Meridian Energy Limited (15M1.F) Earnings Call Transcript & Summary

[Presentation] [Foreign Language] good morning, everyone, and thank you for joining us for Meridian Energy's results announcement for the financial year through 30 June, 2025. I'm Mike Roan, Meridian's Chief Executive, and I have with me our acting Chief Financial Officer, Helen Peters. For those that are new investors, I sat in that seat at our interim results announcement back in February. So at the very least, I bring continuity and given the environment the business is navigating right now, my experience and the experience housed throughout our business is more important than I would have imagined a year or so ago. And while we're challenged by the perfect storm this year, I'm incredibly confident about the future of the business and its ability to both support and grow the economy while rewarding shareholders for doing so. As I'll talk to soon, there are some challenges immediately ahead that require attention. But when we properly harness the natural bounty that this country has to offer, I believe the electricity sector will underwrite the economic growth of the nation, and I want Meridian to be a driving force behind that. This will require an evolution of where we've come from and some change. I have an immense respect for what people have done to get Meridian to where it is today, but I also have a clear idea of what's required for us to continue to succeed as we move forward. First, I want to further accelerate our development of renewable energy. While we're well on track to deliver 7 new developments in 7 years, that was framed before the gas sector collapsed so we need even more clean energy to realize the ambition. And as we do this, I want us to go back to our roots. 60-odd years ago, the Waitaki Power Scheme was devised and built in the Mackenzie Basin. It remains the country's largest hydro scheme and the backbone of Aotearoa New Zealand's electricity system. But it's so much more to give. There's more water to be accessed, more megawatts to be achieved from existing assets and a fundamental shift in the role stored hydro plays. At a time when politicians and others are calling for a solution to the firming issue, I say look to hydro for a lower cost and lower carbon solution. In my view, the route to global competitive advantage for our economy can only come if we harness more water within that and other existing hydro catchments. We need to be bold and we are. We've recently established a hydro development team to explore opportunities in the Mackenzie Basin and in Fiordland. We worked with [indiscernible] Guardians to create more flexibility and storage in that catchment, and we've just received ministerial approval to have our application for access to Pukaki contingent storage head through the fast track process. Second on my list of priorities, I want us to get even closer to our customers. That's where we've set our compass. Like every business, you're only as successful as the customers that you serve. So as well as evolving at pace to help customers thrive in the future, we're highly tuned into how we can support industrial and residential customers in the current tough environment. But back to today. There's no question that underlying financial performance was poor last year. From a financial perspective, the business struggled to get out of first gear and even had to hit the brakes hard at one point. Now that result has been well signaled and every Kiwi knows that when it doesn't rain, it's tough to make hydroelectricity and turn that into profits. The second half of the year was better than the first but only just. EBITDAF was $100 million more but the January to March period was the driest on record, and the rebound from April to June brought only average inflows. The result? The lowest earnings for our business in a decade. Now business is always going to take a hit in a drought, and this year, we had 2 and both of them one-in-90-year droughts. And when gas was switched on to replace hydro, that also failed. There's no historical precedent for this series of events, there's none. Despite these challenges, there was no loss of supply and 99% of Meridian's customers were entirely unaffected. And they're unaffected because we sheltered them from the high wholesale prices even though we didn't have that surety ourselves. As a result, we lost money in our retail business last year. But that's the advantage of a vertically integrated business. We can and will continue to navigate the challenges on behalf of our customers. I think the '25 financial year will be defined by Meridian putting the country's security of supply first, keeping power flowing for homes and businesses and the financial hit we took because of that. I understand that people are calling for generation to help bring prices down and ensure that we have enough electricity for the future. I want these things, too, but there's babies and there's bathwater. The New Zealand electricity system is robust, possibly more so now than before the events of August 2024. The same cannot be said of the gas sector. The failures evidenced in August '24 are now playing out more widely in that sector with customers facing higher gas costs, businesses having to put up prices to cover these costs, and the worst instance is shutting up shop because they can't get the molecules. The electricity sector uses gas, too, but we can't fix the problem of declining gas production. We can, however, work around it. As the Huntly Strategic Energy Reserve Agreement signals, the electricity sector is switching away from gas as well. Executing that agreement was a very challenging decision for everyone at Meridian, given our commitment to decarbonization and renewable energy. But the economy needs fuel and our job is to support that economy and ensure homes and businesses have the power they need. So we had to enter into a pragmatic solution. The good news is that so long as Pukaki contingent storage gets fast track approval, the Strategic Energy Reserve arrangement alongside NZAS demand response should see the electricity sector through the disruption. My key point is that the country's energy supplies have been challenged so we have adapted, not perfectly yet but things have certainly stabilized. And if I bring things back to the company level, the strategic energy reserve also signals that your management team has reset Meridian's portfolio settings to manage future risks. And despite these challenges, we've been able to provide a stable dividend to shareholders. Now we can't deliver our strategy without the confidence of shareholders who will always endeavor to reward for their loyalty. Furthermore, our business needs the support of those shareholders if it is to invest, and we have been and are investing billions. At least 1/4 of all electricity generation has been replaced over the past 15 years, costing $12 billion and that wouldn't have happened without big businesses like ours. $0.54 on every dollar of the dividend that Meridian makes is returned to the government. And that money, approximately $300 million this year, is used by the government to fund health, education and roading. A further $0.25 on the dollar goes to mom, dad, and youthful Kiwi investors. So in total, $0.79 on every dollar we make stays right here in New Zealand supporting Kiwis. And while the numbers we post are invariably large, shareholder returns have been incredibly reasonable. So a stable steady dividend is very important and it provides evidence of the strength of the business, and that strength is now being leveraged to grow. Not only did we deliver the $450 million Harapaki Wind Farm and the $186 million Ruakaka Battery last year, but we obtained 5 consents for new developments, including the $227 million Ruakaka Solar Farm, which is starting construction next month; Mt. Munro Wind Farm, Te Rere Hau, another battery near Palmerston North, and the Te Rahui Solar Farm, a joint venture with Nova. We don't just focus on today, we're focused on tomorrow and delivery of our strategy, and I'm going to move on to that strategy now. As this slide shows, the strategy is straightforward, invest in new renewable generation and firming assets to accelerate decarbonization of the economy, deliver cheaper energy to customers so they can unlock value in their lives and businesses, strive to deliver more from the operating business and grow the capability within the team so we can do better every year. It's aligned with where I want to take the business, it's clear for our teams and it connects directly with our purpose, and it will grow shareholder value. Now despite the challenging operating environment and conditions and intense industry scrutiny, Meridian continues to attract and retain engaged staff. In my view, that's because smart, capable people want to make a positive impact, and they can here. It's one of the reasons why I've spent 17 years of my life here. The people are terrific and they're also terrifically motivated. They also have the courage to do what needs to be done to make us better, a lot of it. I'll provide a little more color on this a bit later. Now we've also overhauled the well-being strategy and the overhaul was pleasantly straightforward. If we focus on leaders providing leadership and we take the draws out of daily of