hours in solar and 4 terawatt hours in wind with a focus very much on the near term getting those resource consents in place. Kowhai Park has a resource consent. We're now awaiting fast-track resource consent for Glorit and for Southern Wind. We raised a bit of a storm earlier in the year -- not a storm, but a curiosity around our approach to Wairakei. And it's fair to say that our attention to the balance sheet as well as the economics of the project meant that we moved from a single-build, one-stop rebuild of are Wairakei with the GeoFuture projects where we're planning to close the existing plant to 2026. Given the scale of our ambition across all technologies, we've moved to a phased build where we build out Te Mihi Stage 2 and Stage 3, each 100 megawatt, with a clear choice of technology around binary plants. And what enabled that was the realization that we could, through very powerful asset management techniques, extend the life of Wairakei power station through to the resource consent period after 2031. There is a note that we did get ISO55000 in this last financial year in terms of proving out that asset management capability. Te Mihi Stage 2, we expect to come to FID between -- before the end of the calendar year. The capital we expect to be between $600 million to $700 million. It's fair to say the teams have been working extremely hard on some creative options there for the steam field, in particular, to ensure that capital was deployed as efficiently as possible. We expect it to be a 100-megawatt binary plant with an uptime of around 95%, producing about 0.8 terawatt hours per annum. Wairakei, we expect to keep the B station, in particular, up and running with a little bit of additional capital of around $25 million to $35 million with a focus on keeping 30 megawatts of steam turbines available and 7 megawatts of the binary unit to keep us going out to 2031. The work around this has been progressing well and there have been no nasty surprises, I'm pleased to report, which is just delightful for a plant that was built in the late '50s. We take the next one, and this is also to clear out [indiscernible] misunderstandings. Average output from the Wairakei field prior to today with about 2.7 terawatt hours a year. On average, with the new resource consent, we expect that to rise by 0.1 terawatt hours over the following 5 years until we build the second stage of Te Mihi 2, so Te Mihi 3, in effect, which will then lift the output from the Wairakei field to about 3.1 terawatt hours per annum. And then at that stage will represent the Wairakei field, effectively sorted out for the next 6 years with very resilient and robust new plant in place and that uplift in output. We're looking forward to that. We believe the staged approach better fits the capability and capacity that we have built up in the Taupo region these last 4 years. We believe that better fits the capability and capacity in our balance sheet which, in turn, allows us to pursue other technologies at the same time. And all that, what is becoming clearer is how the energy transition is going to play out in New Zealand. And this is important not just for Aotearoa, but also for the OECD because we are leading the OECD in terms of our transition. So in terms of natural gas, which is, of course, we're always advocated for as the transition fuel, we expect the gas fields to decline a lot faster than what we anticipated and that has been borne out by the unsuccessful drilling campaigns, which have taken place in the last couple of years. There is possibility of LNG import, but there is also the need perhaps for continued reliance on coal and electricity generation. We do expect more intermittent renewables to come online, which means that a high-cost gas baseload generation won't necessarily align to what the market needs. It will be probably a shift towards gas peaking. And we do expect thermal power stations like base load and TCC to continue to close. What that means for a thermal plant that remains? They will have to recover their higher fixed cost base in much shorter periods, which may contribute, we expect, to that higher volatility going forward. And you will see these spikes in prices in thermal generation comes on. What you'll see is a lot more renewable generation being built, as I said, 40 power stations by 2035. And that will put pressure quite rightly on the consenting bodies because they have a part to play. They cannot drag the chain on this. They need to move and move quickly to ensure that those consenting bodies play their part appropriately and with agility in terms of the decarbonization of this country. Dragging the chain and worrying about peripheral and often minor environmental issues is not an appropriate response to the need to decarbonize and decarbonize quickly. I cannot emphasize that enough. Their duty of care is their role in decarbonizing the planet, and they must recognize that duty of care and respond appropriately, swiftly and in an agile way. There is a backlog in consenting, and we do expect that the cost escalation that we've seen to continue to some degree and that is on us to make sure that we are building and designing [indiscernible] Okay. For the next slide. So what this means is that we see a value shift to flexibility to respond to that volatility and intermittent generation. We do see that long run wholesale electricity prices will remain above historic. And you see there, look, people often quote at us, well, the cost of solar and the cost of wind coming down, but that ignores that cost are firming. And it's not just a statistical forming. As a first world nation, we have an expectation that our electricity is there for us when we need it and that requires us to not form the electricity, but to firm the electricity 24/7 365 days a year and there will be a cost on that, and we need to recognize that cost. We do see the winter-summer spread increasing as intermittence come on. Obviously, solar will have a higher output in the summer and the wind will blow regardless. And so we do see that demand between summer and winter, that separation widening and that in itself both presents a challenge and an opportunity for us as we see summer demand load. And we do see a value shift in the market towards flexibility, which is why investments and the likes of the battery and the reconsenting of our hydro and investments in base like geothermal carry such value because that is where the value is shifting in the market towards that flexibility and the ability to reliably provide electricity, 24/7 with sun shining or the wind is blowing or not. So what can you expect in the next 12 months? We will continue with this strategy, which has served us so well. We will achieve FID for CO2 commercialization and keep the bubbles in New Zealand beer going. We will announce FID for Te Mihi Stage 2. We will deliver Te Huka 3 online. You can see the battery and Kowhai Park making excellent progress over the next 12 months. We will lodge the consent for Stratford Solar. We will achieve the consent for Glorit solar, subject to the authorities cooperating. And we will achieve the consent for Southland wind again, subject to the relevant authorities providing their support. We will close TCC, but we will continue to operate the peaking plant at Stratford, and we will sustain our position in the Dow Jones DJSI. In terms of our retail base and the engagement with ordinary kiwi households, you'll see our multiproduct connections grow to 148,000 connections while maintaining the best-in-market cost to serve at $123. We will -- electricity prices will rise in the order of 2% to 3%. And we will scale up our hot water sorter. The note that electricity price rise excludes the potential price rises coming through network and transmission charges. And on that, with the outlook and very much the company busy, but optimistic on the back of a very strong result, I'm go to slide to your questions.

