Good morning, and welcome to Meridian's interim results presentation for the six months to 31 December 2024. I'm Neal Barclay, Meridian's Chief Executive, and with me in the co-pilot seat for the last time is Mike Roan, our CFO. I'm sure you're all aware that I'm stepping down on 30 June, and Mike will be taking over as CEO from then. And given this is my last results announcement for the company, I would genuinely have liked it to have been an event that was nice and steady and even a bit boring, but not to be. This time our profit announcement is packed with drama and even a little bit of intrigue. Now, if you put aside the operating result, I couldn't be happier with how our teams are progressing towards our strategic goals. Our renewables pipeline has strengthened considerably, and as of today, we have five consented projects in the Ruakākā and Rangitaiki Solar developments, the Te Rere Hau and Mt Munro Wind Farms, and a second battery at Bunnythorpe in the Manawatū. Despite a soft New Zealand dollar, the business case for all five looks solid, and we plan to get at least four of them to our board for an investment decision this calendar year, and once completed, these projects will add more than two terawatt hours to the New Zealand system. Our real challenge from here is one of human capacity, as we plan to take a number of these projects forward in parallel, but we have been working on extending our team for a few years now, and we are on good and solid growth path. Our retail team has also been through a massive transformation. 80% of all roles were impacted, and while we've created some new roles with a strong focus on enhancing our digital capability, all up the workforce in retail has reduced by around 10%. Despite the disruption, we've kept our focus squarely on the customer and developed a number of new retail propositions to help customers manage their energy consumption more efficiently, which will save them money and save them power, obviously, and enabling them to participate in demand-side grid management. Now, Mike will elaborate on some of those offers a bit later. And at a headline level, 50% of our customers now have access to new, smart, time-of-use products. We've also continued to grow our retail business, and retail connections are up 5% since June 2024. But regardless of this progress, our operating environment has been as challenging as I can recall in my 17 years in the business. Meridian's financial performance for the full financial year will be materially impacted by the events of last winter. That fact has been clearly signaled through our monthly operating reports and also at our annual profit announcement last August, when the impact of last winter was already pretty apparent. Now, the underlying theme in the sector is of the rapid decline in gas availability, which has impacted the reliability and cost of gas-backed hedges. It's quite clear that these costs have flowed through to the ASX forward prices. Compounding the situation has been a unique and challenging hydrology pattern since May last year. An extended drought from May to August led to historically low lake levels. Then it rained excessively through September to November, causing spill across all of our catchments. Since December, hydro catchments across the entire country have experienced another extended drought. As of today, whilst national storage levels are within the realms of normal, the outlook remains dry. Accordingly, at Meridian, we are again taking a cautious approach to storage management and have called on various hedge arrangements, including our 50-megawatt swap with Nova, the 25-megawatt HFO with Genesis, and a new 50-megawatt demand response agreement with NZAS. Now, true to recent form, both of those thermal-backed hedges have been suspended to some degree due to various physical constraints, but the energy available is effectively reserved at this point, and that will help us manage lake levels until the dry conditions break, so in summary, to date in FY 2025, we've either been in drought conservation mode or flood management mode, and both of those put pressure on the company's financial performance. We've said it before, and it's true. These eventualities can and do occur. It's relatively infrequent, fortunately. And that's why we maintain a conservatively geared balance sheet and why we also look through the near-term results when assessing the dividend. And despite a dip in cash earnings, the board has declared an interim dividend consistent with last year. So, by way of recap, significant and inadequately signaled gas shortages emerged during 2024. That, combined with particularly low hydro inflows across the country and unseasonably low wind, caused wholesale prices for electricity to lift materially throughout the winter. But there was little risk of an energy shortfall, and the market responded to these high prices by delivering physical responses that ensured energy security was maintained while exerting downward pressure on prices. I mentioned at our annual results announcement last year that those of us old enough to remember when the lakes were last that low in 1992, the country saw rolling brownouts. In 2008, the lakes were nowhere near as low as they reached in 2024, and yet we had a public savings campaign. This is certainly not where we're at today, and I think the sector does deserve some credit for that. Meridian did the heavy lifting on these responses. We incentivized NZAS to reduce demand and made that energy available to other users. And we underwrote gas purchases from Methanex through hedge contracts with other generators. These actions were necessary to mitigate the risks and came with significant cost. All up, that cost was around NZD 200 million for Meridian. The spot prices at the time gained a lot of media and political attention, and they still do. But who took the brunt of them? No one more than Meridian. We took a hit for New Zealand. The only consumers affected by those high spot prices were those that chose to go into winter unhedged. There seems to be a common misconception held by many market commentators that generators are just sellers and are incentivized to drive wholesale prices up. The reality is usually entirely different. Meridian is often a net buyer, particularly during droughts, and our incentives are usually to keep prices as low as possible. But we do understand the risks, and we accept the financial impact. We put security of supply first, and as New Zealand's largest renewable electricity generator, our balance sheet tends to underwrite the mitigation of extended droughts for all consumers. That's one of the ways our country benefits from having large and financially strong gentailers. Amongst the commotion that ensued, there have also been suggestions that the large gentailers are failing to invest in new renewable solutions, thus causing the issue. I think those suggestions are disappointing and not consistent with the facts. This graph shows the level of investment that has gone into the generation sector in the last 15 years. More than NZD 10 billion in total, mostly in renewables, meaning that the system has lifted from around 65% renewable to around 88% renewable in normal hydrology conditions. Clearly, a lot more investment is required to decarbonize our country, but developments are being racked and stacked through the RMA system, and the run rate of new projects coming to market is lifting further. To date, this investment has occurred in the absence of any demand growth and in the absence of any form of government incentive. Investment in renewables has been driven purely by the economics, and that is relatively unique compared to other energy systems around the world. Actual