tasks, people will have space to look after themselves and it's working. Employee engagement remains strong with our latest survey showing 3/4 of the people that we work with are engaged and want to tackle the challenges ahead. Now that puts us in an upper echelon of New Zealand businesses. The safety metrics reflect the complexity of our operations, but we're committed to making sure that people are armed to make decisions regarding their safety as they go about their daily tasks. I talked to some of what's on this slide earlier, but the 2 One-in-90-year seasonal droughts May to mid-August 2024 and again from January to April 2025 were unprecedented and inflows into the hydro catchments reflect this. They were 64% and 57% of average in each period, respectively. And while the hydro lakes look large, the reality is that they only hold up to 16 weeks of water at best so they're, in fact, quite shallow. We have to remember that they were designed to meet expected electricity consumption in the 1970s, not the 2020s or 2030s. Financial impacts of lower physical generation flowed into monthly energy margin figures that are shown on the top right graph. The August through October impacts were exacerbated by the loss of gas and the impact of freeing up more from Methanex. We also asked NZAS to do more than contemplated last August and they did. The second drought saw NZAS provided even more support to the electricity system, which was appreciated. But as with all commercial arrangements, that 50-megawatt deal cost money, and it reduced energy margin by a further $40 million. Now if you want to understand what the electricity sector has been through, look no further than NZAS, that will finally be back to full load later this week after more than a year supporting the electricity system. So thank you to the NZAS team, you've become a bigger and more important element to the electricity sector than either we or you may have imagined only 18 months ago. And another that was then, this is now story, the green bar on the top graph shows that energy margin has reverted to pre-drought levels. As for gas, I've talked to that story, for 1 reason or another and I don't have the answer for it, but gas has not been able to keep up with the needs of a modern economy or the transition fuel to this country's low-carbon future. Instead, its demise is putting the electricity sector and the economy through the wringer. Looking ahead and based on what we know today, the graph on the right of the slide shows that dry year risk in the electricity sector has been stabilized so long as the Pukaki contingent storage fast-track application is approved before winter 2026. Combination of the strategic energy reserve, NZAS demand response and critically, that contingent storage provides enough energy to manage a drought should it occur. This combination is important as it buys time for Meridian and other businesses to accelerate the investment in renewable generation. We're targeting $2 billion of capital spend in the next 3 years. And our renewable development pipeline allows us to do that as it strengthened over the past 5 years. Te Rere Hau may have slipped by up to 12 months, but construction of the 130-megawatt Ruakaka Solar Farm is underway. Stage 1 of the Te Rahui 200-megawatt solar farm is about to hit financial close, possibly as soon as Friday. And we'll make decisions on the Manawatu Battery, a solar farm in the Waikato and Mt. Munro in the next 12 months as well. That would represent 1,800 gigawatt hours of new energy being delivered and $1.6 billion more capital deployed this decade with more to come. Our PPA for the Tauhei 150-megawatt solar farm enables that asset to be commissioned in 2026 as well. So we're cooking without gas and the benefits of these developments will flow through to shareholders in the country quite quickly. You'll also see that the pipeline has a higher concentration of solar development than wind or batteries. While solar is valuable to us as it's not correlated with wind or hydro inflows, our core development competence remains in building wind farms, and there are some material prices in that space so expect the pipeline to move over time. The Electricity Authority and Commerce Commission Task Force provided further insight into its level-playing field measures last week. It's hard to offer much commentary other than to say that we're up for any change that reduces cost for our customers. What is creating uncertainty and considerable noise is the fact that no one has any real idea what the government intends to do as a result of the Frontier report. And while I know the government is carefully assessing what to do, if anything, evidence from offshore interventions and electricity markets suggests that they typically increase rather than decrease prices for consumers. Now we're prepared for whatever might play out. The minister is talking about a surgical intervention. It's certainly not the time for an amputation. I say that because the underlying issue not only for the electricity sector but for the wider economy is the lack of gas. It's this that's driving up prices everywhere, and that, in my view, is what requires attention. If I was making surgical calls, I'd be considering the following: some form of funding to help gas customers convert to electricity or biomass, and quickly; deferring the Commerce Commission approved increases in distribution and transmission costs, as this is what's driving above-inflation cost increases for electricity consumers; and combining the gas industry company and the electricity authority to improve regulation and disclosures across the energy sector. Each would have an immediate benefit, and I'm hopeful that this is where the government focuses its response to the Frontier report. The reality is that the electricity market works and it did its job last August signaling gas shortage. Gentailers did not earn excess profits. The EA report of March '25 and this result approved for that. And the investment is pouring into the sector to remedy the problem that loss of gas created. And while the overall cost of living pressures on households are big right now, electricity costs, although a factor, have, as a percentage of average household incomes, been reduced over the past 10 years. And there are only 5 countries in the OECD with better industrial pricing than New Zealand. Of course, we can and we must do better. But where we're at today is a very strong starting point for a remote country without that many people. Now I want to change gears for a minute. Specifically, I want to talk about emissions as while not front of mind right now, given the overall cost of living challenge that people are facing, climate change is still a thing. And reducing emissions, especially as the sector is likely to burn more coal in the short term, is important. Meridian reviewed its Half by 30 framework during the year. And while the target to half Scope 1 and 2 emissions by 2030 has been retained and is tracking well, the Scope 3 target has been revised, given we're now in a period of material sector growth and investment. It's unrealistic to expect our supply chain emissions to half from 2021 levels in this capital-intensive environment. So we've reset that target to focus on a 51% reduction in Scope 3 emissions on a per megawatt installed capacity basis. That is we've changed it to an intensity target, a target that reduces the intensity of Scope 3 emissions as we grow. Now some may have noticed but in case you haven't, Meridian is now the highest-ranking utility in the Asia Pacific region on the Dow Jones Sustainability Index, again not bad for a utility in a small country. Before handing to Helen, I want to talk to the efforts of the retail team over the past 12 months as the decisions they are making and the outcomes they deliver will create considerable value for shareholders over the long term. They'll also support customers. Customer numbers lift by 35,000 over the year and Meridian now has 405,000 customers, excluding Flick. That's an important marker of customer support for what the team is doing, but as importantly, the retail team has begun to offer products to reduce customer costs. The first being a product that offers $10 off a customer's monthly bill if they hand over control of their hot water cylinder to us to reduce peak demand. Now that product already has 18,000 customers so it is popular. The team's also added 60 new EV chargers to the Zero network and reset the entire team structure, dropping 45 roles in the process or close to 15% of that team before the change. And after that change was complete, the team moved to select a new operating platform, Kraken to support the business into the future. The first customer has already been migrated to that platform. Of course, the retail team also runs an award-winning fund to support customers who decarbonize their businesses and a proper hardship practice to support our vulnerable customers. And when I say retail, it's people that make those tough calls and have to roll up their sleeves to make them work, and they did. They're outstanding last year, and I'm proud of the courage shown and the achievements to date as they're all designed to make energy cleaner and cheaper for our customers, the people who pay the bills and work hard themselves. Helen, over to you.

