Welcome to Contact Energy's full year results presentation for FY 2024. Today, we're joined by Mike Fuge, our CEO, and Dorian Devers, our CFO. To you, Mike. Yeah. Kia ora, everyone, and welcome. Welcome to the FY 2024 results. If we move quickly into it, sorry, pause at the photo. Photo of the new Tauhara 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 230-235, and the amount of capital going into the company at the moment was NZD 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, NZD 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 two weeks ago to something more sustainable over the short to medium term. We expect that the overriding messages 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 of NZD 115-NZD 125 per megawatt hour, noting it is 2024 real terms. We remain committed to the closure of TCC, not because TCC itself, we've managed to extend the hours, but quite simply, we need the gas next year if we're 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, and operating well. In terms of highlights, of course, we also have the commitment to two 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 2026. What's clear, particularly in the events of the last two weeks in particular, is gas storage remains very important because that flexibility in gas and supporting the transition is critical, not just to us, but to the whole nation. 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, delivery on promises made remains a core focus within the company. The only red 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 found to have problems, and it was rebuilt within the space of 90 days, with people working literally 18 hours a day, seven 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 has been delivered. If you walk around Tauhara, you cannot fail to 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 MW, and we have pushed the plant up to 174 MW. So those prices are very much in front of us, and if you look online today, you'll see the plant is indeed operating at 152 MW during the day. We're delighted it came on at such a period of scarcity in the market. Te Huka 3, demonstrating we have learned, it remains on track. We've achieved first steam, and we expect live commissioning of the power plant to commence in the next two 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 up to full capacity, we will have delivered on about 1.8 TWh-1.9 TWh of additional generation into the market or 225 MW. It is reliable base load, 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 Battery investment, 100 MW. We expect it to enhance our EBITDA in terms of taking advantage of the volatility we see in the market of between NZD 15 million-NZD 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%-10% internal rate of return. And we expected to have it online by quarter one, calendar 2026, so not too long to get built in. 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, in partnership with Lightsource BP, 150 MW in Christchurch. 80% of the PPA is under contract to us. It is an innovative, non-recourse project finance capital structure. The PPA price is less than NZD 90 real terms. We're delighted with that. The project cost, we expect to be in the order of NZD 273 million. It's important for us because we have other solar projects, obviously, in the pipeline. Glorit, north of Auckland, near Helensville, and at Stratford itself, which points to the opportunity at Stratford in terms of revitalizing the area and taking advantage of both the transmission connection and the consented site we have available there. In terms of the market, look, stepping outside drama of the last couple of weeks, demand has been up in FY 2023. It's been good to see that, finally, after years saying that it's gonna be increased, and it has actually turned up and started 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 and Whirinaki, 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 four or five weeks it was able to run in FY 2025, 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 caused this spike 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. I t's up in price, but obviously, we're able to get the flex 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 NZD 115 to NZD 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 some form of demand flex, whether it's Good Nights, 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 2, 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. What that leads to is that increase in multi-product 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, regulations obviously are a hot topic at the moment. Fuel security obviously, the events of the last week have heightened the degree of interest in 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 a market working and working well in ensuring security of supply. MBIE have 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 Ahuroa 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, the Commerce Commission signaled, of NZD 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 put into the fast-track reform, but quite frankly, it is not happening fast enough. And in itself, it's 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. 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 gonna come out as I go through the performance for FY 2024. 