demand growth as the economy transitions to electric will invariably incentivize and pull through even more investment. And just a little side note, despite the challenges last year, the system burned less thermal fuel than we have in any previous and mostly less severe droughts. And while I'm in myth-busting mode, I thought I'd share some data on how the electricity system in New Zealand stacks up compared with other countries in terms of the trilemma of affordability, security, and sustainability. The data presented in this slide came from a recent report produced looking at New Zealand's energy security options. While no one is happy with wholesale electricity prices at their current levels, when compared with most countries in the world and many of our key trading partners, the prices consumers pay for delivered electricity in this country stacks up very well. In respect to security, we're there or thereabouts, and from a sustainability perspective, we are an out-and-out leader. The key point is most energy systems around the globe are struggling with aspects of the transition to a low-carbon future. And New Zealand is performing well in that context. I know New Zealand loves a tall poppy, but we should celebrate an electricity system that's punching well above its weight, in my view. Like many parties, we've been contemplating whether these high wholesale electricity prices are becoming a structural issue. I think yes and no is the answer. When you look at average inflows over the course of last year, 2024 looks remarkably unremarkable. But when you break it down into seasons, the story is very different. We've experienced a record-setting drought, followed by a record-setting wet period, followed by another record-setting drought. Given the relatively small size of New Zealand's hydro catchments, these weather events have been extremely challenging to manage. But volatile weather is part of New Zealand's climate, and there's nothing to suggest that there's been a structural change in the weather patterns. More, we've just copped a few extremes in succession. The decline in the gas market, however, is clearly structural, and it will take some time to overcome, at least another couple of years, I think. Beyond that, with the pipeline of new renewables and battery systems likely to be built, with confidence that the Huntly Rankines will remain part of the system for the foreseeable future, and with further demand response opportunities, we should start to see a reversion to the long-term trend in wholesale prices. But there are two immediate opportunities that need to be addressed, and we think both or either would have a significant softening effect on market prices right now. Firstly, if Methanex can be appropriately incentivized to offer the electricity system a transparent and enduring interruptible arrangement at a reasonable price, that will reduce risk and help immensely. We understand conversations are underway between Methanex and the thermal generators, but as of today, an enduring arrangement has not been struck. Secondly, there are more hydro resources physically available, but a combination of system rules and consent restrictions means the market can't count on that additional hydro generation, even in extreme circumstances. While hydro still makes up 60% of the country's electricity generation, only about 23% of that capacity can be stored, and Meridian's own storage represents just 15 weeks of our average generation. So loosening up these restrictions is the lowest cost option for the sector to take the heat out of the energy component of electricity prices and to allow time to work through the pinch point that the demise of domestic gas has created. The main problematic and unnecessary restrictions relate to what is termed contingent hydro storage. The current rules that allow hydro generators to access around 830GWh of additional water have evolved sporadically and do not work, and that they create an infeasibility, so contingent storage cannot be accessed unless Transpower intervenes in the market and increases the South Island hydro storage buffer. The infeasibility became very apparent last winter. Now, at that time, Transpower responded to the situation by temporarily increasing the hydro storage buffers, but it was late in the piece, and going forward, this provides no certainty as to how they may react in future drought situations. We have a security supply regime that we believe is not fit for purpose and does not give participants confidence that contingent storage will be available when it's needed. Now, we're working on this with Transpower and the Electricity Authority and government officials, but as yet, the situation has yet to be resolved. Now, getting confidence that contingent storage will be available when lake levels get to extremely low achieves two outcomes: provides larger lakes for hydro generators to work with, meaning they will likely target lower average lake levels, meaning they will avoid spilling water during high inflow events, meaning they will generate more hydroelectric energy and therefore, A, reduce our country's carbon emissions and B, reduce the cost of electricity to all consumers. It's really that simple. The changes we're seeking will not create an environmental issue because the contingent levels are still highly unlikely to be used, and it will not increase the system security risk as hydro generators are heavily incentivised to manage storage conservatively and not run out. In particular, and speaking just for Meridian, we will still seek hedges from thermal operators because the model cost of using hydro contingency will still exceed the reasonable marginal cost of backup thermal. I think common sense will prevail. I'm just hoping that happens before I leave this job. Now, last winter, both the government and the electricity regulator came out with freshly worded programs focused on the electricity sector. For the Electricity Authority, these are generally extensions of existing work areas, albeit with some additional fallback measures which could signal stronger interventions. The government published an energy policy statement in October last year, and it's something we support. It reinforces market settings and the role of the government and the regulator, and it appears to set some ground rules for the Ministerial Review that's currently in progress. But most of what has been announced does little, if anything, to address the immediate issues that were the underlying driver for the 2024 situation, which is fuel scarcity. The fundamental issue is how the electricity sector further responds to the gas supply decline and low confidence in the future of the gas industry. And that's against the backdrop of very asymmetric transparency of hydro and coal storage and electricity hedge contracts compared to their gas equivalents. Now, I've talked about what I see as the most immediate and logical initiatives to address the fuel constraints ahead of the next couple of winters. It remains critical the sector gets these done as renewable electricity will support the decarbonization of a large chunk of New Zealand's non-animal-based emissions and drive lower energy costs for all Kiwis. I've no doubt that these outcomes will be achieved. It makes economic sense, and it will provide a degree of energy dependence for Aotearoa. We just must stay the course. Now, customers across the country are about to see price increases come into effect from 1 April. For Meridian's customers, 80% of those increases will come from Commerce Commission-approved increases to transmission and distribution prices. These price changes will be acutely felt by many customers, and so our team are looking at all the ways