Thanks, Mike. Before we dive into the numbers, I do want to take a moment to recognize Mike Roan on his appointment as our Chief Executive. Mike, we're all genuinely thrilled to have you at the helm. And I do have to thank you for passing the acting CFO baton to me just in time to talk about our most financially character-building year in over a decade. So let's get started on the financials. FY '25 was a year where nature really tested us. As Mike mentioned, 2 record droughts, 1 in winter, 1 in summer, combined with low wind, decline in gas availability, a wet spring and low prices all created extremely challenging conditions to manage. As you can see, our operating cash flows have taken a significant hit, down 52% on last year. At $318 million, this is the lowest level we have reported since 2009. That's a tough number to stand in front of and I want to acknowledge that upfront. There are a few key drivers behind the result. Reduced physical generation from the back-to-back droughts; low wind generation and the cost of risk products, including the NZAS demand response cost saw energy margin drop by 23% to $982 million. This really reflects the cost of keeping the lights on when hydro and wind were scarce. We leaned heavily on derivatives and demand response during the year. And those tools did their job but they came at a cost. So in summary, operating cash flows fell by $349 million, driven by energy margin dropping $294 million and the increased tax of $35 million. This also all flows through to EBITDAF, which fell 32% to $611 million. What's important here is that our balance sheet held firm. We've actually built it to withstand dry years and FY '25 proved that our structure works. Now on to dividends. Despite the financial pressure and current year cash flows, the Board has declared a final dividend of $0.1485 per share, bringing the full year dividend to $0.21, which remains unchanged from last year. To support this, we drew on over $300 million of debt headroom. That's the equivalent of a reasonably sized new wind farm. That's not something we do lightly. We have also always carried conservative balance sheet settings to manage the business impacts of droughts. As a renewable and predominantly hydro generator, it is neither practical nor cost-effective to try and hedge away or the tail risk to our portfolio. So extreme drought will have an earnings impact. We're also being realistic. If we face similar droughts in future years, we may or may not need to review our dividend levels to provide flexibility and maintain our existing BBB+ credit rating. The dividend reinvestment plan remains in place with a 2% discount. Let's now look at EBITDAF. The biggest driver behind our decade-low EBITDAF was the $294 million drop in energy margin. That's the direct result of lower physical hydro generation and significant derivative and demand response costs, and I'll talk more about that soon. The winter 2024 drought broke in a hurry and the spring that followed proved to be the second wettest spring ever. And while $800 wholesale prices through a small number of August 2024 trading periods got plenty of headlines, the $1 prices that came with the spring inflows didn't quite grab the same attention. Managing those large inflows into our catchments meant we ran hydro hard, realizing very low generation prices. Other revenue has a couple of one-off items in it this year, including a new metering contract benefit, insurance proceeds from cyclone damage at the Harapaki Wind Farm and the operating revenue from our joint ventures in Flux. Transmission and distribution cost increases are also now flowing through. Energy margin fell to $982 million, down from $1.276 billion last financial year. The impacts of the drought show up in physical energy margin with hydro volumes more than 1,000 gigawatt hours or 10% off the 10-year average. In fact, you have to go back to 2012 and 2013, which were back-to-back drought-affected financial years to see our hydro output at less than 11,000 gigawatt hours. These conditions also affected wind generation, with calm periods coinciding with the droughts, particularly in winter and summer. Despite that, we've had almost a full year of production from the Harapaki Wind Farm, and it performed exceptionally well, achieving a 35.5% capacity factor in its first 12 months. However, to manage the volatility, we did spend $300 million on derivative purchases and demand response calls. And while they worked, they were expensive and drove a $460 million reduction in financial energy margin compared to last year. Now I do want to take the opportunity to address the common misconception that high wholesale electricity prices are somehow a windfall for Meridian. That idea is simply not the case. High wholesale prices are a signal, a signal of fuel scarcity. That's how the market is designed to work. During the year, we became a substantial net buyer of electricity derivatives and at those elevated prices. And those prices were compounded by gas scarcity. The sector's traditional backup fuels were simply not available in the volumes or at the prices we've relied on in the past. So while wholesale prices were high, they reflected a stressed system. And for us, that translated into higher costs, not higher profits. Now let's talk about our retail business. Retail really was the bright spot this year, and it's where we're seeing the most visible transformation. We ended the year with over 405,000 customer connections, a 10% increase from last year. That's more than 35,000 new connections across our Meridian and Powershop brands. We saw a 2% increase in sales volumes across our mass market segments, excluding agriculture and a 6% lift in net average sales price, delivering a $32 million increase in revenue. In the corporate segment, volumes were flat, but pricing strength drove a $36 million uplift or 7% growth in revenue. And while agricultural volumes declined, down 13% on last year, these can move around year-to-year based on the irrigation season. But our growth is clearly being led by residential, SME and the large business segments. Overall, this is a standout performance from the retail business, and it positions us well as we roll out our new Kraken platform and the digital customer experience. Moving on to generation. At first glance, inflows came in at 98% of average, which sounds pretty solid, but that headline hides the extreme volatility we experienced. FY '25 brought the kind of variability that is incredibly difficult to manage, and it resulted in our lowest hydro generation since 2013. The Harapaki wind farm delivered its first full year of generation, producing 549 gigawatt hours. That contributed to a 20% increase in wind generation year-on-year. We've also made progress on our generation upgrade program, restoring 29 megawatts of capacity at White Hill and Te Apiti and an additional 18-megawatt uplift at Aviemore and Ohau B and C. This all links to the 112-megawatt of new hydro capacity we are chasing from our existing assets. We've also faced challenges. At Manapouri, we've been dealing with issues related to 7 transformers originally supplied in 2015 and '18. Two of these were removed from service in 2023 due to elevated gasing. A third was installed at the end of 2024. Two new transformers from a different provider are expected to arrive by early 2026. We've made the decision to proactively replace all 5 over the next 2.5 years. At West Wind, a prolonged transformer outage took 45 megawatts out of the system, reducing capacity to 98 megawatts for most of the year. We did secure a loan transformer from Transpower in late 2024, which restored that lost capacity and the permanent replacement has now arrived and is sitting on the Wellington Wharf. So we're on track to have the new one operational before the end of October this year. Let's now move to operating expenses. This year, OpEx came in at $289 million, a 3% increase on last year and importantly, below our revised market guidance of $298 million. Now that sounds like a modest rise, but there's a key reason behind it. In short, this year, we didn't meet our short-term incentive financial benchmark. This contributes to a cost reduction of $7 million. This means that our people received a small proportion of their potential incentive payments and our senior