Meridian Energy Limited (MEL) Earnings Call Transcript & Summary

[Foreign Language] Good morning, everyone. If you're new to Meridian's profit announcement, I'm Neal Barclay Meridian's Chief Executive, and I have with me Our Chief Financial Officer, Mike Roan. We will talk through aspects of the financial results for the last year, and we'll also provide perspective and context for the current market conditions. On balance, we think the business performed strongly during FY '24 across the board, and we knocked off several major milestones. The top of that list was the long-term deal struck with the New Zealand aluminum smelters or NZAS. The 2 standout features of the deal were firstly, the 20-year term that has removed massive uncertainty for the sector and allowed us to reset both our dividend policy and renewable build program. And secondly, the demand response agreement. And we're seeing just now how valuable that has turned out to be. We delivered the Harapaki wind farm on budget and on time. The wind farm is now fully operational and early wind mills have been absolutely fantastic. And we're well progressed on our grid scale battery at Ruakaka and Northland. I'll talk to our renewable pipeline shortly, but at a headline level. We have a line of sight now to $3 billion of investment in renewable projects, and we intend to make that through the remainder of this decade. We've also lodged our reconsent application for the Waitaki hydro scheme. This will be the largest consent ever granted under the arm in New Zealand. We have support for the key affected parties, and we are confident in the outcome. And that is essential to this country's low-carbon future and security of supply. And we've made the decision to put on hold our Southern Green hydrogen project or SGH. Global inflationary pressures have presented significant headwinds for SGH, and we will not progress to detailed design until the economic prospects for the project have improved. All up, though, financially it was a great result. And over the course of the year, we continued our excellent momentum in customer sales and hydro inflows turned up with almost impeccable timing throughout the year. That was obviously too good to last, and that is my segue into some comments on the current conditions. Now droughts are insidious things. They come on slowly, but then the effects start to compound rapidly as they extend. As shown on the top right graph between May and mid-August, inflows with the lowest on record across the 2 catchments that we manage. That has led to unprecedented low storage levels in the Waitaki scheme. The story is similar in all other hydro catchments across the country, and that's turned into quite a challenge for the sector. But the reason why wholesale prices have been so high in recent weeks is because of the scarcity of gas, which is a key backup fuel for when the system is short on hydro. There is just not enough domestic gas available for either gas users or electricity generators at present. And what is available is very expensive. Prices peaked 3 weeks ago in the electricity market, and they reflected the fact that the diesel generator at [Feraneki] was running during that week. But the industry is clearly in responding and several significant actions have been taken in recent weeks. These include: creating the opportunity for early access to contingent hydro storage if we need it, buying gas off methanex to use in electricity generation and coaling demand response options with NZAS, so they reduce consumption and make that energy available to the market. The Meridian is investing heavily in each of these actions to ensure security of supply. As a result, we've slowed the drawdown on the hydro lakes and wholesale prices have moderated, although they are still hovering between $200 and $300 per megawatt hour on average. For Meridian C&I customers who have or are coming off contract between July and the end of October, we are rolling their contract pricing through to 1 November. Hopefully, some of the heat will have come out of the wholesale market by then. We're also offering extended duration contracts with levelized fixed prices to take the sting out of the current prices when customers do recontract. So we're doing all we can to insulate our customers from wholesale volatility. We still believe wholesale prices will soften considerably over the next few years as more renewable projects come to market. And clearly, current market prices do not impact the vast majority of our mass market customers as our internal transfer price has built up over a number of years. Back to the position today. The inflow deficit over the last few months amounted to about 1,000 gigawatt hours compared to average. And Meridian's combined storage presently sits around 710 gigawatt hours less than average. The rain events over the last week have brought welcome relief, but we still have work to do to restore the lake levels. And we're relying on the NZAS' demand response and financial contracting to do that. The hedges we have invested in total around 800 gigawatt hours. So if we get anywhere near average inflows from here, they should do the job. Now the average cost of those hedges is around $258 per megawatt hour, and that will impact our bottom line over the next few months. Lake Pukaki is New Zealand's largest hydro storage Lake by far. Contingent storage represents up to 5 meters of water for Meridian or 545 gigawatts of energy. This is material. And at this stage, we're not likely to have to use it, but we do have a plan in action in case we do. That plan includes layering in 26,000 tonnes of rock to armor the lower reaches of the Pukaki high dam as we drop into the contingent zone. We've previously stockpiled most of the necessary rock near the dam for this eventuality, and we have the team on standby. I think FY '25 will be in Battle Ventures. A few of us in the business have seen something like it before, and we are well prepared for it. And of course, if everything changes if we get a decent amount of rain. Now when we signed the demand response agreement [indiscernible] in May, we did not expect we'd be asking them just 1 month later to reduce electricity consumption by the maximum amount. And the team at the smelter certainly weren't expecting it either. So I would like to acknowledge the NZAS team because operationally, it's a considerable task to turn off a potline. They managed it well. And in fact, they managed it faster than was contractually required. We have agreed with NZAS that they will make an additional 20 megawatts of demand response available. So they are leaning in heavily to help manage the effects of this drought. All up, the amount of curtailed demand at the smelter will be around 650 gigawatt hours, and that's material in the context of the current energy challenges. Obviously, we don't want to make a habit of this, and the historic weather patents suggests we won't. But this is a great example of the value that well organized and well compensated demand response can bring to the market. This arrangement makes financial sense for the smelter as they are compensated for the reduction in demand. No one is losing their jobs. In fact, their employees and suppliers are busier than ever. And the electricity system will rely less on gas and coal to fill the energy gap. And from Meridian's perspective, there is a risk management tool, customer demand response can be more reliable than thermal swaption type agreements. Thermal swaptions typically have suspension clauses that cover instances where fuel is not available or plant failure occurs. So we're working with other customers who can flexibly manage their demand to strike similar demand response agreements. We've embarked on considerable