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, but make it clear how you bridge from one to the other. We've also got NZD 50 million of write-offs in these results, so you don't need to normalize your numbers for these. We now actually report write-offs and impairments outside of EBITDA, which aligns more to how others report. Biggest component of that is NZD 36 million linked to Tauhara and the rework after the steam hammer event. It's a non-cash topic. The cash element of that was announced with the 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've 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 lakes 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 out businesses' 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, you know, 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 NZD 120 real in 2024 terms for our long-term view of pricing. We introduced this topic a couple of years ago. It wasn't the most revolutionary topic. It was basically just saying that electricity pricing need to move with electricity costs. 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 about our FY 2025 EBITDA, based on mean hydrology, we've announced that's NZD 770 million up on our expected and normalized for FY 2024 that we guided this time last year, by NZD 170 million. That reflects Tauhara and Te Huka 3 coming online. When we actually announced this, it was lower than I think some in the marketplace were expecting, and I'm just explaining, I think, what some of those differences were. I'm not sure the market had properly taken into account some of the temporal headwinds we have in FY 2025, such as the outage that we had at Te Mihi, and the relatively new news about slightly lower volumes of Tauhara in the near term. Also, we have 0.7 TWh 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 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'd previously talked about, the cost of risk management is going up significantly. So on to the overall financials. As I said, the profit, profit after tax impacted by that onerous contract provision to the tune of NZD 84 million in the prior corresponding period, and NZD 5 million favorably in FY 2024. If you adjust for that, profit after tax is up by NZD 19 million. EBITDA on an underlying basis is NZD 663 million, and we've got that's up NZD 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 GWh. On a fuel replacement basis, that cost us about NZD 11 million. As we guided to, we stepped up our volumes by 1.5 TWh. We sold the expected Tauhara volumes because we were comfortable in our fuel position going into FY 2024 to do that. We've also seen market pricing bounce back after it was quite depressed in FY 2023, 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 NZD 5 million benefit from them. However, the fact that we were even though we had delivery risk on Tauhara going into FY 2024, we were able to place those sales into the market was good, you know, reflected our fuel and the diversification of our assets because that gave us exposure to that NZD 63 million increase in market channel pricing. As I say, as CFDs pricing bounced back after being depressed in FY 2023 because of all the water that we had nationally in that year. We've seen NZD 61 million of increased pricing across long-term channels. That's largely the retail channel pricing up closer to the wholesale market. It's important that it does that. Specifically, Mike mentioned we've got those high network costs that are gonna be coming through going forward. We've seen improved thermal efficiency of NZD 19 million. Two, drivers of that, we've 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 of that is it becomes, more carbon, efficient. So the carbon intensity of thermal for us has dropped from 0.8 to 0.4 tons 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, NZD 23 million. We had some big headwinds actually going into FY 2024. We lost the steam revenue of NZD 32 million linked to Te Rapa, and also we've made some profit, 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 a swap option that we sold to Meridian and improved margins across our retail adjacencies. And then fixed costs have stepped up NZD 24 million. NZD 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 EBITDA story. Going back to profit after tax, depreciation is higher by NZD 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 gonna replace them more frequently to improve reliability, and that pushes up depreciation, too. Interest expense is down NZD 3 million on an underlying basis. A little bit perverse, because obviously our debt levels are up and our interest rates are 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, also 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, NZD 26 million. That's the bounce back after we had those unusually high market making losses in the prior corresponding period. Talked about that NZD 50 million write-off and the Tauhara component. We've also got NZD 8 million linked to the damage we had to the pipe, and then NZD 6 million in relation to ICT projects that we started and then stopped because they were increasing in both costs and activity. And then tax is 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 profits, EBITDA across our three operating segments, the wholesale business is up by NZD 114 million. This reflects the re-pricing of channels it supplies through and also the high volumes. Retail is down by NZD 18 million. This is a price cost recovery issue here, where you've got increases in network costs coming through here. We've got that arm's length transfer price that goes into the retail business, reflecting the higher wholesale market costs, but the tariff increases aren't increasing enough to offset that cost inflation, and then you've got corporate costs, which are up by NZD 6 million. We'll talk about that when we get into the OpEx section, but there's some one-timers and inflation there, so onto the wholesale business. Generation costs are up by