people received no payment. That's a tough outcome, but it reflects -- but it's a reflection of how closely our remuneration is linked to performance. Beyond incentives, we also signaled operational changes to our retail and Flux business units. These round the $11 million of staff cost reductions and reflect the new Flux structure, which now has 29 fewer roles. At the same time, we have invested in transformation. We have brought in contract support to help deliver the retail transformation and DigiGEN, our digital generation program. These costs are reflected in the $8 million increase in contractor spend. We have successfully completed the implementation of our new Oracle finance system on time and on budget. These one-off costs show up in the $6 million ICT line. The cost line also includes the addition of Harapaki's operating costs. And finally, like everyone else, we have also encountered higher counsel rates across our generation assets. Now on to capital expenditure. In February, we revised our guidance and indicated that we might spend between $220 million and $250 million. We landed at $193 million, down 45% from last year and below that guidance. It's important to note that this lower spend simply reflects timing changes and not a slowdown in our strategic investment. FY '24 included milestone payments for Harapaki and the bulk of the Ruakaka BESS investment. In contrast, FY '25 fell between the tail end of Harapaki and a later-than-expected start to the construction of the Ruakaka Solar Farm. Consent for that project was initially lodged in September '23. It took just over a year to secure initial approval in September '24. That decision was then appealed and it took another 5 months to reach resolution and final consent in February 2025. Stay-in-business CapEx also lifted this year, driven by 2 key investments, the replacement of our SCADA generation control system and upfront costs for the new Manapouri transformers. Looking ahead, our investment program is accelerating, including the 5 new consents that Mike talked about earlier. Now we jump to talking about FY '26, where we want to continue to provide guidance on our future operating and capital expenditure. Operating costs first. We are looking at spending between $311 million and $316 million next year, which represents an uplift of up to 9% on last year. What's driving that increase is not just inflation or overheads, it's investment in the future. One of the biggest contributors is our retail platform transformation. In FY '26, we'll be running 2 billing platforms, Flux and Kraken as we transition customers across, temporarily doubling up on costs. Once we're fully on Kraken, we expect to remove $15 million of annualized Flux expenses from our cost base by FY '28. So this is a short-term transition cost for the long-term gain. The other key driver is our expectation that we'll meet our short-term incentive financial benchmark next year. This means that we expect to pay a higher level of short-term incentives than we did in FY '25. Now turning to capital expenditure. We have allocated between $330 million and $360 million next year. As you can see from the graph, growth CapEx is largely driven by the completion of the Ruakaka Solar Farm. On the stay-in business CapEx, the more generation assets you build, the more likely you are to see asset maintenance costs rise. We're also continuing the transformer replacement program at Manapouri that I talked about earlier. The $10 million cost of the 2 new transformers in FY '26 is also included in the asset maintenance bucket. So in summary, costs are going up, but they're going up for the right reasons. We're investing in platforms, people and infrastructure, and we're doing it with a clear view of the long-term benefits. Let's now look at the results below EBITDAF. These graphs clearly show a massive swing in our reported profit. Net profit before tax fell $671 million and net profit after tax dropped $881 million. Even our preferred non-GAAP measure of underlying net profit after tax was down $303 million from last year. So what's driving these movements? The key factor was a $1.247 billion loss from the fair value movement of our energy hedges. This number includes realized and unrealized losses. $901 million of that total loss relates to NZAS and is driven by the accounting treatment of the new electricity agreement, which came into effect in July '24. Under the new structure, the NZAS contract is treated as a financial instrument or a derivative for accounting purposes, a 20-year contract for difference or CFD rather than a standard revenue contract. This means it's now carried at fair value and remeasured at each reporting period, with the main driver of any value change being movements in the long-term electricity price forecast. In FY '25, the unrealized loss on the NZAS contract was $465 million. This loss does not reflect actual cash flows. We also recognized a $33 million impairment on the Flux platform following our decision to transition to Kraken as our retail technology platform. Depreciation increased by $113 million, largely due to last year's $3 billion asset revaluation across our generation assets. Again, this is a noncash adjustment, but it does affect reported profit. And with another $2 billion uplift in asset valuation this year, depreciation will increase again in FY '26. Our generation assets get revalued each reporting period based on the same long-term electricity price forecast as electricity derivatives. All of that washes through to a statutory loss of $452 million. Our underlying NPAT, which adjusts for the noncash items was just $56 million, down $303 million from last year. That movement is largely explained by the $294 million drop in energy margin with the higher depreciation expense offset by the negative tax expense on the current year statutory loss. So while the headline numbers are poor, it's important to understand that these are largely accounting-driven impacts, not operational ones. Our underlying business remains strong. We continue to invest in growth, maintain our dividend and support customers through the energy transition. Net debt increased 18% to $1.505 billion and our net debt-to-EBITDAF ratio rose to 2.5x, up from 1.4x last year. We have $658 million of undrawn facilities, all under our green finance program with a diversified funding mix. And while Meridian's spot debt-to-EBITDAF has increased, this was due to the dry year EBITDAF rather than a large increase in leverage. S&P do take a multiyear view of our debt-to-EBITDAF and have affirmed a stable outlook as at July '25. We have ample liquidity available to support our balance sheet through debt facilities. We're also considering a $300 million green bond issue, which would extend our debt maturity profile and support strategic investment. Our capital structure remains robust, and we're well positioned to fund our growth agenda. Finally, a quick look at July. The good news is that we're seeing signs of recovery, and we are well past the drought impacts of last financial year. Inflows for the month were 89% of average. Waitaki storage was also sitting at 89% and snowpack was 76%. Hydro storage is significantly higher than this time last year, and generation volumes are tracking well. That's a solid foundation heading into the new financial year. Customer connections grew 1.4% in July and are up 11.2% year-on-year. Retail sale volumes were up 9.4% and generation was up 9.6% compared to July last year. These are further strong indicators that earnings reversion has happened and operating conditions are stabilizing. August will also see the final fees paid on the largest smelter demand response call we made last year. The ramp-up is almost completed and NZAS are nearly back to full consumption. The annual premium fee for the demand response continues, but the temporary call has now concluded. Looking back, that demand response call was critical. It underpins security of supply through the extraordinary drought we faced last year. And it's a great example of how customer flexibility in the system can support resilience when it's needed most. So in summary, while FY '25 was financially poor, we're heading into FY '26 with a strong balance sheet, lots of momentum and a more stable operating environment. Back to you, Mike.

