Morning. Welcome to Contact Energy's interim results presentation for FY 2023. We're joined today by Mike Fuge, our CEO, and Dorian Devers, our CFO. Over to you, Mike. Yeah, kia ora koutou. Welcome everyone. Good to have you on. Just before we start, a big shout out to obviously those in the north at the moment, who it's gonna probably be a pretty tough 24 hours. Look, let's get right into it. The usual disclaimer, just noting that, moving into it. I'll cover the highlights and give you a bit of an update on the market, where we see it at. Dorian will take you through the details of the financial results and what we see as the outlook and supporting materials are there in the appendices, which hopefully give you an abundance of information if you have any questions. We'll give an opportunity to questions at the end. Mm-hmm. Happy to take those. Look, the performance, underlying EBITDAF and actual EBITDAF, underlying, has itself dropped, given the hydrological conditions. Very strong hydrology in the North Island, obviously, weaker hydrology in the South Island, where we got less inflows. Obviously, as a result, lower thermal generation getting linked into the market. Behind that also, thermal generation costs remain very high. Our ability to dispatch into the market over that period was very limited. The other thing, obviously, there is the declaration of onerous contract on Ahuroa, which we'll speak to more later. That's around getting the portfolio in shape, and the go forward. Quite simply, given the shift in the portfolio that we see less value from that facility than what we're potentially gonna pay for it over the coming years. Dividends and operating free cash flow. Dividend remains as per the formula which I keep presenting to you all and is robust in that regard. Look, how are we responding? The focus is very much on, if anything, this result just bears weight to the rebalancing of the portfolio through new renewable generation. Continuing that, the focus clear and deep focus on delivery and the go forward of that absolutely critical. Recognizing that NZD 120 million onerous contract as part of that getting ready for the future. The strategy remains the same, growing demand, growing our renewable development pipeline, which we'll give you a bit of an overview of today, decarbonizing our portfolio and creating outstanding customer experiences. You'll see all those today underpinned by ESG. You'll have seen our entry into the DJSI late last year. Operational excellence and transform ways of working. Just on a key part of that, we do see improving demand outlook for electricity. I know commentators are commenting on the fact that it remains flat. You remember that's masking the fairly significant exits of both Northcote and New Zealand Refinery. In the meantime, you have seen some large scale data center announcements from Microsoft and Amazon. Industrial process heat conversion, we continue to work with C&I New Zealand. We do see with industrial users, the likes of New Zealand Steel, working with them on interruptibility and the likes. Road transport, EVs appear to be going gangbusters on the basis back of the government's announcement. We do see opportunity also for green chemicals, particularly both, domestic hydrogen, but also, using CO2 from our geothermal plants to provide a more sustainable solution for New Zealand. Otherwise we are facing flat there. We are working with BOC Linde about how we can do something in that space. The big elephant in the room on demand is of course the smelter, and I just wanna give a bit of our perspective on that. Look, we have really tested other uses for our electricity in the south, such as hydrogen export, process heat conversions, data centers. What it is telling us is aluminum is the highest value user, so we're comfortable that any new deal with NZAS will comfortably pass any EA test. It's good to have the alternatives. The work has been worthwhile as a backstop. Who knows, with the extensive renewable development we have available to us in this country, they may come to pass. Look, from our engagement for Rio, they appear ready to do a long-term deal at a reasonable price. Importantly, they've made clear their commitment to New Zealand, to Southland Murihiku, and to broader stakeholders, as well as the commitment to global decarbonization. In that regard, the carbon efficiency of the smelter at 2 tons of CO2 per ton of aluminum versus 16 global average, there is also a moral imperative to get this right. We're in for our existing base load of volume of 100 megawatts, which aligns with our generation market share. We don't need to do any more as the South Island transmission upgrade is in place. From our perspective, it would be good if the deal gets done as soon as possible, so we can all get off the transitional pricing we're on and move on. It is in the interests of us, the country, and the broader market that we all move. The other big highlight of the last six months, aside from the DJSI entry, is the re-consenting of Wairakei. I just want to spend a few minutes on that. 35 years, this will enable us to proceed with our plans for the replacement of Wairakei A and B, legacy power stations. It's a commitment that increases the offtake we can. The planned redevelopment of it, to me, he will use the steam more efficiently. There will be an increase in output in the order of 0.4 terawatt hours per annum, and it has reinvigorated our partnership with local hapū and iwi, which we're delighted with. On a whole range of things, this is a good, if not great project. It enables us to get off the Waikato River and to stop our discharge into the river. It enables the further development of the 60-year-old Wairakei field, which will further reduce carbon emissions for the nation. It's a good use of the resource for us as Contact. It's a great project, and we're looking forward to advancing it such that we're ready. It's up and running second half 2026. The other piece of news is that over the last 18 months, we have been working hard on broadening the development pipeline, which now totals some 6 terawatt-hours of real projects. You obviously are aware of the 1.4 we have in progress with Tauhara, the 0.4 that we have in progress at Te Huka 3, and signaling that there's another 0.4 with the redevelopment of Wairakei. Beyond that, you'll have saw the announcement last week of the 150 MW solar partnership with Christchurch Airport and Lightsource bp. We're excited by the progress the wind team have made at the same time. We actually see a development pipeline that it's broadened its scope to up to 6 terawatt-hours over the next decade. Also within there, you'll see Roxburgh, which also signals we're looking hard at our existing operations and how we can get more out of them through improved efficiency. All in all, with the combination of geothermal, what we already have, plus solar, plus wind, we're excited about the road ahead and our ability to build in to the demand growth that we have talked about earlier. Demand I talked about a little bit before, it looks flat, but it's actually masking some moves that I've already talked about with refinery and Northcote. We did see higher irrigation demand with the very dry November, December and indeed January. We actually saw the smelter increase its load. Our assessment, as I said, is that there is an underlying trend for growth. Hydrology, quite frankly, it's not our half year. The rain as we've seen, and we see again as we speak today, has been very much focused on the upper North Island. That's the way it lands. The portfolio remains robust. What it does mean is it limits the need for thermal generation. You'll have noted already that November and December as a nation, we were up well over 97% renewable, which is a great outcome. Wholesale risks, they do remain elevated. What you're seeing is that despite the recent drop off, that coal remains at an elevated price, particularly with the carbon price sitting steady at around NZD 75-80. We do see continued challenges in the supply of gas in the upstream. That just means we have to work harder. Methanol and aluminum both remain very healthy. The hydrology in the short term looks promising. In