NZD 186 million as we've sold more volume. When you look at most of that extra sales has been backed by thermal generation and risk management, and those two components of our costs are up by NZD 174 million. This is where the actual impact of Tauhara being late is felt, because had Tauhara generated in the second half of FY 2024 as we'd expected, we would have had 0.6 TWh more geothermal generation, and our fuel bill would have been 40% or NZD 70 million lower than what we reported, but that being said, as market channels differently 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 usually 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, we can say it's been relatively easy. There's only been three 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. They've got the benefit of that extra 5,000 tons per day of fluid consent we got with the new Wairakei consent there. So that was good. That stepped up our volumes by 50 GWh per year to 3.3 TWh. We've got a bit of extra volume with Tauhara coming on in the year, 127 GWh, and then it dialed back slightly because we had a planned outage at Poihipi. Thermal's 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 have signed off the extra 2500 hours. Our internal engineers have signed off a further 2500 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 the 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 lake 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 contracted revenue was up by NZD 235 million, and that reflects a terawatt hour increased volume. The biggest component there was in CFDs, which is actually in line with what we guided to, at the beginning of the year, when we pre-sold that, Tauhara volumes. With the step up in market pricing, we ran more thermal generation to support the market. Overall channel pricing, NZD 146, up NZD 14 on the previous year. C&I, volumes and pricing were up marginally, slightly less than we'd 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 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 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 the ending of 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 NZD 35 million to NZD 3 million. That's what I mentioned earlier, that's linked to Te Rapa, too. Incidentally, you know, 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 NZD 66 million. With wholesale pricing going back above the marginal cost of thermal generation, we saw merchant length increase by NZD 83 million. With the higher market pricings, location losses increased naturally, 17 million dollars. Not as much as you'd expect they should increase, though, and that's because we saw our percentage location loss reduce with South Island pricing, relatively high because of the dry conditions that we saw. In terms of the retail business, its EBITDA dropped by NZD 18 million dollars to a loss of 32 million dollars. This reflects the long-term nature of this channel, and that pricing is generally increasing by about 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, but that's why it's good we've got more customers on these time of use tariffs now. It gives them the option to shift 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 are on those time of use tariffs, which is fantastic. Gas margins were up from NZD 9 million to NZD 17 million, and that actually reflects a netback of NZD 20/ GJ, which is comparable to the value that we can make running that gas through a peaker. Big issue for us, obviously, we don't have no upstream gas position, so 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 per year to supply our retail customers. Broadband's 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 underrecovery of local fiber company costs, which went up in the prior corresponding period. When you actually look at the performance across the two periods, connections are up by 42% and margins are up by a similar percentage, which is good. Our industry-leading cost to serve continues to be very well controlled. On a per-connection basis, it's up just 2.5% to NZD 123. In absolute terms, it's up by NZD 5 million. That represents wage inflation of 5%, but also NZD 2 million of advertising and spend linked to the launch of our mobile product. product. That segues neatly onto Contact's operating costs, or OpEx. It's up 8.5%, or NZD 20 million for the year. That's NZD 4 million lower than we were expecting, because obviously, with the delay of Tauhara, we didn't incur some of the operating costs to support 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 NZD 2 million increase in costs linked to one-time movements between the two years, and that's because we've got NZD 5 million of one-timers this year. That relates to a restructuring within our Simply Energy business, which will deliver NZD 2 million of sustainable OpEx savings from FY 2025 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 Contact 26 strategy, and so there's some costs regarding support for that, too. We continue to see the impacts of inflation coming through. That's increased our OpEx by NZD 11 million, although we are starting to see that sort of come off, so we shouldn't see those levels of increases in FY 2025. Headwinds are NZD 4 million. We've got NZD 1 million of increased bad debts, which won't surprise anyone based on the economic situation. Just to put that into context, so Contact's overall bad debts are just NZD 3 million on NZD 3 billion of sales, so they are being very well controlled. The rest of the headwinds are NZD 3 million in relation to ICT and our S/4HANA project. Unfortunately, the CRM system stays on the old version of SAP, so we're still paying two lots of