Welcome to Contact Energy's interim results for FY 2024. This morning we are joined by our CEO Mike Fuge and our CFO Dorian Devers. Good morning and welcome everyone to our FY 2024 results announcement. I'll just flick through to the next slide with the usual disclaimers around information and then we'll get right into it. So this morning I will be presenting the highlights and some observations on market and external conditions. Dorian then will take you into the details of the financial results and anything that requires explanation there. And then there's in the pack you'll have seen an amount of supporting materials which again just gives you the details of how we have landed, where we've landed. Going right into the headline results, it's a very strong result, certainly one of the strongest in the last four years for a half. And what characterized that is a return to hydro volatility. After FY 2023 we saw very strong inflows. We've seen the El Niño start to bite with a reduction in hydrology. We've been running TCC harder over that period compared to first half 2023. We actually took action to get ready for that. We brought the TCC outage forward to make sure we could run it over January, February, and also in response to the extended commissioning on Tauhara. The results themselves on an operating free cash flow basis, things have improved significantly. The other thing that Dorian will turn to is that we have successfully controlled our operating costs. There have been increases but we understand where those are and the cost basis of the company remains well in hand. We'll talk a little bit as we go through about the reversal also of the provision on AGS. And just right at the bottom of that slide, our view remains that the long-term pricing is going to be in that NZD 110-120/MWh. We're making that 2024 real. That's consistent with what we've said in the past when we had it 2022. We believe the volatility in the market, the need for firming, and the fundamental structural change, and particularly wind costs, supports that long-term view. And we're certainly seeing it play out. And as you go through the presentation today you'll see some supporting graphs which just highlight that fundamental shift in the market from about 2019 onwards. One of the things about the result also is that channel pricing is much closer to the market conditions that we now see. The next slide, I presented Contact26 almost three years ago now and it remains so relevant today in terms of its strategic themes and what has been done. And if we go through each of those strategic themes, there are some important milestones from the last six months. In terms of growth demand, we continue the constructive engagement with Rio Tinto around the future of the smelter. We continue to stand by our position that we see a long-term future for the smelter here. We can talk through the details of how we see that landing, what's required. The other thing about the period is that we did develop proposals for CO2, food-grade CO2, at Ohaaki. Why that is important is that it ensures a sustainable supply of CO2 as an industrial gas to New Zealand that isn't based on thermal generation. It's also very important in terms of putting to use what would otherwise be a Scope 1 emission. Then the growing renewable development. At Tauhara, the team have worked incredibly hard over the last four months to put in place the modifications to the steam plant that are required. As we speak today, we're boxing up hydro testing and getting ready to recommence the steam blow sometime in March. So far everything has gone well there. On GeoFuture, the drilling campaign is actually underway. We're seeing some good positive results, all the more significant given it is the Wairakei field that is 60 years in production already. We're on the advanced stages towards an FID for co-fired part solar and the same is for the BESS project. We've launched the Fast Track Consent for Southland Wind which would be up to 300 MW. In terms of decarbonizing our portfolio, we delivered on our promise in terms of the closure of Te Rapa which has improved the emissions intensity from our remaining generation fleet combined with the running of TCC. As I mentioned, we continue to assess the viability of a 100 MW battery at Glenbrook and that's been advanced again, taking on those lessons about advancing front-end design for projects going into an FID. We remain on track for a TCC commissioning at the end of this year. One of the standouts for this half year that I do want to bring is the performance of the retail team. We have expanded the telecommunications offering into mobile. Broadband, we're fast approaching the 100,000 connections. Overall, we've grown by 20,000 connections in the period which has included some growth in electricity connections as well. Just to highlight the challenge in that business is that the consumer has been largely protected from the absolute price shocks caused by the last three years. At the same time, bringing them to a realistic market price has been a challenge. We appear to have been able to do that without tipping the boat over, as it were. If you think of the price shocks that have occurred even in what we pay for, say, petrol, but certainly what the rest of the world has seen, we appear to have navigated both as a company and an industry that well. We continue to expand our time-of-use offerings in terms of Good Weekends. We now have over 84,000 households on some type of time-of-use plan whether it's Good Nights, Good Weekends, or Good Charge for EV charging. We were an Energy Retailer of the Year finalist for the second year running. Now, the elephants in the room. We continue to have constructive negotiations with Rio Tinto and that only reinforces our view that the smelter is likely to stay open. However, we do expect any new agreement to be long-term. We don't need this hanging over us as it has for the last two decades. It has to be at a fair price which is obviously materially above the current price. It should include some form of demand response. Contact Energy, both in BlueScope but in the New Zealand Steel deal, have been a strong advocate of industrial New Zealand participating and being part of the solution to our dry year and intraday demand flex challenges. So we see that as important for this deal as well. What it would create is market certainty which would significantly de-risk investment in new renewable generation. That's for the whole industry. We see that as incredibly important as we turn our eyes forward to that decarbonization challenge. Having a large-scale demand response participant would significantly contribute to a Dry Year Risk mitigation which would be significantly lower cost to the nation compared to other solutions which may have been proposed in the last five years. It is complicated. Multiple bilateral negotiations with multiple other stakeholders with an interest along with other potential third-party parties. This is not a straightforward deal. We have to acknowledge that. We aren't the only participant in the room. But we continue to be very optimistic about a long-term solution. It's important to the country in terms of its contribution to an otherwise deteriorating trade balance. It's important to Southland in terms of the employment and the contribution to the Southland economy. It's important to the industry in terms of its potential to provide demand response for dry years in particular. Just in terms of the geothermal investment program that we've got underway, Tauhara, as I said, as we speak, the team are boxing up, getting preparing themselves to provide steam again to the EPC contract scope. We expect that to be on in quarter three this year and we remain committed to that. Te Huka 3 continues to make good progress. It remains