Meridian Energy Stock

[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?

Got you.

Yes.

Just a couple of quick questions. The first one is just about your growth CapEx envelope, I suppose, from here. Several projects on the horizon, sort of, FY '30 weighted. Do you have any color on when and where spend, I suppose, will peak according to your existing gen dev profile? I suppose the context of that question is you used to guide to $3 billion in CapEx over an FY '24 to FY '30 period. Just wondering if you're tracking in line with that or I suppose, behind that kind of prior guide.

Vignesh, we're still tracking to that guidance is the simple answer. It comes down to key developments being Te Rere Hau, which first time I've been able to give pretty good clarity on that project, which feels great. But the next significant developments that fit into that time frame are Waiinu, so large integrated wind and solar farm just south of Taranaki. And possibly, we'll see, but Western Bay Solar.

So there are 3 large developments in front of us. And then we've got a bunch of other development options that you would have seen more recently, we've consented the Morrinsville Solar Farm and the Bunnythorpe integrated solar park as well. Are you still there, Vignesh? I don't think Vignesh is there any longer. You there, Vignesh? Was that you?

Pardon me for the troubles there. We are now back online.

Did you hear any of my answer, Vignesh?

No, I just heard the start. I think I missed out the second half. Sorry.

Did you hear the 3 big projects being Te Rere Hau, Waiinu, and Western Bay Solar?

Yes.

And then there are a couple of smaller solar developments that we've recently got consent for. But yes, they fit that $3 billion envelope that you had mentioned.

Okay. Cool. I suppose the follow-on is the implication on the debt profile, right? Like where do you see peak net debt? And when do you get back to the 2 to 3x range from here, Mike?

I mean, Mandy might want to take this, but...

So we only expect to peak just over the 3x range and to be back under in the 2 to 3x range by, I think, FY '31. So peaking through '29 and '30.

I'll put another...

The second question, I suppose, is just on the battery. Your FY '27 targets include delivery of best business case benefits. Slide 7 is obviously pretty helpful in understanding the impacts there. But I was just after a couple of bits of color on whether or not the current more subdued wholesale price has sort of impacted the return on that battery in sort of -- in light of where forwards are tracking and spot prices are tracking. And if you can guide to maybe what the explicit sort of EBITDAF implication has been from that battery in this financial year and what you're expecting to '27, I suppose, would be helpful as well.

No. I mean, again, Vignesh, we're going to release a project implementation review for the battery later in the year so that people can see the economics. Remember, we said there was about 1/4 of the value through arbitrage, 1/4 of the value through reserves markets, and about the remaining 50% through improved portfolio pricing for our hydro developments is when you look at the arbitrage opportunities, they're really -- I mean, the last few weeks have really evidenced that they're there, and we have nailed execution was one of the points I was trying to make.

But in terms of meeting the business case annualized revenues, probably a little lower than we expected. Reserve market revenue for the battery, again, has been a little lower than what we expected. But -- the key point that I was making is the capacity of that battery to lift HVDC transfers, allowing us to release more energy from the Waitaki and the Waiau and close the North to South Island price differential.

They've both exceeded what we expected to be possible for batteries, which is why we are looking at whether we can accelerate another integrated energy park. And the only reason you do an integrated energy park is it's one set of transmission assets across 2 actual generation assets. So we're pretty enthused by what we've seen by the battery, Vignesh.

And so just to clarify, into FY '27, are you expecting to the full kind of target gross return on capital of about 20%, call it, on the $186 million spent, so $40 million, sort of, guided EBITDA to fall through to that $1.08 billion midpoint number?

Yes. Yes, we are.

Your next question comes from Stephen Hudson from Macquarie Securities.

Can you hear me okay?

Yes.

Yes.

Just a couple from me. Just going back to the payout ratio, you mentioned that there's quite a disparity between the ratio on a tax expense and a tax paid basis, and we can see that from the slide. Are you saying that, that disparity will continue for quite a period of time, Mandy, given your elevated levels of investment?

No, it was caused by the...

In other words, should we be thinking about the 83% as being the sort of the right basis or the 102%?

No. It was -- it's a one-off issue caused by the swing in profitability over the last couple of years. So we've had a difficult year followed by a strong year. The tax paid on that gets -- a good proportion of it gets paid in the following financial year and therefore, impacts cash flows a year later than the poorer or better year.

So in going forward, in kind of standard profitability, assuming that in the kind of standard growth profile, you should not see that level of swing and we can return to just treating 80% to 100% as the standard range. It really impacted last year and this year.

102% tax expense basis is really the one that we should be focused on then?

Yes, that's right. And what you will see in future years is that those 2 become -- the difference disappears.

Yes. Got you. Okay. I mean just at a high level, Mike, what do you think the Board is trying to signal with the dividend at the moment? We've kind of got -- it's great that you're providing guidance, but we've got a strong start to the year. I think July, EBITDA was up 8%. The dividend is up 8% and guidance is up 3%. What do we -- at a high level, what are we supposed to be taking from all of that?

Huddy, it's confidence. I think that's the key you take away from the result is higher operating cash flows. We expect those operating cash flows to grow over time. And as a result, we expect what we've always wanted to deliver, which is ongoing lifts in underlying dividend. So I hope what you're taking from it is good confidence in our capacity to produce cash and that, that cash will continue to fund both the dividend and the growth program.

Okay. Should we also take away the fact that the Waitaki refurbishment is a relatively, how should I say, a confined period? Or is it kind of like a Mercury 20-year kind of exercise?

Yes, it's really confined. I mean Waitaki Power Station is 90 years old. So I doubt that I'll see that one again refurbished. Well, I won't. We don't have any other power stations that are nearing that age, Huddy. So we don't have anything in our plan that says get out there and refurbish a whole bunch of other hydro power stations. It really is Waitaki.

But the beauty of it is the economics of the investment are outstanding. And we'll be able to increase the capacity of that station while maintaining strong cash flows through the next 90 years.

That's useful. Just a couple of other quick ones. The Pukaki contingent storage, I think you talked about a $15 million impact. I'm not sure if that was on the sort of 50% assumption that you provided that you're going to operationalize sort of 50% and kind of hold back on the remainder. It sounds like your estimate has pushed higher. Can you update that for us?

It has pushed higher, Huddy. So I think $15 million would be conservative. Where that's lifted to, I would say probably in the order of $20 million or $30 million. So not massive, but certainly that opportunity to capture spill in the Waiau is in front of us. I'm just being a little bit cautious because we haven't done it yet, right?

So we haven't actually tested the low-range operation and ability to capture that spill. But when you look at the numbers, the 600 gigs of annualized spill down there. And if we can operate the way that we expect to operate, then the opportunity is in that order.

And if I can just be clear on that, we have included our initial assumptions on contingent storage in guidance, but have not included anything further on the Waiau.

Sorry, just firing off 2 more quick ones. We've seen some pretty c***** GWPs, TWAPs in North Island solar this winter, sort of, I think summer kind of was $100 and now we're in the mid-80s. It sounds like Te Rahui -- you are waiting for kind of customer kind of PPA kind of engagement.

It's not a peaking factor issue, but I am interested in your view on peaking factors and what your assumptions are across all of your solar developments. Are you surprised to see the sort of decay in peaking factors that we've seen? Or is it sort of in line with your expectations?

It's in line, Huddy. As -- I want to go back to, I think, at the Investor Day, so was it November '24 that we had the Investor Day, and we actually provided those price participation factors as part of the forecast. We provided them for the Waitaki, for Manapouri, for wind generic, and solar generic. Those factors showed a reasonably quick reduction in participation rate for solar farms. And there hasn't been anything that's played out that's inconsistent with that forecast.

Last one, I promise. The NZAS contract, just remind me, I think there's some conditional escalation in there, but it kicks in early 2028. Is that right? We've still got to wait another year before we get the benefit of that escalation?

Yes. That starts calendar year '28. And it's reasonably straightforward is the escalation is our aluminum prices in '26 higher or lower than 2027. If they're lower, then you escalate. If they're higher, then you hold the price at the level that it is.

Thank you. There are no further phone questions at this time. I'll now hand back over to Mike Roan for any closing remarks.

Brilliant. I think I said my closing remarks just before. Thanks, everybody, for joining this morning. I hope you got the info you're after. Thanks, everyone, in the room for showing up. We'll see you at interims.

Good morning, and welcome to the Meridian quarterly operating results call. I'm Mandy Simpson, Meridian's CFO. And with me today is Owen Hackston, our Investor Relations Manager. This is our regular call where we share thoughts and insights on the last quarter.

And this is something we do in the quarters in between interim and annual results announcements. Owen and I will provide commentary today on climate, hydrology, generation, wholesale prices, electricity consumption, retail operating costs and capital spend, and we'll take the next 10 to 15 minutes to do that.

Given it's a general update on Meridian's operations, we will be steering clear of the financial results. We'll take questions at the end. So if you do have any questions please drop them and your name into the Q&A, and as we go through, there's around about a 20-second delay between you submitting the question and us being able to see it. So just bear that in mind.

And with that, I will hand over to Owen.

Thank you, Mandy, and good morning. February felt like autumn and March felt like the height of summer, that's pretty much how the season has been. The most recent summer started warm and it finished cool. Summer air pressure was lower than normal over the country, and that led to some very active weather patterns.

At least that's partially driven by the weak to moderate La Nina conditions that were prevailing through summer. Despite that overall lower pressure, there were extended periods of high pressure. In between those were repeated heavy rainfall events that brought record rain totals to parts of both islands. As I said, La Nina conditions were prevalent with that La Nina transitioning to an El Nino neutral state by the end of the season.

And while March saw a dry and very mild start to autumn for much of New Zealand, a subtropical low late in the month pushed monthly rainfall totals in the Upper North Island to well above average. Looking ahead on the climate, Earth Sciences autumn outlook suggests near average temperatures for all regions with the possibility it's warmer than average in the west of the South Island.

And from a rainfall point of view, normal to above normal rainfall across the North Island and the eastern part of the South Island. And slightly more interestingly for us, normal to possibly below normal rainfall in the West and the north of the South Island. There's a high likelihood that the current El Nino neutral conditions remain in place over autumn and into early winter.

And looking out later this calendar year, El Nino conditions are expected to become increasingly likely with already an 80% probability of emergence into spring 2026. And that matters because within a decent range of variability, El Nino conditions tend to bring stronger hydro inflows to the west of the South Island.

With the La Nina prevalence, you see increased drought risk in the South Islands West. From a hydrology point of view, this time a year ago, we had just experienced the lowest summer inflows in our 92 years of rainfall records. And that was despite only a weak La Nina influence around last summer. And that probably highlights how much variability you get within general weather patterns in New Zealand.