the medium to long term, we always have to work hard to make sure the market is covered. In that regard, the ASX futures appears to reflect the reality of what we face both in the short term, but over the long term as well. Retail, intense competition. We have continued to grow our connections. You see there over the last two years, in particular, the bundle that we offer with broadband has continued to give us momentum. You'll see underneath of the second part of that, the increasing electricity tariff. The important thing there is that it's steady. We have shielded consumers from the rock and roll of the wholesale market with below inflation increases. It's important that we continue just steady as she goes to make sure that we get the balance right between shielding consumers, but also making sure they are aware of the increasing cost of energy globally. Yeah, happy to take questions on that later, but the retail business, all considered, remains in good shape. On climate change and regulation. Look, there is a consensus in this country to deliver net zero by 2050. There is consensus on the Climate Change Commission and the emission reduction budgets. There is consensus on the ETS. The thing I would say is that as opposed to other energy markets globally, the New Zealand market is performing remarkably well on balancing that trilemma of balancing cost versus scarcity, versus actually getting on and reducing emissions. If you look at the investment program and the go forward, you can see the progress in emission reductions in the sector. You can see even in what I'm describing today, the concern about consumers, that they do not experience price shocks at the same time. You can see the overarching anxiety to ensure that our electricity supply remains viable, stable and secure. We will continue to balance that. You'll have seen there in this graph, the developments where there have been announcements on net zero carbon emissions by 2050, transport policies, government procurement has altered what we do about TY. You can see also very active engagement on other projects, which I'm happy to take questions on later. The thing I will call out is the fact that on resource consenting as an industry, we did approach government on the trap we found ourselves in with wind farms taking up to seven years, if not a decade, to consent. The government responded on that in the RM reform program. We are grateful that this unity of purpose that we have as a nation is resulting in fundamental change. People rethinking the way we think about how we respond to climate change. You can see that in the RM reform, which we're very grateful for. Other regulatory matters, wholesale market, security. We are reasonably comfortable on that. We've obviously... this winter there's been some noise in market. As an industry, we have respond. We continue to engage constructively with the EA, we fundamentally remain of the view that the market is working well and the market where there are issues of scarcity will respond. For our own space, we've been leading on demand response. For instance, you think of a demand-side-led solution. I think the industry is also responding well. On the New Zealand Battery Project, we've made our views clear. We were part of the Boston Consulting Group. Our big ask in this space is that people are honest and transparent about the costs of significant investment like what is being proposed potentially at Lake Onslow. We don't believe, given the experience overseas, particularly on the Snowy scheme, that it will be anything less than NZD 10 billion-NZD 12 billion, if not more. In that context, we ask people to exercise good professional judgment on whether it is the right thing for the market. On that note, Dorian. Thanks, Mike. Hello, everyone. I just wanted to start, as usual, just by highlighting some of the key themes that are gonna come out as we go through the rest of the pack. You know, Mike's mentioned that NZD 120 million onerous contract provision that we've made, that links to our contract with First Gas for gas storage. The reason why we've made that is because what we have forecast to pay for that storage, between now and the contract finishing in September 2033, is more than the forecasted value that we're gonna get for it. There's a couple of things that have driven that. You know, our decarbonization of our own portfolio is happening at a pace quicker than would have been envisaged when that original contract was originally struck, a number of years ago. You've seen the announcement around the closure of Te Rapa in June, we expect TCC to exit the portfolio at the end of 2024. If you've got less thermal in your portfolio, you don't need as much gas storage. Secondly, we put that announcement out on the NZX just before Christmas. You know, the storage facility itself has just got less capacity than everyone expected as well. Those are the two drivers. It is a non-cash provision. Remember, what we paid for the storage facility is a function of the price that we actually sold it to First Gas for a number of years ago. From an operational perspective, you know, we're comfortable that in most scenarios, you know, we've got enough storage there to support our portfolio. In the extreme scenarios, you know, we're putting mitigations in place around that. Pretty comfortable all round on that. Next topic is, you know, coming into FY 2023, everyone was talking about fuel risk. It was gonna be really dry. La Niña weather patterns. From a Contact's perspective, you know, we had that technical working group looking at AGS, and we were worried about our fuel for that reason, but also, you know, we had deliverability issues we could see with OMV's fields and, you know, there was an indication we were gonna get less gas in 2023 than we got in 2022. That's why we weren't selling into the high prices at the beginning of FY 2023. Everyone got it wrong. We ended up with a deluge of P96 inflows which for people that don't understand terminology, it means there's only 4 times in the last 100 years that we've seen wetter weather in that six-month period. That has a pretty major impact. You can see the impact it had on our financials as prices dropped significantly in particular in Q2. We're still very comfortable with our trading strategy overseas as operate with a lower level of fixed price variable volume sales. The reasons for that is it gives us space to participate on the and sell on the ASX. That's important for us because that allows us to seasonally shape our sales into our future, so they better align with our generation portfolio. That's becoming increasingly important as we bring more baseload geothermal into our portfolio and offset flexible thermal generation, which shuts down. The other topic is we see the cost of risk management going up. Whilst we have seen international coal prices drop a little bit, they are still relatively high. The other topic we've got here is, you know, we believe the Genesis swap option, which expired at the end of 2022, has been shielding the market from those high international coal prices. Remember, that was relatively cheap, 250 MW of swap option that was provided to the market, and it was cheap because the pricing was set in a completely different environment to what we're in at the moment. For those two reasons, we're pretty comfortable with our trading strategy and keeping that level of fixed price variable volume sales lower. It also sort of ties in quite neatly with our future portfolio and where that's going, because when Tauhara and Te Huka three are all online, getting towards the end of calendar year 2024, our mean hydro year generation, renewable generation is gonna be about 9 terawatt-hours. We've only actually sold about 7.6 of that through fixed price variable volume channels, through PPAs that we have or expect to commit to, and then covering our location losses. We've got about 1.4 terawatt-hours that we need to work out the most optimal way to place that into the market. I think you'd agree based on the market that we see in front of us, when you look at the ASX curve, for example, that's a pretty good position to be in. In terms of the fixed price variable volume sales, we are