Meridian Energy Limited (MEL) Earnings Call Transcript & Summary

[Foreign Language], good morning, everyone, and thank you for joining us for Meridian Energy's results announcement for the financial year ended 30 June 2026. I'm Mike Roan, Meridian's Chief Executive; and with me today is our Chief Financial Officer, Mandy Binnie. A year ago, I presented a result that reflected some very challenging market conditions. At the time, I said I remain confident in Meridian's future and in our ability to grow the business, support the economy and deliver value for shareholders. This past year demonstrates why. We delivered a strong financial result. And as importantly, the business is stronger, more resilient and better positioned to create value. The foundations we've put in place give me confidence that Meridian can continue creating value as wholesale prices normalize, business electricity prices fall and electricity price increases for households begin to moderate. Financial outcomes matter because they tell us whether we're creating value, but they're not the entire story. The broader story is the improvement in Meridian's underlying capability, some of the most significant elements of which are captured on this slide. Over the last year, the Meridian team is focused on increasing the flexibility of our generation portfolio, supporting customers and continuing to build and execute a high-quality development pipeline. We increased our hydro storage by 20%, secured a further 35-year consent for the Waitaki Power Scheme, added 30 megawatts of hydro capacity, improved hydro availability, expanded our development options, grew our customer base and extended our EV charging network. At the same time, Dow Jones recognized Meridian as 1 of only 10 utilities globally and the only utility in our region included in its Best-in-Class World Index. I'll return to many of these achievements throughout the presentation, but first, I'd like to talk about our people. No business outcome happens on its own. It's the product of the people who come to work every day and make Meridian what it is. As the slide shows, Meridian continues to attract people who are highly motivated, effective and committed to our purpose. Despite significant change across the business during the past year, staff engagement has continued to improve. That's pleasing, but it also comes with a responsibility on leaders, including me, to keep raising the bar on what good looks like, and we will. Our development program continues to grow and with it, the risk profile of the business. More construction, more contractors on site and more field-based work all increase the importance of getting health and safety right. Meridian's culture gives me confidence that our people feel empowered to slow work down or stop it if conditions warrant. What concerns me is that this culture is not yet flowing through to our contractors as consistently as it should, and our injury statistics reflect that. I regularly tell contractors the same thing I tell our own people. When you're on a Meridian site, it doesn't matter what badge you're wearing, you're one of our team, and the expectations and standards are the same. Our focus is on better contractor induction, clearer site communication and stronger critical controls. Of all the responsibilities I have as Chief Executive, keeping people safe remains the most important. The regulatory and political environment remains fluid and many of the larger policy decisions will be influenced by the outcome of the election. Investors generally dislike uncertainty. Fortunately, Meridian only has 2 significant near-term capital allocation decisions: the refurbishment of Waitaki Power Station and Mt. Munro Wind Farm in the Wairarapa. The first is relatively straightforward. The second will be considered by the Board in December, by which time we should have a clearer view of the policy environment. The key regulatory matters affecting the business are set out on this slide as well. While the eventual shape of the LNG proposal and the winter energy reliability obligation remain unclear, the Electricity Authority's level playing field regime is now in force and Meridian's first retail price consistency assessment will be submitted in September. Last year, Meridian's Retail business recorded an EBITDAF loss again. As captured in a later slide, that outcome reflected retail prices not moving as quickly as wholesale costs. As wholesale prices have now returned to levels that reflect the long-run cost of new investment, over time, I expect retail profitability to normalize. The Authority will form its own view on that relationship. Our job is to apply the rules properly while making sure sensible pricing decisions are made for customers. Before moving on, I want to acknowledge the government's progress on fast-track consenting and broader resource management reform. We talk a lot about affordability, security and decarbonization. None of those things happen unless projects get built. New Zealand's got no shortage of renewable resources. Often, the challenge has been gaining timely consents to make the best use of them. These reforms are helping address that problem, and in my view, will make a meaningful difference to the pace at which the country can electrify and grow. Now there isn't really a great deal to say on this slide, which is exactly what you want from projects under construction. Ruakaka and Te Rahui remain on schedule, costs remain well controlled, and Tauhei is a little ahead of schedule. As you'll see, we're taking a diversified approach to funding solar development. Ruakaka is on balance sheet, Te Rahui is project financed and Tauhei is purchased. We do like solar as part of the portfolio, but diversity of funding and structuring seems important as we observe its impact. One thing not on the slide is the role that solar can play in reducing dry year risk. As droughts generally coincide with periods of high sunshine and low rainfall, the more solar generation there is in the system with a utility scale or behind the meter, the less pressure there is on hydro storage during those periods. Solar, therefore, does more than add generation. It can help preserve water when water is most valuable. And early analysis suggests that benefit may be meaningful. While the work is not yet complete, it