operational change at Meridian over the last couple of years. We've reshaped the operating model in our generation business, and we're in the process of adopting a more agile operating model in retail. But putting the buzzword bingo to the side, what we're really trying to achieve is speed to market, speed of decision-making and ultimately, more efficient outcomes that benefit our customers. The change can create uncertainty for people. So it has been pleasing that staff engagement continues to steadily trend upwards, and that reflects our focus on creating an inclusive, high-performing and safe work environment for our people. On this slide, we've highlighted a few areas of focus and improvements to our approach to well-being and our overall health and safety management systems. At our June Investor Day, our Chief Customer Officer, Lisa Hannifin, unpacked the retail opportunities we intend to pursue. That evolution will enable a fundamental shift, we believe, and the role customers can play in our industry. When customers can shift their demand to less congestive parts of the day or a year as it turns out, we can pay them for that flexibility and save them money. We can also point to good progress on operational outcomes like our energy well-being program, new demand through process heat conversions and sales of renewable energy certificates. But right now, our customer focus is on the impact of these high wholesale prices. SPOT X exposed consumers have experienced significant price increases, and that is hurting them, the employees and the communities where they operate. But spot prices during extended droughts tend to be high, and these are sophisticated businesses who have assessed the risk and chosen to take exposure to the spot market. The Electricity Authority requires businesses to take spot exposure to complete a financial stress test each quarter to demonstrate their resilience to extended high prices. And the stress test case for this current quarter has assumed -- was assuming a $400 average price for 3 months. And that's probably higher than what we actually transpire. Fortunately, 99.9% of our customers are on fixed prices. And this demonstrates the value that a vertically integrated business like Meridian can offer. We remove risk for our customers by managing wholesale price volatility over time. And today, that is very clear and present for most of them. And as I mentioned earlier, where we have C&I customers whose contracts are ending, we have chosen to support them by rolling their contracts through to 1 November this year. The thing that will put the most pressure on retail prices in the near term is the significant uplift the sector faces in transmission and distribution costs. The Commerce Commission are determining a significant increase in cost from 1 April 2025. While increased network investment is one factor in that, much of the forecast uplift is driven by the increased cost of capital due to high inflation and interest rates that we're all experiencing. The ComCom's draft proposals include smoothing to reduce the extent of a step change in any 1 year. But even so, the average distribution cost increase for our customers next year equates to around 9% of their total bill. ComCom will finalize its decision in November. We are working through what that means for customers. I think we will see the prolonged period of sub inflation price increases coming to an end or at least paused until the next ComCom regulatory pricing period for the Manapouri parts of the system also comes to an end. This year, we published our first climate-related disclosures under the newly mandated reporting standards. That contains more detail than is probably helpful. But if I boil it down, we remain sharply focused on our climate action plan, which delivers a significant renewable pipeline, customer decarbonization and manages our own emissions reductions as we do it. In the year ahead, we will build out how we deliver on our new net nature positive commitment. While our existing approach to mitigating the impacts of our operations is already robust, we will better define and enhance our contribution. And the work we should do to enhance -- and this work should enhance the consenting processes by giving communities, confidence in us as a leader in sustainability and a developer of new renewable generation. And on that score, we are making good progress on our battery the Real [indiscernible], and we expect it to land it inside original budget. The delay in Transpower's work program is likely to push commissioning to the first quarter of 2025, but it will be in place well before next winter for sure. We've also progressed the consent of our Manawatu battery project. And we note our competitors are now also seeing value in Grid scale batteries. And I think that's good for everyone. The sector does seem to cop criticism for a lack of investment in new generation, that is a story that is entirely baseless and flies in the face of facts. The facts are, there has been no real or sustained demand growth in New Zealand since 2010. So the electricity system is the same size as it was then. But in that time, around $10 billion of new generation investment has occurred and virtually all of that has replaced the aging coal and gas-fired plant. In 15 years, the industry has replaced around 1/4 of current capacity mostly through geothermal and wind developments. And since all of that investment has just got us to the start of the energy transition, but suggests the sector has not invested is just playing wrong. Also as a country, we only took up the challenge of Zero Carbon by 2050 and not in 2019. But well before that, the electricity system was evolving rapidly towards 90% plus renewables. And we'll hit that milestone this decade. Because of the intermittent nature of renewables and this country's relatively low hydro storage capacity, we will have periods where we will still have to rely on coal and gas like right now. Wholesale prices will be high during those periods, but the trend towards a highly renewable and lower cost system will happen. If we look at the recent past, the last 5 years alone, Meridian has invested $1 billion on existing and new renewable assets, and we will increase that level of investment threefold by the end of this decade, creating renewable energy is our core business, and it's a great business to be involved in with huge growth potential. But the competitive nature of the market has ensured that investment returns are modest and stable. Since listing in 2013, Meridian has delivered an average return on assets of 3% and return on equity of around 5% per annum. Now I've talked plenty about the long-term investment required by the sector to deliver New Zealand's low-carbon future, as that imperative that underpins our development pipeline at Meridian. We continue to prospect and develop a set of options that will ultimately double the size of the generation capacity we have today. And finally, before I pass over to Mike, I'll quickly talk to our decision to pause work on our hydrogen option. SGH is a unique opportunity to leverage Aotearoa's renewable resources and support global markets to achieve their carbon reduction commitments. But the economics of green hydrogen have become challenged over the last couple of years. And globally, markets have been slow to resolve the gap between the cost of producing the product and the potential customers' willingness to pay for it. So SGH will go on hold, and we have agreed to conclude our partnership with Woodside. We have built up considerable IP in green hydrogen, however, and we will continue to actively monitor our target markets in case the prospects improve. I'll now hand over to Mike to delve into the numbers.