Thanks, Helen, and thanks for the CE Plug. It was a nice touch. Tough experiences character. And last year, it certainly did that for us. It was tough financially, and it was very tough for customers. But it would have been a lot tougher for them without us, and we are proud of the support we provided and we'll continue to provide them. We realize that we have got to prove ourselves to investors all the time, even more so when things don't go to plan, and we are. Delivery of the Harapaki Wind Farm and Ruakaka Battery, alongside consent and current construction of the accompanying solar farm at Ruakaka mean that we're growing. With Te Rahui, Mt. Munro, Te Rere Hau, the Palmerston North Battery and the PPA supporting Tauhei, that growth will continue. The meaningful progress within the retail and generation teams and the Flick acquisition will make a difference as well. And the stable dividend should allow investors to look through last year's challenges and focus on the future. With that in mind, I'm pleased that operating conditions have returned to normal. And with a risk -- a new mix of risk management products on hand, the business is well equipped to navigate the next few years. So the majority of the damage that the sudden collapse in gas supply has caused is behind the electricity sector. Absent more unhelpful news, any remaining uncertainty has been driven by concerns that the government may intervene. My observation is that they know the cost of doing that would be high, and so are taking their time to assess whether it's worth it or not. Regardless of what they do, it will be up to us to navigate the course. And I'm ambitious for the company as I know that we're busy unleashing the renewable bounty that New Zealand has. And as that happens, the country will gain a sustainable, competitive and cost advantage that other countries will not be able to match. We intend on providing a little more insight into this at Investor Day -- on Investor Day that's scheduled in November. But right now, we can move to questions, and we'll start with questions from anyone here in the room. Hugh, we'll go to you.