that we can lessen the impacts, including introducing smart products to save power and money and further use of our energy wellbeing program. Now, while the Commerce Commission's process allows for some investment in the resilience and growth of networks, most of the cost-increase customers will bear goes back to past levels of inflation and interest rates. As we look forward, given we see the need for massive grid investment, potentially as high as NZD 100 billion by 2050, we think the five-year pricing reset mechanism that the Commerce Commission seems to favor will lead to significant price fluctuations that will ultimately land on consumers. We think that approach needs a fundamental rethink. Now, as you're probably aware, we've been operating at reduced capacity at Manapōrī for around two years following the discovery of faults to two of our seven transformers. We landed a replacement transformer at site back in October. That was no easy task, and it was the first time we've transported a piece of equipment that size by barge across the lake. As you can see by this photo, it wasn't a great day to be out on the water with 104 tonnes of transformer on board, but it did arrive safely. Now, that unit is now fully installed, meaning 128 more megawatts are available at Manapōrī, lifting station capacity from 640MW to around 768MW. Now, while we're still a unit down at Manapōrī, the seventh unit largely provides for redundancy as total station output is limited to 800MW under its current consent conditions. We've procured two new transformers from a different supplier to diversify our supply chain. The first of those is due to arrive in late 2025, and the second will arrive in 2026, and it will be held as a spare. Our West Wind Farm outside Wellington has also returned to full capacity in October following installation of a leased transformer from Transpower. A permanent replacement will be in place later this year. Now, onto a bit of the good news as well. The first grid injection of our Ruakākā Battery Energy Storage Facility occurred on 16th of January, and it will be fully commissioned in April. The battery has had a decent commissioning period, and being the first grid-connected battery of this size in New Zealand, we and Transpower have learned a lot. We think we can largely apply a cookie-cutter approach to our next battery at Bunnythorpe. We're still sizing up that option, but conservatively, it'll be at least 100MW and 200MWh. This month, we announced that we've obtained a final Ruakākā Solar consent, and that project is now on track for investment decision by our board next month. The Te Rere Hau Wind Farm investment decision is expected in June 2025. Our offer to buy the remaining 80% of New Zealand Wind Farms' shares was enabled by cheaper finance opportunities available to Meridian versus the JV, plus some other synergies. Given the scheme of arrangement that has been put to the shareholders of New Zealand Wind Farms, included a 105% premium to the market price the day before our offer became non-binding. Because we have the support of the board and other major shareholders, we expect that scheme to be approved. In December, we announced the JV with Nova for the 400MW Rangitaiki Solar Farm, including a 50/50 offtake arrangement. An investment decision for the first 200MW development of that project is expected in April. We received the final consent for the Mt Munro Wind Farm through a relatively torturous Environment Court process, and I'd say that was for all parties concerned. Pleasingly, the project secured consent for all 20 turbines that were included in our application. Also this month, we signed a PPA for 100% of the production from the 150MW Tauhei Solar Farm. This agreement demonstrates how new entrants to the electricity sector can and are working with existing participants like Meridian to deliver commercially viable, independent electricity and increase market competition. On Waitaki reconsenting, the evidence exchange process starts in May, and an Environment Court hearing is likely to be in the final quarter of this calendar year. Now, a picture tells a thousand words. Our renewable development pipeline looks significantly stronger of late, given the number of successful consents we've been granted. This pipeline will see us commit around NZD 1 billion to future developments this calendar year and at least NZD 3 billion by the end of the decade. Now, as I said at the start, Meridian's strategic momentum continues to build nicely. Now, if it just weren't for the pesky weather, everything would be sweet. I'll hand over to Mike now to talk through the numbers. Ngā mihi, Neal, and [Foreign language]. Thanks for joining the call this morning. Now, it'd be usual for me to jump into the financials at interims, but first-half performance, as Neal mentioned, was anything but normal, so I want to build on Neal's commentary regarding gas before we get going, as it needs additional airtime, and this slide's the perfect way to do that, as the graph on the right is particularly insightful. That graph starts at 2018 for a reason, because before 2018, the electricity and gas sectors were reasonably boring. Now, that isn't really true. The electricity sector has always been interesting. But what was true was that New Zealand had a world-class electricity sector before 2018. That was borne out in every piece of evidence you could find locally and internationally. Interestingly, if you look at the international comparisons that Neal tabled, that remains the case today. This country is a world-class electricity sector from a pricing, sustainability, and resilience perspective. We should celebrate having an electricity system that's punching above its weight. But if you look at the emerging local tensions, then you might reach the conclusion that things were different. The graph on the right largely explains why. This is because it plots electricity prices against spot gas and coal prices. And while the coal price doesn't explain electricity prices, the gas prices, for the most part, do. If you focus the grey matter on late 2018, gas and electricity prices spiked on the back of deliverability challenges at Pohokura. In the subsequent five years, the graph suggests that gas issues have continued. Now, I'm the wrong person to explain what drove each of the spikes, but they clearly show that the gas sector has struggled to supply molecules at prices that were available pre-2018, and those increased prices flow through to the electricity market, as gas is often the marginal fuel in our sector, particularly during periods of hydro drought. You could say that the cost of gas is discovered via electricity markets, as gas prices can be opaque at least compared to electricity prices. And if we roll into 2024, the drought that impacted our business directly exposed the gas sector's issues, as the swaptions that many electricity participants carry to ensure they can access gas were suspended due to the lack of physical stored or deliverable gas. If I put it bluntly, we discovered that the gas sector's struggles since 2018 meant it was unable to support the electricity in the same way it had historically. So over a very short timeframe, a week to be precise, we had to replace the suspended swaptions. And for a brief period, the electricity market had to rely on distillate while it negotiated with Methanex, who was incentivised to turn down consumption. That ultimately resulted in the release of gas to the electricity sector, but the cost was in the order of NZD 30- 40 per gigajoule if market analysis is correct. And that cost flowed through to wholesale electricity prices. The advantage of the wholesale electricity market is it's transparent in this