It's fair to say it's something of a relief that this summer, we have seen inflows approaching more normal levels with the Q3 inflows slightly below average at 87%. Getting 80% more water this Q3 compared to the last has certainly alleviated the fuel stress of 2025. And coupled with the wet first 6 months of this financial year, inflows for the 9 months of FY '26 are the sixth highest on record.

South Island Lakes, including Pukaki, are sitting very slightly below average, while the most recent rainfall events have pushed North Island storage to 180% of average. Reported demand growth for the March quarter looks reasonably strong at 2.4%. A year ago, we had in place with the New Zealand Aluminum smelter agreement to reduce electricity consumption by 50 megawatts, and that reduction was running between March 2025 and August 2025.

And it gets slightly complicated because that agreement actually modified the remainder of a ramp-up to a demand response call for the biggest option we have under the agreement with NZAS. We'd originally exercised that option for call back in July 2024. And we called that to help manage with the record winter drought of 2024.

What all that means? Well, if you back the Tiwai load out, underlying Q3 demand growth is about 0.8%, which is a similar level of growth that we've seen in earlier quarters of this financial year. And look, with more water, you'd expect our hydro volumes to be up, and they are. Q3 is up for hydro about 15% on the drought impacted Q3 of last year. And that quarter last year was also characterized by pretty low wind.

By comparison, this Q3, we've seen a 24% or 81 gigawatt hour increase in our wind generation. And typically, more hydro sees a lower reaction in terms of spot prices and our generation spot prices averaged 61 megawatts -- sorry, $61 a megawatt hour during this Q3, 71% lower than the same quarter of last year. And in this quarter, we had the most remarkable January where our average generation price averaged just $1.

And what I'll do now is pass it back to Mandy to talk a little bit more about market prices.

Thanks, Owen. So spot prices have lifted from those extraordinary lows of January as South Island storage eases back towards the seasonal averages and then front-end coal forward prices jumping with the uncertainty in the current Middle East conflict.

Meridian's average generation price cleared $41 per megawatt hour in February this year and $146 per megawatt hour in March. Despite climate forecasts suggesting some chance of drier than usual conditions in South Island catchments over the next 3 months, winter 2026 prices fell over 20% during quarter 1.

Across the longer-dated forward curve, prices fell in the order of 15% during quarter 1, perhaps starting to reflect some of the impacts of proposed new renewable generation expected to come to market. And the Huntly Strategic Energy Reserve contracting now in place. We're also seeing compression of North Island to South Island price differentials in the ASX forward curve.

That differential is running around half what it was a year ago prior to the completion of our Ruakaka battery. So while the ample rainfall this financial year has seen modest day to nighttime price differences and so limited battery cycling, we are getting the expected portfolio benefits from that asset.

In the retail business, the retail business is powering on with another quarter of sales volume growth, albeit with a lower irrigation season than last year. Our Kraken migration now has 135,000 customers on the platform, including 40,000 Powershop customers. Customer service levels are feeling some pressure from the temporary situation of having 2 customers on the 2 platforms, along with a lift in customer engagement following the 1st of April price increases.

Quarterly OpEx, up 5% on the same quarter last year, and we remain on track to land in the $311 million to $316 million full year guidance range. After an extended consent process ahead of the start of the build, we have now seen the first solar panels installed at Ruakaka. With $27 million spent on the project in quarter 3 and resolution of the Te Rere Hau Airways Tower still progressing, our CapEx outlook has been tracking down.

We now expect to land between $280 million and $310 with growth CapEx of up to $200 million and stay in business CapEx up to $110 million. Our Fast Track application to access Lake Pukaki contingent storage for the next 3 years is currently being considered by the expert panel. Submitters to this process tabled their views to the panel last week.

Encouragingly, the electricity authority was supportive of the significant economic benefits delivered by enhancing this country's electricity supply security and lowering its wholesale electricity prices. However, we note there are opposing views on this application, but we remain confident of a successful outcome. And lastly, a few updates on some Meridian projects.

I mentioned the consent process for the Te Rere Hau Airways Tower. While that is continuing, long lead time equipment for the tower has been purchased and roading upgrades to the proposed tower site will get underway later this month. Te Rahui solar JV with Nova has construction well underway with the program on track for full power mid-calendar year 2027.

Ruakaka solar farm construction that I mentioned earlier has some pressure around its quarter 1 2027 full power date. However, that is what we are still aiming for. The Waiinu Energy Park Fast Track application was submitted late March. It will take 3 to 4 months before we know whether it will gain acceptance into the fast track process.

Between December 26 and February 27, we expect to FID 3 projects: Te Rere Hau, Mount Munro and Te Rahui Stage 2 with the Manawa 2 Energy Park to follow by mid-2027. And by the end of this calendar year, Waikato Solar and Swannanoa Solar should have their consents granted and the Fast Track application for both stages of Western Bay Solar is still on track for submission later this year.

That is it from us. So I'm going to move to questions if we have any. If you do have one, as I said, please make sure that you include your name so we know who we're answering, and there is a 20-second delay between the time you submit your question and when we see it.

And so I'll start. I think we've got a couple of questions waiting for us. Firstly, from Josh, should we read the $50 million reduction in CapEx for FY '26 to mean the pushing out of construction timing for Ruakaka or Te Rahui? I think hopefully, I've covered that as we went through Te Rahui Stage 1 remains on track and no changes there. Ruakaka has been a little bit slower to get going than we had hoped, but we are expecting to catch that up through the process. And so that remains roughly on track for full power.

The majority of the reduction in CapEx spend is actually to do with Te Rere Hau being pushed out to next financial year as well as some minor changes in some of our stay in business CapEx.

Do we yet have a sense of the potential generation uplift from the Waitaki Station replacement? Owen, I don't think we are ready to give that figure yet. Do you have anything on that?

No, we certainly will. But the economic viability and engineering feasibility of the program at Waitaki is still being developed, and it's too early to start talking potential generation uplift.

Great. So we'll -- as we get closer to FID on that replacement project, we will provide that information.

And then another question on the CapEx guidance. Is that the result of project timing or drop in total projected cost?

That is simply project timing. Our pipeline remains as it was when we last spoke to it, but particularly Te Rere Hau being pushed out into next financial year.

I think that is all that we have on questions today. So with that, we'll wrap up. Thank you so much for your time this morning, and look forward to speaking to you again soon.

Thank you.

Good morning, everyone, and welcome to Meridian Energy's interim results presentation for the 6 months to 31st of December 2025. I am Mike Roan, Meridian's Chief Executive; and with me is Mandy Simpson, our CFO.

It's great to be back talking to investors and the media about the performance of the business. And doing so with strong, what I'd probably term as more normal financials to support the conversation. So one of the key elements I'd like you to walk away with today. First, the result was supported by the fact that it rained a lot in the Southern Alps through spring and summer, and it was windy in the Manawatu as spring tends to be.

It was also supported by customer growth even as we transitioned our customers onto a new technology platform. The retail team under Lisa Hannifin's clear and ambitious guidance continues to perform strongly. And there were some sound decisions made by Rory Blundell and his portfolio team over the period as well. But the result frames historical performance. And while that should provide confidence, what also matters is how we set up the business for future success, and that success relies on growth.

So this slide touches on that as well. Over the next 12 months, Mt. Munro, Te Rere Hau and Te Rahui Solar Stage 2 will be set for investment decisions, and the retail team will complete its migration and really start to hone in on customer service and product creation. We'll also start to see the early impacts of the generations team's efforts to move its practices to predictive maintenance, but we'll do that slowly given the value at risk.

It's always pleasing to be able to reward investors for their patience and confidence by increasing cash distributions to them, even as we prepare to spend upwards of $1.2 billion on the investments I just mentioned. Once completed, they'll add 1.3 terawatt hours of renewable electricity to the New Zealand system. This will further strengthen national supply and help bring prices down. Both are really important.

Kiwi families, many of whom are still struggling with cost of living pressures, are looking to companies like ours for relief. So commitments of this magnitude really do matter. I'm also happy that we can show our investors progress against the company's strategic goals. I can tell you that everyone feels a sense of pride in what's been achieved, but more importantly, what will be delivered.

And what a difference a year makes. As the graph at the top of this page shows, wholesale electricity prices over the past 12 months were a lot more tolerable than the previous year. What you can really see -- you can really see what a fully fueled renewable electricity system producers, particularly in the spring of both years. The 2025 was a recovery year.

And while it didn't go perfectly, it demonstrated that progress was being made with a key market being the completion of the Huntly strategic energy reserve. This agreement, alongside the NZAS demand response options largely restored the security balance. On the Huntly strategic energy reserve, it was good to see competitors work so quickly and pragmatically together. And for the competition regulator also move quickly to review and approve the agreement on the basis of the significant public benefits it delivered.

It was also the year in which construction got underway on a couple of new investments. Our Ruakaka solar farm and the Te Rahui solar farm being delivered through our joint venture with Nova. When complete, they'll add 702 gigawatt hours to the electricity system. In 2026, '27 and '28, we'll see the benefit of further investments being made not just by Meridian, but enough from us to maintain our 30% market share.

If you jump to the bottom graph, future prices, the fully fueled renewable theme has flowed into the 2026 contract. And while 2027 and '28 prices have come off, they remain stubbornly high. Now I do note this graph was last updated Monday and prices have fallen further since then. So even as market participants remain concerned about the risk of price spikes and droughts, it seems that they're increasingly aware of the avalanche of investment that's coming, probably no coincidence given interim results announcements. It will also be difficult to miss the LNG announcement, and I suspect this is also having an impact on '28 and '29 prices in particular.

While on LNG, I'll talk to it quickly here. The government sees LNG as necessary to shore up security and bring down prices. We support both of those objectives, so we await the detail that will come on this project. There's no silver bullet, but there's an upside to anything that will reduce dry year risk. That's precisely why we remain fully focused on delivering our new renewable pipeline and unlocking the country's hydro advantage.

While the electricity sector is a key enabler of a green economy and growth, we do recognize that electricity impacts households as a significant contributor to the cost of living. We need to get back to a position where electricity price increases sit at or below inflationary levels, and this is possible. Over the 10 years before 2024, that's exactly how it played out. As I mentioned earlier, the best way to do this is to invest in new generation.

So the top graph, gas prices and local rates have been increasing faster than electricity costs. I understand and agree that this is cold comfort for electricity consumers, but the context is important. Now I can't talk to rates increases, but gas is increasing quickly as it's the fuel that's in short supply. So it will continue to increase most likely until demand falls for it materially. And that will only happen if people can no longer afford it, so either switch to another fuel, biomass or electricity or the gas supply is shut down. It's a tough truth for gas users, residential or not, but it's an honest one. So if you can, get off gas.