Hi, I'm Hugh Lockwood from Forsyth Barr. Mike and Helen, just a couple of questions. Firstly, are you able to provide a bit more color on the dividend commentary and maybe talk to what net debt-to-EBITDA gearing ratio the Board would be comfortable with looking at a sort of normalized hydro earnings basis?

Yes. I mean it's exactly what I have said, Hugh, is, you know, we have paid a stable dividend over a year where cash flows haven't sustained that. So all we're trying to say to people is we're mindful that, that has consumed a piece of the balance sheet. And if we have another drought in the future, we'll look at it. Other than that, we expect normal business, which is what we hope for as well. Net debt to EBITDAF is driven by the S&P ratios really as you look -- we had a spot ratio this year that was 2.5x this year. Last year, it was 1.6x (sic) [ 1.4x ]. We expect that to normalize as we head into next year as well. So we're just -- we're looking at the 2x to 3x is the range for net debt to EBITDAF.

Okay. My second question is on the pipeline. So you mentioned that Te Rere Hau's time line has been pushed out, but you've got the target for 3 projects to commence in FY '26 and it sounds like a lot of projects might reach FID in the next 12 months. So can you talk to what other projects might be part of that 3? And also if there's maybe the potential for more than 3 next year?

Well, we're hopeful that there might be more than 3, but the 3 that I've mentioned, the first one is Te Rahui, I mentioned that the next couple of days, we expect that it will reach financial close. The team is working really hard on the battery in Palmerston North and Mr. Munro Wind Farm as well. And while Te Rere Hau has slipped by up to 12 months, there's a lot of work that's going on to see whether we can't bring that forward as well. So time will tell. Development, as everybody knows, who's in the development game is tough. You find things out that you just didn't expect, but we have a lot of people working really hard to deliver those outcomes. Jonty?