regard. We don't have to like the outcomes, but prices simply reflect, and in this instance, reflect risk. And in this instance, spot and forward prices are reflecting the unaffordability of gas. For now, the government and regulator are focused on competitive issues within the sector, and that's always a useful thing to do. But it would be hard to find a media story about winter 2024 that didn't talk about spot prices, and they were driven by a lack of gas, not a lack of competition. And that lack of gas needs attention from both regulators and politicians if we're to bring electricity prices down. Finding alternate, cheaper forms of energy should be the priority number one for all of us. Now, wholesale electricity market participants have been onto this since last August. As soon as we worked out that the gas market issues were worse than expected, we started working to secure alternate fuels and fuel storage in attempts to manage both the electricity price impact and security of supply. Examination of an LNG terminal was the first move. Unfortunately, today, it looks a little more difficult and costly than initially expected. So more recently, the Huntly Power Station heads of agreement and Meridian and other generators' request to free up hydro storage have followed. Anyone who's operated in our sector will know that there's no magic bullet that will fix the gas sector's challenges, but more coal and hydro storage will help, and the recently renewed focus on increasing New Zealand's hydro stores may prove more valuable than it appears, and the reason for that's actually simple. Hydro storage or water is a low-cost resource that has no emissions, and it doesn't link the country to global gas, coal, or oil prices. It's also something that New Zealand has plenty of and other countries do not. So if we're able to extend existing hydro storage lakes, wholesale and forward prices will come down, and this asset can create durable competitive advantage for our country. The good news is that increasing hydro storage can be done reasonably quickly if we have the collective will to make it happen, as we're talking consent changes as opposed to infrastructural ones for the most part. Neal presented the obvious opportunity. Lake Tekapo and Lake Pūkaki, New Zealand's largest hydro storage, have an additional 765GWh of storage, or 20% more storage than currently exists across all controlled storages in New Zealand that can't be used as part of their normal operating ranges. To date, it's been thought of as contingent storage, that is, use it only when we have to. Well, that contingency occurred last August. The country lost access to affordable gas, and we need to mitigate the increases in wholesale prices that have been experienced since. This change can't happen fast enough. New Zealanders are rightly proud of our country's hydroelectricity, but when only 23% of that capacity can be stored, we can't afford to ignore an easy way to increase it. 2024 showed why. For Meridian, our total lake storage equates to only 15 weeks of average generation. So we're engaging with Transpower, regulators, and politicians to try to make this happen. Now, the above is not a doom and gloom story, far from it. It's just a call to action. And we've got the solutions at our fingertips, but action has to play out soon. And while we're throwing the kitchen sink at new renewable investment, that investment will show up in two to three years. Prices here and now need considerable attention to support economic growth, and our country's fortunate to have additional hydro storage that can be tapped to do this. You'll hear and see more from me on this topic over time, but for now, I'm going to step back to being CFO and talk to our financial statements. And to kick things off, I'm going to talk about operating cash flows and EBITDA. There's no escaping the fact that when a renewable electricity business doesn't receive fuel, it can't make as much electricity as it had expected. And the risk products we lean on during such periods come with a cost. The first-half numbers reflect that. When compared to the first half of last financial year, operating cash flows fell by NZD 253 to 50 million. That's a very small number for us. And EBITDA fell by NZD 186 to 257 million. As Neal said, we took a hit for New Zealand and its security of supply. If you look at Meridian's history since listing, as the graph shows, the graph on the right shows over a shorter timeframe, up until this financial year, both measures have lifted incrementally over each operating year. And while our operating teams have had to manage droughts over that time, the last time a drought as large as 2024 occurred was back in 2012, before this company's listing. The reality, of course, is that droughts are inevitable, and this was the year a big one emerged. And it put a big material dent in operating cash flows and EBITDA. The good news for our shareholders is that Meridian's financial structure has been designed to accommodate a large drought and continue to maintain dividends. So let's move to that topic. Recognizing that droughts are inevitable, the dividend policy and balance sheet have been designed to support dividend stability even in the face of substantial operating cash flow disruption. So while operating cash and EBITDA are well down, we're able to maintain an interim dividend of NZD 0.0615 per share. The dividend will be imputed at 85% and paid to shareholders on the 25th of March. We're also applying the dividend reinvestment plan to this interim dividend. And if you choose to participate, you'll once again receive a 2% discount to market for the shares purchased. EBITDA fell by 42% on the first half of last financial year. As you can see from the graph, the main reason for that was energy margin or operating performance. I'll break that down shortly, but the other smaller drivers of the fall were increases in operating costs, metering expenses, and transmission costs. I'll also pick up on operating costs shortly, but the rate of increase is slowing, and it's lower than I forecast it might be last August. And that sees us reducing our full-year operating cost guidance. But right now, let's talk energy margin. Energy margin fell by NZD 185 million when compared to the same period last financial year. As Neal and I have already canvassed, this is driven by the lack of rain and wind that had to be replaced by demand response and swaptions. You can see from the language on this slide the cost of these instruments was substantial, NZD 200 million to be precise. Those payments are not a typical feature for our business, fortunately. They will emerge in years where we're unable to make as much electricity as we'd like. Having companies like ours big enough to weather the storm is the benefit to New Zealand of having gentailers. The demand response payments are not too difficult to break down. They represent payments to NZAS for exercising all four blocks of the demand response agreement with them. NZAS also provided an extra 20MW of response and ramped down quicker than was required under the contract. A quick thank you to the team at the smelter. Time and again, they've showed a willingness to work with us to put the interests of Kiwi homes and businesses first. That's something we really appreciate. I noted that the gas swaptions that we held were suspended, and we needed to buy new contracts at much higher gas prices to replace them. I can't go into too much detail on these, as they're all confidential, but the increase in strike price between the initial contracts and the second set was NZD 230- 250 per MWh. So you can see why we're concerned about gas moving forward. Now, I want to move to customers. Mass market customers