reinforces our view that continued solar development can improve system security while benefiting Meridian and electricity consumers. We'll share more on that work at our interim results. The Ruakaka battery is a good example of successful electrification. It improves security, lowers system costs, enables greater use of renewable generation and creates value at the same time. It's done this by improving HVDC transfers, value captured during volatile market conditions and improved efficiency across the electricity system. Starting with the top right graph, the battery has supported higher levels of HVDC transfer. As you can see, since the Ruakaka battery was commissioned, transfers above 1,100 megawatts have become a new normal for the market. That additional transfer capability allows more renewable energy from the Waitaki and Waiau catchments to reach North Island customers, and it reduces the reliance we would otherwise have on thermal generation in the North Island. Second, the battery is capturing value during periods of extreme price volatility. The bottom right graph shows that. Our trading systems are highly automated and the battery increasingly optimizes between energy dispatch and reserve services in real time. Third, the North Island to South Island futures price differential has narrowed materially since the announcement. That improves South Island price capture and reduces the cost of hedging our North Island customer base. Encouragingly, these benefits are not just limited to Meridian. They also support the wider electricity system. We saw that between the 4th and 7th of August. During record electricity demand, the system continued to perform despite Huntly 5 being unavailable. Ruakaka was one of several assets supporting system security and demonstrating how a more renewable electricity system can operate reliably. There are 2 key points on this slide. First, any major investment decision we make over the next 12 months will largely affect 2029 and beyond. That's the reality of developing and constructing large-scale renewable assets. Second, we now have multiple credible development options in front of us. That means we can remain disciplined and allocate capital only where and when returns justify the risk, and the use of capital is attractive relative to other opportunities. Looking across the portfolio and as summarized on the bottom graph, Mt. Munro is a quality asset. Barring a material change to our market or policy conditions, it remains on track for a final investment decision in December. Te Rere Hau is arguably a higher-quality asset again, and the outstanding issues I discussed at interims have been worked through. The wind farm is shaping up as a strong candidate for an investment decision in the third quarter of 2027. At interims, I said that Te Rahui Stage 2 would be ready for an investment decision within 12 months. That remains the case. Being ready to decide, however, is different to being ready to commit capital. While its economics remain attractive, it represents a meaningful increment of new solar generation. Therefore, before committing, I want confidence in sustained demand growth or a customer arrangement that supports the investment. The Ruakaka battery has also demonstrated the value that an integrated energy park can create. Combining generation and storage alongside our existing portfolio is proving more valuable than we originally expected. As a result, I've asked the team to look closely at how we might accelerate the development of the Bunnythorpe Energy Park. Few companies can combine batteries with more than 12,000 gigawatt hours of South Island hydro generation and a large North Island customer base. We can, and we are becoming increasingly confident about the value of that combination. The final project worth mentioning is one of our oldest assets. Waitaki Power Station turns 91 this year. And next month, we expect to reach a final investment decision on a major repowering and uplift project. Waitaki has served the country exceptionally well over many decades. This investment ensures that it will continue doing so while improving its performance and value. As the market evolves, many developers are seeking to align new generation directly with new load, whether that's a data center, an industrial customer or another electricity user. We'll do that in some cases, and I've already touched on at least one example of where that might occur. Our preferred broad approach, however, is to grow generation and customers together. As you can see from the graph on this slide, the level of customer sales currently exceeds our optimal market position. As a result, we buy ASX contracts to cover the difference. However, when Ruakaka and Mt. Munro come online, the volume of North Island hedge purchases required to support our customer book will reduce. And those projects are needed. While the sales position looks flat, we expect our customer book will grow to 500,000 and then 600,000 customers before 2030. Our development projects can, therefore, create value as stand-alone investments and as part of the wider Meridian portfolio. This approach maintains development discipline, reduces our reliance on external hedge markets and creates greater resilience if wholesale prices fall materially. We don't need every project to be tied to a single customer nor do we want every project fully exposed to the merchant market. The right position sits somewhere in between. This slide updates the one presented at our interim results with the important addition of the storage now available at Lake Pukaki. The key point is not simply that Meridian has more risk management volume available than it did in the 2025 financial year. The portfolio is now considerably broader and more diverse and more flexible. Compared with back then, the volume of available risk management options has roughly doubled. It is diversified across different mechanisms, counterparties and fuel sources. A greater proportion is now controlled or directly accessible by Meridian rather than being entirely dependent on third parties. I know this remains particularly important to shareholders given what unfolded during the previous financial year. Looking at the portfolio today, my assessment is that we probably have more flexibility than we strictly need in current conditions, but