on budget. And as we speak today, by the end of February, it'll be in excess of 80% complete. GeoFuture, as I said, we've made good progress on the drilling program and front-end design. We expect to take FID on that first half of this year. But what is really important is that we remain committed to it being on stream by the second half of 2026. And we've been able to maintain that commitment through the early drilling works and advancing the front-end design. On the cost at the moment, we have two bids in from high-quality international tenders for the power station. When we have more information, we'll be able to update you. In terms of the enablers and the strategy which we outlined to you three years ago, our ESG commitment remains strong. We now top New Zealand companies with a DJSI. We got the Sustainability Leadership Award in the Deloitte 200. In terms of operational excellence, the team were able to give early delivery on the 50 GWh that was enabled through the Wairakei consents. They were able to make that a reality. You can see how they responded to the challenging hydrology by bringing the TCC outage forward. TCC has started very well over the last couple of months. We have worked to accelerate the return of GT22. It was expected back sometime next year. We're now expecting it back in the first half of this year in time for the bulk of winter. In terms of our transformed way of working, the thing I do want to call out is the much improved safety performance of the company in these first six months. That was a result of hard work and significant investment and training of our leaders and frontline leaders as well as a replatforming of the business to enable safety observations to be recorded much more easily and acted on. We won the Wellbeing Award in the New Zealand Energy Awards. And certainly what we're proud of is that investment paying off in the wellbeing and health and safety of our people. Now, we've talked about this for a long time, demand. And finally, we can see some increase in demand from the underlying. Certainly underneath this, in terms of the retail arm of the business, we see the number of ICPs growing as well as the usage per household growing again as households go on that decarbonization journey. In commercial and industrial, we've now seen a stabilization where there was downward pressure from the closures of the refinery and Norske Skog plants. And now with New Zealand Steel's Future Steel, with Oji, Pan Pac coming back online later this year and an expected long-term security around the smelter, we expect the demand growth to start picking up as well as the decarbonization initiatives in terms of boiler conversions and dairy factories, meat processing, and of course the New Zealand Steel electric arc furnace. So it looks positive on that front and that emergent demand growth is very much welcome. I talked about the hydrology impacting the generation mix. You can see there first half 2023, we had virtually no coal-fired generation as an industry. It's kicked up a bit in the first half of this year with an increased gas-fired generation as well. You can see in the graph on the right how we are sitting now below mean compared to what was a very wet combined FY 2023. What that means is increased volatility. It means that typically the market is pricing at thermal dispatch. We do see increased volatility also from the additional wind coming on. You really notice it in the market on a day-to-day basis when the wind is there and when it drops away, the effect that it has. We expect that volatility only to increase. That in terms of the market and the market forces, this is a slide that we have presented consistently as what we're seeing the overriding influences on the wholesale electricity primary in this country. Aluminum prices remain largely flat. Hydrology, we're sitting at about 80% of mean. We're seeing a decrease in coal prices but gas prices remain reasonably elevated. Methanol prices are best described as steady. And in terms of gas and carbon, you've seen a recovery in carbon prices. The AGS facility remains constant in both its storage and its deliverability. Demand, as I said, was up. That graph on the right-hand side talks to how the market has shifted. It is a fundamentally different market from what it was six years ago in terms of the volatility that we all have to manage through. That speaks to both the demand, the supply-side challenges that aging thermal plant has built as well as the increasing penetration of wind and solar into the market. That is something that we all have to manage in the go forward. We do expect future marginal prices and higher renewable development costs played through into the market in the go forward. The reality is that wind is not as cheap as what people globally assumed. That it is more expensive. I think wind turbine suppliers have discovered that to their chagrin that it is an expensive option. It's more expensive than what anyone assumed. That is going to play through into electricity prices. In terms of retail, it's important to acknowledge that we have one of the most competitive retail markets in the world which has protected the consumer from the price shock. That graph at the bottom tells that story in terms of when inflation has been going at a CAGR of roughly 4.5-5% per annum, electricity prices have increased 3% per annum. What we've seen at the fuel pump by contrast within a neighbouring or adjacent energy market has been completely different from what we see on that graph. We have seen different strategies play out. We see the competition in the market continuing in terms of churn rate remaining at 19%. We remain third best in market in terms of doing better than that in terms of our own churn rate. We have seen consolidation in the telco market with 2degrees and Vocus merging. And that provides them also stepping into the energy space as well. So the competition remains intense. Our ability to compete depends on our ability to both control costs and innovate as the team has certainly done over these last few years. There is a challenge in the go forward which we'll talk to in terms of network costs and transmission costs, which are expected to increase substantially with the resetting of the WACC for the industry. Also as was highlighted with the BCG report, that the cost of transition, the additional connections required will mean additional costs flowing forward. It's important as an industry that we face into that challenge going forward, particularly as inflation subsides, which leads to where we're sitting with the regulatory matters as we see them today and with the change of government, we have seen a refocus. Security of supply remains top of mind and is even more top of mind for the incoming government. It's important that we as an industry continue to ensure that New Zealand continues to maintain one of the most reliable electricity supplies globally. We are paying attention to this. Our investment in baseload generation in Tauhara and GeoFuture and Te Huka 3 remain part of that story. We do see electricity price pressures in the go forward as increased lines and transmission charges flow through both to pay for the transition but also reflecting the higher WACC. We continue to look after our vulnerable customers and to help people step through that transition. And another part of that is giving households the ability to control their energy costs through those time-of-use products which is very important. We saw Lake Onslow being put on the shelf or cancelled. We think that's the right solution. But that requires us as an industry to now step up and come up with innovative solutions around how we can provide both demand threats but also that dry year cover which as I anticipated before may require commercial and industrial