Electricity inflation, on the other hand, has been driven by the factors in the bottom graph. The key element is lines and transmission company cost increases that are approved by the Commerce Commission. The energy component increases are still significant at twice inflation in two of the years shown, but they're not the key contributor to the overall increase.

If you remember my point earlier, we'll be able to arrest the energy component once the investments in new generation start to flow through the market. Lines and distribution increases will flow through customer bills for the next 3 years at least. So all going well, we'll be able to bring the energy portion of the overall price increases back to or below inflationary levels by 2027 or 2028. But doing the same at an overall electricity bill level is unlikely. The magnitude of the increases in lines and transmission charges is a hard thing to offset.

I want to be clear, I'm not trying to point the finger at others here. We're going to need a stronger transmission and distribution network. But as those costs -- as the cost of those activities are regulated and tend to flow through electricity bills before the benefits show up, I suspect that ongoing lines and transmission increases will become a regulatory and political issue as the heat comes out of the energy component.

Which brings me back to the pace of investment is that's what will drive actual outcomes and will determine whether my forecast that I just mentioned is accurate. And I like this graph because it's really clear. Since 2024, Meridian has added 542 gigawatt hours of new generation to the electricity system. And as I mentioned earlier, there's 702 gigawatt hours under construction.

Looking forward, I anticipate we'll commit to all consented projects or just over 1,300 gigawatt hours inside the next 12 months. So Meridian's pace of investment is increasing. And to provide context, the total gigawatt hours of constructed, in construction and consented projects is over 2,500 gigawatt hours, which will grow Meridian's business by more than 15% when complete. Beyond this, projects and time frames are ultimately in the hands of consenting authorities. We have 720 gigawatt hours in the consenting process and expect projects totaling just over 2,900 gigawatt hours to enter those processes over the next 24 months.

BCG, who produced a report titled Energy to Grow recently, noted that the electricity sector was building faster than during the think big period. And at current rates, the investment was enough to support expected growth in electricity demand through 2030 at least. So the sector is responding well, and we're doing our share. I can see a path out of the spotlight subject to what plays out with lines charges.

And with all this investment in train, you can see why I think we'll see further downward movement in forward electricity prices. This graph presents a time line of when the investments I just talked to and others will be fully available to the electricity system. I don't intend talking to it in detail, but if you look closely, you'll see that the wind pipeline has been upweighted -- you may also have picked up Tauhei, a 200-megawatt solar farm that's been built in the Waikato that wasn't captured in earlier slides. We don't own that farm, but we are taking electricity produced from it for 10 years.

I'll now cover off each investment in turn. First, those in construction. As you know, Ruakaka is an integrated energy park. It will have both a 100-megawatt, 200-megawatt hour battery and 130-megawatt solar farm connected to the grid through 1 transformer. We've done this as we don't think the economics of stand-alone batteries directly connected to the transmission grid stack up yet, largely as it costs a lot of money to buy a transformer. If you can buy 1 transformer for 2 assets, then the economics change and co-located batteries and solar arrays work really well together.

As the picture shows, construction of the solar farm is well underway at Ruakaka. The picture of Te Rahui also looks great, but it's a stylized representation of that farm rather than a real one as its construction window runs through mid-2027 as opposed to Q1 that year for Ruakaka. Stage 1 of the solar farm at 200 megawatts will ultimately be larger than Ruakaka, so it's important. But completion of Stage 2, which is another 200 megawatts, will make the farm nationally significant.

And we, Meridian and Nova have begun a conversation on how and when to approve it. But it's too early today to provide certainty. That said, the economics of Stage 2 are stronger than for Stage 1 as much of the infrastructure built for Stage 1 will be leveraged, and it wouldn't make too much sense to have a gap between delivery of the stages, so take that for what you will.

Mt. Munro is a cracker of a little wind farm, and it's good to see that it will get a green light later this year, all going well. I'm really looking forward to progressing it as it's been sitting on our books for some time. I talked to Te Rahui Stage 2 earlier and the Manawatu solar and battery park will largely replicate Ruakaka, which is why we can push this development along so quickly. But I'll finish with Te Rere Hau. It's a magnificent site, and it will become the most productive wind farm in New Zealand when complete. It's frustrating that it's taking longer than we expected, but we are making progress and a consent for the airways facility at Marima Peak is the only thing holding back the final investment decision.

Now for the longer-dated list. As the pictures show the geography for both Swannanoa and Manawatu is designed for solar farming. Waikato is no different. And consents for these assets are not controversial. So unless something unexpected plays out, the time frames for consenting them will be pretty quick. But Manawatu will be first cab off the rank given its co-location with the battery. As for Waikato reconsenting, formal process is complete, and we expect a decision later this year. There's always a risk of appeal, but if that plays out, it won't have any impact on our operations because our existing consents roll over, but we'll have to work through a bit more red tape and a few more legal fees to secure the new consents.

Progressing contingent storage has been a bit more difficult than I expected. When the frontier report was released last October, one thing everyone agreed was that New Zealand needed to find more firming solutions. So I thought that this one would be straightforward as it's the only option available to the sector that will immediately drop wholesale electricity prices, and it will do this at the stroke of a pen, but it's had its challenges.

To be clear, we must get system security settings right as we unlock this value for consumers. And we must also make sure that our neighbors' assets remain operable if it's ever used. From where I sit, both can be managed. And politicians, our regulator and our customers have told us that affordability is the key issue right now. I agree with them wholeheartedly. The good news is that everyone who has been invited to join the contingent storage fast track process agrees with the above statement. It's the only option that will create immediate consumer benefit.

And we've been working with everyone who will present their views to the panel, and we're up for compromise to get this through. So hopefully, consumers will be the beneficiaries in July. And for anyone who looks at this a little cynically and thinks it's only about Meridian shareholders, here are a couple of facts for you. We assess the annual benefit to Meridian shareholders as marginal, whereas the benefit to electricity consumers is in the order of $400 million per year.

So the reason we're pursuing it is that it's simply the right thing to do in the midst of a cost of living crisis. In the next few months, we'll ask for fast track referral for 2 large energy projects, the integrated Waiinu wind and solar park and the Western Bay Solar Farm. As you can see here, they're massive in New Zealand terms. If approved, these investments will not produce electricity until 2030 or 2031, respectively. So they're longer-term commitments, but they are important if we're to grow this economy and manage the transition to even greater electrification.

And last but not least is the Waitaki power station upgrade. We intend on completing an upgrade at that power station, which will see an uplift in its capacity. While the team is still finalizing details, a final investment decision will likely be in the second half of 2026.

And before handing to Mandy, I want to finish with the reason we do what we do, our customers. The only reason we have a business is because we make a product that our customers want and need. Our job is to make sure that we're able to provide the products and services that support and enhance the lives they lead and the businesses that they run.

We're putting considerable effort into getting better at both. And as the graph shows, the growth in customer numbers suggest we're doing a decent job. But we don't take our relationship with customers for granted, which is why we're deploying Kraken, a new technology platform because we know it will be crucial in delivering on our strategic ambition to make electricity cleaner and cheaper for all. And growing customer relationships while changing technology stacks is not easy to do, but our retail team is pretty damn good.

As the slide shows, we've slowed the migration down a little to make sure we manage that experience for people. There's nothing material that we've found, just your typical niggle as we cut through and into a new technology. But we're never bound by a June date, and it won't cost us any more money, so it will take a little more time. Other than that, and as the slide notes, additional customers have been valuable for the business during a period where wholesale prices were low.

So over to you, Mandy.

[Foreign Language] Mike and everyone joining us this morning. This is my first interim results presentation on behalf of Meridian, and it's a pleasure to be able to present such a strong result to you. As Mike has already headlined for you today, we're announcing FY '26 first half year operating cash flow of $336 million and EBITDAF of $506 million. Putting that result into context is somewhat complicated by the difficult conditions faced by the company in FY '25.

In a straight comparison with the previous equivalent period, July to December 2024, the current result shows operating cash flows $286 million higher and EBITDAF $249 million higher. However, I believe it's more useful to compare to the year before that, the first half of FY '24 when more normal conditions prevailed. In that comparison, operating cash flows are $33 million or 11% higher and EBITDAF $63 million or 14% higher.

What we see is the growth trajectory returning as we bounce back from the unusual result last year. Then comparing the two, gross operating cash flows are $85 million lower than EBITDAF. There are two main reasons for this. The first is timing related. Timing of the recognition of the earnings component of derivatives, mostly those traded on the ASX can vary from the timing of the cash flow component, such as settlements of derivatives or movements in cash collateral levels.

These timing differences are expected to mostly wash through by the financial year-end with closeout of positions. The other significant difference is a payment under our financial commitments as a party to the Huntly strategic energy reserve, which impacts operating cash flows. With earnings reverting to a more normal pattern, we can now return to an increase in the level of interim dividend payment. This is a 4% lift in the interim ordinary dividend from $0.0615 per share to $0.0640 per share. The dividend will be imputed at 85% and paid on the 24th of March. We are also applying the dividend reinvestment plan to this interim dividend with a discount of 2% to the volume-weighted average price from 5th to 11th of March.

Now on to EBITDAF in more detail. EBITDAF lifted by 97% on the first half of last financial year. The graph to the right of this slide shows a breakdown of the drivers behind the change. I'll talk to energy margin more on the next slide, but in short, higher contracted sales and higher generation volumes with lower purchase and demand response costs. Those higher generation volumes reflect the period having both record wind output and the second highest hydro inflows on record.

Other items impacting EBITDAF include higher regulated costs for transmission and distribution from April 2025. This reflects the first year of 5 years of increases as determined by the Commerce Commission. There are also a number of project-related movements such as operating costs relating to the Kraken implementation, set off against the costs relating to the Oracle implementation last year. And finally, the inclusion of New Zealand wind farms into the Meridian result.

So coming back to energy margin in more detail. Firstly, the increase in retail sales, a total of $133 million. That is the sum of the first 2 green movement bars. This is almost 2/3 driven by volume. That's $84 million of the total, with the rest being driven by price, including recovery of the higher transmission and distribution costs that Mike discussed earlier.

Retail sales volumes are up 12%, including the onboarding of ex Flick customers. And an increase of 11% in agri volumes gave our contracted sales book a lift right as we were into peak hydro generation. The abundant fuel supply meant generation volumes were up 14%, but average generation prices reflect the high levels of hydro storage and are down more than 50% on last year.