that's a good position to be in. It gives us confidence to continue growing the customer business, it supports future investment decisions, and allows us to optimize the risk of risk management products as conditions evolve. In a more renewable electricity system, the ability to respond to changing hydrology, demand and market conditions is becoming as important as raw generation volume. That is why the 20-year demand response arrangement with NZAS is strategically important. It provides a significant source of flexibility at a time when flexibility is becoming increasingly valuable. Combined with the Huntly Strategic Energy Reserve, additional Pukaki storage and our growing renewable portfolio, Meridian is in a materially stronger position than it was just 2 years ago. I want to explain why securing access to the additional storage at Pukaki may prove to be one of Meridian's most important achievements in recent years. The events of '24 exposed a significant vulnerability in this country's energy system due to the unexpected decline in the gas sector. As the top graph shows, had additional hydro storage been available, wholesale prices would not have reached the levels they did. That is why we pursued it through fast-track. The first benefit is, therefore, greater protection against dry year and security of supply risk. The second benefit is lower wholesale prices, and these will flow through to customers. We estimated that increasing storage flexibility could reduce average electricity prices by up to $10 a megawatt hour or by $400 million per annum. And the last benefit is to shareholders. Recent operating analysis has highlighted that the opportunity to improve coordination between the Waitaki and Waiau catchments is a little larger than initially expected. While we knew that this additional storage would reduce spill in the Waitaki system, increasing usable storage at Pukaki also creates flexibility in the Waiau. In practical terms, we should now be able to use Lake Manapouri and Te Anau low ranges more effectively when conditions allow, knowing additional storage remains available at Pukaki if a drought develops. As historical annual spill is in the order of 600 gigawatt hours in the Waiau, and 800 gigawatt hours across both catchments annually, capturing a proportion of spill in the Waiau creates a larger opportunity than we had previously expected. But the most important benefit remains security of supply. The major focus for the retail team this year has been migrating customers onto the technology platform, Kraken. We've easily passed the halfway mark in that endeavor. At interims, I said that we had slowed the migration to protect the customer experience. That was the right decision. The broader migration has gone quite well, although some decisions affecting the Powershop experience frustrated customers and understandably, they let us know. We're still working through a small number of issues, but most have been resolved. I actually became a Powershop customer during the process. I switched from Meridian, partly because I wanted to experience the changes firsthand and to understand what was frustrating people. The new app experience is definitely different to the old one. And while change always takes some adjustment, it's actually pretty straightforward to use. Importantly, we now have a platform for continued -- to continue improving the customer experience and operating efficiency. And despite the scale of the migration, we continue to increase our market share and the real value lies in what comes next. The new platform gives us the ability to innovate, improve the customer experience and add value for customers. The other important development for customers has been the movement in wholesale electricity prices. Since the start of the year, wholesale futures prices have fallen by between 25% and 40%, depending on what year you look at. That's a material shift, and it's great news as those lower wholesale prices are already flowing directly to business customers as contracts are renewed. And that is strong evidence that the market is doing what it's supposed to do. Meridian and other generators are investing in renewable generation at an unprecedented scale in New Zealand, and those investments have increased supply, improved security and put downward pressure on prices. The top graph on this slide compares real residential tariffs with wholesale spot and futures prices. The key point is that residential prices have not risen at the same rate as wholesale prices since 2019. They've lagged materially. If you wanted a simple illustration of why the gentailer model exists, this is it. Gentailers absorbed and smoothed wholesale market volatility, so customers do not experience the extreme movements that occur in spot and futures markets. But as wholesale prices have fallen, the question on everyone's minds is, will residential prices also soften? The headline's relatively straightforward. Wholesale prices have fallen materially and customers will benefit over time. However, as the graph on the bottom right shows, the pace and scale of that benefit will be influenced by regulated lines charges, which remain a significant headwind out to 2030. These are obviously outside of our control. Households may, therefore, see less relief in the total bill than movements in wholesale electricity prices alone would suggest. But to provide some confidence, today, we're committing to ensuring that for residential and small business customers, the average price change to the energy component of the bill across all of our plans will be held below the rate of inflation over the next year. Meanwhile, we remain focused on helping customers save through our products and services, and continuing to support those who are finding it hard to keep up with their bills. Our Board has approved an additional $7 million to extend our Energy Wellbeing Programme through 2030, allowing us to continue partnering with community organizations to provide practical support for customers experiencing hardship. We've also materially sharpened pricing at one of our brands, Powershop, starting this week. So if you're a Powershop customer, keep an eye on your app. It's a small way of thanking customers who have stayed with us through a challenging period. We appreciate it. Mandy, over to you.