[Foreign Language] Thanks for joining the call this morning. As you now know, we had one heck of a year last year, delivering $667 million of operating cash and $905 million of EBITDAF, both records for our business. And the timing of the result is fortunate as the last couple of months and most likely the next couple have been tough by comparison. In fact, the only analogs that come to mind to describe the challenge the industry is working through right now are 2012 and before that, maybe '91 '92. And while the story of 2024 is yet to be finalized, there are some very unfortunate outcomes for those who talk spot exposure. These large businesses may be sophisticated and will have understood the risk they were taking but that certainly doesn't help their employees, their suppliers and the communities caught up in the situation. It's times like these that being a customer of a business like ours is really valuable because not only can you rely on the fixed prices that we offer, but if you're unfortunate to come off contract right now, we will see you through, given the commitment you've made to us over the years. But enough of that for now, I'll come back to the current conditions as I close, but I want to unpack the fin year '24 result as it deserves some attention even if it was so last year. As this slide shows, it was another year of strong performance and the first for some time where the weather didn't interrupt our plan until near the very end. In fact, way back in February, I noted that we had a chance to deliver stronger second half performance for the first time in 5 years, and that is exactly what the operating teams did. Alongside the result, and as Neal mentioned, we had a couple of pretty other special things happened during the year as well. First, we delivered the Harapaki project, and it's now producing 176 megawatts of renewable energy while adding a new and, in my view, graceful dimension to ridgeline above Napier. And of course, the NZAS contracts, they're important as they brought certainty for the smelter, the electricity sector, Southland and our nation. Certainty is a new thing for our industry, and I think that some have forgotten that but it's very important as it unlocks investment. And now that we have it, that is what we'll do, invest faster. As Neal noted, we're already out of the blocks having committed over $1 billion to new renewable energy assets, but certainty is also supporting new entrants invest in our sector. While collectively, our traditional competitors have also committed another $2 billion to new renewable generation assets, others like New Zealand wind farms have arguably the largest wind farm development that New Zealand has seen in front of them at [Te Apiti]. We're helping out there, but the team at New Zealand wind farms is doing some very heavy lifting. And we're pleased to see that through fast-track legislation, the [indiscernible] consent has been granted, subject to conditions, and this should result in a larger wind farm being developed. [indiscernible] and Nova, Load stone, final solar, runway generation and many others attend to New Zealand's solar generation resource and building at scale. In fact, 69% have committed and actively pursued developments in the electricity authorities investment pipeline are being pursued by new entrants to the sector. My rough estimate suggests that combined, they have committed to or propose to invest upwards of $1.6 billion across their sites. My point is the market is working to encourage both traditional and nontraditional investors to invest in our sector. And given the scale of the challenge through 2050, there's plenty of space for everyone. And the investment is not one dimensional. We're also investing in nontraditional relationships that will reduce the impact of dry years. The new demand response agreement with NZAS is just the start. And while I've heard suggestions that asking businesses to temporarily shut production lines when energy supply is tight is a poor outcome. I think that sentiment is misguided. My conversations suggest that these type of arrangements improve the financial well-being of those businesses as they get paid to reduce consumption and only enter into such agreements to the extent these payments add to the bottom line. Demand response products may not be for everyone, but we're talking to plenty of customers looking for additional revenue streams right now. So I can see a bright future for these types of products. If I was to summarize the last couple of minutes, it would be to say that certainty is a good thing for investment and for customers, which gives me a perfect segue to dividends as certainty is good for investors as well. For the last 3 years, I've said that we'd review both dividend levels and the dividend policy when Rio Tinto makes a clear decision on the smelter's future. It's done that emphatically. So the lift and final and full year dividend shouldn't be a surprise, but I do hope it's satisfying as you, our investors, have been patient. This morning, we're declaring a final ordinary dividend of $0.1485 per share. This is a 25% lift on the fin year '23 final ordinary dividend and brings the full year dividend to $0.21 per share. And we're lifting the dividend reinvestment plan discount from 0% to 2% as we're hopeful that this new era of certainty will accelerate development plans. The final ordinary dividend will be imputed at 80% and paid to shareholders on the 20th of September. We're also adjusting the dividend policy. Specifically, we're moving that policy to an operating cash flow based measure to make sure dividend payments align fully with operating cash flows. Other elements of the dividend policy remain. The key one's ones being payouts will be between 80% and 100% of operating cash flow over time, after assessing wider business needs and the Board's commitment to a BBB credit rating, right, on to EBITDAF. You would have seen on Slide 14 that both EBITDAF and operating cash flows continue to grow as our teams improve performance. As you can see from the graph here, the 16% year-on-year lift in EBITDAF was largely driven by increases in energy margin, even as lift operating expenses offset some of that gain. And while I talk to the net profit after tax figure that comes later in the pack soon, as it's driven by large noncash movements, it doesn't offer useful insight into operating performance. So EBITDAF and operating cash flows remain the key performance metrics for our business, and they both show that our operating teams delivered superbly last year. If we jump over to the energy margin slide, you can see that the lift in performance was once again driven by our retail team. Well, that may not be as easy as I just stated, but to help you get to the same answer, I'm going to do some on-the-fly mass gymnastics to help out. If you deduct the cost to supply customers from increases in generation spot revenue and then remove the cost of derivative purchases from the value of those derivatives, you'll get a net number of negative $9 million, that is the portfolio of wholesale, physical and financial sales and purchases were reasonably balanced. So what really drove the uplift again this year was retail team performance. I'm not saying the wholesale and generation teams didn't do a superb job. They did, as they generated enough energy to meet customer needs while securing financial cover that manage risk. It's just that when you compare their performance to fin year '23, the result was similar or similarly excellent. And thus, our expectations of their performance during the current drought are also very high. But the retail teams stole the show again, and they continue to work hard to secure and grow valuable relationships across customer segments. And you can see some of that might here. Total sales volumes continue to grow across mass market channels and pricing improved as well, but the team balanced this growth by holding corporate sales volumes steady even as they lifted price. I've said it before, I'll say it again, we're very fortunate to have the best retail team in the sector and improve their performance again while continuing to grow our business. Now I mentioned our generation team a little earlier. And as you can see from the bottom graph on this slide, fin year '24 was not particularly wet. In fact, inflows were the lowest on average in 7 years. And as a result, hydro generation volumes were down on fin year '23. However, wind generation made up for that reduction. Now the generation team don't make the wind blow or influence rainfall patterns, but they make sure that the generation fleet is available for use by the wholesale team and as fin year '24 wholesale prices were more than double those in fin year '23, that job was particularly important. And while they did their job admirably, we had 2 disappointments during the year, both related to Transformers. The Manapouri transformer challenges continued, and we lost one of the 2 transformers at West Wind. Interestingly, with low inflows, the Manapouri transformer outages did not impact generation volumes or energy margin delivery at all. However, the West Wind constraint costs $6 million in lost energy margin during the year. The good news is that the West Wind constraint will be unwound in October as Transpower is lending us a transformer for 10 or so months, after which a new transformer will have been installed and the situation of Manapouri will improve in March '25 as a new transformer is brought to bear down that way. As the Manapouri transformers have been a challenge for our business since 2011, the generation team will buy a spear for Manapouri. But with global demand for Transform is high, that spear and the transformer for the seventh unit aren't expected until September 2025. And then we'll need 12 weeks for installation and commissioning. We laid out most of the above information at our recent Investor Day, but the key point is that the generation team is tireless in its efforts to make sure we have maximum generation available while tackling the transformer challenges that have confronted us for some time. Now