Those lower spot market prices saw significantly reduced customer supply costs despite the higher customer volumes. And just on the small negative $1 million bar in the middle, that is NZAS sales. Despite an option for demand response call in the prior year, NZAS sales volumes were little changed from the first half of FY '25. That reflects our volume under the contract reducing from 472 megawatts to 377 megawatts from the 1st of January 2025. The price remains the same as originally set under the 2024 contract. The start of 2028 is the first potential price escalation point and is conditional on London Metal Exchange aluminum prices in 2027 being higher than 2026. And so overall, that has meant a $246 million lift in physical energy margin.

Then on to financial energy margin. Firstly, let me just say, trading of financial products is not intended to make the company money directly. It provides balance and risk mitigation to our overall portfolio. With our higher physical generation, we sold significantly more ASX contracts, up 953 gigawatt hours for the period. However, we also purchased more ASX contracts, primarily as a result of the higher North Island retail position as well as reestablishing a more normal portfolio position post-winter 2024.

As I mentioned earlier, in the first half of FY '25, we called the largest demand response from the smelter. While the very early months of FY '26 still had some demand response, call fees included, overall, you can see the demand response costs were down $72 million. With this included, financial energy margin lifted a total of $20 million on the first half of FY '25.

Now we'll look in more detail at retail sales, with mass market volume up 16% on the first half of FY '25. This includes the addition of Flick customers, but also shows customers are continuing to choose to switch to the Meridian and Powershop brands. With a 10% higher net average price across all mass market customers, overall, this has added a significant $117 million of additional revenue. C&I sales volume also increased, but the flat sales price reflects softening in the forward curve. The overall increase in retail netback reflects both the revenue growth, but also relatively small increases in metering and retail operating costs.

Moving on to our generation for the period. A relatively dry July and August has been followed by a record wet period, the wettest September to December on record. And while you can't see it on the slide, this has extended into January. Generation volumes were 892 gigawatt hours or 14% higher than the previous July to December period. This long period of high inflows has meant we've needed to spill in particular at Manapouri, but also at Pukaki in order to maintain our consent and other legal conditions.

Spill events are a reminder of how the country could benefit from more efficient use of existing hydro storage. A 1-meter higher operating range at Pukaki is entirely possible from an engineering point of view. Through our most recent spill event, this would have more than halved the 521 gigawatt hours of spill, providing enough additional cheap renewable generation to power the equivalent of 1/3 of Auckland's homes for 2 winter months.

From an asset maintenance perspective, GM of Generation, Tania Palmer outlined at last November's Investor Day, the significant multiyear work programs underway around the Manapouri transformer replacement and automation and the seismic strengthening of the Benmore penstocks. Operating expenses are up 3% on the same period last year. This year, we have contractor support in place for both the Kraken platform implementation and development of our DigiGen program with both expected to continue through the financial year.

As we move across to the Kraken platform, we also see dual system operating costs for Kraken and Flux running through to the end of this calendar year and potentially into 2027. Increased wind component costs reflect investment in lifting wind farm availability. We've lifted that availability from less than 90% in May 2025 to over 92% by December. This added availability is a factor in our record first half wind generation volumes.

Our full year guidance remains unchanged at $311 million to $316 million, with our most recent forecasting at the higher end of that range. Capital expenditure in the first half of the year has been lower than in recent times with much higher spend expected in the second half of the financial year. We expect to be within the range of previously issued guidance at $330 million to $360 million.

Of the $86 million CapEx in this period, $53 million was growth CapEx with construction beginning at Ruakaka solar farm and the implementation of Kraken. Stay-in-business CapEx includes work underway on the Benmore penstocks, replacement transformers at Manapouri and the ongoing generation control system replacement work.

In the graphs on the right here, we show net profit after tax and then a non-GAAP measure of underlying net profit after tax. The fair value of unrealized energy and treasury hedges moves a great deal year-on-year. And so stripping out this movement, which was $120 million gain before tax in this period, versus $154 million loss in the first half of last financial year is important in comparing performance between periods. Underlying NPAT shows $143 million profit compared to a $5 million loss in the prior first half year.

Looking back to FY '24, 2 years ago, you will see underlying NPAT was higher than in the current period. That is the impact of the $2 billion increase in the valuation of generation and plant assets at the FY '25 year-end, flowing through to a $36 million increase in depreciation and amortization. At the end of the period, Meridian's total borrowings were $1.9 billion with net debt of $1.7 billion.

During the period, we simplified and strengthened our funding profile by transitioning from multiple bilateral bank facilities to a $1 billion committed syndicated bank facility. This structure underpins our balance sheet as we continue in this stage of sustained investment and provides improved efficiency and flexibility.

In September, we issued $350 million of 6.5-year unsecured, unsubordinated fixed rate green bonds. All of Meridian's borrowings are green debt instruments under our green finance framework, which has been refreshed and externally verified to align with market standards. Net debt-to-EBITDAF at December was 1.9x, down from 2.5x in June.

Finally, before I hand back to Mike, I'll briefly touch on the January result. Wet conditions continued with higher-than-average inflows and higher-than-average storage levels in both the Lakes and Snowpack. As I mentioned earlier, we were spilling throughout January, and we cleared an average generation price of just $1 per megawatt hour. We also saw a drop-off in irrigation volumes through the wet conditions. That said, the remainder of the retail sales book performed strongly, and the January result was still a very solid one.

And with that, I'll hand back to Mike for his closing remarks.

Thanks, Mandy, and well done. It's super pleasing to have had a strong performance in the first half of the financial year. It's been a great one for Meridian and our shareholders, but it's also been a good one for the New Zealand economy. The country needs companies like ours to be performing well right now.

And the country, as Mandy just said, can expect more of it. The business hasn't slowed down since December. It's too early to tell how things will play out in winter 2026, but it certainly feels pretty good that Pukaki is full late February. The investment profile remains strong. And while Te Rere Hau delays are definitely frustrating, they've opened the door for Mt. Munro, and you can expect us to make some further commitments over the next 12 months.

At the same time, the wider business is focused on improving what it does with support from our customers and stakeholders, and we continue to progress longer-term hydro development plans. As we noted at our recent Investor Day, the dry year risk that Meridian in the country faces is reducing significantly. While up to 4 terawatt hours is required to mitigate national risk today, by 2028, that drops below 3 terawatt hours and by 2035, falls to around 2.5 terawatt hours.

This factors in the Huntly strategic reserve and Pukaki contingent storage, touch wood. But the key is the huge volume of current and planned renewable build-out. The more renewables we build, even if they're intermittent, the more we protect our lakes and the Huntly stockpile. And if we can get more lake storage through our hydro development team, the equation gets better still. As this plays out, and it is playing out, Meridian's lake storage will increasingly become a firming solution. This means the company is extremely well placed to create and capture value in the future.

Now that concludes the formal part of the presentation, and I'm going to move us to questions.

I'll move first to the room, and then we'll open the phones. So if there are any questions from in the room, if you could put up your hand, if you would mention your name and then ask the question, that would be great.

Thank you. [ Peter Wakeman ]. I'd like to ask, when you look at the United States, their energy costs are about 7x what China is? And to have a competitive country competing against China when your electricity costs are 7x more doesn't seem very sensible, especially with regard to the recent renewal policy?

Now if you look at the New Zealand aspect, putting a levy on electricity to fund the Taranaki LNG supply, one wonders how we can mitigate the cost of lines companies because the cost of what you point out in your presentation is pretty significant. So I can't understand why the government doesn't try and go for the cost of line companies given the Commerce Commission at the time approved such things.

And I just wonder if there's government finance available, like during the pandemic, they spent $61 billion created money from nowhere. Can we use that to reduce lines costs? And can Meridian lobby the government with other generators to try and address the line charges with respect to people's power bills. That's the first question.

Yes. Thanks, Peter. I think there were maybe a couple in there, but I'll try and take the 2 that I think I heard. I think first, for an economy to prosper, you've got to have reasonable or low energy prices. I mean that's how economies perform. And New Zealand has been really, really fortunate historically that we have had low international energy prices. And while they've gone up over the last few years, we still compete really well for a small island in the middle of the Pacific.

And that is driven by the fact that we've got a whole wealth and bounty of renewable assets to deploy. And as you -- so we've been through some challenges with gas, but we are deploying more of that renewable asset base. And I can see that we can restore comparatively low electricity prices in this country, at least the energy portion.

Your point on lines and distribution increases, I think that's an issue for the regulator being the Commerce Commission and the government. I do get that it increases costs for consumers at a time where consumers are feeling the challenge. But other than talk to, as you mentioned, the regulator and the government about those increases, I think that decision is largely in their hands.

It is. And the publicity doesn't seem to show with the low electricity prices for generation at the moment. But the lines companies, they seem to have a cost base of reducing labor intensely with technology. So the next question I have is with respect to the ongoing development. Do you foresee doing any capital raising or just carrying on with the dividend reinvestment plan?

Yes. I mean -- so I mean, jump in, Mandy, if there's something you want to add here. But the simple answer is no, Peter. We've been preparing for electrification of the economy for any number of years. And so as a company, we are really placed with a strong balance sheet to support the investment that we have just framed.

So as we look forward, we can see capital constraints possibly beyond 2030, but that will depend on what we're able to do before then, and that's some time away. So I feel really good about the strength of the business, the strength of the balance sheet and the need to invest in front of us but...

Yes. I would just add, everything that you saw today, we believe is affordable from our use of the debt capital markets. Were we to go beyond that, if there was something to come through that requires further investment, then that is the point at which we may consider a capital raise, but there's nothing in our current investment profile that requires that.

And then the last question is with regard to baseload and New Zealand independence. Ohau apparently was looked at some years ago with respect to the coal supply. And bearing in mind the South Island is connected to the North Island. So if we have dry problems in the South Island, is a baseload available if Tiwai doesn't make wind and hydro possible or solar. So with respect to that, how safe is the South Island with respect to dry years if there's problems with the cable between the north and the south?

Yes. I mean, again, Peter, providing forecast dangerous stuff, but I feel really good about the dry year risk that the country faces given the investment that's going on into renewable assets. I don't think we'll need to -- it's certainly not in our plan to invest in some form of coal back up in the South Island.

I think what will play out is, as I kind of talked to there is I think there'll be a wave of renewable investment that will both support more affordable power prices and economic expansion while reducing the dry year risk that the country faces from about 4 terawatt hours today to around 2.5 in the future. So I think the current frame for investment being in renewables is what will support the country and support the energy system.

Thanks for the questions. I think that's Peter's questions. We might move to the phones.

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

My can you hear me okay?

Yes.

Just first question, on the Waitaki Station replacement, you've mentioned before, it's looking like a $400 million project. Do you have a rough idea yet of the potential generation uplift from that?