Thanks, Mike. As Mike has covered, this has been a strong year for Meridian, financially with excellent EBITDAF and cash flows, operationally with high generation volumes and growing availability, 2 significant developments underway and a growing pipeline of consented options. These foundations provide us with a platform for growth. And so today, we are pleased to deliver our investors an increased dividend. And for the first time, we are producing forward earnings guidance. I'm very glad at this point to be putting descriptions of the difficult FY '25 year firmly behind us. It is worth noting them though, when looking at the comparisons to our FY '26 results. As I go through this presentation, where needed, I will also give comparisons to FY '24, which was more of a normal financial year. In FY '26, Meridian recorded strong operating cash flows of $810 million, up $492 million on FY '25. This is also a 21% increase on FY '24's cash flows. EBITDAF was a similarly excellent result, $1.05 billion, up $440 million on FY '25 and 16% higher than FY '24. These results show the scale of the turnaround from our lowest result in over a decade to our highest ever, almost $0.5 billion increase in operating cash flow and in energy margin, which we will look at in more detail shortly. The business continues to provide high-quality earnings, converting 93% of EBITDAF to pretax and interest cash flows. We continue to deliver higher-than-GDP-levels of earnings growth over the long run over a 15-year period, EBITDAF compound annual average growth of 6%. Now on to dividends. Recognizing the excellent result, the Board has declared an increased final dividend of $0.161 per share, up 8.4%, bringing the full year dividend to $0.225, up 7.1%. Imputation credits on the final dividend will be attached at 90%. The strong earnings reversion in FY '26 provides ample short-term headroom. As a result, we have dialed the dividend reinvestment plan discount back to 0%. Our modeling suggests we may consider reinstating a discount in the future, particularly when we bring the large wind options to final investment decision alongside other sources of funding. Energy margin was the main driver of EBITDAF growth, with a lot more water available and without the need to lean on risk products as much as last year. Significant growth in mass market customers also supported energy margin. The fall in other revenue is predominantly related to one-off insurance proceeds received in FY '25. I'll talk to costs in more detail shortly. However, it's worth just touching on a few of the larger items. Transmission and distribution cost increases continue to flow through and operating costs landed within guidance at an 8% increase on FY '25. With more fuel in the system this year, physical margin was impacted by big swings in both volumes and prices. Wholesale spot prices were significantly lower, while both hydro and wind generation volumes increased. Continued mass market sales growth is the result of the successful execution of our Retail Strategy, and it is great to see that showing up in our financial performance and more than made up for a flat commercial and industrial book. Significant margin movements relating to financial products shows how much improved hydro conditions in FY '26 reduced derivative purchases and demand response costs compared to FY '25. The shift in the retail book more towards mass market was accelerated at the start of the year by the acquisition of the Flick Electric customers. As Mike has already mentioned, total customer connection numbers are up 12%, leading to sales volumes up 14%. Declining ASX wholesale prices are flowing through into C&I contracts, leading to a slight decline in revenues in that segment, while mass market revenues were up $217 million. C&I contracts are now out to an average tenure of over 3 years. Overall, we continue to deliver sustained growth in retail network. Moving on to generation. Annual inflows were above average at 122%. While this is a relatively normal level of inflow, it's similar to levels seen in other above-average years, it's the timing of inflows that is important. Record hydro inflows through September to January supported the FY '26 financial result. Then the third wettest June on record means we have started FY '27 with healthy storage. The generation upgrade program continued, delivering 30 megawatts across additional capacity across Benmore and Ohau B and C, as well as significant availability improvements. Finally, an update on the transformers at Manapouri. We had 2 delivered in the financial year, with 1 installed ahead of winter and the other due to be installed later this year. 3 more are expected to arrive in FY '27. Operating expenses were $313 million in FY '26, an increase of $24 million or 8% and within guidance. Included in the increase from FY '25 is a reinstatement of short-term incentives. We also saw inflation-level remuneration increases. We now have both quantification and a clear pathway to remediating our Holidays Act obligations and costs for this have been recognized at just over $3 million. We have had an increased level of customer service staffing through both the Flick customer onboarding and then the Kraken migration program. We expect to complete customer migration to Kraken by interims. Maintenance costs were around $7 million higher, mostly due to higher spend at Manapouri and ongoing wind farm maintenance, including major components, which do not get capitalized. Major IT projects remain a feature of our work program, with DigiGEN and the Kraken migration featuring in FY '26, but the level of spend was $3 million down on FY '25 when we completed the finance system migration to Oracle. Now on to capital expenditure. In March, we revised our guidance and indicated that we might spend between $280 million and $310 million. We landed at $261 million, up 35% from last year, but still falling just below that guidance level, largely as a result of movements in the payment schedule for Ruakaka solar. At Ruakaka, 64,000 of the 257,000 panels are now installed at 1 of the 3 sites. The build remains on target for full power towards the end of this financial year. The bulk of the other spend is in the multiyear work programs for replacement transformers, the generation control system and the earthquake strengthening works underway at Benmore penstocks. Net profit before tax for FY '26 rose $779 million and net profit after tax rose $582 million. Here, you see the impacts of the better year, including a $403 million reduction in unrealized losses from energy and treasury hedges. This was offset by the $88 million additional depreciation that resulted from the $2.1 billion revaluation of generation assets at the end of FY '25. And with another $1.8 billion uplift in asset valuation this year, depreciation will increase again in FY '27. These items have no impact on cash flow and are not included in EBITDAF, but are reported as part of net profit before and after tax. Finally, the non-GAAP measure of underlying net profit after tax, which excludes items such as movements in the unrealized value of hedges, was up $252 million. During the year, net debt increased by 11% to almost $1.7 billion, but spot net debt to EBITDAF improved to 1.6x, down from 2.5x in FY '25 as a result of the earnings reversion. We expect this to rise again in the coming years as our renewable build program continues. The funding base remains diverse, with issuances in the last year in both the Kiwi and Australian markets. Headroom is strong with $1 billion of committed borrowing facilities, none of which were drawn at year-end. Overall, the capital structure remains well positioned to fund our growth program. And now on to FY '27. And for the first time this year, we have chosen to deliver forward earnings guidance. Subject to a reasonable set of caveats, which you can see on this page, our expected EBITDAF for FY '27 lies in the range of $1.04 billion to $1.12 billion. We continue to provide guidance on our future operating and capital expenditure, operating costs first, where we expect to spend between $321 million and $326 million next year, an increase of between 2.5% and 4%. Like any other company, we are experiencing inflation-related cost increases with these being broadly managed through efficiencies. The majority of OpEx increases are related to, firstly, IT, both system licensing and cybersecurity costs; secondly, Ruakaka solar operating costs; and finally, an increase to the scale of our DigiGEN Programme. The DigiGEN Programme identified over $3.5 million in opportunities to improve revenue or decrease OpEx. It delivered over $1 million of those savings in FY '26, and we are aiming to deliver $6 million in value in FY '27. I mentioned completion of Holidays Act remediation included in FY '26 previously that will drop away in FY '27. And we expect to enter a lower insurance cost cycle for at least the next 12 months. Capital expenditure is predicted between $370 million and $410 million. I've given you a fairly granular breakdown of how that is expected to be spent with the completion of Ruakaka solar being the largest growth expenditure, while the wind projects at Mt. Munro and Te Rere Hau move into preconstruction. Work will commence on the Waitaki Hydro Station upgrade. While that program of work is designed to maintain the long-term reliability, safety and operability of the station, the project also delivers additional generating capacity. The CapEx for that project is, therefore, split between growth and maintenance. Finally, a quick look at the start of FY '27. The retail sales growth and higher generation seen last year continued into July. As context, inflows in June and July have been twice the level of those months in 2024. Lake levels are well above average for this time of year, and we're seeing a strong start. Back to you, Mike.