Thanks, Mike. So we'll go to questions now. We'll start with -- start then into Grant Swanepoel.

Contact, can you hear me?

Yes, we can, Grant.

I'll just run through a few quickly. What's causing Wairakei to cut back from 1.1 terawatt hour to 800 gigawatt hours by 2026? what have you uncovered that it's failing on that front? My second question, you indicated Te Huka is in for about 8 months in your guided FY '25 numbers. When does -- do you also have that 4-week trial? And will that start in November according to 8-month expectation? The third question, the Tauhara rattle that you're sorting out. I see Tauhara's jumping between 130 megawatts and 153 megawatts over the last week or two. Is that still due to be sorted out by the end of this month? Fourth question, just on the 3.5 PJs of gas you recently got from Methanex, is that included on your Slide 49 on the right-hand side there where you're talking about securing short-term gas? Or was that over and above that quantity? And my final question is on TCC. If you wanted to and the market required it to be running post-December this year, what are the costs to keep it going for another winter season? And how many gigawatt hours would you have left on that piece of equipment? That's it for me.

Okay. Right. I'm baking those. The geothermal volume from Wairakei driven by outages. So we have a significant outage from to Te Mihi, which is on the Wairakei field in FY '25 as we do the -- as we not only replaced or renewed the steam path on the existing generation, but also due to times. And in FY '26, we obviously had the major Wairakei shutdown. And that's -- the combination of those is what takes the volume. That's not in the assumptions, particular assumptions, around increased outages or anything we've found in the Wairakei plant. In fact, we're delighted with the way the Wairakei plant continues to operate. The second question was around Te Huka 3.

The 8 months to be included.

Eight months of included. So we expect on a P50 basis to start the reliability run mid- to late October, which should be 30 days, and that would then be concluding towards the end of November, early December. And so we expect to have those 30-day production, which sort of gets you to your 8 months of production.

You should be running at full capacity grant on a reliability run. So that gives you your 8 months.