license fees now and two lots of cloud storage. So while 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 NZD 5 million of savings, so we have NZD 3 million with Te Rapa shutting, and then you've got the usual NZD 2 million of fixed cost leverage that we get as our retail connections grow. And then we've got this NZD 8 million, what I call growth OpEx, again, aligned to what we'd signaled at the beginning of the year. NZD 3 million linked to the retail business with the launch of the mobile offering that I talked about. NZD 1 million of higher rates at Tauhara. Even though the plant was barely on in FY 2024, Taupō District Council don't miss an opportunity to increase their revenues, and then we've got NZD 4 million of right-sizing 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. Our reporting is getting more complex there, but again, as I said at the beginning of FY 2024, this is the last year of big OpEx increases for us. FY 2025 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 NZD 470 million, which is 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 two 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 it 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 2025 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 just lets you know where that's going and that the spend is aligned to what we told the market. Then in terms of our balance sheet, we continue to see high levels of debt as we continue to build out our development pipeline. Very pleased we entered the Australian bond market during FY 2024. Gives us another option in terms of debt as we as our balance sheet grows. Floating rates for us are up by 152 basis points, but you only see our average interest rate going up by 30 basis points, and that's because of some great work the treasury team have done. They took out fixed interest rate hedging in a lower interest environment in a nticipation of our debt levels going up as we built 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 above 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. Onto dividend. Very exciting for me. First time in my Contact career that I've ever been able to announce an increase in our dividend. It's up by 6% for the full year, for NZD 0.37 a share, and that's got the final dividend going up by NZD 0.02 from NZD 0.21 to NZD 0.23 per share. The intention is then to increase the interim dividend of FY 2025 by a couple of cents, too, taking FY 2025's full year dividend to NZD 0.39 per share. 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, you know, to support our build program. After FY 2025, 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, this growth, it really is a sustaining business CapEx project and but it 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 as a growth project, but the quid pro quo is there. We think it's the right thing to do to hold dividends while we're building that project, which then comes online in mid-2027. Our expected and normalized EBITDA, so mean hydro, EBITDA for FY 2025 is NZD 770 million there. As I said earlier, that's up by NZD 170 million on our expected normalized for FY 2024. But 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 eight months of Te Huka 3 in there. So we are a little bit sensitive about people writing about profit, and they're not actually talking about the investment that's driving that. So remember, that's a NZD 1.2 billion investment that's enabled us to get that NZD 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 talked about earlier being offset by pricing being a bit higher. The other question that we're being asked a lot is this is, this is mean hydro for FY 2025, 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 GW 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 Whirinaki. So that displacing that water is costing us about NZD 90 million. But going into the year, we had about 500 GW 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 electricity 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 is 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 in 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 transition through demand flex, and we're delighted with the outcome of that negotiation. If we look at the next slide, the risk of being boring, this is the same slide we've put up for the last three 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 Te Mihi 2 and 3, and with Tauhara Stage 2, which will lead us eventually, by 2031, 2035, to about 6.3 TWh of geothermal. In addition to that, we haven't been idle in developing other technologies. Already with the Kowhai Park announcement of 0.3 TWh, we have a total pipeline of 2 TWh in solar and 4 TWh in wind, with a focus very much on the near term, getting those resource consents in place. Kowhai Park had a resource consent. We're now awaiting fast-track resource consent for Glorit and for Southland Wind. We raised a bit of a storm earlier in the year, not a storm, but a bit of curiosity around our approach to Wairakei. 