Thanks, Mandy. Before we move to questions, I want to leave with 3 thoughts. First, obviously, fin year '26 was a good year. We delivered a very strong financial result, but more importantly, we materially improved the capability of the business. We strengthened our hydro position, expanded our development options, improved the risk management portfolio, grew our customer base and continued investing in the infrastructure that will support New Zealand's future electricity needs. Second, many of the benefits from those decisions still sit ahead of us. The investments we're making today, whether in generation, storage, customer systems or development are designed to create value over many years, not simply the next reporting period. We're also approaching capital allocation with discipline. We have options, but we do not need to pursue every option. We'll invest where returns justify the risk and where an opportunity strengthens the value and resilience of the wider Meridian portfolio. And third, for the first time in several years, I think the industry can start looking forward with a greater degree of confidence. Wholesale prices have fallen materially, new renewable generation's being built at pace, security of supply is being strengthened, and the benefits of all of this are starting to flow through to customers. None of that happened by accident. There's still plenty of work to do, but both Meridian and the wider electricity industry enters the new financial year in a stronger position. And the opportunity ahead is significant. As New Zealand grows its renewable generation base, we strengthen an advantage that few countries can match: abundant, affordable and increasingly renewable electricity. Last year, I said I was confident in the future of the business. Now having seen what the team has delivered, I'm more confident than I ever have been. Thank you. We can move to questions.