as expected, they are repricing. There is still quite a big gap between those though, and the ASX going out to 2026. Just to put that in perspective, the weighted average price that we sold our electricity for in the first half of the year was only NZD 112 per MWh, which, as you all know, is considerably below the ASX going out to 2026. That does highlight the extent of an opportunity there. The last point, as we were talking about for the call, we're gonna have another capital markets day. Investor Day in May, we're gonna have it in Taupō, because for us, that's where all the action is. Opportunity to take you through Tauhara, which will be nearing completion. Then at the other end of the scale, we can take you through Te Huka 3, which is starting. Good opportunity to take you through how we're deploying our strategy and some of the topics I've just talked about, which are quite important and structural in nature. We can put a bit more color on those as well. On to the financials. We're coming off the prior corresponding period where our profit after tax was NZD 134 million to a loss of NZD 7 million in this period. That's a lot about the ownerist contract provision, though. I will, when I talk about the numbers, I will generally talk about it before the ownerist contract provision because it has nothing to do with the underlying trading of the business in the last six months. Within all of our commentary, we're very clear as to what the numbers look like with and without. The biggest component of the drop in profit before the ownerist contract provision is the EBITDAF, which is down by NZD 76 million. As usual, we've got that chart on the right-hand side of the slide, which explains what's driving that. We can just talk through it quickly. In the prior corresponding period, Contacts had relatively high renewables. Remember, it was very dry in the North Island, so prices were high, and we were able to sell into that and get the financial benefit from that. This year, though, we've seen very strong hydrology across the whole of New Zealand, which has seen prices a lot lower. We've also seen our inflows actually higher, but the problem we've had is the inflows have been very concentrated into short periods, so very high inflows in July, August, and November. The issue is those inflows have often been a lot higher than we have capacity to generate into. Because we're a run-of-river catchment, we're sort of limited in our ability to store those excess inflows so they do get spilled. The other topic is because there was just so much inflows across the whole of the South Island, the HVDC was also a constraint because you couldn't get all that water into the North Island, so that drove spill as well. This sort of manifested itself in our numbers with our renewable generation being down 392 GWh, and that has a fuel replacement cost of NZD 51 million to us. We actually then reduced our sales position down by more than the renewable generation. It came down by 539 GWh. That reflects the fact that with those very low market prices, it wasn't economic for us to run our thermal generation as well. The overall impact of that drop in sales and also the reduced market pricing and how they impact our market channels, the short-term CFTs, the merchant length, was a further NZD 25 million reduction in our EBITDAF. Going the other way, as I said, the fixed price variable volume channels are repricing upwards. There's NZD 33 million of benefit there. Other income is down by NZD 7 million. There's some market making losses within there, which I'll talk about later. Fixed costs are up by a lot. I'm not gonna hide from that. They're up by NZD 24 million. We did have that Holidays Act provision released in the prior corresponding period, which artificially reduced our OpEx by NZD 6 million. We are seeing higher transmission. Remember, there's no ACOT benefit in this period. There was in the prior corresponding period. You've got higher OpEx overall inflation, some strategic investments in OpEx to drive our strategy and things that we'll talk about later. Overall, that gives you the NZD 76 million reduction in our EBITDAF. Other topics that have impacted our net profit, depreciation is lower. Remember, we did accelerate the depreciation in the prior corresponding period for some parts of our SAP system that wouldn't be required in the new S/4HANA system. The interest is flat period on period, even though net debt levels are up by about NZD 300 million, and that's because all that extra debt is driven by our major projects, Tauhara and Te Huka 3, and therefore the interest associated with that gets capitalized against the projects. Tax is down as you'd expect based on the lower profits. Fair values of financial instruments. This is quite a topical area with the IFRIC that got released recently, which all of the technical accountants in the room will understand. I like talking about this topic. Adverse NZD 80 million for us. We had a favorable NZD 10 million position in our prior corresponding year, and then we were adverse about NZD 8 million this period. That relates to some unrealized market making losses, but also the swaption that we've got in place with Meridian, as they have the option to call it. It's not in a hedge relationship for us, and hence we have to put it through the P&L, and the market pricing has moved up since we entered into that arrangement, so it's slightly out of the money. In terms of our performance across our three businesses, the wholesale business is down by NZD 48 million. That reflects the lower pricing, reflects the lower renewables, and reflects higher location losses. We'll talk about that. Retail is down by NZD 16 million of EBITDAF. That's the fact that we have that arm's length transfer price into the retail business, you know, reflecting the higher wholesale market. The fundamental issue here is the tariffs aren't going up quick enough to offset that cost increase. The good news is, and you'll see this when we get to the retail slide, it is sending a signal, and there has been a step up in the level of tariff increases going through that business. The corporate costs are high by NZD 12 million, and this reflects some one-timers and some other cost increases, which again, we'll cover when we go through the audit slide. Onto the wholesale business, generation costs are down by NZD 11 million period on period. This reflects less need for risk management. We had less acquired generation and thermal generation. They were down 147 GWh collectively. That saved us about NZD 22 million in terms of thermal fuel costs and acquired generation costs. Within that, our marginal cost of thermal generation remained flat, NZD 121 a megawatt hour. There's a few offsetting things going on here. The cost of gas actually reduced in the period because the market had excess fuel in it because of the hydro, but we've continued to see higher carbon prices. Naturally, our thermal portfolio, we saw the heat rate move against us from 10.7 to 11.5, and that reflects with the very low prices that we were seeing in the marketplace. We were running Te Rapa in turndown mode because we didn't want it to get merchant length at those low prices. Offsetting the NZD 22 million of lower fuel costs, we've seen fixed costs up from a generation perspective by NZD 11 million. That's that transmission cost increase of NZD 4 million. ACOT, the fact that that's been discontinued is feeding through here. Also, the regulator has signed off a whopping great 13% a year increase in the gas transmission rate, and that will carry on for the next five years. That will be feeding through as well. Luckily, that is largely offset in the period because our generation, gas generation volumes were lower, and we have a variable component within our gas transmission. Just a heads-up that we are expecting gas transmission rates to be higher into the future. On top of the higher gas transmission costs, we've got other operating costs that are up by NZD 7 million. Within that, we've got development costs for our renewable pipeline up by NZD 2 million. This reflects the less mature part of that pipeline where we can't capitalize those costs. We've got NZD 1 million just under that