And I'm glad you're watching Tauhara so closely, Grant. We're all watching Tauhara closely. In fact, some people, externals, tell us when the plant is going up and down. So what you've seen is us operating the plant at a prudent level, which has minimized the vibration at that 130 megawatts to 135 megawatts. What we've done is a number of improvements around the vessel that's been vibrating and we've installed vibration monitors, which tell us exactly how much we can run the plant up to before we run the risk of fatigue failure. And so what you've seen over the last week is us taking the plant up to about a 2.5-millimeter vibration level, which is well within the bounds of not risking fatigue failure. And what we're doing is running the plant during the day at the 152 megawatts where you get about -- you're up at the sort of the 2.5-millimeter limit and then just taking it down at night where there is not the need to fatigue it so much. What we expect, we can expect to continue in that for about another 2 months, Grant, in that mode between the 140 to the 152 megawatt mark. And then after that, we should have some new foundations and structural support around that IP vessel and a reconfigured inlet piping, which will mitigate and allow us to go to probably the 152 megawatts on a very consistent basis. What you'll see by that because we have these very high [ actual ] vibration meters is the opportunity to then test whether we can go any higher or whether we need to wait until November next year to get the plant finally up to the 174 megawatts. So that is as hot off the press as I can possibly give you. It's a very dynamic situation. It's fair to say this vibration issue has got the engineers deeply enthralled with potential solutions, and it's nice to see the results coming. But like all the engineering solutions, they never come in a linear way.

And on Page 49, Grant, that does include the Methanex gas. And the last chart -- the last question was about TCC. So I think I said it, the TCC -- GE have signed off the extra 2,500 operating hours that we've talked about quite a bit. And then our internal engineers have actually signed off a further 2,500 operating hours, which will allow us to comfortably run it to the end of 2024. And like I say, we've got the fuel now with that Methanex deal to do that as well. There, we obviously get questions about can you continue to run TCC into 2025. I mean, there's the engineering question around running the asset, but there's -- the bigger question is actually around there's no natural gas to run it. That's the primary issue around constraints of fuel.

Can I just have a follow-up on the first question on Wairakei. If there's no issues with it, why didn't you consent more than 37 megawatts through to 2031?

No, we've got full consent. The consent is for the offtake of 250,000 tonnes average per day -- average over a year with a peak of 280,000. So we could run -- the generation associated with that is the generation. The idea is that we build a binary plant that consumes its appropriate portion of the high-efficiency offtake and you're effectively just sending the balance of offtake down to Wairakei B.

We'll move to questions in the [indiscernible]. Andrew, is that you?

I have a couple of questions. First of all, it's probably one for Dorian just around the guidance on EBITDAF. Obviously, we've got quite volatile situation in wholesale prices in hydro situation. Will you be able to give us a sense of, I guess, of the possible range of outcomes we're sitting at, at the moment? I mean, the way you described things sounds like it's relatively narrow, but yes.

It's, look, I think we are -- we're in probably a better position than most because of the multiple options that we have around risk mitigations with the fact that we've got stored gas. We've got these demand response solutions, which are directly impacting us with the Tiwai deal and Methanex. We've got Wairakei. So all -- I think it's what I'd say is that we -- if it stays dryer for longer and you have higher prices, then we may be able to eke out some fuel running Wairakei for longer. You can run that at about 1.5 gigawatt hours a day if you need to. So we're in a pretty good position in that -- relative position in that regard, I'd say. It's difficult to say. I mean, I think we'll probably be on a tighter range than others when I say we're still at our $770 million. And like I say, the other topic here is we might be happy to forego profit this year to actually store fuel because I think we're going to be looking at probably a relatively tight winter 2025. So that might be the right thing to do as well. So we'll do the right thing. So I mean, at the moment, I'd say we're pretty good for the $770 million and the range around that will be tighter than others, I suggest.

Okay. Next question I just had was, I guess, looking at the development pipeline, and in particular, I guess, Tauhara Stage 2. If you could give us any indication of timing around that.

Look, I think into Tauhara Stage 2 is that would follow after Te Mihi Stage 3. Indeed, one of the attractions of that whole program is that we can now see a decade of work: we have Te Mihi Stage 2, Te Mihi Stage 3, Tauhara Stage 2 and potentially the redevelopment of Wairakei. And so we can retain that skill set in the Te Rapa region designing and building those plants, just [indiscernible] and just getting more and more productive and more and more efficient as they do it.

Is there a slight change in thinking? Because I think previously, sort of sometimes they have it at the back end of this decade as opposed to after?