We might start in the room, which I'm going to guess, could be Andrew.

Andrew Harvey-Green here. A couple of questions from me. So first of all, stay-in-business CapEx, it's a reasonably big step up there. Can you sort of talk through, I guess, how much -- how long will it be at these sorts of levels? Give us a bit more color, I guess, looking beyond FY '27? And also, I guess, I mean, it looks like there's lots of little bits that sort of add up this year. And I guess when we think about what is a long-term stay-in-business CapEx number, you said you got an underlying number, I think, about $40 million, but there's always going to be little one-offs that come in. So if you can give us a bit more color around that, that would be great.

Yes. Thanks, Andrew. So firstly, I'll just say the stay-in-business CapEx number is impacted in future years by the Waitaki upgrade program, which we have for the first year, attempted to do an allocation of that between stay-in-business and growth with an indication of 85% of the cost of that program as stay-in-business. There are a number of kind of periodic items, which we've said up to $120 million at the moment, including that Waitaki upgrade. There will always be those. I think you would in the longer term, see, excluding Waitaki, that come back to around about $80 million.

Next question I just had, I guess, was looking at some of your long-term growth aspirations. And I think there's a slide at the back there, which shows 6 terawatt hours of additional generation between now and 2035. I understand what you're trying to be doing in the mass market space, but that's not going to give you 6 terawatt hours of demand. So can you -- I mean, obviously, we've seen Mercury and Contact push go on some data centers or sort of push that forward. Can you sort of talk what you're doing, I guess, on that demand stimulation side and how, I guess, you plan to try and balance your book with 6 terawatt hours of new generation?