New Zealand to be part of that solution. I've talked already at length about lines, assets, regulation, investment. That additional investment is something that we need to as an industry turn our minds to. We are pleased with the incoming government's attention to Resource Management Act. The Fast Track for renewable projects we see is absolutely vital. It's great to see that legislation introduced. It's great to see a degree of pragmatism about how we can achieve that. That of course is going to put the challenge back to the industry to actually step up to the mark and mature and deliver these projects. But it's a challenge that I think we're all up for. And on that, I'll hand over to Dorian to go through the results. Thank you, Dorian. Thank you, Mike. So first up, again, I'll mention a few topics that will come out as we go through the financial and operational performance and so any relevant market insights. So within our financials, we've got a NZD 29 million positive before-tax fair value adjustment. It's a bit of a mouthful that relates to the AGS onerous contract provision. What's happened there is the actual expected inflation has come in lower and therefore the escalation on the contract is going to be lower than we previously modeled meaning the contract becomes less onerous. And also we're using thermal generation more than we anticipated because of the course of the Tauhara delay. And again, whenever you're using thermal generation more, it makes the gas storage more valuable and the contract more valuable. So that reduction in the onerous contract provision shows up with the NZD 29 million non-cash increase in our EBITDA. We'll do what we did in the prior year. We strip that out of the numbers when we talk to them because it's a non-underlying topic and we refer to that as the underlying performance. Unfortunately, we do have NZD 8 million of write-offs within these numbers. NZD 4 million relates to some work that we've been doing developing a new CRM solution. Our current system will be end of life in the next few years. The path we were going down though looks like less likely that we will actually go down that route and therefore you have to write off the costs associated with that. So that's NZD 4 million. The other NZD 4 million relates to the eaker breakdown GT22. Components of the peaker haven't lasted as long as they were expected to so you have to write off the costs around that. There is a broader peaker reliability topic which we are looking to address. Some of the things that we're looking to do around that is replacing component parts more frequently and actually changing how we operate them as well which puts less stress on the assets. Both those things we think will contribute to improve reliability. They will come at additional costs though because these are key assets supporting the energy system. We'll look to ensure that we recover those from the market. Those write-offs show up as OpEx and you'll see that in the OpEx side when we get to it. There's a further write-off which we're likely to do at the full year. We don't have all the information yet, which is why we haven't been able to do it yet. It won't surprise you to do it at Tauhara. We've had that steam hammer event which caused some damage and we're also reworking the water handling system. No extra cash costs associated with that because that was all covered in the NZD 40 million increase in the project CapEx that we announced a few months back. But this is obviously adjusting our asset base accordingly. So you'll probably see something on that at the full year results. Our view is that Contact retail tariff has sort of historically been at the lower end of the scale regarding market pricing. We've worked very hard actually over the last few years to close that gap and you've seen that within our performance. The reason why we're working very hard on that is because the industry is faced with a major headwind which is those regulated increase in network costs that's been signaled by the Commerce Commission. Whenever you've got a major increase in pass-through costs particularly to a consumer-facing business, that comes with risks. It's important that you don't go into that process with a tariff that's already discounted to the market. That provides you a little bit of insight as to why we've been behaving the way we have been behaving. It's also one of the reasons why we've been keeping our retail load flat because not only over the last few years has the retail channel been discounted to more market-linked channels which makes it less attractive for that reason but also going forward we've seen more risk around it because of that pass-through recovery that's going to be required linked to those higher network costs. The EBITDA performance or underlying EBITDA performance has been strong for the first half. We're expecting it to soften just a little bit in the second half. That's as we've acquired generation to manage months where we see there being more risks. For example, when the HVDC's down on an outage and Pohokura Gas Field outage and also covering some of those Tauhara or whatever those sellers that we thought were going to be backed by Tauhara volumes. But overall, we still see a strong result for the year with underlying EBITDA up from NZD 600 million which is what we'd previously guided to NZD 620. And that's due to improved thermal efficiency and pricing. That's also net of those NZD 8 million of write-offs. So if you adjust for that, it's actually at NZD 628. And Mike mentioned we've got a sort of increased confidence on our view of long-term pricing. So we're not actually changing our view when we say it's NZD 110-NZD 120 2024 terms. That's just adjusting the previous number that we talked about for inflation over the last couple of years. I should just remind everyone that the average spot price over the last 10 years was NZD 103. So that sort of puts in context what we're talking about here. The reason why we're growing in confidence is, as Mike said, the increase in renewable build cost doesn't seem to be just the impact of a COVID recovery and a few supply chain issues. It looks like it's here to stay. I mean, interestingly, when I entered the industry back in 2019 as a ward of farm, people used to talk about geothermal costing NZD 4 million a megawatt, wind costing NZD 2 million a megawatt, and solar costing NZD 1 million a megawatt to develop. And you guys, everyone knows what that's moved to now. You can see the impact of the higher build costs flowing through there which obviously needs to be recovered in terms of wholesale pricing. Otherwise, people will stop building. We're also getting signals others believe have similar views to us even if they don't say it publicly. You can see it based on the PPAs they sign up to and the investments they make knowing that they need a price like we've suggested in order for them to be economic. So that gives us a bit of confidence around that price level. Last thing I'd say is there's a lot of renewable development opportunity in the South Island. It's been constrained obviously over decades because of the uncertainty around Tiwai. If a long-term Tiwai deal is announced, you'd expect FIDs to be announced on the back of that. Batteries will help with this. But it is important that transmission keeps up with the renewable build. We're blessed to have all of that resource. We just need to make sure we do it justice and ensure we can get it to where the demand is. So on to the financials. So the AGS onerous contract provision shows up here in the net profit. We had an adverse impact of it of NZD 86 million in the prior corresponding year, a favorable impact after tax of NZD 19 million in the current year. Chart on the left back shows out. So you can see our underlying net profit is