It's too early, Josh. It's funny you mentioned it, I was kind of toying with putting something into this presentation on it, but I was advised by the team that the numbers are a little too rough at the moment. So next time we catch up, I'll probably be able to give you a bit more info.

Look forward to it. And the second question, do the economics of the Manawatu battery makes sense alongside Manawatu solar alone? Or do you actually need some of your other projects to maximize the value of that battery?

The economics stand-alone solar farm in the Manawatu look pretty good. But we get that -- the benefit of scale and efficiency at that site if we deploy both a battery and a solar farm, just as we do at Ruakaka. It does come down to that -- the cost of the transformer to connect it to the grid.

So preference would be to invest in both. But as you know, we'll only make investments if the economics make sense for us. So we would need to see better battery pricing certainly than we saw at Ruakaka, and we would want to see the benefits of ongoing improvements in battery economics before we make that decision.

So solar farm works by itself. Solar and battery be far more effective and economic, but we're pressing those battery suppliers pretty hard. So if they're listening, they need to shape up.

I guess what I was asking is, do you need some of your other solar projects to go ahead in addition to Manawatu solar for that specific battery to make sense...

Sorry, Josh...

Does Manawatu Solar do it alone?

Manawatu does it alone.

Okay. That's helpful. And maybe last one just for Mandy. The interim dividend being imputed at 85%. Do you expect the same level for the final and your dividends going forward?

Yes, I think that seems to be the level at which we're likely to impute going forward.

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

A couple of questions. First one, just looking at the cost of the wind projects and particularly Mt. Munro actually, I mean, both of them are around about that $4 million a megawatt, which is a reasonable step up on what we've seen other wind farms go for. Is there any sort of particular one-off costs sitting in there? I do realize that both of these wind farms have got circa 50% capacity factors. So that does help the LCOE numbers. But are there any particular sort of one-off costs associated with those projects? Or do you sort of see this as kind of the new level for wind farm costs going forward?

I think you've seen a lift up. And it's not just in wind, Andrew. We've seen a lift in the cost of solar panels as well. I think you're seeing that internationally.

So I suspect that the unit cost that you mentioned to be an ongoing phenomenon. That said, for both farms, we've got reasonable competition for the delivery of both the roading networks and the turbines. So the dynamics, particularly in the turbine space have changed a little bit from Harapaki.

So we'll see. It's like everything, if you can get a bit of competition, you can get a bit of price out of people, but I think your numbers are pretty reasonable. There's no one-off for either of those wind farms outside of the normal construction profile and cost base that you would have with a wind farm.

Okay. I kind of assume the difference between Mt. Munro and [ Te Rere Hau ]. I think you're probably looking after the cost of moving the airway sites, for example, which would be a few million dollars, I imagine?

Yes, it is, Andrew, but it's not substantial. it really isn't. So those costs, it's -- I mean, as I said, it's more frustration in the time that it takes to affect those outcomes at Te Rere Hau. And it's not something that we have as business done before. And so as you do things that are new is you're discovering a bit as you go about them.

So it's just -- I mean, Te Rere Hau is a fantastic -- I mean you've been up there. It's an unbelievable windsight, and we will get there. It's just a bit frustrating that we're doing some stuff we didn't expect. And the benefit of doing it once is we'll get better at it, if it ever plays out again.

Okay. A couple of questions on batteries. I'd be interested in theroaka battery, I guess, has been operational for circa 6 months or so now.

Are you able to give us an indication of what sort of EBITDA uplift the battery has delivered?

I don't have a number off the top of my head, Andrew. We'll get you one. We do include numbers in the monthly operating reports that capture the revenues for the battery. But it would be fair to say, if you remember that graph that showed spring and Mandy's comment that wholesale prices were $1 in January, it means the arbitrage opportunity hasn't been there for that battery in any material way.

That said, it has had a material impact on the way that reserve prices have formed in the North Island. And that has meant that the North and South Island price differential has come in not just spot, but also on the forward curve. And remember, that's where the majority of the value of North Island battery installation comes for us is lifting the price that you receive for your South Island generation. So from that perspective, it's delivering as we expected, but the arbitrage hasn't been there. But I don't have a number for you, Andrew.

Yes. Okay. That will be interesting. And last question also just around the battery -- around the Manawatu battery. It looks like you're talking about a 4-hour battery there, which I think will be the first one in New Zealand. So that sort of suggests I guess, the business case for that really is firming solar and I guess, wind as opposed to sort of more wider portfolio benefits that you might see on the sort of protecting the retail side of things. Is that sort of fair?

Yes, there'll still be a benefit in that battery and helping manage that portfolio optimization that I mentioned, the South North Island. We can't assume that others who have batteries will operate them to help manage that price differential. But your point is reasonable that the benefit that batteries bring ultimately is from a wider portfolio arbitrage perspective.

Your point on the 4-hour battery is we'll only deploy a 4-hour battery at that site if we can get the economics to work. So we've got a bit of a trade-off to make ultimately between a 2-hour battery, what you've seen at Ruakaka and elsewhere. And can someone make a 4-hour battery economics work. So we'll see. Don't know the answer to it yet, Andrew.

Your next question comes from Grant Swanepoel with Jarden.

Can you hear me?

Through loud and clear, Grant.

Fabulous. So Contact and Mercury came out and they both indicated that they're expecting about 3.5 terawatt hours of demand through 2030. Does that sit well with you guys?

Yes. Yes. I reckon we've got something very, very similar.

And then about 2.5 terawatt hours of thermal displacement?

Yes, a number might be a little lower on that, Grant. I'm not going to give you a number, but we'll get you one today, slightly lower.

So less than 6 terawatt hours of renewable availability. You guys have 2,000 gigawatt hours penciled in and partially inked until 2030. Contact just raised capital to fast track some of their stuff, Genesis raised capital for theirs. You guys are sitting at about 8,000, 9,000 gigawatt hours of potential by 2030. Who's going to get out the way?

We'll wait and see good question. It's funny how these things move from undersupply to oversupply very quickly. And it happens, right? You're a capital-intensive industry as you deploy, as Grant is saying, really big slugs of capital and investment at a time. And so there is a risk that you move from undersupply to oversupply.

The two things I'd say, Grant, are, one, you have businesses, and I can definitely talk for us, but I've observed it from others where there is a very strong discipline as it relates to deploying the capital of our investors. We're not deploying our own money. We're investing in people's money who have had the confidence in us to do so.

So we have really strong commercial discipline when it comes to spending other people's money and making a return on it. The second thing that we haven't really talked up yet, and I don't mean to by way of this answer, but we have another part of our business, which its sole ambition is to grow the underlying economy.

And it's early days. So they are actively looking for new sources of consumption that are not in that demand forecast that you mentioned, Grant. So the process of electrification. They're actively talking to businesses that are offshore that we could attract to New Zealand because of the two things that we feel are available here, one being the access to renewable resources, but two, the lower cost of energy.

So what I'm really saying is if the risk of oversupply manifests, then what we would look to do is to bring new consumption to the economy. And as I say, I don't want to talk that up here and now. I just wanted to answer the question, but it is something that we are working on in parallel with investing in new assets on the supply side.

And then just a follow-on to those costs that Andrew was talking about earlier on. Have you adjusted your medium- to longer-term wholesale price expectation?

No, we're still at the $120 to $130 range that we were, Grant, in November from the Investor Day.

And my final question, a bit for Mandy, but for yourself. The dividend is up 4%, but only less than inflation over the 2 years since the last normalized year. Should we be interpreting that as a Board's conservatism? Or should we be expecting that cash flows will convert into dividend -- meaningful dividend growth in the second half?

Yes, I can't comment specifically on the second half. It obviously depends on the result for the second half of the year. But just reiterating that our dividend policy is to return that growth to shareholders via a policy that returns 80% to 100% of our operating free cash flows over time.

Grant, the only thing I'd add is -- I know you know this, but last year, we got slowed down a little bit by the conditions, and that slowed down that progressive dividend approach that we like.

So I can't talk for the Board and what they intend to do in the future, but you're seeing us restore that dividend profile, a progressive profile. And like everything, you build confidence and you look at it a little more carefully next time you think about dividend.

There are no further questions at this time. I'll now hand back to Mr. Roan for closing remarks.

I think I'm done with closing remarks. Thanks for the questions, everybody. Thanks for your attendance. I hope you got something valuable from it. I think that's us.

[Foreign Language] Welcome to [indiscernible]. I'm Owen Hackston, Investor Relations Manager. I'm just going to run through a few logistics for the day. Starting with the end of the day. If you're flying out of [indiscernible], there will be many vans to take you to the airport from here. In terms of those in the room, bathrooms immediately beside the caffeine station and back past the main entrance you came in. Orlando free is the WiFi. There's no password.

In the event of an alarm or an emergency, we are asked to vacate -- evacuate to the car park. In the event of an earthquake, get under the table and get friendly. Today is a series of reasonably short punchy sessions. There is time for questions. If you're in the room and you have a question, can you please wait until the microphone is shoved under your nose. That will allow our online audience to hear the question. Questions from the online audience will come through and Phil Clark will very coherently read them out.

I've highlighted a couple of key points, morning tea and lunch. Very important because there will be the Meridian Investor Day Golf competition running. Orlando Country Club staff will take you through the comp. So you can either get out early and establish a clubhouse lead or spend the morning visualizing how you're going to win it. There's some tremendous Meridian merchandise up for the winners. They will no doubt be the envy of the capital market.

Michael will announce the winners at the end. So welcome. I hope you enjoy the day. Please participate. And with that, I will pass it over to Mike.

Great to see everyone this morning. Thanks for those that are here that we're able to make it in person. And thanks to everybody who will be no doubt glued to their PC screens for the majority of the day given the talent that we've got coming to you. I'm Mike Roan, for those who don't know me, CEO of Meridian. I've worked at the business for -- in a number of roles for 17 years now. I love the industry. I've spent probably longer in the industry than I've done most other things. And it's incredibly important what we try and do as a country.

So you get a lot of meaning from being in the sector. And the Investor Day is really important piece of our calendar, is it allows you to hear from people within our business that are out there doing the work, actually leading and we've got a great brand and the merchant is tremendous. But what makes businesses successful are the people who are running it. And Owen and I love talking to you like we love hearing your thoughts and questions.

Again, I was saying to someone last night, it's actually very difficult to get straight feedback on the things that you do well and places where you may not be best spending your time. And so we get that from these sessions, and it's really appreciated because I can tell you, and you'll see it as we go through this, this morning, the people that are here are from within Meridian are committed to making this business as successful as we possibly can, and insight from others is always helpful.