Yes. Thanks, Andrew. As you said, there are new sources of demand emerging in New Zealand in the form of data centers. They will consume a portion of everybody's expected generation development. So whether it's Datagrid or CDC, to meet those commitments, it's going to require everybody to probably step up the pace of their development to meet the time lines. Beyond that, we didn't talk to it specifically today, but I have talked to it before, which is we formed a small team within the company to go out there and look at growth beyond the growth in existing customers in New Zealand. And they're out there still looking. It's still too early to tell you what might land because it's like any funnel, it takes time to prioritize and then deliver outcomes, but they are making progress. The last piece that I'd say is, you probably know this, is there are a few large RFPs out there at the moment for conversion process. And we've got a gas sector in the country that's really looking for what it needs to do. Both of those are significant and substantial and will help us deploy into that 6 terawatt hour pipeline. But the last thing I'll leave you with is the single most important thing that we do beyond operating the business is we deploy other people's money efficiently and effectively, i.e., good capital allocation. So as market prices and demand forecast turn into actual delivery is we'll be incredibly disciplined in the way that we actually deploy capital as opposed to the options that we're creating because we think the development of optionality is as important as driving raw energy into the market.

And last question from me. Great to see guidance. Can you give us some -- in terms of the base assumption around your hydro generation for FY '27, what sort of range are you looking at that sort of underpins that those -- the EBITDAF range?

I do not have that information to hand, but it was -- we have -- obviously, we have produced that information. I will get that to you.

So it's around -- it's a deviation around average, Andrew. So it's just what you expect as a normal deviation across wind and hydro generation. And then the caveats that Mandy laid out were one-off specific events that might occur.

And normal hydrology.

Yes. So it's just a deviation around average, nothing sophisticated. I think we can go to the phones. Well, sorry. Anyone else -- before we do that, anyone else in the room? I did see a couple of others that sat down. No, they're not moving at all. So let's go to the phones.

[Operator Instructions] Your first question comes from Joshua Dale from Craigs Investment Partners.

Well done on a strong year. Nice to see some guidance. Just on the FY '27 range you issued, when I last looked a couple of weeks ago, you were sitting on an additional 800 gigawatt hours of hydro storage compared to PCP. July inflows have been favorable. I don't know whether you have this at hand, but how much of that benefit is in your guidance? And what might the range look like under more normal conditions?

Yes. I mean I can pick that up. The guidance is based around expected generation, Josh. So look at what our models tell us we'd expect and then drive a reasonable deviation to that. So guidance does capture the current starting position. That said, as you say, we've had a pretty strong July and August isn't shaping up too badly either. The -- so that's why we produced a range is you can take and use your judgment as to where we might sit in that range. But the range is important because we're in month 2 of what tend to be reasonably long years. So we're trying to be cautious given it's the first guidance that we've produced.

And I would just add to that, obviously, if we see any significant change, we will update the market at that time.

So if the midpoint is $1.08 billion, what would -- I mean, if you were standing here on the 1st of July looking ahead without the benefit of that hydro that you've seen so far, what would that $1.08 billion step down to as a P50 figure?

No. Sorry, Josh. I think you're right. Our P50 is $1.08 billion. So we've spread that around the range.

But -- sorry, that includes the benefit of a strong July and part of August, too, right?

Yes, and expected.

So I guess what I'm asking is what would P50 have been if you had issued that on the 1st of July as opposed to now sort of latter part of August. If you have that in hand?

Yes. I think -- so the way I would phrase that is we took into account the starting point as at the start of July. So we knew that the lakes were looking full at that point. I don't think there was any significant difference between that and where we are now.

Okay. Just looking at Page 8 in your slide pack, it shows most of your on-balance sheet developments don't come online until FY '30, which is a little later than peers. But you did say you think the retail book can soak up generation from Ruakaka and Mt. Munro. In terms of the demand to soak up generation from Te Rere Hau, are you looking at -- are you counting on that retail book growing from 500,000 to 600,000 customers?

So we'd like the retail book to grow.

Or might we see some other...