up by NZD 55 million. The biggest movement there is underlying EBITDA which is up by NZD 68 million to NZD 325 million. Chart on the right explains what's driving the year-on-year movement. So hydro inflows for us have been pretty erratic. We've had extreme dries and extreme wets in the six months. But overall, renewable volumes have been down by 91 gigs which on a fuel replacement basis cost us NZD 11 million. We guided to a step up in sales volumes of half a terawatt-hour. That aligned to us anticipating that Tauhara was going to be online in Q4 2023. We've had to back those sales by risk management and thermal fuel. Obviously, with Tauhara being delayed, the impact of those sales volumes is minus NZD 10 million. However, even though we had that delivery risk associated with Tauhara, it's important that our diversified asset portfolio and fuel mix allowed us to make those sales because it gave us exposure to that NZD 57 million increase in market channels. And that's the repricing of short-term CFDs. Remember, the market pricing was very depressed in the prior corresponding period because of all of that water that we had naturally. We've seen a NZD 39 million improvement in our long-term channels. And this is about the retail channel slowly repricing, getting closer to market pricing. NZD 18 million improvement in our thermal generation efficiency. This is two topics driving this. Firstly, we've shut Te Rapa which was our least efficient thermal plant. Also, as Mike said, there's been less hydro in the system year-on-year. So we're stepping up our thermal to support the system. And as you'll know, whenever you run those plants at high capacity factors, they're more efficient. Also, the carbon intensity dropped, linked to that as well, a 30% reduction. So a good social topic there that was supporting energy security and a good environmental topic that we're doing it in the most sustainable way. Other income is down by NZD 9 million. This is where we had NZD 17 million of steam sales on the back of Te Rapa going to Fonterra. So that obviously don't have that anymore. But partly offsetting that, we are making some risk management sales backed by thermal generation to the market. And this is where the premium on that goes. We've also seen improved margins on our retail adjacencies. Fixed costs before those write-offs are up by NZD 9 million. We've got a bit of inflation on gas storage and transmission and then some higher OPEX which we'll talk to later. Then obviously, you've got those NZD 8 million of write-offs. That explains EBITDA back to net profit depreciations coming in NZD 15 million higher. That reflects the higher cost of thermal. If we're replacing components of the thermal asset more frequently, there's a higher depreciation charge associated with that. Interest, it's dropped a little bit. Remember, all of the interest expense associated with debt to build all of our renewables gets capitalized until the projects come online. Tax is higher reflecting higher profits. The fair value of financial instruments, always a complicated one, that's shifted favorably NZD 22 million. Really happy about this. Do you remember we had some discussions at the full year about our market making? This is where market making goes. They've leveraged technology and process improvements and actually beaten our expectations on that. So that's largely driven by improvements in realised and unrealised market making gains. In terms of our EBITDA or underlying EBITDA across our three segments, you can see wholesale is up by NZD 75 million. Retail's moved from NZD 1 million to minus NZD 1 million which doesn't sound like a big, big thing. But then we look at what's in the middle there and all the effort that goes into recovering NZD 45 million of higher energy, transmission, and network costs, the judgment that's involved in ensuring it's done in a fair way and also managing risk to maintain a low level of customer churn. So great performance there, I'd say, for our retail business. Then in terms of the corporate costs, they're up driven by some higher OPEX which we'll talk about when we get into the OPEX section. So just onto the wholesale business, we're reflecting a big increase in sales backed by thermal fuel and risk management. Our generation costs are up by NZD 67 million. That is NZD 59 million. And that's linked to the risk management of thermal fuel. This is where you actually see the adverse impact of the Tauhara delay coming through because had Tauhara been online, those sales would have been backed or some of those sales at least would have been backed by geothermal fuel at a marginal cost of NZD 5/MWh as opposed to thermal fuel at a cost of NZD 96/MWh. The remaining NZD 8 million of the increase, that NZD 4 million write-off linked to the Peaker and then some cost inflation on our fixed costs. Just to talk a second about our actual assets. So hydro performance has been good. The only outage of note in the second half of the year has been cleverly aligned to the HVDC outage. We've also got the last of those two transformers that are being replaced at Clyde showing up. But that's not until January 2025. So no impact on this financial year. We've got our four turbines that we're replacing down at Roxburgh. So that ultimately will add an extra 45 GWh generation. That process is starting in May with one turbine replaced every six months. Big news on geothermal business as usual, geothermal, I should say, was that reconsenting of Wairakei that we announced last year and the extra fuel associated with that. Just to double down on what Mike said so that people don't miss it. We've sort of formally said that based on our current geothermal footprint, generation will go up from 3.25-3.3 terawatt-hours a year now. And that's before Tauhara and Te Huka 3. That's very valuable for us because minimal investments and ongoing costs are required to deliver an extra 50 gigawatt-hours of baseload renewable generation for the country. Regarding thermal, we talked about peaker reliability issues, what we're doing to deal with that. Some good news on TCC. We were able to take advantage of the weather conditions and retime the Radex repair. So we did that in the first half of the year. TCC is up and running and available for an HVDC outage. Also, GE signed off the extra 2,500 hours. We've now got enough to run TCC base load for seven months for this calendar year, which hopefully won't be required. From a wholesale contracted revenue perspective, it's up by NZD 126 million. Volume's up by 529 GWh. And pricing has aligned to market conditions. Biggest topic is around our CFD revenues and volumes, which were up NZD 116 million and 697 GWh respectively. As I've said previously, we went into the financial year expecting Tauhara to be online in Q4 2023. Therefore, we contracted upload to manage price risk. We also had some legacy strategic fixed-price sales that were coming up to end of contract. Rather than recontract them, we actually moved them in 121 GWh into short-term CFDs in order to get a market price for those. So that explains the overall volume change. The channel repriced up by NZD 32/MWh to NZD 140/MWh. Remember, that's what I said earlier. Prices were depressed in the prior corresponding period because of all the water that we had across the country. C&I revenue was down NZD 6 million. To manage fuel risk when we found out about Tauhara, we stopped selling through this channel. So you can see volumes dropped off a little bit. Prices did improve but not as much as we'd guided to. And that reflects if you're not in the market repricing and recontracting, you can't get your price up. Interestingly, if you adjust for load shape, the net back on this channel has now dropped below retail. So we do see an opportunity in the second half of the year to