continue to switch to Meridian, as evidenced by increasing mass market sales volumes, even as prices lifted. While overall customer sales volumes fell 56GWh when compared to the first half of the last financial year, the reduction was driven by overall portfolio constraints. As I mentioned, price increases. Residential prices will increase more than usual this year, given Commerce Commission-approved increases in transmission and distribution rates of return. As Neal noted, to help soften the impact on customers, the retail team has been working on a suite of new products. They're accelerating the rollout of a smart hot water product across both brands. This will help customers save money by shifting hot water cylinder heating to off-peak periods. We'll take a reasonably chunky fixed amount off their monthly bill for the right to do this for them. We also have smart charging and four free products. The charging product uses technology to shift EV charging to low-price periods, whereas the four free product gives customers the ability to seek four free off-peak hours of power. Good for customers, particularly in the face of rising prices. But getting to this point has meant a lot of work for the retail team. They've had to reorient their operating structure, and they're currently looking at the technology suite that supports them. We unpacked this at the Investor Day last May, and we'll do so again as things continue to progress. But the key point is that bringing new products to market and at the same time reducing the cost of supporting those customers. It is impressive stuff. And one of the reasons we're able to limit price increases to customers for the electricity portion of the bill. And customers are already responding to our shift in retail approach with record numbers signing up. As of the 1 January, we've achieved our highest ever market share of electricity connections, with 16.6% across the Meridian and Powershop brands. Our brands also led the power industry rankings for new connections in December, with Powershop first and Meridian second, and more than 4,000 connections that month across both brands. Now, there isn't too much on this slide that Neal hasn't already covered, but hydro production volumes were 11% lower than in the first half of the previous financial year, even as average generation prices lifted. Wind generation volumes increased due to the commissioning of Harapaki and a return to full capacity at West Wind. This doesn't really tell the full story, though, because if we had known that it was going to rain cats and dogs in September, we wouldn't have exercised the swaption contracts in August. It actually hurts a lot looking back on it, but that's the problem with the future. You don't know how it's going to play out, and anyone who relies on weather forecasts knows that you can only see three to seven days ahead. So knowing what's going to happen next month is unfortunately unknowable. Now, don't show it here, but we're dealing with similar challenges this month as a result of the new drought that's emerged. The wholesale teams executed swaptions, and we entered into a new demand response agreement with NZAS this week. Time will tell whether these decisions were necessary to support this winter's electricity security, as there's still plenty of time for it to rain. But given the cost of relying on gas, we don't want to look back and be left wondering. This does mean that February energy margin delivery will be impacted, as will likely early March, possibly to the tune of NZD 25 million. Further out, it's too difficult to call today. As signaled last August, operating costs continue to lift. However, they've not lifted as directly as expected, as I touched on earlier. The graph at the bottom right provides detail on the increases. We paid our people NZD 3 million more to ensure they're compensated competitively. As the Harapaki wind farm was commissioned in August and we restored one transformer at Manapōrī, asset maintenance costs lifted by NZD 3 million. There's also a lot of change going on within the business. We're replacing our finance systems. The retail team made a material adjustment, and the development team is really starting to push projects through the consenting process. Each of these changes requires support from our ICT team and the backfill of people who are committed to those projects. So contractor and ICT costs lifted NZD 5 million between them. Of course, change should also reduce costs, and the two million reduction in cost flows from the retail team adjustments. Given how first half cost tracked, we've reduced operating cost guidance from NZD 302-308 million to NZD 298-304 million. Now for CapEx. At the start of the year, I suggested we might spend between NZD 295 and 325 million. That's looking more like NZD 220-250 million today. The primary reason for this is that the Ruakākā solar farm has been pushed to late FY 2025, given consenting delays. You heard Neal say that we'll take this project to the board for final investment decision in March, and the economics look good. So it will get built. Over the coming months and well before the end of this calendar year, you'll see us land Te Rere Hau, the first stage of the Nova Meridian 400MW solar farm, and potentially the 90MW Mount Monroe wind farm. All up, we expect to commit well over NZD 1 billion of Capex to support these developments this calendar year. At a net profit after tax level, the first half result was just as ugly as it was at cash flow and EBITDA levels. As I've said any number of times, net profit after tax moves around as a result of unrealized fair value movements in electricity and interest rate derivatives. So stripping these out is important to get comparable year-on-year performance. That's why we provide a non-GAAP measure underlying net profit after tax in an effort to remove the effect of unrealized derivatives. But that measure was just as ugly, and across all financial measures confirms what's been and is a difficult year. I'll leave it to you to pick through the detail that might help explain where and why things didn't play out that well, but I can tell you what happened. We didn't receive fuel when we needed it. There isn't too much to talk to on this slide, although you can see the impact of a poor financial result on spot net debt to EBITDA ratios. For anyone concerned that this might impact the credit rating in some way or test our financial capacity to develop assets, it does not. S&P used net debt to EBITDA ratios that spanned three years to assess our business, as they know what we know. It's performance over time that matters, and droughts are part of life. The only other thing I'd say about this slide is that funding lines are well diversified and that we'll be going to debt capital markets to support development of our assets. And that'll keep our bankers and ultimately shareholders happy. So to summarize all of that, it was a challenging six months for our business, one that thankfully we don't experience very often touch wood. At the same time, the electricity sector learned something important and difficult in 2024. That is, our reliance on gas as a transition fuel, or at least an affordable transition fuel, was potentially misplaced. It still has a role to play, but that role is diminished as the cost of securing that fuel to make electricity is too high. And it's unclear whether the physical molecules are available anyways. The industry and country have some challenges ahead, but we've begun to tackle them. And if we can unlock more clean green domestic hydro storage while investing as fast as the consenting frameworks will allow, then we'll overcome those challenges, and the electricity sector will be