You'll see some more, Josh. So it'd be no surprise to you, but we're out there talking to people about that volume that we expect to bring into the portfolio. We just haven't completed those transactions yet. So it's hard to announce what they might be, but you can expect us to contract for portions of that volume alongside the customer growth that we'd expect.

Got it. Okay. And one thing I did notice, obviously, there's been a bit of a delay in FID for that project, but it's still looking like the full power date. I guess that project contributes essentially fully for FY '30. So that final date hasn't really been affected. Why is that?

Yes, it's the use of summer construction periods, Josh. So while it has been delayed, it's been, as you know and others will know, it's been very frustrating. So it's actually nice to see the window emerge for that and that uncertainty disappear. But what we haven't lost is we haven't lost a summer construction period. So while it gets delayed through a winter stretch, you haven't lost the key period, which is the period you construct the roads.

Got it. And final one, hopefully, an easy one. Just the comments around the Kraken customer migration completing by the interim result. Does that include both C&I as well as mass market?

Yes.

Yes.

Your next question comes from Grant Swanepoel from Jarden.

Yes, about time you gave guidance, that's fantastic. Now we're going to look for the type of Contact-style deconstruction of that guidance going forward, and we'll have less analyst questions around it, hopefully. Moving on to questions. Similar to Andrew's start, you've got about 710 gigawatt hours of extra power usage from the end of this fiscal year. Is that fully encapsulated in your portfolio position currently? And therefore, the next 12 months are filled up by 1.3 terawatt hours potential, that you will wait to see how that demand will be stimulated?

Yes. I think the simple answer to that, Grant, is yes. We will wait -- we're making financial investment decisions as we work through the year. So the first one is Mt. Munro, December. We'll look at conditions in December. And then again, whether it's Te Rahui or Te Rere Hau is we'll make the decision that's relevant at the time. The thing that I tried to signal is when we look at the relative merits of the developments is Mt. Munro is really strong from an economic perspective. Te Rere Hau is the same. And while Te Rahui has got really good economics, we're watching really carefully to see how solar positions itself in the market. So we're trying to be really careful around the deployment of capital in our solar portfolio, even though it brings additional value to the business, as I mentioned, through helping to manage dry year risk. But we'll make the right decision at the time.

But just going forward in terms of creating demand for building things. How did you miss out on the 50-megawatt Tiwai contract that Contact seems to have first right of refusal on? And the second question around that is, it does appear that Mercury and Contact are dead set to build behind the PPA for those data centers themselves. How do you get into that mix if you think that data centers are for everyone?

It wouldn't surprise you, Grant, that we're in conversation with the smelter around the additional potline energy. We've got a reasonable exposure to them already. So take that for what you will. But customers typically want the best price that they can find. The second thing is while you may not see us in front of, I'll say, data center like Datagrid, CDC, obviously is reasonably new. The key thing that I said just before is no one has enough energy to meet the needs of those data centers given the time frames that they're contemplating. So I would be incredibly surprised to find that Meridian was not part of the mix if they're successful. The only thing that limits us is actually getting the energy developed. And as we get that energy developed is then writing it into the market. But maybe I'll give you a stronger indication is there's no question that we're involved in pretty much every major consumer investment that's being made in the country. Whether we tend to broadcast it or not is -- tends to be our style that we let people know when we've completed those arrangements.

And my final question is just around dividends. So 83% payout of your normalized cash flow and net debt position of 1.6x. I know you've got some capital ahead of you. But where do we expect that payout ratio relative to your balance sheet over time, particularly since your debt covenant is -- I mean, debt guidance is 80% to 100%?

Yes, Grant, we haven't changed the dividend policy on that. We pay out between 80% and 100% of cash flow. There's obviously been an interesting twist to that in the last couple of years because that doesn't envisage the significant change that happens in tax payments as a result of the large swing in our earnings over a couple of years. So that is -- it's a notable feature of this year where last year's tax payments were much lower and were made in this financial year. So while that is at 83%, when you normalize that, it's actually closer to 100%. Consider we continue to pay out at 80% to 100%.

[Operator Instructions] Your next question comes from Vignesh Nair from UBS.

Can you hear me?