we are paying to staff at Te Rapa. This is a retention payment to ensure that we have a smooth process around the closure of that plant. You've just got higher inflation flowing through here. There's a lot of people in this part of our business, and on average, salary costs are up by 5%. Because those development costs, by the way, have got nothing to do with the day-to-day running of our renewable and thermal plants, we have started to split them out on the slide for you. I should also just talk about our renewable costs, which are up by NZD 6 million, 'cause normally those costs are relatively flat. What's happening here, the cost of carbon is gone up, which obviously impacts the geothermal business. You've also got one of our geothermal plants, Te Huka, was getting benefits from the ACOT in the prior corresponding period. There's a couple of million dollars there, and again, just salary inflation feeding through here. In terms of the overall performance of our assets, we got one of our new transformers installed at the end of August down in Clyde, which was great. The issue though we had is that meant we were down a unit for most of August and all of July when inflows were relatively high and a unit is worth 108 megawatts for us, say, down there. That's, that would've contributed to some spill. We've got the second unit is being installed as we speak, but we expect to get that back into action in May, so before winter, which is important. In terms of geothermal volumes were below average generation volumes, and that reflects that we had that five-year statutory outage at Wairakei. It also reflects that we've been able to build some more flexibility into our geothermal operations, and with the prices being so low in the first half of the year, we were able to conserve some fuel, which we'll get the benefit from in the second half of the year. The other big topic here is the news that Mike mentioned, you know, getting the reconsent of our fluid take on Wairakei for the next 35 years, is very, very important. The team have done an amazing job and also got an extra 5,000 tons a day of fluid out of that, which just goes to show how strong the relationship is, and the confidence that the various stakeholders have in our ability to operate that reservoir up there. That 5,000 tons per day is worth about 20 GWh of increased geothermal generation, and that kicked in from January. Thermal assets were all working after a bit of a torrid time, let's face it, in FY 2022. They were all up and running and working. They weren't needed a great deal with all of the water we had. That's always the way. We are taking TCC down for its annual outage in February, and that we'll repair the radix through that process. We're actually hoping to build in some more flexibility, which means when it comes back, we'll be able to turn it down to 100 MW overnight. Currently, it only goes down to 160 MW. In terms of our wholesale contracted revenue, that was down by NZD 47 million. This is all about the fact, as I said earlier, we had lots of renewable generation in the prior corresponding period when prices were high because of the dry North Island effects, and therefore we sold a lot of high-priced short-term CFDs. For all the reasons I already outlined, that didn't happen this period, so the revenue that we got from short-term CFDs has dropped down by NZD 114 million. Has been offset partly by NZD 74 million of increased revenue across C&I and sales into our retail business. Great to see the C&I business repricing quite significantly with the net price there up by NZD 38 a megawatt hour. Whilst the increased pricing to the retail business, as I said earlier, is just a sort of left pocket, right pocket thing, it is sending the right signal into that business to look at tariffs. Unfortunately, we saw a NZD 12 million adverse movement in our other operating income, and this is all about the market making that I mentioned earlier. The problem you've got is when you're a maker of a market, you're taking all the positions other people don't want. When the market is both high priced and volatile, it does have adverse consequences, which is what we can see here. I'm gonna be very interested to, you know, when I look at the other generators and how they're going with this as well within the results. I think the problem is it's always difficult to get an underlying view of market making because people do move market making positions into the portfolio. In terms of our wholesale trading and merchant revenue, there was a loss of NZD 17 million here, which is an adverse movement on the price corresponding period of NZD 12 million. We aim for this to be zero. We aim that the money that we make from merchant length to offset the location loss, or some people call it LWEB, GWEB loss. The reason we do that is because there's a natural hedge between them. As wholesale prices go up, your merchant length goes up, and your location loss goes up, and the vice versa happens when wholesale prices go down. The reason why they didn't offset in this period is because the spread of the location losses increased quite significantly. We normally expect it to be about 6%. It went out to 13%, and that's because of the disconnect between pricing between the North and the South Island because of all of the water in the South Island, and it couldn't get across the HVDC. In terms of the retail business, as I said earlier, the EBITDA has dropped from NZD 16 million down to NZD 1 million. This reflects that, you know, Contact and the rest of the market, to be honest, has been slow to pass on those cost increases to consumers. At the full year FY22 results, I did talk about this market's net back is now relatively low, and it would need to improve for it to continue to be an attractive market for us to sell electricity through. I guess for that reason, we're not overly concerned at the moment that we've seen our electricity connections drop by about 2% since our full year results of about 10,000. The good news is, though, we are seeing the repricing. Tariffs are up by NZD 10 a megawatt hour, which is about 4%. From what I know of tariff increases that we've already put through, when we look at this for the full year, we'd expect about a 6% tariff increase on average. You know, we do recognize this is a long-term channel. We don't do knee-jerk decisions around this. We keep pricing changing at or around the level of CPI. You know, we do recognize that any increase in price is obviously difficult for people in the current environment. We do run this business as an arm's length business because it's competing with independent retailers, and so it's important that we do look to recover costs and keep the business profitable. Gas transmission and gas costs have gone up significantly over the last few years. We don't have any position in those, either upstream or own any gas infrastructure. Any costs that we see increases there, we have to pass through to consumers, and that's led us to a 20% increase in our gas tariff in order to maintain gas margins. What we're actually seeing is we expect gas tariffs to actually outpace electricity tariffs going forward because of the exposure to carbon, but also those gas transmission increases that I talked about, and the fact that you're gonna see gas generation shutting down, which means the gas transmission is gonna be recovered over a smaller and smaller amount of volume, leading to even bigger increases in gas tariffs. We're actually trying to encourage customers as much as possible to get off gas onto electricity to avoid all of those cost increases into the future. In terms of our broadband, the margin there has remained flat even though our connections went up by 30%. This reflects the fact that we've been in growth mode. We haven't been changing our broadband tariff. That's been fine when inflation has been relatively low, but it's started to kick up, and the biggest cost that we have is the local fiber companies. For example, in 2021, the cost increase was 1%. That's now gone up to 4% in 2022. We can't absorb that, and we have to pass it through. Unfortunately, with that timing difference that we've seen in these financials, which will be sorted out