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 Wairakei with the Geo Future projects, where we planned 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 2 in S tage 2 and Stage 3, each 100 MW, with a clear choice of technology around binary plants. What enabled that was the realization that we could, through very powerful asset management techniques, extend the life of the Wairakei Power Station through to the resource consent period of 2031. And it is a note that we did get ISO 55000 in this last financial year in terms of proving out that asset management capability. Te Mihi Stage 2, we expect to come to FID before the end of the calendar year. The capital we expect to be between NZD 600 million and NZD 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 the capital is deployed as efficiently as possible. We expect it to be a 100 MW binary plant with an uptime of around 80%-95%, producing about 0.8 TWh per annum. Wairakei, we expect to keep the B station in particular, up and running, with a little addition, a little bit of additional capital of around NZD 25 million-NZD 35 million, with a focus on keeping the 30 MW of steam turbines available and 7 MW 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 delightful for a plant that was built in the late 50s. We take the next one, and this is also to clear up any misunderstandings. Our average output from the Wairakei field, prior to today, was about 2.7 TWh a year. On average, with the new resource consent, we expect that to rise by 0.1 TWh over the following five 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 TWh per annum, and that, at that stage, will represent the Wairakei field effectively sorted out for the next 60 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 Taupō region these last four years. We believe it better fits the capability and capacity in our balance sheet, which in turn allows us to pursue other technologies at the same time. In all this, 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 of course, we always advocate 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 a possibility of LNG import, but there is also the need, perhaps, for continued reliance on coal in our thermal generation. We do expect more intermittent renewables to come online, which means that the high-cost gas baseload generation won't necessarily align to what the market needs. It'll be probably a shift towards gas peaking, and we do expect thermal power stations like base load, TCC, to continue to close. What that means for a thermal plant that remains, they will have to recover their higher fixed costs back in much shorter periods, which may contribute, we expect, to that higher volatility going forward, and you will see these spikes in prices as 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 behave 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 our part cost, cost-effective way possible. Apologies. 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 the, well, the cost of solar and the cost of wind coming down, but that ignores the cost of firming. And it's not just a statistical firming. 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 just firm the electricity, but firm the electricity, 24 by 7, 365 days a year, and there will be a cost in that, and we need to recognize that cost. We do see the winter-summer spread increasing as intermittents 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 of widening. And that in itself both presents a challenge and an opportunity for us as we seek summer demand load. And we do see a value shift in the market towards flexibility, which is why investments in the likes of the battery and the reconsenting of our hydro and investments in baseload 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, when the sun is 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 the FID for Te Mihi Stage Two. We will deliver Te Huka 3 online. You will 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 multi-product connections grow to 148,000 connections, while maintaining the best in market cost to serve at NZD 123. Electricity prices will rise in the order of 2%-3%, and we will scale up our Hot Water Sorter. Note that electricity price rise excludes the potential price rises coming through from network and transmission charges. On that, with the outlook and very much the company busy, but optimistic on the back of a very strong result, I'm going to take your questions. Thanks, Mike. So we'll go to questions now. We'll start with. Okay, so going to Grant [audio distortion], unmute yourself. Contact, can you hear me? Yes, we can, Grant. Hi there. Thank you. I'll just run through a few quickly. What's causing Wairakei to cut back from 1.1 TWh to 800 GWh by 2026? What have you uncovered that's failing on that front? My second question, you indicated Te Huka in for about eight months in your guided FY 2025 numbers. When does that? Do you also have that four-week trial, and will that start in November, according to eight months expectation? Third question, the Tauhara rattle that you're sorting out, I see Tauhara is jumping between 130 MW and 153 MW 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 talk about securing short-term gas, or is 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 would it cost 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. Thank you. Oh, okay. Right. Unpacking those one by one. Now, the geothermal volume from Wairakei are driven by outages, so we have a significant outage on Te Mihi, which is on the Wairakei field in the FY 2025, as we do the tie-in, as we are not only replace or renew the steam path on the existing generation, but also due to tie-ins. And in FY 2026, we obviously had the major Wairakei shutdown, and that's the combination of those is what takes the volume. That's not any 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. Te Huka 3? Te Huka 3. You've got eight months that are included. Eight months I've included. So we expect, on a P50 basis, to start the reliability run mid to late October, which will be 30 days, and that would then be concluding towards the end of November, early December. And so we expect to have those 30 days production, which sort of gets you to your eight months of production. You should be running at full capacity, Grant, on a reliability run, so that gives you your eight months. 