If I give a little bit of context and then just talk to the agenda for a touch and then hand it over to Rory, who's going to come up after me is if I jump back 18 months when we did our last Investor Day, I don't know if anyone remembers what we framed it as, but we framed it a certainty. So that was the basic frame for the Investor Day. It was driven by 2 things. It was driven by the 20-year deal that we did with NZAS. And the fact that we had confidence in gas as a transition fuel as the economy move forward. That was May 2024 and no one knew what was going to unfold post that. As we sit here today, the context is obviously very, very different as you've got security, affordability. They've all got political focus and lens.

I think we've dealt with the security, electricity security issues through the arrangements that we've already got in place. So I'm pretty comfortable and confident around the security elements is the political concern of security. And we've got massive pace of change going on within the sector and within our business to keep up with the needs of customers primarily. We've got opportunity to refine and make the business more efficient and effective of what we do. And we've got to grow the scale of our business, if we are to support the economy appropriately and that's what today is about is how do we deliver sustainable returns for people who invest their money and us have the confidence to invest it in what we do. And you will hear from people why that's a reasonable thing for folks to do and get confidence in how we're trying to drive that underlying business performance. So that's the context.

And the agenda follows it really is you're going to hear everything from -- as I hand over to Rory, what we see in the future. So what do we think the future looks like? And then as we present the future, we talk about the things that we're doing, whether it's Murray Hill, who -- many of you won't know, but you're going to learn a lot about Muz is he has kicked off our hydro redevelopment. So while gas has been a challenge, there are silver linings to these things because it makes you do things differently. So we're getting back into the hydro development game.

And you'll hear from Guy about our renewable development pipeline. You're going to hear from a lot of our executives. We're going to talk to how we're digitizing our retail business and our generation business to improve the way that we engage with customers and drive efficiencies. And of course, near term, there's a focus on regulation politics and what choices we've got from a consenting perspective to actually accelerate the pipeline of assets. So it is a super full agenda.

As Owen said, it's -- we're after questions, feedbacks, thought -- feedback and thoughts on the things that you hear. But please mingle, please take the opportunity to meet those who are doing the work, not everybody that is in the room that's within the Meridian team will be up at the lectern.

So we've got other experts that are in the room that are fundamental to the business and choices that we're making moving forward. So take opportunity to say get to someone if you don't know them because they're probably someone within the Meridian leadership team who's got a key role in supporting what we want to do. I'm going to close because we're here in Palmy because the Manawatu is becoming a bigger piece of our business. We've got [indiscernible]. We're looking at battery and solar farm. We've probably got a repowering project to do up at [indiscernible] at some point. So it's becoming a big part of our business as we look forward.

And got a little bit, I don't know, the propellers is you got 91 turbines that produce about 100 gigs of energy every year and the reason that this bid is awesome, I reckon, is give it a couple of years and you'll have 3 bladed machines that are in the air that will be producing 700 gigs or 7x the production -- annualized production that these things do.

So it's a little -- for those that didn't get there yesterday to see what [indiscernible] is today, what it might look like and then give you a comparison of the size of the new turbines versus the old ones. Having done that, I'll hand over to Rory.

[Presentation]

And I love that last piece as that is technology in action. Those turbines were built in 2009. And you look at them compared to what's available to us today to power economy. We are a technology business in many, many ways and harnessing this resource that the country has got is -- it's not only a privilege, but it's bloody important for our shareholders that we do a damn good job of it and for the country. so the economy does transition and become electrified over time.

So I hand it to Rory, who's going to explore that a bit more.

[Foreign Language] Good morning, everyone. I'm here to take you through some of the work on -- we do on how the market might develop and a little bit on how we're reshaping the portfolio to deal with that future. Sadly, I don't have any videos like Mike, but I've got some colorful slides. I hope you look forward to.

For those who don't know me, I'm the GM of Strategy and Portfolio. I took this role back in June of this year. I've been with Meridian since 2020. And prior to that, I've worked in the industry, both on the competitive side and more recently at the regulator since 2004.

Among other things, my group holds the company's long-term I guess, view of how the market could develop, and we're also responsible for positioning the portfolio in the broader sense of what kind of assets we want to develop, but also hedging activities and our long-term contracting.

Let's start off a bit like I did -- I didn't realize it was 18 months ago, but it's a bit of an overview of our modeling work that we've developed. We've -- it's an in-house I guess, replication of how we think the wholesale market will develop, but it tends to mimic what you'd expect to happen in a well-functioning electricity market. By that mean prices over time, tending to cost security, risks are reasonable. New investors are getting revenue adequacy, all that good stuff, what I say an all-singing, all-dancing view of the system could develop, of course, predicting the future is always very tricky.

Secondly, it's great to have these models and stuff but you really need to feed and water them. They only work as good as the data and the information you put in. And to that end, we've got a dedicated team and their sole job is to keep these things up to date. They periodically review them. We've got a huge, I guess, team of interested parties that weigh in with their opinions as well. And we do a big annual refresh every year, take the Board through it. And of course, as things change, we do more regular updates.

And finally, these things are only as useful if you do actually use them. And we feel having that central set of curated assumptions and scenarios is super valuable. It's a really good coordination exercise for the business. And some of the stuff I'm going to talk to up on the screen today, it really kind of underpins a lot of the investment we do at Meridian. It helps form, I guess, internal views of how we should be kind of moving the company forward and helps us respond to regulatory interventions.

Those are just some of the inputs and the outputs I just highlighted. I was going to step through the stuff in green a bit over the next 15 minutes or so. I've put up some charts and figures. I guess my request is don't fixate on them too much. They just a snapshot at a point in time. I think, but I just did want to be open to kind of give you a broad overview of some of the stuff we're seeing, some of the challenges, some of the conversations we're having internally. And as I say, it's not always the answer, it's a path to getting there where you get a lot of the insights.

And we do -- we've got 2 kind of large scenarios or narratives that we kind of form a lot of things. We talk about plausible futures versus predictions per se. On the left, you've got evolution, evo and on the right revo. Clearly, we do a lot more bespoke work depending on what the problem is we're looking at. But these are kind of permeate a lot of what we do. Evo, it's really, I'd say it's a bit more BAU. It's kind of, I'd say, a modestly changing operating environment. Broadly classed as limited decarbonization. So I think it's a future world that you would recognize based on what today.

Revo, it's a bit more shiny stuff, a lot more dramatic path to decarbonization. So a lot more of dynamic future. I guess in either case, you're going out 30, 40 years. We assume that the market design kind of keeps track of what it needs to. And whether it looks like today or not, it's always trying to balance those 3 things that any market should be looking at sustainability, reliability and affordability. And I would say it's probably a pretty optimistic view of the future in the sense we don't assume per se that we're going to have a structurally like the RMA is going to be like it is for the next 30 years.

You've got to assume over time, we'll get our act together and things will be able to be built at about the right time. So kicking off with demand. This is our current house view of annual demand in gigawatt hours for generation. And no matter where that generation comes from, be it rooftop solar or grid connected generation. It's based on bottom-up views that make up the constituent parts of demand. Takeaway here is in either world, Evo or Revo, we still see significant demand growth, but it's really hard to tell what trajectory we're on. And that growth follows around 15 years of stagnation, and you go, well, why is it changing?

Well, the big drivers that come from decarbonization of industry, basically heat conversion towards electricity, EV and EV uptake, which were a bit slower than others. And I guess, the cool new thing, which is data centers. Based on that, you're going to need widespread investment in generation at scale to meet that growth. And it's this kind of analysis that we chunk down to targets like you might have heard about the 7 and 7 target, which Guy and Rebecca and the dev team lead. So that's what's behind it. That target, in particular, takes us to 2030. But if you look beyond that, if New Zealand is serious about moving to a low emissions economy, you're talking decades of growth.

It's a really tricky area to look at some of those big slabs of demand. They're a function of specific policy initiatives and the relative costs of electricity versus substitutes. All of that can change. Data centers present a new kind of binary kind of thing, which is also hard. But -- so this kind of area can move quickly. I think the message though is I don't think we have a head in the cloud here. I don't think our numbers are out of whack with other stuff out there. If anything, I'd say we're kind of mid-ish to lower in the pack of where people see demand going.

And you go, that's great. That's aggregate demand levels. But if you kind of lift the hood, there's quite a lot happening under there, which is why it's kind of so hard to predict as such. The point I just wanted to make was what we call demand that line on the chart is actually made up of a hell of a lot of constituent parts. And what I called out on the previous slide, the 2 big movers coming from that blue and green area, which is EV uptake and industrial decarbonization basically. That makes up the majority of demand growth.

Demand satisfied by rooftop solar is in there and that kind of pinky color. We showed it as a negative. Just to really highlight, it's a bit different than the other ones. But it's still in there. It's from a customer perspective. It's still demand. It's just coming from the roof, not a power station.

I think the other point worth mentioning is how that demand interacts with the market is also super important, whether it's the physical issue like batteries, vehicle to grid, how rooftop solar impacts. And also -- but there's nonphysical things. You can do a lot with tariff design for -- and that can change consumption patterns and that can have a massive bearing on the shape of what we call the residual demand curve. That's the demand left over that generators are competing to fill basically.

Long story short, I think it's not just a question of how much shows up. It's when it shows up and what kind of demand shows up and how flexible that demand is that all kind of matters. That's all sitting behind all these kind of aggregate lines.

So supply now. We primarily -- well, we spend a lot of energy trying to understand cost because if you step back, you go like New Zealand really is a wash with energy potential. The issue is navigating the RMA and making sure you can get stuff connected to the grid and Transpower can build enough grid to move the electrons around.

So if you kind of say, well, look, that should be cleared up. Really, when you're talking about the future and understanding the supply mix, you're trying to understand, to a large degree where costs are going. And the chart here shows the levelized cost of electricity in real 2024 for 2 of the main technologies, solar and wind. So levelized cost of electricity, that's the average price a plant needs to receive in order to meet meters investment hurdle.

So basically, those things have been trending down over time, and that's because the world is getting a lot better at making these and deploying these, and that's the so-called learning curve. But -- and you can see that we're trending down until something happened around something in the mid-2020s. And due to political unrest and inflationary pressures LCOEs have kicked up a bit of late.

You can see from the dots, we do our best to track projects and benchmark our views about the future, and some of those views are those green and yellow kind of shaded areas looking forward of where wind and solar costs could go in the future. As I said, this could all change, no doubt. But I guess I wanted to leave you with the message, we still see innovation has some ability to take costs out in real terms, albeit starting unfortunately, from a slightly higher base just because things have essentially reset at a higher level.