going forward, has meant that the additional margin we got on those extra connections has been offset by the underrecovery of cost inflation. In terms of our cost to serve per connection, that continues to go down, which is great as we leverage our fixed costs with the 20,000 extra connections that we have seen. OpEx, as I said, I'm not not hiding for this one. It's up by NZD 20 million. There is NZD 9 million of adverse one-timers in there, NZD 6 million of that relates to the prior corresponding period topics being artificially low due to that Holidays Act provision. We've got NZD 3 million of one-time costs in this period as well. We've got that retention payment to the staff at Trust, which is about NZD 1 million. We've got the costs associated with that industry report by the Boston Consulting Group. We've also spent some money transforming the way in which we prioritize and execute on projects. We've had some consultants in helping us out with that. We'll see the benefits of that 'cause we have an incredibly ambitious five-year plan, and making sure that we have the right resource and the right process around prioritizing and executing those initiatives is very important. From an underlying perspective, we've seen inflation tick up significantly. Got staff inflation there with wages at 5%. Insurance has gone up by 6% for us, and we all know that CPI, which feeds through here as well, is tracking above 7% at the moment. We talk about headwinds, but that's actually all travel. That's our travel costs are up by NZD 1 million. We know airfares have gone up significantly, but actually the level of activity around travel has gone up as everyone gets out of COVID lockdowns and is looking to reconnect. To be honest, I think we will rein that in a little bit and bring the travel expense back a bit going forward. We've got some growth and sustainability. This is, you know, the money that we're investing to mature that 6 terawatt hours of renewable development pipeline that Mike talked about. This is the money that we are spending to cover that 20,000 extra retail connections. We're also investing in sustainability topics. This is things like our new Growing Your Future policy, which a market-leading policy. We're investing in things like training. We're investing in safety leadership and also improving compliance, which we have no compliance issues, but it helps us tell our ESG story a lot better going forward. Those types of investments are the things that actually helped us gain entry into the Dow Jones Sustainability Index, which is obviously very important. On this, you know, we've got an ambitious strategy. We just need to make sure we're resourcing it appropriately to put us in the best position to deliver it at pace and effectively. The delivery of our strategy, which is decarbonizing New Zealand, obviously touches lots and lots of stakeholders, so it's important we do that. Also, we have to be mindful of the well-being of our employees, and therefore, making sure that strategy is properly resourced is key. Just a few examples of some of the value topics that we've got from, like, these investments. That fast decision on Tukituki Three fit was a result of having the right resource in the right place. That we've now operationalized carbon capture and reinjection on Tukituki. That's 10,000 tons of carbon that's now coming out of the atmosphere and being reinjected again. That's about NZD 1 million of saving at the current carbon price. From a standing start, we've created what we think is actually quite an impressive solar and wind pipeline, picking the right partners as we do that in Roaring40s and Lightsource bp. That consenting at Wyraki, incredibly important for the next 35 years to underwrite Solgria future investment and getting that extra 5,000 tons per day is a brilliant outcome. That's what we're getting in terms of that extra resource that we're putting into the business. In terms of our cash flow, at operating free cash flow, NZD 60 million. That's a relatively low conversion of EBITDAF into cash for us of 24%, there's a very good reason for that. It was very wet. We didn't really run our thermal assets and our commitments around natural gas and carbon purchases were put in place a number of years ago. What that means is you can see the trade working capital has gone up by NZD 43 million because we've acquired NZD 27 million more carbon in the period than our liability went up by. Equally, we've seen that the amount of gas that we've got stored in AGS has gone up by 2 PJs, which is NZD 60 million. We'll get that back in the second half of the year as that trade working capital unwinds because we'll be running thermal generation more, but we won't have to buy as much carbon and natural gas. The other topic, I mean, we're gonna pay about NZD 110 million of tax for the year, and you can see we've already paid NZD 76 million. That's just the way the tax payments are skewed towards the first half. We're comfortable with those timing topics that the full year conversion of our EBITDAF to operating free cash flow will be in that 50%-60% range. In terms of our balance sheet, we are seeing debt levels increase, which we're happy about. It means we're getting closer to the completion of Tauhara and Tukituki Three. We raised NZD 250 million in October with a retail bond heavily oversubscribed, so we're very happy about that. That was NZD 150 million refinancing, but NZD 100 million of that was for growth. We're gonna be back in the market towards the end of March, raising a further NZD 250 million to support our renewable development pipeline. Great to see our average interest expend rate at 5.4% is relatively flat in a high, high interest increasing interest environment, and that reflects the great work the treasury team have done here, increasing the amount of funding that we have through commercial paper, which is on a very tight margin. More broadly, as we support our strategy around decarbonizing in New Zealand, which obviously means building a lot of renewables, you know, it's important that we can finance that. We've got net debt to EBITDAF at just 2.2 times, so well within that sort of ceiling of three times, which S&P have set for us in order to retain our investment credit rating. Remember, we've already got a lot of the debt of Tauhara in that number, but we've got none of the EBITDAF from Tauhara in that number. We're comfortable that our geothermal pipeline, we will be able to build on balance sheet with our existing balance sheet capacity. When you look at things like solar that we're getting closer to FID, with the joint venture arrangements we've got with Lightsource bp, we're comfortable that's gonna be off balance sheet and require minimal amounts of capital from Contact's balance sheet. We're also pretty underutilized in our use of capital bonds, so that's another option for us. We are very comfortable from a financial perspective that we can fund our strategy. In terms of dividend, we sort of guided that the dividend was gonna be flat for FY23. It won't be a surprise that the interim is flat at NZD 0.14 per share. NZD 0.12 of that will be imputed for qualifying shareholders. We're gonna continue with our undiscounted dividend reinvestment plan. Easy way for shareholders to reinvest into Contact, but obviously doesn't dilute shareholders that don't want to do that. I know, you know, dividend growth is a key topic for our shareholders. You know, there's a couple of things that will cause a dividend to change and go upwards. You know, linked to our dividend policy, you know, operating free cash flows going up in a structural way. That's one topic, obviously we're not far from that happening with Tauhara coming online this calendar year. The other topic that sort of Mike mentioned earlier on, it's TY long-term TY deal. That will reduce market risk, and will mean, boards, that's what I expect, all interest boards within this sector will be comfortable with dividends being higher in that operating free cash flow range. As Mike has said, you know, our engagement with Rio Tinto, they appear ready and willing to do a long-term deal at a reasonable price, which will increase sector earnings, and should lead to higher