I'm not sure whether anyone truly appreciates the slide, particularly the top graph that shows increases in costs for all the reasons I've previously explained. But it's here to provide transparency on what we spend investors' money on. The first thing I'll note is that operating costs fell within the guidance range presented in February. And while [indiscernible] explaining is losing, the second graph is the elements that drove the uplift in operating costs. Room increases drove a 6% uplift in salaries and recruiting a new staff was focused primarily on Flux's growth, Meridian's development pipeline and properly resourcing our team that supports vulnerable customers. While I expect Flux staffing to fall this year given the change in strategy for that business, the growth within the development team now means that it'll be able to construct at least 2 new assets at any one time. That's not something Meridian has achieved historically, but it's a sign of the times, and it does signal that we continue to prepare for substantial investment in the coming years. The increased contract spend was also driven by a development team and Flux. I make the same comment for Flux as I did a minute or so ago, and I expect development team costs to stabilize this year. The increase in ICT spend was driven entirely by the new finance system that's being introduced into the business. In total, that will cost us approximately $17 million the majority flowing into fin year '25. I'll finish with insurance as while costs lifted again last year, we did adjust our insurance program, and those changes will see costs held flat in fin year '25. And to be clear, we didn't reduce insurance coverage, rather we found new insurance products that will work for us. On to capital costs. At $349 million, capital costs landed at the bottom of the forecast range. This was down on initial estimates as we were unable to secure a consent for the 130-megawatt Ruakaka solar development within the window that have been expected. That was disappointing for our business and no doubt to those of us who also worry about energy security. There's a reasonable back story to this consent, but we don't have time to present it here, so to steal a phrase from Neal, it looks like it will take longer to get that consent than it will to build the asset. That said, we did deliver Harapaki, and the development team is progressing a number of initiatives outside of Northland, some of which have been announced and some that have not. Stan business CapEx was also reasonably elevated with the new office that we're broadcasting from being built out during the year, and being captured as a component of the workplace facility spend. If I jump to the next slide, you can see the level of investment that's directly in front of us. You can also see how challenging it is to navigate new investment consenting. Now I realize that this slide is a bit of a word salad, but that's the point. I mentioned certainty earlier in my talking points and how that supports investment. Well, as you can see here, there's a little certainty in regards to consent or the best pathway to take to obtain one. In simple language, there are 8 parts you can take to consent new investments, and we're using 5 of them to move 7 development projects that collectively cost $3 billion forward. Each process is different requirements, time frames and costs and they each have different risk profiles. There's no certainty that will obtain a consent from any pathway, which is part of the reason we diversify the approach. That's why we welcome this government's intention to remove the regulatory barriers to support investment and get the job done. If we're able to achieve consent inside 12 months for projects that meet environmental and economic hurdles, then that will be a material accomplishment. But back to more solid financial ground. As presented in this slide, I expect operating costs to land between $302 million and $308 million this financial year. That suggests operating costs will lift between $21 million and $27 million. This is the third successive year of large operating cost increases, but there's always good reason for them and the waterfall chart shows we're intent on investing that cash. Salaries will continue to lift or be under half the rate of last year. There's another slug of cash being spent on the finance system deployment. And now that Harapaki is finished, the operating contract has been crystallized and that lists generation maintenance costs. Finally, we continue to expand our development activities. The increase you can see here is twofold. First, it is money we're investing in [indiscernible] and the New Zealand wind farm joint venture. Second, it was money set aside for Southern Green hydrogen. Given we've put Southern Green hydrogen on hold, some of that cash will not be spent, but the team on that project are now focused on other activities. A couple of other notes from the slide. I'm also forecasting total capital expenditure of between $295 million and $325 million this financial year. That largely reflects cash being invested in the battery at Ruakaka as well as anticipated cash supporting a solar farm at that same site. But it's also driven by a lift in stone business CapEx, given there's a generation control system replacement project that is getting underway. We need to pay for the transformers I mentioned before. And there are a couple of other generation projects, including gravel removal at the Manapouri lake control structure and replacement of the electrical and automation technology at Manapouri Power Station. So Manapouri will continue to be a busy site probably through 2028. I will, of course, update you if anything changes. The graphs on this slide show the difference between net profit after tax and underlying net profit after tax. The reason we present both is that underlying net profit after tax removes items like unrealized fair value movements on derivatives as they are not cash costs, whereas net profit after tax is a GAAP measure that by definition includes these elements. As you can see, the difference between the two can be stark. So understanding why that difference plays out each year is really important to those who put our performance in perspective. To help you with the Slide 50 of this pack shows the reconciliation and while we don't put that up on this slide, a positive $98 million fair value movement in the unrealized portion of derivatives and an $18 million impairment in Flux are those drivers. I tend to suggest investors look beyond net profit after tax when it comes to operating results, but both measures have value. What the underlying net profit after tax chart shows is that business performance was to begin last year. The net profit after tax graph simply shows that unrealized gains and losses on derivatives changed materially year-on-year. The above differences are also a key part of the reason why we've elevated the conversation on operating cash flows. And while we change the basis of the dividend policy is working through accounting measures can be a bit like mumbling at people and hoping that they get it at times. I like to present measures that are simple and that reflect business performance, and it's hard to look past operating cash flows. Last but not least, there was a $3.15 billion lift in the value of generation assets over the year. You might say this deserves more than just a cursory bullet in the presentation. But all it really reflects is that the accounting value of assets is catching up to the market value of those same assets. And the reason for this is [NZA] decided to stay in New Zealand. Now this slide continues to show that our balance sheet remains flexible. Net debt has lifted on fin year '23, but the key S&P rating metric, net debt to EBITDAF remains well below the bottom of the BBB+ threshold of 2x. The reason for the lift in net debt is that we issued a new $300 million green bond during the year as an existing $150 million green bond expired and this cash was used to support delivery of Harapaki. We have another $200 million green bond expiring this year, and it's likely that we'll replace that one as well. And if we can accelerate the development program in some way, it could be that we enter debt markets twice in fin year '25. Of course, that would be a positive if it plays out. So I don't have too much more to add, I'll finish where I started. Fin year '24 was a strong year, but we're currently focused on navigating the drought. This makes for tough operating conditions for our renewable energy business, but droughts are inevitable, and while they can be tough, you learn a lot from them as well. As investors, you know our business well enough to know that we carry balance sheet headroom specifically to cover these types of events. And while operating cash flows will vary, dividend stability will and can be maintained. And to our residential and small business customers out there, you don't have exposure to the high wholesale prices, your electricity prices are fixed. You can see the impact of the drought and the storage graph on the right, National hydro storage has never been as low at this time of year as it is now. So the generation wholesale and retail teams have worked to navigate a tricky period, but that's why they get out of bed. There will likely be a fin year '25 financial impact, but with near-term ASX prices having peaked on the fifth of August and since fallen by approximately $190 a megawatt hour, it could be that the worst is behind us. I'm not saying it has and prices remain elevated. But if markets are right, then we'll turn our attention to winter 2025, it's going to take quite a bit of rain to return New Zealand's hydro lakes to more normal levels, and our job ultimately is to satisfy shareholders while delivering energy security for this fine land we live in. And while we navigate these challenges, the lift in both the dividend and the dividend reinvestment plan discount suggests that the business is in good health and focused on investment. I'll hand back to Neal, so he can make a few closing comments of his own.