Looking at the chart, our sense is solar costs probably have more potential to fall versus wind, perhaps a bit more commoditized. But look, that thing can always change. And I think that's why -- and Guy Waipara is very good with this. It's why it makes sense to hold options in both from our perspective. But I would say, remember, this is just cost. Just because you've got the lowest cost plant does not mean the market is going to reward you, of course, for building that, but it is an important thing to understand.

And before getting to prices, I wanted to touch on these 2 pictures, which is flex or firming, which is kind of a cool new word. And that's how much the market, we think, is going to need going forward from the shorter term on the left and the longer term on the right. Basically, charts show how much energy is being dispatched on average by various firming resources over time.

I think the important thing, no matter how we look at Evo or Revo, whatever scenario we look at, we just see a huge need for more firming resources going forward. And that's to fill the hole, which is left by gas and thermal exit, but also as you move into the 2030s, you just -- the challenge of just delivering reliable power year in, year out from a highly renewable system. The main chart I want to focus on was the one on the right because this gets a lot of news. That is our view on the dry year energy needs in each year going forward.

This is really hard to show, by the way, so it's perfect, but it's a good representation. The line represents how much more fuel is needed in a dry year and the bars show how you could achieve that fuel basically. Bars higher than the line means you're good from a security perspective, though more is always better, basically. And that underlines what Mike opened with. The line could drop over time. And the reason it does that is in our world, as you think the cost, I said we need more firming if that's really expensive to provide, it makes sense for the market to adjust and overbuild renewables because it's just more rational.

When I mean overbuild, as long as prices compensate you doing that overbuild. And what that means is if you overbuild a bit in dry year, you don't need as much extra fuel coming into the market. There's also a bit of hydro profiles changing through time and all this kind of stuff, but it may not happen. It may stay up around that 3 that kind of 2025 figure where the line is 3 to 3.5 terawatt hours that could -- if that line doesn't drop, that's a good kind of rule of thumb that we use for how much kind of dry year energy firming flex, whatever you want to call it, the system needs.

I would say in the bars, because some of you might say, why are they like that. We've derated the thermal plants a bit to account for they may not always be fueled by gas is operational considerations and the NZAS demand response is not at full board because you can't call it maximum every year. So you could argue there's a bit more slopping around on the supply side. But I think standing back, I'm kind of happy with what the story, the chart is trying to tell us.

And for me, it paints a picture where we're okay from a security perspective. But I think the country would benefit from what we'd call more deep storage basically. And while we think the demand response contract with NZAS massively positive, really good, getting more reliable access to hydro resources, be it in the short term from contingent storage or longer term from potential hydro development, which Murray is going to talk about, I think, would be hugely beneficial. It would just add to those bars, give us a lot more of a buffer basically.

So on to prices. You put all that stuff I just spoke about, into our world, into our modeling framework, demand supply, a bunch of constraints at the [indiscernible]. It's not that simple. But those are the prices that come out. Those are average North Island prices Evo and Revo 2024 out to 2050. The front end, so WMO25 is -- that's kind of the name for our big annual refresh. And so I'm just looking at that blue-shaded area going forward.

That's -- you can see the front end. It's still dominated by, in our view, the effects of the rapid decline of the gas industry. But if you look beyond that, you can see it dropping and that's because of the renewable build and you kind of average out the humps and bumps, what you get is prices clearing around $120 to $130 a megawatt hour for the next kind of 15 years thereafter after the prices drop. And then I guess because it's all in real terms, it starts trending down over that, and that's just a function of those learning curves and more renewables, stuff getting kind of -- getting built at the right time and changing that balance.

So to come back to that opening slide, I spoke about at those price levels, build as a plant are getting the investment hurdle, securities concerns are managed, everything is doing what it needs to do. That is a market and equilibrium that can work. There's other views of the future clearly. And over time, you would think a well-designed electricity market, you should see prices trending or going towards costs over time as long as you've got sensible supporting policies, gas, in particular, and resource legislation, then you go, why doesn't it equal just that LCOE of those charts are put up earlier. And the difference is really the cost of firming. That's essentially what's driving that delta between the two.

And so much like I kind of looked under the hood with demand, this is doing the same with price. And I showed you average price. And I should say that's average across all hydrologies and the kind of the spread around hydrology prices is massive basically. But this is what's going on behind the scenes. The chart on the left shows GWAP to TWAP or price participation for some select assets or technologies, that's a measure of the average price received by the plant divided by the average market price. So numbers bigger than 100% mean you've typically got a flexible asset and you're just generating at the right times and so you get a price above the average basically.

What it shows is as you get more intermittency in the system, you get more price volatility, meaning you should see a growing divergence between the price participation of intermittent resources, which is kind of the solar and the wind there trending down and the more flexible resources, and particularly the Waitaki chain up top going up. We think solar price participation will probably fall faster than wind and solar has got a lot higher kind of correlation than wind basically.

And wind also has some variable running costs, meaning when prices get really low, it makes sense to spill wind basically. And what that does is kind of pumps up, I guess, artificially pumps up your price participation because you're not getting your generation away at low prices. And you can see that blue line on the left-hand chart. We just took a slice through that to look at a typical day in 2036. I there is such a thing, that's the one right.

And it's just kind of show you what a typical day could look like. So you've got the price in the red and the output of kind of on average wind and solar in the green and blue. And [indiscernible] prices kind of peak when wind and solar are not at their highest, prices dip in the middle of the day when solar and wind are really cranking basically. In that year at least -- and that's again across all hydrologies which is an average of an average, basically, but you've got to make some headway.

We're not seeing prices really collapse, like they have in other countries there. And the reason is New Zealand has got a really good backbone of flexible hydro. So when solar is really cranking, the hydro can back down and shift water to the higher value periods.

But I would say overnight could get interesting. You can see a bit of price collapse overnight, and that's because we'll have a lot of must-run generation competing to generate overnight. So all the geothermal, any generation with kind of low cash operating cost is all trying to squeeze in overnight. So you could see some real price collapse overnight despite the amount of flex we have in hydro.

And finally, I would say we don't have negative prices in our market. So prices can only go to 0. In other jurisdictions, you get negative prices where you actually have to pay to generate. You can imagine that will change all this story again. But I think that will only add value to flexible assets if you can really shift out of the way and target the high periods. It really just -- I mean, it's just a very complicated way of saying there's a lot of value and flexibility.

And none of this is a surprise. It should be -- people will have their own views, but you've got to factor this at the time you make an investment decision. So I think the takeaway is it's really important the market designers keep the prices adjusting to the physics and essentially the reality of the system because what it does is it makes sure investors are targeting the right investment for the system and instead of just trying to put in the lowest cost plant. It's all about -- it's really -- it's not about an LCO shoot out. It's who can deliver the most value to the system basically.

Now this is -- Owen is looking for it to describe this. But if there is an award for a slide of the day, here it is. I did mention correlation and Mike put me up to this. The 2 blocks of color, yes, I guess, colorful tables, they show generation correlation for solar on the left and wind on the right. Red means high correlation, green means low correlation, yellow is somewhere in between.

If you look at solar on the left, what you see is you've got rooftop solar sites, starting at the south of the country. Why we put South here, I don't know, but we start at the South. And as you head down to about halfway going northwards until your hit that line. And then we do industrial sites as well, starting in the south, moving north.

There's a lot of red there. And it's a very complicated way of saying, it's known everywhere in New Zealand at the same time, basically, all the solars cranking at the same time. Although you can see there's a little bit of diversity with the yellow colors.

Wind on the other hand on the right, again, you've got wind sites starting at the south at the top of the table and as you go down the page, you're going north. Wind, you can see pockets, the red areas. There's pockets of regional correlation, but it's actually quite diverse nationally. And I guess it's a simplest way of, I think, showing why we feel solar's price participation will probably fall faster than wind.

Okay. That's enough energy modeling. You go -- that's great, how you're going to manage all this? Managing our fuel water is -- preoccupies a large part of my team. And one of the main instruments we manage that with is with swaptions or callable agreements, basically, they're just a really good fit for our portfolio. And the lesson from the past year is gas, there's a whole lot worse than we or, for that matter, most people expected in contracts that try to pass that risk through really aren't worth all that much.

So you can see here from this chart, the volume and the makeup of our swaption book and how that's changed over time, away from gas and towards coal and demand response. And in a perfect world, we're going to add more contingent storage to that as well. And the eagle eyed among you will notice that the NZAS -- new NZAS demand response contract starts from 2025 on the chart. We all know we used an angle from mid '24. It's a bit of a par. Sorry about that. I get it next one. But I don't think it changes the story.

I would say we've -- in green there, we've had a bit of success. This is seasonal stuff, not peak demand response. This is more -- goes to that chart I talked about earlier about really long-duration flexibility. We've had some success with other retail customers providing it. But it's -- I think we find the volumes a bit more limited than we originally thought. It's a bit hard to go, but there still could be some sum there.

And the swaption is kind of -- they fall towards 2028, and that kind of lines up with that price chart I showed you earlier, where we feel prices with the amount of renewable build going on and a bit of resetting of things, the market should find a new equilibrium and prices easing, so we don't need as much insurance. Things don't stop at 2028, by the way. I just had to cut it off somewhere. We've got the Huntly deal out to the mid-2030s and we've got the NZAS demand response out to the 2040s.

So just what I wanted to leave you with, I feel we've got a good amount of flexibility, particularly in the front end, where we think the market could be the stressed the most, and we're still actively exploring other options on top of that, with the main event longer term will be augmentation -- potential augmentation of our hydro storage, which Murray is going to talk about a bit later.

Finally, the other way we manage our risk position is the sales book and the C&I channel, which has been really good for us, provides another amount of swing. So managing our C&I position going forward will be particularly important, especially if Lisa and the retail team keep making inroads into the mass market segment.

And that's at other end and if the wholesale prices do, in fact, ease like my chart suggested because C&I tariffs are really correlated with the wholesale market and the ASX curve in particular. So what this chart shows is our contracted sales position for C&I versus kind of what -- where 2025 is. And you can see it really falls in '27, '28. So we've got a choice really how much you want to recontract in those years. And if you do recontract, how much you want to kind of back-to-back or lay off through the ASX.

All of that, that's got implications for our risk position and our appetite to buy more or less portfolio insurance. I think point being combined with that swaption chart I showed you earlier, we've got lots of levers we can pull over the next few years to navigate things. And I think it really shows the benefits of the integrated model and lots of diversity in the portfolio.

Summing up, look, I'll just leave that in the background. I think the main thing I want to say was I think that story I presented, it is all manageable. And it feels as though with the signing of the Huntly strategic energy reserve, security is in a lot better shape despite the faltering gas industry.