We have a look at that as we get out -- come out of Te Mihi Stage 2 what we can do. We might swap them around, for instance.

You want to see how the reservoir responds to Tauhara. So that's what we've always told. We want to collect data on that because that will then help us make the right sustainable decisions around Tauhara Stage 2, which will provide the most effective management of the long-term reservoir and maximize returns on it. So that's -- it is a little bit dynamic around that because you're getting more data all the time the longer Tauhara operates.

Yes. Okay. And I assume it's reasonable to assume the capacity to develop more -- faster is you're pretty much running as hard as you can at the moment.

In terms of human capacity and capability, I think in terms of the geothermal program, we're at a sweet spot. I wouldn't say maxed out, but we're at a sweet spot. And I think the other consideration is that we pay close into the balance sheet. So we are refreshing and ensuring the balance sheet and that net debt-to-EBITDAF we will stay under 3. And I think that's important on the go-forward as well.

Next question I just said was around the Southland consent timing and how much that's been pushed back because I think there's an indication that we...

We've taken a 20-day pause just while we engage in discussions with the [ Wanaka ] family for Southern [ Wanaka ]. And hopefully, we can reach a resolution there and then continue the proceeding.

Okay. And just two more from me. Your views on importing LNG?

We see that as a medium-term option that we'll probably take. Won't be there in 6 months to a year, but might be there in 2 years. Certainly, there is a significant amount of infrastructure already there in terms of the gas infrastructure we already have in the country and particularly the Ahuroa storage facility. And so I think it's incumbent on industry to come together and come up with a solution for that.

Okay. And last one is just really a clarification. So I think on Slide 25, there was FY '25 CapEx of $340 million, then you're guiding to $450 million to $550 million for growth CapEx. I assume that the difference is to Te Mihi Stage 2 needs to be approved and so that, that's coming in, in the second half of the year? Or is there some other...

$425 million in the last. $450 million for the following year.

This is for next year.

The next year. Yes, and the difference is Te Mihi.

Okay. That's a good segue to our first online question. We've had a question from Cam Parker, also Stephen Hudson, so we'll combine that. The question is it looks like that Te Mihi Stage 2 CapEx costs are around $6.5 million a megawatt. This is an improvement on the previously notified $7 million-plus. And are there any further gains to be made on CapEx costs?

It's a work in progress. So I think it's fair to say the team have got a lot of hard work on the steam field design and come up with some very innovative solutions there. But in line with trusting the process, they now have to develop that up on a full front-end design. So when they come out with a cost estimate, it is robust and benchmarked, particularly in terms of a project development readiness index, what we call a PDRI, which is aligned with international practice. So is it an improvement. It is in line with the $7 million because that $7 million obviously included some costs already. So I'd say it's more at this stage, it's in line. Obviously, we'd hope to see an improvement. And certainly, there are positive signs there with the creativity that's emerging.

Stephen's follow-on to that, it's whether anything has changed or impact happened around Ormat's appetite for new, New Zealand projects?

No, not at all. If anything, they have engaged very positively and very collaboratively with us.

And one from Cameron Parker at Craigs. Based on your long-run view of wholesale prices, where do you see long-dated C&I prices [ ceiling ]?

Probably a few percent above based on the fact that you normally get a margin just above the long-term price, the cost to serve and credit risk and all the other stuff in there, so a few percent above.

Okay. One more from an Cam Parker at Craigs. What's your view on the level of battery build in the portfolio and the market before returns start to be eroded?

So we said -- I think we've said in the past, we see about 400 to 600 megawatts of battery being installed, which is probably about the right size. You've seen 2 batteries of significance being committed to, so still a way to go. Is there a risk of overbuild? Always. The only caveat I'd put on that is we need to see where the battery is [ going ] with very increased volatility, which I don't think anyone has anticipated that we now see in the market day.

It also depends on how successful we are with demand response at a retail level as well because that's in a Vector battery. Origin talked about virtual batteries, that's exactly what they're doing over in Australia. That's incredibly efficient because there's no natural investment required around that. And that obviously socializes the benefits in this as well. So if you get a big step up in that as well, which we hope there will be, then that means less need for investments into grid-scale batteries, too.