able to drive competitive advantage back into our exports. Now, before finishing up, I wanted to talk a little about this fellow sitting next to me. As he said, this is going to be his last results announcement, and while I'm looking forward to sitting in that seat and leading off at the next one, it wouldn't be right if I didn't spend a little time starting to frame up his legacy. I think it's how he led our business through a very uncertain period driven by the termination of the NZAS contract. And to provide some context for that leadership, even as our largest customer decided it was better to leave the country, total shareholder return grew by 170% over his tenure. Our retail team grew its sales volumes by 75%. The development team grew the pipeline that's captured in this pack and is now delivering development projects. And of course, that customer decided to stay. If that isn't a legacy, I don't know what is. But the thing I've admired the most is that thing there, kind of right there. I know a bit awkward, but it's that big beating heart of his. He not only delivered superb outcomes for shareholders and positioned the business for the future, but he's done it in a really open, constructive, and personal way. To be a great company, you must have a great leader. And you, my friend, have been exactly that. Now, you still have a few months to go, and you need to sort out the current drought before the new CEO steps in. But it's been a heck of a knock. [Foreign language]. The future remains promising due to the foundation laid by my predecessor. So back to you. And for those on the phones, don't hesitate to give them a hard time, regardless of what I just said. Well, thanks, Mike. I don't know how you managed to sneak that into the teleprompter. And I wasn't expecting to make a final speech this morning, but I do appreciate those comments. Hey, look, I'll just sum up and make a few concluding comments. I mean, clearly, to date, the operational conditions this financial year have been both challenging and abnormal. And our financial results for the six months to 31 December will reflect that. Whilst our hydrology model is assumed reversion to mean, mean hydrology never occurs, but neither does a severe drought followed by floods and then another drought. It's very unusual. So for that reason, the board are able to look through our current results and maintain a dividend at the same level as last year, recognizing the inherent strength of our balance sheet. The business has been building for growth for some time, and the number of consents received over the last few months provides Meridian with some awesome development optionality for the next couple of years. We're hiring capable development and construction people, and I think if you're in that game, Meridian will be the best game in town. I'm very interested and will remain very interested to see how our customer product set evolves, as there is so much untapped potential and demand side response. I think between us and NZAS, we've shown the potential, and as we make it simple and valuable for customers, they'll get on board. Also, and despite my new role on the Chorus board, I still think Meridian's decision to remain a pure-play electricity retailer will stand the test of time. I probably would say that, given it happened under my watch. I think, I mean, look, in a nutshell, the demise of domestic gas remains the issue for all of New Zealand, and it's not just the electricity sector. But certainly, from an electricity perspective, we need to resolve it. And solutions are emerging, but they're going to take some time. So I do think we need to seriously amp up our enthusiasm for enhancing the hydro generation available, even within the existing hydro schemes, and even beyond the contingent storage that we referred to a lot in this presentation. I think to do so, we'll lower emissions, we'll deliver lower energy costs, and it will do all of that for little or no additional environmental cost. The reality is, though, that the RMA process, as it currently works in New Zealand, will stop hydro enhancements dead in their tracks. So I think that's the big opportunity. The government has a role to play, and they can certainly help in that regard. So that's our presentation concluded. We can now move to questions. If there's any particularly tricky ones, despite what Mike said, I'll be just going. I think we'll go to the floor here in Wellington first. Hi, team. Neville Gluyas here. Is this working? Yep. Very good. Two quick ones for me and not about the current conditions. Just following on your point about hydro flexibility and taking points about contingent storage. The uncertainty around that, with the reconsenting on Waitaki still underway, what are the prospects perhaps for revisiting whether or not minimum flows can be addressed? That's sort of question one. And the second point is, obviously, you've got a stream of projects you think you're going to bring to FID very soon. Is there any reason at this point to think that we should be thinking about a longer, sorry, a higher, longer run price view than we've had in the past? Obviously, we've seen a couple of expensive projects inked recently. Just your comments on that would be useful. Thank you. Thanks, Nevill Gluyas. Look, on the Waitaki reconsenting process, we've got a strong strategy there. We're going through a process to get the whole scheme consented on exactly the same terms and conditions that it operates today. And we've got strong stakeholder support across the valley to do that. But I think, yeah, recent events will cause us to think about some aspects of that because there is more flexibility available in that scheme. And as I say, I think it can be extracted for no real environmental impact. So we're thinking heavily about that right now. Projects and prices. Look, no, I don't think so. We've sort of signaled our view of long-term prices and I can't remember the actual range. It's probably at strategy day. [Cross talk] But the projects we're looking and the ones we've talked to today are all well within that. In fact, they're all sub $100 comfortably. That's on a levelized cost of energy. We think the cost, I personally think, probably even more so than our models, that the cost of new renewables will come down even more strongly in the future. That's still to emerge. At the moment, certainly these projects are well on the money based on those forward projections that we gave at our investor day last year. Okay, if there's no other questions from the floor, then we'll go to the phones. Your next question comes from Vignesh Nair with UBS. Hi, good morning, Mike and Neal. Just a couple of questions for me. Firstly, just on DPS, what would we need to see sort of to see a step up, I suppose, in DPS for the full year? Sort of, if you look at what the market's expecting for earnings, sort of looking at 544 for the second half, and then obviously sort of normalizing into FY 2026. So it was somewhat surprising to see flat DPS, obviously given a tough sort of trading environment. Just wondering what we need to see to see a sort of growth year on year in DPS for the full year 2025. Oregon, Vignesh, that's an easy one, which is break to the current drought. You do know that we like stable and progressive dividend. You look at the long run forecast for the business. You forecast it as many others do, and we know that's possible. But you also know that we're a cautious and stable business. So we'll see how the rest of the financial year plays out. I'll just add to that. I mean, I'll have very little influence over the final dividend when it gets announced in August. But I will be w atching very closely. And I will certainly express my views on