Nice to see you.

Jonty Nattrass from Octagon Asset Management. Thanks for the presentation, Mike and Helen. My first question, obviously, with FY '25 kind of fresh in the minds, just wondering if you could provide a bit more context on the portfolio positioning how you see your length? You mentioned the Waitaki contingent storage as part of that wider security thing. Does that play into your -- the thoughts on there? And how does the HFO kind of feed into that?

Yes. It's having gone through, as you say, '24, '25, it allows you to look really carefully at business settings. And we were on this trajectory to not only buy a bunch of risk management products that supported us, but decarbonize the marketplace more effectively. We've had to sit back and look at that again, Jonty. And the 2 things that have gone on within the business is we set an optimal portfolio for our business based on the opportunity in front of us and the risk that we face, and we've backed that off a touch. So we've dropped the optimal levels a touch as we head into 2026. We've also reset the risk management products that we have within the business is the way that I presented is we have about 300 megawatts worth of swaptions or demand response sitting within the business given the transactions that we've written, which are -- that's a lot more than we had as we headed into '24, and we knew, we found out in '24 that some of that insurance didn't work out so well. So we feel really good about looking at 2026. We don't know whether it's going to be wet or dry or normal, but we've certainly the portfolio given the experience that we had. Your piece on contingent storage is, the way we see that is it's just incredibly important for New Zealand energy security is all the analysis you can -- that graph shows -- hopefully gives people some insight into how the strategic energy reserve NZAS transaction and contingent storage line up to cover dry year exposure from a country perspective. And so secure supply as well as moderating costs for customers is really what contingent storage will help with.

And my second question is just on the hydro development that you mentioned, Mike, I know that was a key focus of you coming into the top seat. I just wondering if you could talk a bit more about -- is that on top of the work being done within the generation team to expand, obviously the transformers expand capacity of the Waitaki, is that looking at further expansion of those 2 schemes?

Yes, it is, Jonty. So I kind of mentioned that we're going back to our roots. We're trying to redevelop a skill set that was manifest in the 60s and 70s within the business. And so it will take us time to develop the internal capability and then identify the options that work. But it's kind of simple in one way is as you lose access to gas and gas storage that provides that firm because we have to get it from somewhere else as a country if we want affordable energy. And when you look around, resource that we have that other countries don't have is we have hydro. And so we will be careful of it. We'll work with stakeholders to move our way through that process. But if there's ever a time that the country needed someone to be looking at it, it's now. I don't think we've got any more questions in the room. So why don't we move to the phones.

Your next question comes from Joshua Dale with Craigs Investment Partners.

Just on the Te Rere Hau project. Now you've acquired NZ Windfarms. I think in the past, you'd signaled the cost of that project was $500 million to $600 million. What does the incremental cost look like now, do you think?

So I reckon it's going to cost us more than $600 million, Josh, is probably the best that I'd give you, but the economics of that project, it is one heck of a project, the average capacity factor on that wind farm, it looks superb. I'd love us to be able to push the go button on it. But we've got one challenge at that site, and it's an important challenge to resolve, which is there's an airways tower that sits there and helps air traffic in New Zealand navigate the skies, and we've got to move that offsite successfully. So that's really, really important. We've got to get it right, and we will, but it's just taking more time than we've contemplated. But that is an incredibly valuable property.

Got it. And just on your balance sheet settings, you've talked a little bit about this. Traditionally, the range seems to be 2x to 3x net debt to EBITDAF, but we're in an environment now, obviously, with gas backup getting harder to rely on, we've just had evidence of what your exposure can be to a dry year. And then you've got $2 billion of CapEx coming through. I appreciate you've sort of ended to manage the balance sheet to a bit more conservatively than that 2x to 3x range. But has there been any change in your thinking or perhaps changes to the phasing of that CapEx to sort of provide you more capacity going forward?

I mean the simple answer, Josh, is no to you.

I'm going to say the same thing, so it's good.

No, you come back to the country needs energy. And our job is to provide that energy, and we've got the consents that are coming through our pipeline, and we've got the balance sheet to deliver it. There's no question about our intent moving forward. I think what you've seen for our business is, I hesitate to say you've seen floor earnings because the future is really uncertain, but you've got a sense of what can really happen to our business when things are extreme, two 90-year droughts and the loss of gas in 1 year for a business that relies on hydro energy and then thermal when it doesn't rain, that's a pretty tough thing to go through. So I don't have any concerns as I look at the financial forecast for the business and our capacity to both deliver investment and stay within that net debt-to-EBITDAF range that you mentioned. Helen?

And I think coming back to that CapEx spend, the key driver of any changes to the amount we spend in a financial year is the impact of the development pipeline and any delays to that pipeline. And you saw that in the amount of CapEx that we spent in FY '25. So while we give guidance and we model that of where we think we're going to land with CapEx, any delays in that development pipeline will have an impact to that debt level.