price that channel up. In terms of sales for the retail business, up by NZD 39 million. Remember, we hold volume flat for strategic reasons that I outlined earlier. This is all about the transfer price passing on those higher market costs. And the good news is the retail business is listening and it's adjusting its tariffs accordingly. Steam revenue is up by NZD 17 million sorry, it's down by NZD 17 million. That relates to the Te Rapa steam sales to Fonterra. Just to say that relative to the counterfactual of keeping Te Rapa open, we're in a better financial position. We may well have lost those steam sales. But we've got improved thermal efficiency, less fixed costs, less stay-in-business CAPEX. And of course, you've got those reductions in Scope 1 emissions too. Other income is NZD 500 million. That reflects the premiums that we're making on selling some risk management products to the market. Wholesale trading and merchant revenue delivered 0 which is how we like it. That's merchant revenue offsetting location losses. And that's as per our guidance. We had a loss in the prior year. But there were those unusual situations with all the hydrology and the impact that has on location losses and merchant length pricing. The retail business. So it's good to see the EBITDA of this business only drop before NZD 1 million loss. This reflects that tariffs have been catching up to the changes in the wholesale market prices. Mike said earlier, one of the things that we had been doing had been smoothing out the effects of that rapid change in the wholesale market costs to consumers by only increasing pricing aligned to the level of CPI. Obviously, we've got a bit of a tailwind with the escalations of CPI, meaning we've closed that gap now and getting closer back to profitability, which is good. Obviously, very mindful of the impact of higher prices on consumers, which is why it's great that 21% of all of our retail customers now run time-of-use tariffs because that gives them the ability to shift their load from peak to off-peak and save some money to offset that tariff increase. Obviously, do some good for the environment as well because off-peak electricity is less carbon intensive. Overall, our electricity tariffs are up about 8%, which reflects roughly what the CPI environment would have been at the time of those price increases being tabled. Pleasingly, we've held our customer numbers relatively flat through a period of relatively high price increases for us. And I think that talks about the types of products we've got in the marketplace which seem to be resonating with consumers. That's our Good Nights and our Good Weekends products, for example. I've said previously that our tariffs have been lower generally than other retailers. I now believe we've actually caught up. And that's good because, as I said earlier, we're about to see this period of higher regulated network costs. The assumption is that these are pass-through costs. But the magnitude of the increase that's been signalled by the Commerce Commission, if they are to be passed through, it will likely lead to tariff increases to consumers for quite a number of years above the level of CPI which obviously carries some risk. Just to put some context to this, what a consumer pays, about 50% of what they pay goes to the network companies and the associated transmission. So whatever the Commerce Commission signs off, whatever percentage they sign off, you divide that by 2. And that's what would need to be passed through in terms of a higher tariff to fully pass that through to consumers. They have used things like price shock caps before at 10%. Not suggesting they'll use it this time. But if you did use that as an example of 10% price shock cap plus inflation of 2%, then that would need a consumer pricing freeze of 6% every year for the next 5 years to recover that. And that's before you consider the inflation on cost of serve or energy. So it just puts into context the sort of risk around this. Gas margins have improved from NZD 3 billion to NZD 10 billion. It's good to get this back to a more sustainable level of performance. We're actually now at NZD 20 a gigajoule. That's the net price we're getting on retailing gas which is the same value we could get if you put the gas through a peaker and sold it into the wholesale market which is good. Broadband margins are up from NZD 4 million to NZD 5 million. That reflects that our average number of connections across the year is up by 19%. I did talk about a little bit of under-recovery of the Local Fiber Company costs in FY 2023. We've caught that up a bit. So you can see a little bit of margin expansion in this product. Cost of serve is up by NZD 2 million. We've invested a bit of money in advertising and promotion linked to the launch, as Mike said, of our new mobile product. Also create more awareness around time-of-use products. We have seen a bit of an increase in bad debt. I suspect a lot of businesses will be saying that linked to the external environment we're in. But it is being well managed. Overall, our cost of serve per connection will continue to be the standout within the industry in terms of efficiency. Onto OpEx at a Contact level, NZD 132 million. That does include those NZD 8 million of write-offs that I mentioned. There was also NZD 3 million of one-timers in the prior year numbers just to be transparent. That was the retention payment to staff at Te Rapa, ahead of that plant closing, and some consulting costs. So recurring OpEx has gone up from NZD 115 million to NZD 124 million which is 8% or a NZD 9 million increase. The biggest component of that increase is inflation within the base business up by NZD 6 million. Still got wages and salaries going up by 5%. You've still got insurance going up at significantly higher than CPI and flowing through there. We are going through the renewal process for insurance. I'm sort of hoping that we've seen the last bit in terms of big insurance cost increases. We've also had some headwinds. I mentioned the bad debt increases. We've also got the tail end of the repairs associated with Cyclone Gabrielle. But those headwinds have been offset by improved productivity in particular in the retail business which continues to leverage fixed costs as we grow our number of connections. We've invested NZD 3 million in what I've called growth and sustainability. We sort of guided to this with the FY 2024 performance when we did the full year FY 2023 result. This is about continuing to fund retail connections, investing into finance procurement, sustainability, corporate reputation. All of these things are important. For example, they ensure that we can deal with things like climate-related exposures. It ensures that for our stakeholders, we can tell our ESG story just as well as our financial story. And we're already getting good feedback on that Mike mentioned earlier. Not only are we in the Dow Jones Sustainability Index, we're New Zealand's number one ranked company within that index. I said it before. But I see this as being the last year that we're investing from an OPEX perspective in growth and sustainability. I see us at the time we get to this year will be right-sized for growth and the additional compliance that comes with ESG. In terms of our operating free cash flow, NZD 187 million. That's a cash conversion of our EBITDA of 58%. That's a very strong performance because we have a number of cash outflows that are heavily weighted to the first half of the year such as tax. And also, we buy all of our carbon units. One of the reasons why the performance was so strong is EBITDA is up. And a lot of our cash topics in our cash flow like stay-in-business CapEx, for example, don't flex up with higher EBITDA. So therefore, the marginal operating free cash flow you get on that extra