it before I leave the business. I'll be watching very closely. Yeah. And I suppose just following on from that, what sort of the timeframe that you guys have internally in mind to get back to kind of the target gearing range of two to three times set by, I suppose, S&P? On a normalized basis, you're kind of hovering well below that, apart from this sort of mild aberration with this result. How long does it take to get to that sort of two and a half style midpoint number from here? We see around that 2030 mark, Vignesh, but we're actually just recalibrating our capital affordability and our capital forecast. You heard the slug of investment that we've managed to move through that consenting process. So we're just recutting it. So I reckon that might come forward a touch. But somewhere in that timeframe is kind of where, and I'll know better at year end because we will have completed by then. We will have completed that analysis by then. It's good to hear from you, by the way, because I know you got cut off at our last results announcement, which was terribly unkind. That's all right. I thought I'd be first in the queue this time. And final question, just sort of qualitatively, wanted to hear your thoughts on sort of appetite for sort of PPAs from here, obviously with the Tauhei Solar Farm offtake. That was good to see. But you're sort of obviously running a physical short position ex kind of the ASX hedges. Just keen to hear what the appetite is from here for new PPAs. Yeah, so I mean, it's really simple for us, Vignesh, is we're looking for the most economic projects to be developed across the country. And we've got many within our development pipeline, but where someone shows up with a project that they're developing that we can support that fits into that economic merit order, is we're incredibly interested. So that's what Tauhei represented for us as an opportunity to move a project forward. And I guess the word for anyone else out there is you should be banging on our door to test the economic merits of your project, as you should be banging on other people's doors. So we're open to it. It's part of the development build is we want to get that economic, the best economic outcome we can for ourselves and for the country. Okay, that's very clear. That's all for me. Finally, congratulations, Neal, on a phenomenal career. Hopefully you get a bit of a break from here. Thanks, Vignesh. Cheers, mate. Your next question comes from Grant Swanepoel with Jarden. Good morning, team. First of all, Mike, congrats on your elevation. Neal, thanks for all your tutelage over the last seven and a half years. First question, just following on from Neville's long run wholesale price question. Contact came out and indicated that they're expecting it to move towards the top end of the NZD 115-125 range. Genesis and Mercury both came out and said they're similar to Contact. So you're the first company that's actually putting a downward pressure on that. Could it be because you're only really building or seeing costs of solar and when Tauhei costs start coming in, you might reconsider? And when is actually the problematic? No, we've got a pretty good gauge on Tauhei at this stage, Grant. And that's sort of looking, I think it's a mid-NZD 80 project, that one. So I guess we're seeing nothing in the cost of new renewables that's changed our view from last year. Obviously, the stresses and strains firming that in the New Zealand environment for the next few years are going to be challenging. And that's driving near-term costs, but probably not a factor for the long term. Could be something, Grant, in the. I don't think, Grant, just to clarify, my comments, my personal beliefs, there's a lot of people in Meridian that we model this stuff and we've given a projection on that. I fundamentally do believe the globe will find ways to bring the cost of these things down. That'll be mildly interesting, but not that relevant in a few months' time. We are updating our price forecast at the moment, Grant. So there's a piece of info for you there in draft form. They do sit at the top end of our range. So there is, I think there's a little bit of firming there. I think the difference between what we see and what others see is probably that impact of gas. How much gas do you expect to play out on the margin versus other sources of fuel? And you heard us talk directly this morning to our views on the unaffordability of gas. So as we start to strip that out, as we get support from regulators and politicians to remove that fuel to drive prices down, then we'll wait and see. The only other comment I would have is the draft price paths that we're working on, they do extend the price, the range I mentioned, a little further out. So that's probably the only two impacts. But I want to be clear, they're not material. Thanks, Mike. Next question, just you guys are arguing for extra storage access in your hydro. What is the process and the timeline to potential success? Well, when it comes to the contingent storage and the Waitaki scheme in particular, the process is quite simple. The system operator needs to make a change to what they call the hydro buffer levels in the South Island. That will give everybody confidence that when lake levels get to very low levels that we can access that contingent storage. It's within their degree of mandate or flexibility to do that today. So we should be able to work that through. Like I say, it's a common sense solution. The country needs it. And it actually just provides the market certainty. It doesn't create a security of supply issue at all, in my view. There are other opportunities around the rest of the catchments that require engagement with other stakeholders and working through some sort of flexing in the existing consent conditions and so forth. And we're in conversations about those. Unlikely to be achieved this calendar year, but certainly potential for sort of 2026 and beyond, I think. So Grant, maybe just add to that. Some can be done really quickly. Some require consents. The infrastructure's there, but require consent change. And some of them are infrastructural. But the key point you can take away is hydro should be on the table for the country given what we've seen play out in gas markets. That's the kind of key point. And we're dusting stuff off that hasn't been looked at in any number of years to particularly for those longer dated infrastructural developments. Thanks. And my final question back onto dividends. You changed your dividend policy at FY 2024 year end. And now you just use consensus, EBITDA and cash flow forecasts. Just to stick to last year's dividend, you'd have to be paying out over 100% of the adjusted free cash flow. So therefore, you'd be above your payout ratio just to hold dividends flat. Mike, you mentioned stable and progressive dividend going back to the old type dividend policy. Does that mean that that won't override in these sort of events that we're seeing at the moment? Yeah, there's some key words, Grant, in our dividend policy, which talks to 80% of free cash flows over time. So it's the over time element that matters that gives the board discretion to make payments in any calendar year that exceed 100% or are below 80% of free cash flows. And so that's the language that's kind of important in the dividend policy. So no changes to dividend policy or thoughts on dividend policy, just re-emphasis on that word. I think, as Neil mentioned, we don't see a structural change in inflows. We do see what's happened this year is extremely, I mean, he hasn't seen it. Neil said it. I haven't seen it in my career where you've had a substantial drought, substantial inflows, and then another substantial drought over a 12-month