Cheers, Mike. In many ways, the focus for FY '25 is continuing the momentum we have built over the last couple of years, and that includes getting development projects through the consenting processes and into the build phase, delivering the transformer replacements of both Manapouri and West Wind as well as adding incremental generation from our existing assets, adding to our customer demand flex and process [indiscernible], and we will continue to develop our team capability and culture focusing on digital maturity, diversity, well-being and safety. Mike has a very new and expensive financial system to deliver it turns out. Plus we'll begin the [Trunky] work involved in replacing our existing generation control system. So there's plenty to do, but the entire team are aligned behind a clear strategy and a sound plan. So to wrap up, FY '24 was a successful year for the business. We've got a very significant strategic issue resolved and made good progress on the other key aspects of our strategy. As we've discussed, FY '25 is shaping up to be a different challenge entirely, at least at an operational level. Every hydro catchment in the country has received much lower than normal inflows over the last 4 months. That situation has started to abate over the last week or so, but the likes remain at very low levels. Meridian is investing heavily in hedge arrangements with the smelter and thermal generators, and that is incentivizing physical responses that are helping to manage security of supply. We've also advocated for better access to contingent storage, and we've been listened to. There are unfortunately some large business or more importantly, the people who rely on them for their livelihoods badly affected by direct current wholesale prices. That is not an outcome that anyone wants. But the vast majority of consumers do not have that same wholesale market exposure. And the Meridian customer team is making sure our C&I customers coming off contracts are being supported through this high price volatility. All up, I'm confident we're doing all we can to support system security and to insulate our customers from the current high wholesale prices. But the key issue remains that there's simply not enough domestic gas available to meet either the needs of gas consumers or gas electricity generators. And as a sector, we need to solve that problem, and we need to solve it quickly. LNG import may be the fastest and best way to ensure we have adequate renewable firming fuels available when it doesn't rain much. And the upfront infrastructure investment seems very manageable. So Meridian is engaging directly in this opportunity through the Gas Security Response Group. Delivered LNG will not be cheap. Possibly more than $20 a gigajoule or between $200 and $300 a megawatt hour. So it is not a replacement for domestic gas consumption nor is it a baseload electricity generation option. But it does lend itself to seasonal electricity firming. There will be reliable, flexible and diversified system risks. It will also likely increase competition for firming options and hopefully help improve transparency in the gas sector in New Zealand. If you're not intimately involved in the gas industry, it can be very challenging to understand exactly what is going on. For example, understanding when gas-backed hedge arrangements may be in danger of being suspended. If the sector invests in the infrastructure to enable LNG imports but never has to use it, it will still reduce risk and ultimately prices. And in my view, it will be money well spent. The government's announcement on Monday to support the consenting of a project is very good news. Looking to the long term, the solution is the deployment of more diversified renewable generation throughout the country that will ultimately reduce the reliance on [indiscernible] and hydro. And whilst we'll still see low hydro sequences in the years ahead, they will become less impactful. For those of us old enough to remember, when the lakes were last to slow in 1992, the country saw rolling brownouts and that was not acceptable. In 2008, the likes were nowhere near as low as they are now, and yet we had a public savings campaign. This is certainly not where we are at today, and I think they seek to deserve some credit for that. And lastly, these near-term challenges are not blunting our intention nor are our effort to drive our development pipeline forward and enhance our customer product set. So that's it from us. Thank you all for your attention. We can now move to some questions. And I think we'll start with questions from anyone here in the room this morning.