EBITDA is a very high percentage. Just a reminder, the prior corresponding period isn't a good comparison. Cash conversion and cash flow was very low. And that was a function of depressed wholesale prices, the effect that had on EBITDA. Also, very little thermal generation was run. Our inventory went up because you've still got the contracts in place to buy the natural gas and the carbon. For the full year, we're expecting a cash conversion, operating free cash flow conversion of EBITDA of above 60%. Remember, 60% is a normal performance for us. Our debt levels continue to increase as we talked to our board and took a review. We entered the Australian bond market in November of last year with a AUD 400 million issuance. It provides more diversification to our funding sources which is always good. It helped continue to support our renewables build program and also refinance the maturing USPP facility. We, like everyone else, have seen an increase in floating rates. Pleasingly, our average interest rates only got up by 20 basis points to 6%. What's happened here is we've entered into fixed interest rate hedging in a lower interest environment. We did that in anticipation of our debt levels going up linked to our renewable build program. That actually means that our fixed interest rates are actually dropping as our debt levels are going up. That's offsetting some of the big increase in floating rates. Based on the market as I see it today and the hedging we've got in place, I wouldn't expect our interest rates to go much above where they are today. But I caveat that. Far, smarter people than me make a living out of normally predicting interest rates. In terms of funding our renewable development pipeline, we, like others, have seen an increase in the cost of building renewables. As you'd expect, the wholesale prices adjusted accordingly. So if it's as the long-run marginal cost of building renewables goes up, that feeds into higher wholesale prices. If it didn't, people would stop building renewables because it wouldn't be economically viable. So returns are protected in that regard. It does create a short-term financing topic because obviously, CapEx is high. But we're comfortable with the levers that we've got available to us like our dividend reinvestment plan, balance sheet, capacity hybrids that we can cover. And that chart sets out why. In terms of dividend, you all have noticed that the Capital Bond pack hasn't been landed yet. And also, we're not expecting Tauhara online until Q3 2024. So as we had guided to, we keep the dividend constant at NZD 0.35 per share for the year with the first interim dividend being declared at NZD 0.14 per share which will be 86% imputed for qualifying shareholders. We will, of course, look at the final dividend based on any changes within the environment, Tauhara and Tiwai and things like that and make a decision on that in due course. We continue with our undiscounted dividend reinvestment program. One piece of good news is we're actually bringing the dividend payment forward two weeks. For whatever reason, we tended to have a long drawn-out dividend payment process. We're now condensing that. The payment goes out two weeks earlier which brings us more in line to what normal practice is. But I suspect shareholders will be happy about that. Then this is just about our guidance. We put out guidance, mean hydro guidance at the beginning of the year of NZD 600 million. We've increased that to NZD 620 million. I won't go through the half-year topics because we've already covered those. But what we're expecting in the second half of the year is whilst we continue to see improvements in terms of thermal efficiency in the second half of the year, that benefit relative to our previous guidance is offset by the fact that we've acquired more risk management. And so therefore, those two things net off. So you get no further benefit in the second half of the year from that. We do see some price improvement in the second half of the year. What happened in the first half of the year is we saw improved relative to guidance retail tariffs. But it was offset by lower than guided pricing across market-facing channels. We're expecting market-facing channels to improve. And the retail above-guided amounts to continue. And that gives you that NZD 18 million upside in the second half of the year. I talked about that Tauhara write-off. It's non-cash. I haven't included that in here. But obviously, whatever happens there will come off our EBITDA. Just to say, I mean, there's a lot of work that's gone into adjusting for the Tauhara today. I think it sort of demonstrates the resilience of our business that we're able to put out a first-half-of-the-year performance like this and then also in a position to update our guidance for the full year when we're mitigating the loss of that or the deferral of that fuel. There is obviously the usual risks that go with going forward. Obviously, this assumes mean hydro. The higher-risk months are things like the months when you've got the HVDC outage happening in October or a gas field outage happening and obviously when you get into winter. But we believe we've mitigated those well. And if you've had a chance to look at our January operating stats, we've started the second half of the year very well. So on this slide, I wasn't going to talk about this. This basically sets out what you'll see from us for the rest of this time of the year. You'll be familiar with all the topics. There's a lot going on. The real reason for actually having this in is you can then hold us accountable to delivering on that which is important. And with that, I'm happy to take questions. So we're going to take questions on the line from the phone first. Grant, is it on the call? There's a lot going on. Grant, are you wanting to start your questions? I think you've been admitted. Can you hear me? Yes. Yes. So there's a bit of a delay between the presentation and the call. So in case you're a bit surprised. But just a few questions quickly. Just on Tauhara, on your ops stats, you were showing that you expected to be at 100%. I know there's rounding errors there. And you're only at 99%. Is there a little bit of delay within that three months to end of September we should be worried about? No. At this stage, we've largely completed the reconstruction of the necessary modifications of the steam plant. And we expect to recommence commissioning roughly by about the middle of March. So we're still confident around that end of date, yes. Perfect. Thanks. And then your dividend, you were talking a little while back that if Rio had confirmed a change contract, a bit more confidence, you would potentially up that dividend payout ratio this year. Does your outlook for comfortably holding your net debt ratios taking into account a higher dividend? And would you still be considering a higher dividend at the end of this year if Rio did confirm a contract before then? Yes. Yes. Yes and yes. We've been very consistent on that messaging. Oh, thanks. Can you just give a bit more color on the Ahuroa storage issue? You wrote down NZD 120 million a year ago and now NZD 29 million writeback. Should we continuously expect writebacks until that contract expires? Yeah. I mean, that's the problem. It is quite volatile around this because some of the key things that sort of impact the value of that provision are things like the discount rate you use which is linked to the 10-year treasury. It's the inflation, PPI which is the escalation on the contract. Unfortunately, things like treasuries and inflation rates at the moment, Grant, are very volatile which is why we're seeing this move around a bit. The other thing that moves it around is the amount that we use thermal generation. And if we step up the use of thermal generation which we have done because of the Tauhara delay, that makes the facility more valuable for us, that storage. And therefore, reduces the onerous contract provision. Once TCC is shut and our thermal generation drops to just a couple of peakers which would be, I don't know, 200 gigs a year, the volatility linked to thermal generation going up and down will reduce quite considerably. You'll still have volatility due to inflation and interest rates. Unfortunately, it wasn't a great time to make an onerous contract provision. If it had been done sort of 5 years ago when we had more benign interest rates and inflation, the provision would have barely moved. Good. Thanks. And then just your organic earnings have been absolutely stonking. 