period. So when you see that, I think I come back to we're a stable, we're a low-risk business. We think about that quite carefully, but we don't see any structural change in the way that weather patterns are emerging in New Zealand or expect that they'll change. So I think dividend policy settings are still right. Thanks. Sorry, I do have one final question. Just on your battery now that it has started up, the first real one in the market, are you seeing that the returns you're making out of that are in line with your expectation? Or in this sort of environment, are you making decent returns straight out of that battery? And it's not fully commissioned to April, Grant. So we're not seeing any returns from it yet. The injections of power were mainly around commissioning tests. But certainly the modeling. Yeah, but the modeling suggests that the business case is strengthened from when we went to FID. Thanks, Neal. That's all from me. Thanks, Grant. Your next question comes from Andrew Harvey-Green with Forsyth Barr. Morning, Neal and Mike. I just had a couple of questions, I guess, around some of the key takeouts from the last six months and what it might mean going forward. First one is, should we assume that the last half was pretty close to a worst-case scenario? And then if you had a repeat going forward, I guess your learnings and hopefully you wouldn't necessarily be exposed to very high market prices, that the financial outcome should be better in a similar scenario? Or is this kind of new normal for a really downside scenario? I think it does set a new marker, Andrew. Could you ever say it's worst-case? I don't think anyone would be bold enough to say worst-case because the distribution is what it is, but it's been pretty bad. The challenge, so as you look forward to the end of this year, does the first half set any form of precedent for where we're going? I don't think I could say, Andrew. I don't think I could say whether that's realistic. I talked to weather forecasts being only knowable three to seven days in advance. So I think I'd be wrong to try and give a financial forecast. But your point and one that I totally agree with, it was pretty horrific. So it definitely sets a new benchmark. Yeah, but I would add to that, Andrew. Yeah, and I think where you're going with this is we did learn. For example, the suspension of the thermal swaptions that we talked about was a surprise to our business. So we're well alive to that now. And whilst we understood there were some glitches in the rules around access to contingent storage, it became really, really stark and right in front of us last winter, which is why we're trying to get that addressed well ahead of time. So yeah, I think if we had that same circumstance turn up again, we'd do better next time. But it wasn't hydrology-wise; it was pretty extreme as well. So we don't expect that to continue. Yeah, yeah. I guess the second question, which is kind of related, but we do all our forecasts, I guess, on a normalized hydrology basis, which in essence is coming up with a median number. I guess my question really is, is the average when you do all of your simulation sequences for various hydrological, both positive and negative, is the average significantly average EBITDA come significantly different to the median now? No, there's a small deviation, Andrew, but no. We'll have to wait to see how this latest series of events plays out. But it's just not a big enough piece of the historical trace. So no, I don't think it changes the relationship that meaningfully. Yeah, okay. No, that's useful. And to be honest, quite relieved in terms of forecasting this sort of stuff. Just a final reiteration of the comments and all the best for the future. Yeah, thanks for all of the efforts you've done over the last number of years. Obviously, knowing you a bit longer as well. So yeah, all the best and to, I guess, the boards you're on as the next key thing. Yeah, thanks, Andrew. Appreciate it, mate. Your next question comes from Stephen Hudson with Macquarie Securities. Morning, Neal and Mike. Just two, I think, from me. Neal, you mentioned you'd seen some investments in your development team over the period. I just wondered if you could give us a feel for sort of the team size and what kind of changes you're implementing there. Well, actually, the team's like, "God, I'll tell you what, I'm seeing new faces around every week." And it's a bit embarrassing because I don't know them all as well as I should, but it's. So it's not as big. We had 52 people in the development team back in 2012, Huddy. And there's about 30 people in the team today. So not as big as we were. Where we have more recently, so we've seen, I mean, you see it in our development pipeline, the progress that we've made. That was where we were adding people initially is to get out there, look for the options, assess those options, and build the consent framework for it. Where we've started to bolster the team more directly is in the constructability and construction of those developments because we can see them coming at us. And so even at our best, back at that period I mentioned where we had a larger team, we were only ever able to develop one asset at a time. As we're now confident that we can deliver two, we're working on three. And you heard Neil and I say we might have four going at any one point in time. So there's one particular individual in our organization that you'll probably get to know. His name is Chris More, and we're looking forward to how he develops and delivers these assets. Yeah, we've developed a sort of a hub and spoke type model for a construction team. So there's the core capability project management leadership fundamentally in a core team, and then we can expand teams into various projects with that overarching leadership coming from the hub side of things. So we think it's scalable, and it'll have to be. That's useful color. Thanks, gents. And just the second question, I suppose we're 18 months away from a general election here in New Zealand, sort of three-year electoral cycles, but 30-year asset lives upstream and downstream. You've been having conversations with politicians. Can you share whether your confidence, if any, in particular, the opposition parties get the whole thermal fuel scarcity issue and what needs to be done or not? We don't have a clear bead at the moment on where the opposition stands on that. I think we remain engaged with them and we'll continue to sort of develop those relationships. But I think if there's a plea from anyone for our politicians, it's some of these long-term policy initiatives do need to be supported from across the house. We need bipartisan policy settings that are going to take this country forward. If we're sort of lurching around whether we can allow domestic gas or not allow domestic gas, it's going to create the sorts of problems that we've seen this year, last year, and are seeing. That makes sense. And just to add my voice to the others, Neal, congratulations on your 17 years and we'll miss you. And thanks very much for your help. Thanks. Very humble. There are no further questions at this time. Sorry, I'll now hand back for closing remarks. Okay, well, I think that concludes the presentation, the questions. Thank you all. Like I wasn't going to say a leaving speech today because I've still got a few months left in this job. And while you've seen this guy who likes to cut over me and answering questions, that's what I'm going to have to put up with. But it has been a privilege to be able to talk to investors and others at these sorts of events, talk about our plans, talk about our successes, and also our challenges. So I will certainly miss it. Thank you all. Cheers.