dividends too. In terms of a bit of guidance here, you know, we talk about our NZD 550 million for FY 2023. That's what we guided in normal hydrology, based on our assumptions around, you know, the market pricing and channel pricing and stuff like that. That's where we got to. We were tracking below that for the first half of the year by NZD 34 million. Renewables were slightly higher than a mean year, but it's been offset by the market pricing was considerably lower. The pricing on short-term CFDs and merchant length linked to the wholesale market. We expect that to reverse a bit in the second half of the year and outperform by NZD 14 million. And that reflects renewables will be lower than mean, and that reflects the very dry January, that we've seen. Based on the ASX curve and also what we're seeing in terms of the net pricing that we're getting on, mass market and CNI, we expect that outperformance of NZD 14 million. That leaves us at about NZD 530 million for the year. It's also worth mentioning, though, in terms of future guidance, you know, there's a couple of good sort of structural things there. You know, the ASX is higher in the future than what we had assumed in our original NZD 550 million guidance. Also the net backs that we're getting on, mass market and CNI are also higher. All things being equal, you would expect our guidance for FY 2024 to be higher than FY 2023, and that's before you consider the impact of Tauhara coming online. We just got a bit of an update on our guidance confirmation. Extended CapEx is coming in a bit faster than expected, a bit higher than expected, and this links to the fact that that NZD 100 million of additional capital that we guided that we were gonna spend on improving our renewable resilience in the S/4HANA projects, we're spending that a bit quicker than expected. There was a little bit of CapEx associated with getting that reconsenting of the Wairakei fluid take, which is obviously very wise investment. we've seen a little bit of change linked to interest to do with, you know, unwinds of provisions on onerous contracts, but also the floating rate of interest, as we all know, is higher than everyone would have been expecting as we entered this financial year. Right. Thanks, Dorian. Mike, we'll go to questions now. We'll go to the line first. Grant Swanepoel from Jarden. You, please unmute star 6. Can you hear me? Yes, we can, Grant. Yeah. Yep. A bit clumsy, this process. Just a few questions around CapEx. On Tauhara, what have you spent at the end of FY 2023, and what's left to spend on Tauhara? I'm just gonna rap it all with you. It'll probably be easier this way. Then when are we gonna expect first use from Tauhara? That's still gonna give us about NZD 80 million of EBITDA uplift. What CapEx have you spent on so far, what's left to spend, and when do we expect first use from Te Huka? What is the CapEx expected for the solar JV? Is it now about NZD 100 million from your side? Then adding this extra 1.4 PJs of short-term gas, are you paying over NZD 10 a PJ for gas, or is it less than that for PJ? Thanks. There's a lot to unpack in that, Grant. I'm sure somewhere in the appendices as we go scrambling through, we'll find it. The CapEx guidance for Tauhara remains as before. In terms of what we've signaled to the market, we took the increase, I think it was NZD 780. Eight-eighty. 880, the team are tracking well within that, noting that the project is now 84% complete. There is increasing confidence around that. Our guidance for it starting up later in the year also remains the same. The team have worked incredibly hard to secure that start-up within this calendar year. They continue to track towards that. Hopefully you can see from the photos of the site, the physical progress you can see. The lower half of the turbine has started to be put in place. When you see the turbine in the turbine hall, you know you're getting to the interesting end of the project. That remains on track. Te Huka 3, we went to market with an FID of NZD 300 million. The contracts, both the EPC contract and the supporting contracts for our works have come in within our expectation range. We remain confident of that capital as well, and that is on track, I think October 2024? Yep. October 24. We're getting ready to hand over the site to Ormat. Notwithstanding weather events, as it's been a very interesting time for the, obviously the Tauhara team and the Te Huka 3 team. Both those projects as we stand today are in very good health. Gas, we don't normally disclose, your question is an interesting one, I think we're, we've got a reasonably positive view on that. What were the other questions there? How much are we spending on gas? The gas price. The gas price. I mean, the gas price we've locked in. It's within our contracts with OMV, and that's sort of NZD 8-NZD 9. That does have an escalation in it, which is why it goes up every year. It's there or thereabouts. What we actually report in terms of our gas can be different from that because obviously we're buying spot gas all the time as well on emsTradepoint. There were some pretty cheap good deals in place, obviously in the first half of the year with all of the water around. Actually we can still get some quite good deals at the moment, which we're looking into as well. It'll be there or thereabouts, Grant. In terms of. Cross Street Solar. Cross Street Solar. This is from a Contact balance sheet perspective, we're assuming minimal capital is gonna be required. This SPV, which we'll be building it, will be highly leveraged based on the fact the quality of the counterparty that it's gonna be selling its solar to is extremely good, being Contact. It will be able to be leveraged, I reckon, up to about 70% or 75%. Obviously we put our 50/50 equity in with Lightsource bp. We've done a bit of work actually with S&P on this just to make sure we that none of that debt ends up on our balance sheet, because obviously the fact that we are a 50/50 partner and the PPA offtaker is us, you know, we wanna be comfortable that the debt won't appear on our balance sheet. S&P have confirmed that assuming that the way in which the T's and C's of all of those bank facilities work are aligned to what we've told S&P, it won't appear on our balance sheet, which is important. In terms of how much we've got left to spend on Tauhara, Grant, it's about sort of NZD 250 million-NZD 280 million between those numbers. I haven't got the precise number, but it's somewhere between those. Te Huka three, I mean, we haven't spent a great deal on that obviously, 'cause that project is relatively new. As Mike said, you know, all in, it's gonna cost about NZD 300 million. Thanks. Just to conclude, with that NZD 30 million upgrade to retail pricing and wholesale pricing and the forecast remaining strong, can we consider a run rate once Tauhara is up and running of the NZD 550 plus the NZD 50 improvement in retail, plus the NZD 80 odd from Tauhara, getting us to about NZD 660 million? Is that a normalized sort of expectation in a normal year? All of those topics that you've highlighted are the things that cause our expected normalized for FY 2024 to be higher. I can't tell you exactly whether those numbers are right 'cause I don't have them available to me. Those are the topics, and they are all positive topics as you, as you highlight. It fits with some guidance we gave for FY 2025 of NZD 720. Yeah. Excellent. Thank you so much. Thanks. Thanks, Grant. Let's go to questions in the room. Questions in the room. Yeah, Andrew. Yeah, I have a couple of questions. Yep. First question is actually just around the Wairakei projects. Just wanna clarify something as much as anything else, 'cause the consensus is you finish that on June 2026, then it looks like Te Mihi comes up in the second half of 2026. Yeah. Is there a gap there? No, no. We expect, you're now within cooee of each other and there's reasonable flexibility around that, so we don't expect any gap. You've got some flexibility. Yes. -consenting? Yes. If necessary. Yes. Yeah. That's great. Second question, just in terms of SIB capex, I know obviously that's represented a bit of a step up. Yeah. There's been a little bit of a step up in previous