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 113 MW-115 MW. 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. What you've seen over the last week is us taking the plant up to about a 2.5 mm vibration level, which is well within the bounds of not risking fatigue failure. What we're doing is running the plant during the day at the 152, where you get about. You're up at the, sort of, the 2.5 mil-3 mil limit, and then just taking it down at night, where there is not the real need to fatigue it so much. What we expect, we can expect to continue in that for about another two months, Grant, in that mode, between the 140 to the 152 mark, and then after that, we should have some new foundations and structural supports around that IP vessel and a reconfigured inlet piping, which will mitigate and allow us to go to probably the 152 on a very consistent basis. What you'll see by that, because we have these very high accuracy 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 MW. 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 engineering solutions, they never come in a linear way. And on Pa ge 49, Grant, that does include the Methanex gas. And 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 2,000 operating hours, so we're 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. We obviously get questions about, well, can you continue to run TCC into 2025? I mean, there's the engineering question around running the asset, but the bigger question is actually around there's no natural gas to run it. That's the primary issue around constraints of fuel. Thanks. Can I just follow up on the first question on Wairakei? If there's no issues with it, why didn't you consent to more than 37 MW through to 2031? Oh, no, we've got full consent. What the consent is for the offtake of 250,000 tons 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. Thanks. We'll move to questions from in the room. Andrew, over to you. Thanks. 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 a volatile situation on wholesale prices and hydro situation. You're able to give us a sense, I guess, of the possible range of outcomes we're sitting at at the moment? I mean, the way you describe things sound like you're gonna be... It's relatively narrow, but... Look, I think we are, we're in a probably a better position than most because of the multiple options that we have around risk mitigations, with the fact that we've got, you know, stored gas. We've got these demand response solutions, which are directly impacting us, you know, with the Tiwai deal, and Methanex, we've got Whirinaki. So, I guess what I'd say is that we, if it gets, if it stays dry for longer and you have higher prices, then we may be able to eke out some fuel running Whirinaki for longer. You can run on that at about, you know, 1.5 GWh a day if you need to. So, we're in a pretty good position in that, or 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 NZD 7.70. And like I say, the other topic here is we might be happy to forgo profit this year to actually store fuel because I think we're gonna be looking at probably a relatively tight winter 2025, so that might be the right thing to do as well. So, you know, we'll do the right thing. So, I mean, at the moment, I'd say we're pretty good for the NZD 7.70, and, you know, our range around that will be tighter than others, I'd suggest. Okay. Thank you. Next question I just had was, I guess, looking at the development pipeline, and in particular, I guess, Tauhara Stage 2. Are Are you able to give us any indication of timing around that? Oh, look, I think the issue around Tauhara Stage 2 is that it 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 Ohaaki. And so we can retain that skill set in the Taupō region, designing and building those plants, just cookie cutter style, and just getting more and more productive and more and more efficient as they do it. Is that a slight change in thinking? Because I think previously, sort of some hints that you might be able to do it back end of this decade as opposed to after. We'd have a look at that as we come out of Te Mihi Stage 2. What we can do, we might swap them around, for instance. You wanna see how the reservoir responds to Tauhara. Yeah. That's what we've always thought. We wanna collect data on that because that will then help us make the right, you know, sustainable decisions around Tauhara Stage 2, which will, you know, provide the most effective management of the long-term reservoir and maximize, you know, returns on it. So that's it is a little bit dynamic around that because you're getting more data all the time, you know, the longer Tauhara operates. Yeah. Yeah. Okay, and I assume it's reasonable to assume the capacity to develop more faster is you, 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 certainly are 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 attention to the balance sheet, so we are refreshing and ensuring the balance sheet and that EBITDAF, that net debt to EBITDAF, we will say well under three. And I think that's important in the go forward as well. The next question I just had was around the Southland consent timing and how much that's been pushed back, because I think there was an indication that the We've taken 20 -day pause just while we engage in discussions with the Southern Rūnaka 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? Oh, we see that as a medium-term option that will probably take. Won't be there in six months to a year. It might be there in two 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 2025 CapEx of NZD 340 million, but you're guiding to NZD 450 million-NZD 550 million for growth CapEx. I assume the difference is to meet each Stage 2, is yet to be approved, and so that, that's the CapEx coming in in the second half of the year, or is there some other? NZD 475 million in the last. Yeah. NZD 450 million for the following year. This is for next year as well. The next one. It's 4:50. Yeah, and the difference is to me- Yeah. Normally that. Yep. Okay. Okay. Thank you. 