[indiscernible] Macquarie Asset Management. Just one question for me. If you do -- the announcements you say kind of from the government there's a few bullet points. One of them in there was the transmission line companies been able to potentially develop generation. Just a broader question kind of leading from that in terms of if you think about come to build generation. Is capital actually a constraint? Or do you think there's constraints more in other places like consenting supply chains, people, et cetera, is bringing more capital in other players actually the benefit...

Clearly more players involved doesn't hurt. But capital is not the constraint. There's plenty of money globally looking for high-value renewable projects. We've got a well-positioned balance sheet to contribute most of the other [indiscernible]. But as Mike indicated, we've seen other parties come into the into the sector as well. So capital is not a constraint yes. The key constraint in this country at this moment in time is your ability to get things consented in a timely and efficient manner, and that's been worked on clearly by the government. So the improvements in that consenting regime from a New Zealand perspective, I think will be the key catalyst to unleashing investment at a faster rate than what we've seen today.

And so just a follow-on question. In terms of your current pipeline?

Sorry, I should probably add to that, when we look at the growth required between now and 2050 to decarbonize the country, we don't have enough people in the industry at the moment. There's a lot more engineers, Wintec, trade staff, eroding construction teams that will be required to meet that demand lift. So that's a challenge. That's something we're all very mindful of as a sector, but -- and I'm not calling it out as a constraint, but it's probably more of an opportunity actually for the people of New Zealand to really climb into this in great careers in a sector that's going to grow dramatically from this point.

Kind of follow-on question which was if your current pipeline think about 2030, when you think about that, is that kind of based on what you know now with consents? Or is it assuming some kind of improvement in that [indiscernible] if content issues resolve, could that bring the pipeline forward? Or are those kind of unites talk about people potentially forward [indiscernible].

We've got two of the projects that are in that part of the pipeline are on -- we've put them on the fast track consenting list, don't offer been accepted yet. But it would be helpful if they got a relatively quick consent through that process, and that would enable us to get on and get them built.

[Operator Instructions] Your first question comes from Grant Swanepoel from Jarden.

Mike, this question is for you, and I know expanding is moving, but 14%, 13% deference and an 8% to 9% increase in OpEx. Are we getting close to a cost out program. [indiscernible] $8 million at the midpoint seems quite high watering. Or is there something that $8 million [indiscernible] to keep costs coming down?

I think you see it flatten ground. That's what I was alluding to. I think you'll see ongoing lifts in salaries. There are -- we're always trying to run the business as efficiently as we can. But our focus -- if you go back over those last 3 years, where that money has gone, has gone into the development team and really trying to accelerate our investment pipeline. Outside of that, the corporate costs of largely -- and outside of salaries as the corporate costs have held reasonably flat. So I think you'll see it plateau grant as opposed to coming back, but I do agree. Those cost increases have been significant over the last 3 years. That's why I point them out to people, but they've been for a very good reason. You come back to what we're talking about generally today is being able to and actually investing in new facilities, there are consents, which is typically the holdup, but as Neal mentioned, we need good people to deliver those assets. And so we've invested in that capability to make sure that we can do it.

Next one, on Stan business CapEx. So still well above, I think it's $55 million is your long-term guidance. When does that revert back to a $55 million type number?

That's a great question, Grant. I know that this fin year '25, you can see it sitting at $100 million. Fin year '26, some of those programs that we -- that I mentioned will roll into '26. So I would expect that you'll start to see that reversion '27, '28 as we come out of the implementation of the generation control system. Well, I don't have the numbers up there, and we haven't run it by our board the costs of that initiative are substantially larger than what we've spent in the past. And it takes about 3 years to run through that cost profile. So I think once you get through that, that happens once a decade sort of stuff is then you'll start to see those same business CapEx costs come back to the levels that we've seen historically now. And the only thing that I'd add to that is, of course, we're adding new wind farms to our business. We're adding obviously, solar rays and we've got a battery coming at us. So there will be a requirement for those new investments as well. But I'll be sure to point them out as we step forward.

And then at your strategy day, you had 3 or 4 projects that you're moving towards Further on. Have you got any updates for us on cost to build those projects? Are you still on track your $115 per megawatt hour real wholesale prices over the next 15 years?

Grant, we're still working those projects through. There's no real or new info that we've got since Investor Day. We're -- I guess, touch wood on some of the consenting process. I feel like we're pretty close on the solar development up Northern way. There's a lot of hard yards being put into Mount Manroe over in the [wide and upper]. And we're working through the construction costs and program for Toledo, but again, all going well there. We're approaching FID middle of the year -- next year. So I guess no real update on what you did here back at Investor Day, either in terms of cost profile or ability to accelerate those projects. But what I did note, and you heard us talk to is there are plenty of new entrants looking at the sector. And so we're not just exploring the activities that we might undertake. We're looking to support and accelerate plans that others might have. So if we do get any good news on that front, we will let you know.

My final question, just a question on clarification. When you talk about hydro inflows being down 5 gigawatt hours, is that from May or from the 1st of July?

So that was from May, so May, June, July through August, mid-August, I think, was when we took that measure.

And then 800 gigawatt hours of cover. Is that also from May? Or is that from 1st of July?

That's kicked in more recently, yes, from 1st July.

Can you just give us an idea of what hydro inflows are down from the 1st of July?

Not off the top of my head.

They are the lowest on record ground. And they're on that slide. There's a slide that we've got in the [indiscernible].

That's from May 3. So we can give you a more concentrated recent hydro inflows, if you'd like, but we'll give it to you after the meeting. Sorry, I was just calling out 70-odd percent, Grant.

Your next question comes from Stephen Hudson from Macquarie Securities.

Just a few from me. Just firstly, on Harapaki. Can you give us an update on what you're expecting the capacity effect for that farm to land at seems to be traveling a little bit ahead of numbers that you were giving sort of a year or 2 back?

I mean, Hadi, it's early days, so we wouldn't revise the business case assumptions, but what we are seeing is that, that wind farm next in our capacity in recent times. So it has performed exceptionally well, in the nick of time I might add. So yes, the signs look good, but we wouldn't call a change in our long-term assumptions around that until we've actually seen some at least a year of real life experience.

Okay. And my numbers may be old, but I think I've got in there sort of 35% or something like that?

It's looking well north of that, but we have seasonal things to take account of. So we'll keep an eye, but we're pretty optimistic the way it's playing out.

Steve, if you're not above 40%, then change your numbers.