The last question I had was, if I'm a customer sitting at home logging into your website in, say, 12 months' time, you've got the Kraken platform implemented. Are there any changes to your product offering that I may see.

Yes. That's...

That's the plan.

Absolutely will, Josh, as -- the benefit of technology is, it allows you to both connect with your customers more effectively because you get to know them better through the use of technology, and it allows you to expand your products and services to them. Now Kraken is incredibly efficient and effective at what it does. It wasn't easy for us to step away from Flux, but we have. So that gives you a sense of discipline that we have got and our commitment to delivering outcomes for our customers as well as shareholders. So yes, you will.

Any early sort of insights on what customers may see in a product offering sense?

The simple answer is no, Josh, but not because you've asked this. I'm just not giving anything away to our competitors.

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

Just a couple of questions from me. Are you able to remind us, I think the contingent storage volume that you're looking at is around about 600, 650 gigawatt hours. And how much of that assuming it comes through, do you think you'd be able to access in sort of an average year in terms of what would your average hydro generation volumes change by if you had that available?

Andrew, so it's 545 gigs that's available through that contingent storage. And you're right, on average, we will generate harder. I don't have a number for you. Owen's is kind of signaling 3 or 4 or something, but we'll let you know. But the key point is as you increase access to hydro storage, you are able to generate more because you've got access to more water on average. And the way that we've talked to it previously as I said, we see the financial benefit to customers being in the order of $500 million a year, and the improvement in our earnings base being in the $12 million to $15 million per year. So we think the leverage outcome for customers is brilliant, but there is an improvement in our own financials as well. So I don't have the gigs for you, but given you probably what you wanted to know anyway.

Yes. Well, good. And just sort of following on from that, I mean, you, I guess, applied for emergency access to that storage for 2025 and Transpower turned you down. Going through the fast tracking consent process, I mean, how is that going to differ? I assume you're more confident of being successful through that. And presumably, the aim is to get that in place for 2026.

Yes, it is. So the aim is to get it in place before winter '26. And I think about it like we think about consenting is you've got to choose a number of routes if you want to improve the odds of success. And so we were hopeful that working with Transpower that we would get confidence for winter '25 access to that storage, but we didn't. And in the meantime, while we were going through that process, we lodged a fast track application. And we do have, I'll say, reasonable confidence. We haven't been through that process before, but certainly, the effort that we're putting in and bring it back to what I said before, when you look at charts or talk to people about winter 2026, security supply is going to be driven by access to it. So there's a national need as well as a company outcome.

Okay. And just last couple of questions, just sort of looking at the Kraken implementation and just understanding, making sure I'm getting the OpEx right going forward. So you've got elevated OpEx for FY '26. And I'm right in saying in FY '27 as well before we see things reduce. Helen, you talked about, I think, $15 million reduction in OpEx after that. Is that just the one-off costs dropping out? Or is that in addition to one-off costs?

So the $15 million dropping out is essentially the operating cost of the Flux business. So once we fully moved over to the Kraken platform, then those costs will come out of the business. And that's why we've said that, that should happen by the end of FY '28. But it will be a gradual reduction in that over those financial years.

And in terms of the elevated level of cost per annum as you implement Kraken? I guess what are the Kraken costs?

They're in the same order, Andrew. So that lift that Helen presented, they're in the $12 million to $15 million range. So you kind of -- the challenge for us over the next couple of years, as Helen said, we're running 2 retail billing platforms. And as we migrate to Kraken, we'll be able to reduce the cost and impact of the Flux platform and by '28, we should have unwound it entirely.

Your next question comes from Grant Swanepoel with Jarden.

Just I wasn't quite clear on the answer to Andrew there. So this $12 million of extra Kraken costs related costs this year, that drops out and you get just a $3 million extra reduction in costs by 2028?

So I think we'll probably be looking at probably a $3 million to $5 million drop.

My next question is just on your maintenance CapEx. So that's been creeping up every year, and we understand why it's been creeping up, but our valuation obviously links to a long-term maintenance CapEx expectation. What is the long-term expectation for ICT costs and asset maintenance?

Yes. Drawing on the asset maintenance cost and what I've tried to pull out in the presentation is that as we continue to add new generation assets, they do need to be all maintained. So you will see higher levels of stay-in business CapEx in relation to asset maintenance just due to the fact that we'll have more assets to maintain. On the ICT side, the costs over the next couple of years are all related to the digital transformation that we're doing across retail. So that's in that Kraken space. And then also in our DigiGEN, which is a digital transformation of our generation business.

Grant, you know, how we used to talk to $65 million of annualized CapEx was kind of the number and then we actually only spend about $50 million of annualized CapEx. I think what we'll do is we'll give you an update at the Investor Day in November on CapEx because those numbers still feel reasonable. But what we're seeing is a bunch of one-off replacements, whether it's the SCADA environment or...

Transformers.

Yes, the transformers. And of course, they flow through multiple years. So I think we do owe it to people to come back and rebaseline that underlying business capital forecast.

Mike, that's very helpful because your asset management costs have risen from $24 million to $65 million over 2 years, that's quite unfortunate...

Yes.