638 if you add back the hydro, NZD 10 million, and the write-down or write-off, sorry. Could we have even considered another NZD 10 million or NZD 20 million if you hadn't sold toward Tauhara contracts? No. No. I don't. They were beneficial to us, Grant, because of the fact that they gave us access to the repricing of the CFD. So while on the chart, I showed it as being negative because they were backed by thermal fuel, the way I calculated that is I applied last year's CFD pricing to that. And then you get the uplift in the market pricing on that volume which is within the NZD 57 million. So overall, it's definitely financially beneficial for us to have sold those volumes. Okay. So what you're saying is you've hedged that out pretty successfully to not negatively impact the EBITDA? Yeah. Yeah. Yeah. Thanks. And my final question is more a macro question on your NZD 110-NZD 120 long-run marginal costs now. With Rio potentially coming on, ratifying a deal, call it in the next few months, does this not put us at risk of a massive overbuild as not just yourselves but everyone and their dog is now looking to build some renewable into a space that actually isn't seeing demand growth to the extent that you would like to see it? And then also, can you talk to government's policy of using carbon tax as a driver of carbon conversion and not using a GIDI Fund-type tool anymore? Thanks. I think two-fold. There's always a risk of underbuild or overbuild. The requirement, I think, was in the order of one large-scale wind farm every year for the next decade. We're nowhere near that at the moment. I think as I intimated at the beginning of the presentation is that we're seeing the demand growth start to kick up now certainly in the retail market at a per ICP and the number of ICPs with population growth. On top of that, you're starting to see the industrial conversion. So there is always a risk of overbuild as there is always a risk of underbuild which that's why we're in this market. The second part of that is we do actually see some very positive signs on the demand growth particularly if the Tiwai deal lands. So we're comfortable with that risk. Yeah. In terms of your spot-on around we're expecting carbon prices to escalate with that being the new government's mechanism to drive decarbonization as opposed to providing subsidies like the previous government has been doing. We're still in a bit of a state of flux around that as to where that goes. You haven't seen you're still waiting for the old process to sort of clear before the new one kicks in. I was just checking actually. Carbon prices have dropped a bit in the U.K. and Europe as well. But even relative to those, you're still with the New Zealand carbon price still looks relatively cheap. So we're expecting carbon prices to go up quite considerably over the next few years which will be the mechanism to carbonize. Thanks, team. That's all from me. Grant, we'll go to questions in the room. Morning, guys. I'm Shelley, of course. I have a couple of questions. First of all, I guess just following on around that 110-120. Certainly, you can see what's going on in the wind space. And then it doesn't look like those turbine prices are coming down particularly quickly. But the solar space is quite different. So can you just sort of talk to what you expect, I guess, solar prices to do and why they may not impact critically on that long-term price is what you're indicating? I think for New Zealand, solar was always going to be a niche application. It has an attraction and the speed of deployment. And certainly, there is always downward pressure on the cost of, for instance, panels. The reality is that for any project, there is always a balance of plant which is subject to the same inflationary pressures which we're seeing on geothermal and which we've seen on wind. Those balance of plant costs are endemic to New Zealand. They will put up with pressure on solar prices. The other thing about solar, as I said, it's niche. It will not play an overly significant role in the market in the longer term. It more than anything needs significant firming where we only see upward cost pressures. At best, the capacity factors you see in solar are between, let's say, 18%-25% in this country. Something needs to firm it for the other 75% of the time. Okay. Thank you. And next question, I guess, was just around what you're seeing longer term, I guess, for your expectations on the CNI and mass market pricing relative to what the current ASX is. So I guess you're indicating second half you've still got some more increases to go through and the fact that your retail profitability is basically zero suggests there's more to go on the mass market side as well. How far away, though, are we, I guess, from these prices actually catching up to what that long day-to-day ASX curve is? Well, obviously, outer periods in the ASX curve come in. We do see a tailing off in the outer years of the ASX at the moment. But of course, you get events like Ukraine. Suddenly, that gets tipped up overnight. And so that's why we maintain that very long-term view of pricing. But of course, the ASX captures those near-term risks which just continue to surprise us all. Okay. Thank you. And next question I just had really was just around an update on the tender process that you did back in September actually and how that's going and when we might hear something on that. On the CFDs? Yeah. Yeah. We have got one that we're looking to progress, my understanding. Obviously, the other topic was sort of that was done pre the delay of Tauhara. So then we had to adjust. We had less fuel to sell. So we've sort of adjusted for that. My understanding is we are following through with one of the proposals that was put to us. Yeah. Yeah. Okay. Thank you. And last question again was just I think you alluded to it really on the January ops stats were very strong. I think rolling 12-month EBITDA is I've got as circa sort of 660-ish. I can't remember the exact number. But it's sort of in that sort of order. So you've still got, I guess, it looks like quite a significant headwind you're expecting to come through in the later months. Or is there a degree of conservatism built in? I would love to say that. I mean, as you know, market can change very, very quickly. The numbers that we put together were before the January result. So I can give you that in terms of context. That's helped us understand them a little bit more. But yeah. As I said, we have got more acquired generation and at a higher price in the second half of the year which does offset some of that benefits we had in the first half. That's all from me. Right. Thanks for the chance. A few questions. I'm just going to scratch a little bit at the 110-120 question as well. Different angle this time. I'm presuming you're giving us sort of a baseline, a TWAP price at Otahuhu. Obviously, the low generation option's being thought about in the South Island. And we see a very large spread between the North and South Island in the ASX today. What do you think the equivalent price is in the South