It's my margin [indiscernible] Contingent hydro -- just on contingent hydro, obviously, there's some temporary relief in the offering, but I just wondered whether or not you foresee any permanent changes to the trigger levels there?

Yes. Well, look, the government called that out in their announcement earlier in the week, and we need to work with the consenting authorities. But from my perspective, Lake Pukaki is a hydro lake. It was created purely for hydro generation. It's not used for any social amenity. We can actually stretch the like -- it's currently got a standard operating range of 14 meters. But if we can extend that to create an extended operation range of around 19 meters, it will mean on average, we will produce more hydro generation in this country. And that will also go towards reducing price pressures over time. So I think there's a strong case to normalizing the consented level and bringing the contingent back into the standard Lake [indiscernible]. So that's the conversation we want to progress with -- We're not only consenting authorities but also government to the extent that they can help facilitate that end outcome.

I think the only thing I'd add to that, Hadi, is in the absence of gas that we expected to show, I think Neal's point is more important than it would have otherwise been. And so normalizing the use of that contingent storage, particularly in the short term, while we look at whether LNG as a longer-term opportunity or domestic gas arrives is something that is within the control of the country. And as Neal said, it's a hydro storage facility, and that storage looks like it's increasingly valuable as compared to where we were even a year ago. So I think if you were prioritizing it as something to do, it would be a good one to have near the top of the list.

And you might take a different approach with contingencies around hardware, for example, which does have more of a social impact or -- so -- [indiscernible] think needs looking at.

Very good. Just 2 more quick ones, sort of polling accounting on this, unfortunately. I think you're alluding to a change in the Optrum premium accounting to take that cost above the line. Mike, if that's the case, can you confirm that? And what would a sensible number for FY '25 be noting that I think FY '24 was about $23 million. Could we use sort of $30 million, $35 million for FY '25 as a Broad estimate?

Yes. Thanks, Steve. So one, yes, we've changed the accounting treatment of the option premiums, they sit below EBITDAF, and now we've moved them back into energy margin. So it's, I think, a useful change. This year is a funny one. And that if you look deeply at those Indus contracts, we only pay the premium for the demand response beginning the first of January 2025. So we're only paying half of the option premium. And I think I heard you say 23, Steve, I think if you cut that number in half, you're not going to be far from the mark.

And sorry, last one for me. Just on the reval, I know you've added sort of the accountants catching up with the market. Can you just break down the 3152 in 2. I don't know wholesale price or WAC or just some sort of broad buckets there?

Wholesale price, wholesale price and cost to capital. Those would be the 3 pieces. So a small change in cost of capital, Steve, but it really was, I mentioned -- and I think we've said it before, is we've used indexed price path for the valuation of our generation assets to date and that we wouldn't make that change until the contracts were struck. So what you have seen is that we've changed the price path that we used. So the majority of it is wholesale price.

Your next question comes from Peter Wakeman, a private investor.

I was just wondering if there has been any warranty issues with transformers or anything like that and how things are shaping up on that requiem bearing in mind how long it takes to replace these items, first question.

Yes, Peter. I mean, we're looking at the warranty relationship around all the transformers that have failed, and that's an ongoing conversation with the providers of those transformers.

and So that hasn't been concluded yet.

Not entirely no.

Right. And with respect to the government fast tracking, have they given you any idea when they will come up with a faster decision?

I'm not better informed than anyone else, Peter, on that. We'll see the bill go through the parliamentary process in due course. And what we're interested in, as I mentioned earlier, has seen a couple of our key and very significant projects around that first list, so they can be considered by the expert panel and hopefully, consented and at a rapid pace.

Right. And with respect to insurance, what sort of -- for example, has the government ever offered you or have you ever asked the government for insurance when 9/11 happened, the government provided an insurance to [indiscernible] because of the private industry wouldn't do it. And I just wondered if the government would ensure Meridian an event of an Alpine fold or Wellington fold or whatever it happens to be a [indiscernible] whatever. Have you had any sort of agreements because I think if again [indiscernible] actually lower the cost of insurance or how significant would that be for balance sheet?

So Peter, the answer is no. We don't ask for government support as it relates to insurance. What we do, do is we ensure our properties against the events that you mentioned. So we do take our insurance cover. But as the costs have lifted over time is what we've done is we've explored new products from an insurance perspective. Typically, we've gone to the global reinsurance market. But we've actually entered into arrangements with a new entity for us in any event that provides insurance called Everon. And they effectively consolidate a number of companies, insurance, not just in New Zealand but across the globe, and as a result, can provide premium to us that reduces our overall cost. So what I'd say to you is we like to explore further arrangements similar to that with Everon and other types of insurances as opposed to stepping back to the government and asking for support from that perspective.

All right. And the last question has to do with the solar panels and the integration over time and what page and technology are there for the [one grey]?

Peter, have those questions might be beyond my technical means. I'm not sure about Neal.

We haven't contracted them yet, Peter. We're working with various suppliers understanding is they've got at least a 20-year life frame. But we could provide a bit more information. In fact, we will provide more information when we get the project to financial close, and we announce it as a committed project that we're getting on with.

Your next question comes from Cameron Parker from Craig Investment Partners.

Congrats on a really strong performance. I'm just wondering if you could talk to the transition and distribution price increases were expected to come through and also the impact on your underlying customer increases and also in the context of what your intentions are growing into the North Island, given your supply arrange also growing in that geography as well.

Cam, I mean, we've laid it out in the pack, the ComCom are looking at distribution pricing across the whole sector, have come out of a proposed -- set of proposals that see those costs increasing reasonably dramatically. And in fact, the increases into next year on the current proposals look like about 23% on average across our customer base. It will depend on who your customers are, but that's how we've modeled it. Now they do have a smoothing mechanism because those cost increases would be more rapid than that if they didn't smooth it. But when we take that 23% and spread it across the whole customer bill, the increases are between north of 8.5% to 9%. So that's pretty -- I6 mean that's significant. We haven't quite worked out exactly how we're going to manage that with our customers. Obviously, we're doing a lot of work on new product sets and least we'll be talking a bit more to the market about that in the coming days. But we do have products coming to market or they're actually being rolled to market today that if customers can provide a bit more flexibility and ship their usage and their demand around we can actually help them save money overall, not only on the distribution side of the build, but also the energy component. So we're doing everything we can to try and minimize the impact of those costs as they flow through. In terms of our position in the North Island, yes, as we grow our position and we get access to not only more generation in the north, but also through PPAs and other hedge arrangements. We're still focused on growing the size of our retail business. Most of the customers in New Zealand are in the North Island. So we will continue to actively seek out growing our market share in the north as well. We understand the risk, obviously, and we manage those through various instruments and product types.