processes additive. You're still going for 65 long term. I mean, how comfortable, I guess, are you? I mean, we're looking. Very. years out. I think there's a number of things. One is we've got the S 400 SAP upgrade, which will come to an end this year. The other thing is the Roxburgh Runner project, which we have deliberately decided to step into, which gives us an upgrade in output from Roxburgh. That's a one in 60 year event. The other one which is playing through is the replacement of the transformers at Clyde, which is unfortunate. We're not happy that we only got 25 years out of them, but that should be a one in 50 year event. Once we get through those, as I said, as I indicated, you get to 2026, we've got a new plant at Te Mihi. Te Mihi remains in good shape, new Tauhara, new Te Huka 3, Pouakai is in great shape. Your hydros are completely refurbished. The assets will be in very, very good shape, and so I'm very confident in that ESIV CapEx level. I know this question how it doesn't work with timing on inflation pressures. Yeah, we are going through a bit of what we call a surge at the moment. Once we get through to 25, 26, the base will be good shape, so the base will come down. Yes, there are inflationary pressures, hopefully it's being applied to a much lower base. You make a good point 'cause that 65 was, or you could argue it's a real number that was announced about five years ago. Yeah, there might be some higher costs linked to that feeding through here as well. I think it'll be rounding in the grand scheme of things. Yeah. Yeah. Yes, we've got our last set of questions. This is just around a couple of clarification things. Interesting on the guidance and the second half increase. In terms of, maybe quite good, I guess, merchant length in the sort of first half of the quite long generation. What is the sort of assumption in there for the second half? Also our price assumption, I assume, is just straight off the ASX. Yep. That's different, yeah. Basically what we've got a dry January, very dry January, which we've taken into account. We then expect a sort of revision to mean hydro for the rest of the year. Maybe slightly lower because we'll use a bit of our Ahuroa storage over the course of the year, but it won't be too far off mean inflows. From a contracted position, most of our sales are fully contracted. We've got a small amount of very small amount of pure merchant length, so over and above the location losses which obviously we're still exposed to, but that's not hugely material. You know, we've got expecting to have sufficient gas to run any thermal we need. The risk therefore to that number would be, as usual, will be hydro and whether we're gonna get the inflows. We don't see there being price risks from a sales perspective. Obviously, if we don't get as much hydro, the issue there is you're displacing, you know, low priced hydro with having to run our thermal harder than expected. If there is a lot more hydro, then that's probably upside because we've contracted all of our sales positions. Yeah, we think it's pretty balanced. You know, as is always the same with renewable operators like us, you know, it'll all depend to a certain extent on the weather. Actually, just one last question, which I'm not sure if I missed from some ground questions. In terms of Tauhara timing of this generation? Q4 this year. Calendar. Calendar year. Calendar year. Yeah. Any other questions, Neville? Three from me. Yeah. Okay. I'll start with a relatively, maybe detailed question. I'll just throw this. Hopefully at the back you've given us the contract details for the next two years and your expected use of gas. If I did the math right, that would suggest the short-term gas you've purchased, plus the contracts you got down for OMV, those deliveries, if those are deliveries, look like they could exceed your need for gas. The question is: What's your ability to, if you like, delay the taking of gas? If you did, those contracts look like they're gonna give you more than you need. That's helpful. They're not take or pay. They are time shifted into later periods. Can you tell me how that works? I mean, we use things like swaps. We've got a swap gas, a gas swap in place with Methanex at the moment, so that helps us time shift gas if it comes through to the extent that we don't need it. The other thing that we can do on this stuff is we can commit to sales on the ASX where the sale is higher than our short-run marginal cost of running thermal plant, so that we know that we can actually just generate and get some sales into extra gas if we realize we don't need it for our own portfolio. You can do that, you know, based on where the curve is at the moment, and just lock in some value that way as well. You know, to the extent that we have capacity within AGS, you know, there still ability to inject there as well, depending on, you know, what's going on. I mean, how much could you inject into AGS? It's, it... Over the summer period, the capacity went up to 10.7. It was more than we expected. Yeah. It was 0.5. The high pressure operating regime that the technical working group recommended for us and Flexgas has indeed had a positive effect. We're obviously very happy with very interim result of that. We want to see it operate now over the winter and then back up and see how we can continue to mitigate and improve the volumes we can get in there. Yeah, it depends how that sort of stuff flows through. If it is operated as per the technical working group's recommendation, which is to keep as much in there as possible because that forces back the water, then, you know, well, hopefully, we're hopeful the capacity will expand again. That's a bit of a, bit of an unknown, I guess, at the moment, Neville. Great. Thank you. The second crunch question, which might be stealing thunder from the investor day you're planning. You've been quiet in here about Thermal Co and discussions we've had about out in the past. Obviously, the MDAG and BCG work highlighted the increasing and perhaps sooner need for peaking capacity than has been in the past, whatever form that takes. It would seem that the cheapest form for that is gonna be sort of fast start thermal. So- It's been off the agenda for a while. yeah. Could you give comments? Yeah, Thermal Co, as we now call it, we see high value in those peaking units, both at Stratford and Whirinaki. A lot of the last year has been about sorting out the operational issues with them, getting them in good shape, and you saw them run a bit late January, early February. Indeed, peaking capacity for New Zealand is going to be important in the medium term as we see it. Thermal Co, first and foremost, we will continue to operate and maintain those peaking assets. We have a great deal of in-house expertise, which we're very proud of, and for as long as it makes sense for us to have those in our care, we will look after them and nurture them through. Thermal Co was more about, is there an industry solution? We have challenges. As an industry, we have to give confidence to upstream operators to produce the gas, to drill and produce the gas. We have to maintain that fleet with a workforce which is aging and give that workforce confidence to stick around and use the fantastic skills they have. Thermal Co as a proposition for the industry is very much still there. In the meantime, we'll continue to do our job as well. In terms of the potential need to invest in new peaking thermal, you know, I guess what both of those pieces really provide, I think you potentially need to shift away from slow start that, you know, in the past, there was sort of a, maybe a bit of a hope that they could help serve that role. That hope seems to be decreasing. There is a possibility, and I think Transpower have been very transparent about the potential need for additional peaking capacity. We don't necessarily see ourselves as investing in that, but we certainly see ourselves as maintaining Whirinaki and the peakers at Stratford for the foreseeable future. Being contract counterparties. Yeah. -represented to a transition. Yeah. There's also, you know, the growing use of things like demand flex interruptibility being built into contracts and, you know, the