Island? Well, I should just say we're a buyer of the South Island. So yeah. There is a current spread which tells us that people are assuming there's going to be a lot of renewables built down there. And they don't believe the demand story as much. We do believe the demand story. And you do need a higher price of carbon. But we think that will come. But there's enough examples that we've got now with the Fonterra process that's going on. I mean, you go through other market participants and their investor presentations. And they talk about all of the process heat conversions that they've done in the South Island. A lot of that still needs to come online because a lot of it's to do with these boiler conversions which take time to operationalize. And then obviously, you don't need all of the you can still have more demand coming on in the North Island which will ultimately support natural gas prices as well which you can see through data centers. The electric arc furnace looks positive. And I think actually, they've got more scrap steel than expected. So there's opportunities around that with New Zealand Steel. So we see a lot of stuff which gives us comfort that the demand growth is going to happen. But I'd caveat that that we would like to see the carbon price escalate quicker. And I think that will happen as well. If it doesn't, then we're going to struggle to hit our carbon reduction targets as a country which isn't an option that anyone wants to consider. So I think everyone will do what's required. And renewable energy therefore grows accordingly. So to just follow on to that. So confirming then that basically, your thinking is that you're going to see that basis spread shrink over time. When you say 110-120, are you thinking nationally? Yeah. We base it on Otahuhu. But we do see that spread shrinking a bit over time. Yeah. And in terms of the carbon price, I mean, what kind of number do you have in mind? I'm expecting it to escalate rapidly over the next sort of five years. 100, NZD 150, NZD 130? NZD 130. That's the sort of price that we see is required to get sort of economic-based switching now that you don't have corporate welfare, if you like, supporting conversions. Great. Thank you. You mentioned with the Stratford units sort of changing perhaps their operating model and putting more work, intense work into them. How should we think now about the annual operating costs and annual OpEx of those units? It's more about changing the modus operandi where we slightly restrict their output. We don't ramp them up. We've been ramping them up perhaps faster than we needed to. It's changing the operating. We're not expecting an impact on the operating costs per se. It might be. There might be an impact on standard business CapEx. We need to work that through but not in OpEx. And as Mike said, it's more around actually the GWAPs that you get from dispatching peakers might drop a little bit because you're not operating quite as flexibly. You might lose some ancillary income because you're not in the frequency-keeping market or that sort of stuff. So they're the sort of topics. And what kind of ramp rate changes are we talking about? It's just when, as you come into a half-hour period, we may have gone without going into too much detail. We may have come up just a bit. But we can ramp it up a bit slightly what we were. Okay. Yeah. Great. Thanks. We're coming into a winter that those that prognosticate about the market are very worried about. What's your view on how winter 2024 is going to look? What should investors be looking forward to through this period? I think obviously, you're subject to the vagaries of the asset base of the market. But we are very comfortable, for instance, with how TCC has performed. We consider we have gas. We have the extension in hours. GT22's coming back. And so we're as ready as we can be. We're taking advantage of the HVDC outage to get some critical work done down south. And our geothermal plant is in good shape. So we're confident that we've done everything we can. There tends to be an industry worry about every winter which means everything goes fine. So yeah. That's right. Last one from me then is looking beyond next year. So it's all beyond this year. TCC gone. You've got two peakers. Start to think about how to cover dry winters. You've obviously had your competitor talking about biomass capable units. Would you participate in a tender if they can somehow make that sort of scheme available? Would you think about buying something? We always give it consideration. We're an active market participant. Previous tenders that have happened, we have actively considered if not participated. So yes. Great. Thank you. We'll go to the online questions. We have a few here from Stephen Hudson. One is just, is the current channel pricing of 140-150 MWh when adjusted for shaping location pretty much at your long-term wholesale price view? Or is there more to come? Remarkably, it is, Stephen. So obviously, as inflation goes up, it's a real-term price guidance that we've given. And so it allows for future increases of our gas price. This is Tom Termaat. What are the milestones or timeframes for the last 22 MW at Tauhara? The last 22 MW, once we've started it up and done the process testing and got an assessment of where the capacity is actually sitting, is going back in and doing some final piping modifications to de-bottleneck when you identify bottlenecks. So the ultimate is we have to shut down after one year from a statutory point of view. That's when you'd have any necessary modifications in place. 2025. Next one. You don't have a comment in the slide pack around your four-year trailing operating cash flow payout policy. Is this dividend basis under review after NZAS? Or will you just think about where in the existing 80%-100% range you will move to? We will. Sorry. Yeah. No, we don't at the half-year, we don't generally comment on that. It's a four-year thing. But no, the dividend policy is staying as it is at the moment. Yes, we said earlier, we will adjust that accordingly as market risk changes such as the Tiwai deal and also as more volume comes online such as Tauhara and Te Huka 3. Stephen, no change in that regard. Last one from Stephen. Do you think that falling PV prices recently have had anything to do with the largest buyer in the world, the US, banning purchases from the largest seller, China, due to the 2022/2023 forced labour-based import bans? Stephen, like you, I'm in the world of speculation. Probably yes. This one is now from Vinesh Nair at UBS. A 2-year build timeframe for GeoFuture from FID seems ambitious given Tauhara has taken 3.5 years. Can you give some color on how much easier the design site work required and build process is for GeoFuture versus Tauhara? I think the answer to that is it's not easier. It's not going to be easier. We've done a whole lot more work upfront. And so remember, pre-FID expenditure, we've estimated in excess of NZD 100 million. We've already spent NZD 30 million. We're actively drilling ahead of FID. We're doing a lot more front-end design. And so that gives us much more confidence in that 24- to 30-month delivery. Okay. And the second question from Vinesh is, you talked about incremental increases in EBITDA lifting the operating free cash flow meaningfully. Higher than 60% conversion. Can we assume that the increase in guidance for FY 2024 should make its way to the DPS for FY 2024? Or is a revised dividend policy likely to impact FY 2025 and beyond? I think we answered that with Stephen's question as the dividend policy at this stage remains as it is. The guidance remains as it is. That's all. Thank you. It looks like we have finished with our online questions. No more questions today. So with that, we'll draw this to a close. Thank you. Thank you, everyone.