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 the Te Mihi Stage 2 CapEx costs are around 6.5 million a megawatt. Is this an improvement on the previously notified 7+ million? 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 done 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 to a full front-end design so that when they come out with a cost estimate, it is robust and benchmarked, particularly in terms of a project development readiness, and that's what we call a PDRI, which is in line with international practice. So is it an improvement? It is in line with the NZD 7 million, because that NZD 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 was whether anything has changed or impact happened around Ormat's appetite for New Zealand, new New Zealand projects? No, not at all. If anything, they have engaged very positively and very collaboratively with us. One from Cameron Parker at Craigs. Based on your long-run view of wholesale prices, where do you see long-dated CNI prices settling? Probably a few percent above, you know, based on the fact that you normally get a margin just above the long-term price to reflect the cost to serve and credit risk and all the other stuff in there, so a few percent above. Okay. One more from 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've said. I think we've said in the past, we see about 400 MW-600 MW of battery being installed, which is probably about the right size. You've seen two batteries of significance being committed to, so there's still a way to go. Is there a risk of overbuild? Always. The only caveat I'd put on that is we're yet to see whether batteries can, with being very increased volatility, which I don't think anyone's anticipated, but we now see in the market today. It also depends on how successful we are with demand response, you know, at a retail level as well, because that's a virtual battery. Origin talk about virtual batteries, that's exactly what they're doing over in Australia. That's incredibly efficient because there's no capital investment required around that, and that obviously socializes the benefits for consumers 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 three EBITDA gates, 740, 770, 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 that was allowing for is if there were potential issues with commissioning of plant 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. You know, with the challenges around the IP separation plant 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 three years in a row due to the impact of Tauhara, which, while it's very important, it, it's also a relatively small group of the company and the corporate scorecard to be impacted three years in a row by it. So I think there's an element of, providing a bit more sort of pragmatism around these are big investments and getting them online and 35-year cash flows and things like that. There'd be that type of lens that's being put on it as well. I would certainly wouldn't read anything into it around that means that we, are expecting not to get eight months worth of, Tauhara into our numbers in FY 2025. Well read, Stephen. Yeah. So we're moving to two questions now from Vignesh at UBS. The first is on the 770 million EBITDAF guidance into FY 2025. On Slide 40, the assumptions talks to gas price of NZD 8.20 per gigajoule. Is that still appropriate? How does the Methanex gas cost flow through, and has the implied generation from the Methanex gas purchases been sold forward? Yeah, the Methanex isn't included in this guidance, so that's what I was talking about. This was the guidance. Remember, we actually released this about six weeks ago, I think, in a NZX announcement, but as I've said, we still expect to be kept whole, because while our fuel costs will probably be about NZD 90 million higher than what's in this guidance, such as, you know, the more expensive Methanex gas, you know, such as what we're paying on the demand response on TY, we expect that to be offset by the fact that we can contract our uncontracted volume at a higher price offsetting that, so no, going forward, we don't expect gas to be anything like NZD 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 too much 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? Could be, Vignesh, there's a role for you, in governance. That's a very, very good question, Mike. So we've obviously spent the last four 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 widened in their skill set, 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 in Lightsource BP, in Roaring Forties, in Western Energy, in sort of subsurface geothermal, in 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 well in advance of good 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 in maintaining its market-leading position, all of that, I'm absolutely delighted with. 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 four years. I 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 and the placement, about making sure we're right-sized but 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. With that, there's no more questions, so we will draw this to a close. Thanks, everybody, for joining. Thank you. Thank you.