underuse of things like ripple control, which is another form of, you know, demand management on retail. Those things, I guess, need to become more mature as well, which will help. Great. Thanks. Really the last question then was just about, the RMA reform you mentioned right in the intro. I mean, do you think as the, you know, the adjustment is progressing, that it will take, you know, a great deal less than seven years now to, you know? There is a clear national policy statement around renewable energy, and particularly in the context of the bipartisan approach to decarbonization, which I highlighted. Once you set that posture, I think as a government saying, "Hey, renewable development is important, it's something we have to get done," and it's actually more important than some of the senses we get around nimbyism and the like. It assures an appropriate trade-off. You know, when a renewable development is proposed, it doesn't end up in extended court hearings or appeals and the like. It's clear that this is important. It's important for the planet, it's important for the nation that we get on. I think that national policy statement will help tremendously. Unconsented sites on the new modern very tall turbines, how many years do you think they might take? I think well, hopefully a lot quicker than eight years or 10 years. In an ideal world, you'd like to see that down to something less than 3. Whether we get there, that remains to be seen. That's all for me. Thank you. Yes. One more question. Just one on your solar pipeline. You've got this 380 gigawatt hour target by 2026, now you've got obviously a fairly meaty project at Kopeka Park and another fairly sizable one in the North Island that's in the consenting process that should take you well north of that target before then. How do you see solar fit into your generation stack, I guess, towards the latter half of the decade? Can we see more projects now? Because you got another 50 megawatt one as well, which might be quite early stage. Are we expecting more projects coming out of that pipeline speed? Yeah, absolutely. Look, solar is interesting on two fronts. One is to Neville's questions. You can get it consented and up and running quick. So if you see elevated prices, the consenting seems to be a lot less painless, and you can get them in and up and running. I think the second thing about solar, which is probably more nuanced to the New Zealand market, is that it does give you good coverage in that February to April period, when hydro always gets a bit squeaky. That's something just... It's a unique characteristic of the New Zealand market. So we see a role for solar, here in Aotearoa. We don't have the resource, obviously. Witness the February downpour we're now experiencing. I think as a niche application, there are a number of opportunities which we're quite excited about. I think we'll move to take some questions online. Okay. We have one here from Pattrick Smellie. Mm-hmm. How do you respond to suggestion by Simon Upton that the full pipeline of renewables development has been spurred by the prospect of Onslow, and that Onslow has therefore not been a break on investment? That is simply not true. The development pipeline has been spurred by strong market signals. In a very strong ASX curve, a very strong signal in the carbon price that's gone up. Those market mechanisms have sent a signal. The wobble and all that was obviously demand growth. The investment we are making has always been market-driven signals in response to market-driven signals. Onslow is absolutely nothing to do, and I can absolutely testify, it has not been a consideration at any board discussion when they've been taking final investment decisions on these investments. Yeah, it's the question is like, I think the wrong way around. If anything, any talk about Onslow and if you actually thought is credible, it's likely to happen, would actually reduce the amount of renewables that are being built because the providers of capital into these projects would have a lot more uncertainties to the market that they'd be building into, and therefore you'd have less renewable development pipeline in a, in a situation where you had Onslow on the table. I think it's the wrong way around. I think Onslow would actually reduce the amount of renewables being built, not increase it. All right. We have three from Stephen Hudson at Macquarie. I'll read them all out. First, what is the best guess on market-making cost assumptions for FY 2024 mean guidance? Dorian, your question. Best guess. somewhere between, I don't know, 0 and NZD 10 million loss, I think at the moment. It's, yeah, like I say, it's a function of the market. It's quite difficult to, to predict. We've always historically until about the last couple of years, we've always sort of been 0 or made a little bit of money out of it. I think the market's changed quite considerably. There's been a few extra sort of conditions that, that have gone in which people are getting used to. I wouldn't like to hazard a guess. I'd say somewhere between NZD 10 loss and breakeven. Second is industrial interruptibility a real prospect? How much swing would that translate to? We can't comment too much in detail. Yes, it is a real potential prospect as the conversations we're having with other industrials is that as they've looked hard at the way they operate their business, they have found that there is interruptibility within their operations, which may give them challenges necessarily on asset utilization. If it's a higher value equation, then that looks promising. This also relates to New Zealand Steel has a fantastic consented site that provides opportunities for things like batteries as well. The third from Stephen is, based on your pre-FID solar thinking, which way are you leaning on your NZD 100-NZD 110 per megawatt hour long-term wholesale price assumption? That remains very much in place. I think what people have missed in the NZD 100-NZD 110 is, and the current ASX bears it out, we've got the cost of firming collectively wrong. Firming is a lot more expensive than what we understood. That NZD 100-NZD 110 still looks appropriate. If anything, we see upside to that. I mean, the MSO process that Genesis Energy has just run has sort of provided a bit more insight into that. When you sort of run the models on the details that were provided around that, you end up with a sort of strike price of even with today's coal prices, which is only just under NZD 400 a megawatt hour, and then you've got to pay NZD 13 million to get access to 100 megawatts on top of that. You sort of work through that and what that means in terms of the cost of firming. That's pretty significant. That's how, you know, the main firmer of the market values their generation and, you know, if they're, if they're not going to provide free insurance to the market, that's an insight into the price that they will dispatch their generation other than to cover their own position. And with the marginal fuel setting the price for the market, you know, that's where you get to these prices. That's, that's where it should be, because that's gonna be the trigger for people to build more renewable firming. You need the high prices to trigger people to build more batteries. Batteries at the moment aren't economic unless you're Meridian, and you can use it to get more volume across the HVDC. You actually need a higher prices for firming to make the batteries economic. One more question. This is from Lance at Aspiring. His question is, what NZ carbon price underpins your assumptions or outlook? When should we be preparing for NZD 90+? Carbon prices. They're not far off that at the moment. I think they dropped a bit down to 70 because the government didn't take the recommendation that the Climate Change Commission to increase pricing. We think that's a sort of short-lived topic, and it links more to, you know, the broader concerns that the governments have around inflation and that feeding through. Carbon prices do need to go up to fast-track electrification. We think it's gonna get there pretty quickly. Okay. We have no more questions. We're going to wrap up there. Thanks, everybody, for joining the call. Thank you.