Yes, great. Okay. Then just the last one for me is just around gas risk and gas-fired swaptions that you have. Are you able to talk to that. Any detail?

Well, I guess -- and I alluded to this in the presentation, but as these gas issues emerged, it's very difficult to get a handle on them. And what I can tell you is all the gas back swaptions that we had, to some degree, were suspended and relatively short order. So we had to do a lot of work behind the scenes to get that hedge position back into some sort of shape and that's why we were leaning on the NZAs demand response quite heavily. We also bought hedges on the back of Taranaki and we've been right and behind the Methanex deals as well. So took a bit of work. I guess the thing that concerns us most is just the line of sight a customer of those hedge transactions has through to the fuel source and when it's running scarce and visibility or transparency in that regard is poor, I would put it, absolutely poor for our sector in that scenario that we do need to improve. I think quite interested in the -- and I've just had a quick read of it, but the government review into the electricity sector. I think we welcome that. I think it's appropriate. I do wonder whether I missed the point a touch because they've indicated that the high prices are driven by low hydro inflows. We know that and gas availability. But the gas that's about the last time it's mentioned in the scope for that piece of work. So I think we'd all benefit if the scope of that review was extended to include regulation in the gas sector and how that impacts through to electricity prices. I think it's a must-have and it's a bit of a missing in that scope at the moment, but we'll be giving that feedback.

Your next question comes from Andrew Harvey-Green from Forsyth Barr.

Neal and Mike, just a couple of questions from me. First of all, in terms of technical structure going forward and [indiscernible] dividend policy, do you have a particular sort of EBITDA [indiscernible] ratio that you're looking at [indiscernible] deal underlined?

Andrew would like to get back into BBB+ territory. So between 2 and 3x net debt to EBITDAF is where we would look to trend as probably the simplest estimate that I'd have. I think we felt we're trending that way, although our underlying operating performance has been as strong as you've seen. So that EBITDAF figure from last year means that, that net debt-to-EBITDAF ratio is a little lower than we expected it might have been, but that's the track we're headed towards between 2x and 3x.

Next question is just around the Manapouri transformers and I guess those of us who are able to go and see them a couple of months ago. Are you able to give us any update on progress in terms of finding what the actual issues are. And I think there was a suggestion you're going to be pulling them apart to have a closer inspection. Has that actually thrown up [indiscernible].

We're still working through the process to do that, Andrew. But yes, we will be pulling the 2 that are out of service apart. We're just trying to work out the arrangements between the original manufacturer, and how we do that effectively without having to ship them back off to Australia. And we will have the right level of expertise involved in that process, so we can get to the root cause. We've got another -- of those 2, there was another 2 transformers that were in part of the same bet. They're not misperforming at all, but we certainly need to understand the root cause, just so we get comfortable around their likely longevity. In the meantime though, we're committed to -- we've got a new transform it should hit the water later this month and be installed well before Christmas, and we've got -- we're looking at 2 others which will leave us with a spear for delivery sort of back end of next year.

Great. Next question is just around demand response and the opportunity there. And then I guess we've seen what the smoker has been able to do, which has been great and very well timed. Can you give us a sense of the sort of the target for yourselves? I assume probably relates to some of the South Island demand that's transforming load away from coal potentially, but do you see or the size of demand response you might be able to give?

Look, we're not clearly, but we're working with at least 2 milk processing businesses in the South Island for a decent chunk. You're talking sort of potentially between the 2 of them, 50 to 75 megawatts. And I think that's -- and we're only just starting this conversation. I mean I noticed [indiscernible] through this whole process has slowed down operations. I mean if they had a demand response agreement with someone like us through this period, that would actually make that a profitable exercise for them. So there is a lot of demand, we think, around the country that can be tapped into. But we're too early in the process, Andrew, to call out exactly how much. but we think it's significant. And you're talking hundreds of megawatts.

And last question, just a follow-on from Steve's question, I guess, around the contention hydro. So if we were to move the contingent hydro to standard operations, I assume you'll probably still look to keep a chunk down there as a reasonable contingency. But what sort of uplift in annual generation -- hydro generation could we be looking at?

I would have to run that through all of the models, and we haven't done that yet because we don't have that agreement. But we'll provide a bit more insight, Andrew, if we actually get that change through to the sort of consent processes.

Yes. And there were announcements, Andrew, that we made, I can't remember the year, but they're on our website around that contingent storage utilization. So the range from 518 to 516, reasonably easy to access and operate other than the 26,000 tonnes of rock that you need to put into Pukaki. Beyond that, it gets tougher given the configuration of Ohau A power station. And you got to be careful around how you actually run water down the Pukaki canal. So you got a couple of meters, I think, of water that would be reasonably easy to operationalize. And then the other stores, it's about 3 meters of additional water lower is would need to take more time and effort if we were to use that. And that 2 meters is an additional couple of hundred gigawatt hours. So as Neal says, we have to run it through our modeling, but that's the type of storage that's down there that's -- I'll say, reasonably easy to exit.

I just add, sorry, Mike. But the engineers are doing more work, and we think we can get into those -- the meters below those 2 as well, reasonably productively. That's why I was sort of hesitating to give you a number because we've still got to work that through -- but it's a chunk. It's a decent chunk of generation.

Unfortunately, that does conclude our time for questions today. I'll now hand back to the presenters for any closing remarks.

Well, thank you all for your attention. Hopefully, that was informative, interesting times, clearly. We're all very, very busy, and we will catch up with as many investors over the coming weeks as we can in person as we typically do. So thank you all for your attention, and good morning.