One more question from Stephen Hudson at Macquarie. He's looking at the STI and the integrated report, which has 3 EBITDAF gates, $740, million, $770 million, $785. He's asking if that suggests risk to the downside? And can you clarify?

It reflects a reasonably crude assessment of risk to the downside. And what it was allowing for is if there were potential issues with commissioning of plants and things like that, it reflects more so a baseload delivery. So that's, indeed, we see it's tighter than the range that we were forecasting last year. But if anything, the risk is to the downside. When -- with the challenges around the IP separation [ band ] in Tauhara and they're potentially taking a bit longer than what we anticipated.

I think there's probably an element of the corporate scorecard has been impacted, I think, 3 years in a row due to the impact of Tauhara which whilst it's very important, it's also a relatively small group of the company and the corporate scorecard to be impacted 3 years in a row by, so I think there's an element of providing a bit more sort of pragmatism around these big investments and getting them online and 35-year cash rates and things like that, there will be that type of lens that's being put on it as well. And we certainly wouldn't read anything into it around. That means that we are expecting not to get 8 months' worth of Te Huka 3 into our numbers in FY '25.

Well read, Stephen.

Yes.

So moving to two questions now from Vignesh Nair at UBS. The first is on the $770 million EBITDAF guidance into FY '25. On Slide 40, the assumptions talk to gas price of $8.20 a gigajoule. Is that is still appropriate? How does Methanex gas cost flow through? And how's the implied generation from the Methanex gas purchases in Stratford?

Yes, the Methanex isn't included in this guidance, that's what I was talking about. This was the guidance. If you remember, we actually released this about 6 weeks ago, I think, in a NZX announcement. As I said, we still expect to be kept whole because whilst our fuel cost will probably be about $90 million higher than what's in this guidance, such as the more expensive Methanex gas, such as what we're paying on the demand response on Tiwai, we expect that to be offset by the fact that we can contract our uncontracted [indiscernible] at a higher price offsetting that. So going forward, we don't expect gas to be anything like $8 anymore. That was -- those days are long gone.

What appears to be the final question is also from Vignesh. Across geothermal, solar, batteries, potential new wind, solving gas shortfalls and retail innovation, the team is clearly working on a lot. Is the business taking on to match at once? Where is the greatest risk set? What's the biggest challenge at the moment? In other words, what is Mike spending the most time on?

It could be -- Vignesh, there's a role for you in governance. That's a very good question. Mike?

So we've obviously spent the last 4 years rebuilding that muscle fitness around project execution and having a well-resourced project delivery team in place, complemented by a development team that has been in [indiscernible] has been critical. And don't forget on solar, we have not been shy in going and getting expertise and partners from outside, so the partnership with Lightsource bp. They will manage and execute that project on our behalf. And so while it looks very busy, don't forget that we have partners and Lightsource bp and Roaring40s and Western Energy in sort of subsurface geothermal and Tesla in the battery. We're not shy in saying, "Hey, we're not the brightest people in the room on this. There is someone who can do this alongside us just as well." And I think it's really important to understand that, is sometimes the key way of handling such an increase in activity is being humble enough and honest with yourself about the fact that there will be others out there who can do it better and making sure you form those partnerships in advance of the time. Obviously, Tauhara has taken a lot of our attention. But I would highlight here that the base of the business both in retail and generation in the last 12 months has done extraordinarily well in some very challenging circumstances. And whether it's the hydro volumes, the geothermal volumes, the performance of the thermal plant, the performance of the retail business and maintaining its market-leading position, all of that on absolutely delightful work, but that doesn't happen by accident, that happens through a lot of hard work. So my focus is making sure that the core of the business continues to turn up to work to do those ordinary things very extraordinarily well. And where we are trying something new, that we have the appropriate partnerships and expertise in place to walk alongside us on that journey. And we've been very clear about that for the last 4 years.

That should probably also draw the linkage to our operating expenses, our OpEx, going up. This is a direct link to that making sure we've got the right resource in the place when I talk about making sure we've rightsized it right. So we have been investing into the business to make sure we can deal with the additional pace and complexity of doing all of those things faster than we've done historically.

There's no more questions. So we will draw this to a close. Thanks, everybody, for joining.

Thank you.

Okay. Thank you.