That said, I think there's a big difference between meeting security of supply requirements versus having affordable secure electricity prices. And for the latter, you're either going to have to import fuels or you're going to have to kind of unlock domestic resources. And we think for a host of reasons, the better option for New Zealand is to really take another hard look at hydro.

Andrew here who has got the microphone at the moment. So a couple of questions, if I may, to begin. So first of all, how do you think about the LCOEs that you had up before, which declined. How do you think about the -- I guess, you build out the best sites first and the fact that when you think about the sort of generation stack over time, you build cheap sites first and more expensive sites later. Is that built into that chart at all or not?

Yes, yes. Well, I think it primarily shows how the -- if you're talking about the green and the yellow areas going forward, I think that's more just about what we feel the inherent technology costs will do over time as opposed to -- they're probably using probably just average site stuff, like what a reasonably good site will produce as opposed to going through specific sites to develop that curve. When we build up the price, all that stuff that's at the front end that uses specific sites of known projects and announce things. And as you get further out, we're having to make a guess kind of thing. So we do apply a merit order.

Okay. So I guess in terms of the next slide, I think it was, which then showed the one after actually, that one there. So that then includes your view, I guess, of the sort of the generation.

Correct. Yes. The build order, yes, we -- so as I said, we've got this team, they're going through all the announcements, reading some of your analyst reports as well. And it's working out what people have said, what we think they can actually do, a level of pragmatism. And then as you go in the back, that's why I said, we have to -- you've got a choice about how much optimism you apply there.

And we kind of think that again, it's a feedback thing. If prices are too high in our model, we add more generation as long as it's getting revenue adequacy, and we think it's -- you're not adding so much generation like the whole country's out there building wind farms kind of stuff. So we just keep iterating until we feel we've got a reasonable solution of the build run rate, prices, investor returns, security, so that's kind of -- that's where it's a bit more of an art than science, so to speak.

And my second question just relates to overbuild risk, and that's a topic that comes up from time to time. How will we know that when we get into a situation where we may have a bit of overbuild is, I guess, good overbuild in terms of providing additional security of supply versus overbuild, which suppresses wholesale prices for a period of time and we end up in the 2010s again.

How will we know? I think to some -- well, it probably depends upon that demand curve to some degree. I think we should be able to see some of that coming. So we've got the option. I'm not suggesting it, Guy, but you can, if we see the overbuild coming that will feed into our price forecast. The projects that we thought were economic will become uneconomic and you can throttle back the generation. So there is that aspect to it.

I think the trouble which might have been in the past is if there's a real big bow wave of investment, and then you just see some -- the demand just doesn't show up like anyone suggested. And yes, I guess that is a risk. But we got bunches of people looking at this. And I think we've all got lots of projects in various states, and you can do things with pushing them back and all that. You can juggle things quite a lot.

Just. a quick one. On Slide 14, if you mind going there. On the GWAP/TWAP chart, are you able to talk to what the whole business is sort of expecting from portfolio level in FY '36. You talked to hydro increasing potentially. Obviously, you've got in-house wind path as well. Just wondering what on a portfolio level, you see GWAP/TWAP being?

Well, I don't know. It must be dominated by -- from a generation portfolio. Yes. Well, it must be dominated, I mean, in those years by Monopoly and Waitaki. So I don't know off the top of my head, but it would be something approximating I would have thought I'd just be guessing, but it would be around 110 kind of 115. If I look at the Waitaki as a proxy, just so much volume basically.

Yes. So about 5% to 10% above where you're historically sitting in terms of relative pricing lift is fair?

You got -- I don't have that info. But yes, I mean if I look at that -- if you look at Waitaki as a bit of a proxy for the portfolio, right? We just see it increasing. There's just -- as soon as you add more intermittency that just kind of has to trend upwards. I should say that's across all hydrologies. Now people who do this is like we've got 90 hydrologies sequences in history. You've got dry years, you've got wet years in there. There's no such figure as an average year. But yes, so it will be very noisy to know to really say, oh, we're on that path, so to speak.

Okay. Just a second quick one, if I have time. In terms of volatility between seasons, you sort of talked to kind of dry years and wet years. Are you able to talk to how the portfolio is positioned between summers and winters and how you see sort of wholesale prices fluctuate between the seasonal stuff.

Yes. It's a good question because these dry years, they can be like dry quarters, so to speak, which is why the swaption, the portfolio, the callability is quite important. We're doing a bit of work. I guess, fundamentally, you kind of -- with the climate change, what's happening with our inflows. I don't think we've seen any evidence at the moment that we're getting more seasonal volatility, though we are kind of peaking into that a bit more.

So it's a hard one to know. I would just say, just anecdotally, it's just depending on the level of firming that shows up, it's just getting more volatile basically. So I would just anecdotally say it would be more spread between the seasons. So I'm not talking to the microphone. It's just things are getting more amplified basically.

One quick one. Okay. Just the headline one then. What is roughly over the next 10 years, the mix gigawatt hour kind of mix -- of solar this is wind you expect to be built in this profile?

I just don't have that at my fingertips, sorry. Yes. I think I would say, I don't know maybe when Guy chats, he can talk to this, but it's just wind is just so much more energy dense, right? So I would hazard a guess that the wind and the gigawatt hours, it's just, I think, some of the stuff that Mike said. Solar on average, what, 20% capacity factor, you got to build a hell of a lot of solar to kind of get to where wind levels are. Wind is just really big. And when you see some of the options Guy's going to put up, there are some big ones in there.

I'll sneak in a supplemental about your gas assumptions over the next 5, 10 years?

They're not great. So I think we've got some kind of gas experts in the crowd, but -- and we read their reports. We're not expecting great recoveries in the gas. It's kind of managed decline or rapid decline.

Okay. I'm going to have to leave it there. Thank you all. I introduce Lisa, our Chief of Retail coming on.

[Foreign Language] So good morning, everybody. For those of you that I didn't meet last night, and for those people online. I'm Meridian's Chief Customer Officer and I am based in Otautahi. And it's a real privilege to be here today. So when we met 18 months ago with some of you, we set out the new path we are on with our retail business, and that was all about adapting, thriving and staying really resilient in our rapidly changing energy landscape. And today, I'm really excited to let you know how we are progressing there.

So retail's mission is really simple, but we think powerful and that's to deliver cleaner and cheaper energy for New Zealanders. And so today, we're giving you an update on how we're contributing to that, and that's by growing our retail business in new ways that create value from the energy system and crucially passing that value on to our customers.

Our strategy is based around 5 pillars and they aren't just sort of things we made up on a Strategy Day. The other things that they drive everything that we choose to do. So that is our digital and data-driven customer experiences making Flux valuable for customers, electrifying transport and heat, optimizing our cost and efficiency and increasing community good. I'm going to walk you through the progress that we've made on each of those, and the stories about how we're really making a difference.

So firstly, Meridian's digital transformation isn't actually just about new technology. It's changing how we work, how we serve our customers and how we're using data to really drive innovation. Our $30 million next-generation retail program is really a game changer, we think. We've moved from siloed teams and legacy systems to a much more agile, cross-functional way of working and a really modern and modular technology stack.

We've chosen Kraken as our new billing engine and the migration from Flux is well underway, and we are on track and on budget. It's been just less than 6 months since we signed our agreement with Kraken. And as of this morning, as I had to double check, we have migrated 34,000 customers. We're migrating a couple of times a week, so we'll have more customers going later this week. So that's going really well.

Those customers will be the first to have access to our new mobile and web apps, which are built to iterate and really evolve as we introduce those new products and experiences. Underneath the hood of that and our new data -- a new retail data environment, is really tying together all of those things, creating one view for our customers and our business and it's enabling us to leverage AI for both customer-facing improvements but also and importantly, internal efficiency gains.

So what does that actually mean for our customers? It means faster service, it means smarter products and it means a much more seamless experience. And that's whether they're online, if they're calling us or using our app. And for our people, what it means is we've spent time -- we've got more time to spend solving and building new products and less time wrestling with those old systems. And we think we're building a business that's fit for the future.

Now on to flexibility. So we're scaling our first mass market Flux product. We call it the smart hot water plan. And that's really about helping customers use energy when it's cleaner and cheaper and rewarding them for that. So since launch, we've credited $880,000 back to customers. and we've shifted 2,500 megawatts out of those peak periods. So every month, we're moving hundreds of megawatt hours out of those peaks. That means customers can save on network and energy costs. And what it means for us is we're learning really fast how to do that and where the value lies.

People often ask me whether as a $10 monthly payment really good value. And I think for retail customers, it absolutely is. So they're getting $120 a year in the pocket. They've got no disruption to their hot water and there's no required effort from them to do that. For us, it's really about a move in the right direction. It shows us how we can find that value, how we can pass it on to customers. And we'll keep scaling and learning and sharing in those benefits. So it's not really about running experiments. What we're really doing is building the infrastructure and the data system so that we can make Flux a core offering for retail but also for our wider business.

The next one is around transport and heat. So they still remain really massive opportunities for us. And today, I'll talk about electrifying transport. So our ambition is really clear. We want to build New Zealand's largest and most loved EV charging network by 2028. So far, we've deployed 396 charge points nationwide with around 1,100 weekly charging sessions. And this year, we have a further 194 charge point agreements with the landowners. And of those 118 are currently in the under construction category.

So we're really focused on DC charging, making long journeys possible and making charging simple and reliable. By 2030, we expect Zero network to generate $20 million of annual revenue. And that's based on the assumption that the share of pure EVs in the light vehicle fleet will grow from around 2% today to approximately 10% by 2030. So that will see an increase from around 90,000 vehicles to around $0.5 million.

Those numbers do sound quite ambitious. And they do come from really reputable public and private sources. But as we know, it's really hard to be very accurate around the focus of our new technology, but we know that there's been some political change that has derailed some of that growth, but we're confident in the long run, it will come back.

That revenue stream is really backed by Meridian becoming the dominant player in the rapid and ultra public -- ultrarapid public charging market. We've currently got a market share of less than 1% and we're aiming to get to over 20%. So turning to the customer, you need to have a very good customer experience to win in this space. So we're constantly improving that experience with better apps, better payment options and hardware.

And I guess that our charging product is really one of those examples of how we're extending our core competency and energy to create that additional product or, if you like, it's our form of bundling. We're leveraging our existing service infrastructure, our in-house asset deployment team and our core retail technology to drive that. So we think it will be a really low-cost new product for us. This is about us -- this isn't just about infrastructure though. We're very committed to accelerating New Zealand's transition to a cleaner and in the long run, cheaper energy source.

Costs and efficiency. So retail has executed on a very clear growth strategy since 2018, and our customer numbers have grown by over 160,000 over that period. So this, along with our C&I growth has seen retail's annual sales volumes increase over 70% during that time.

This calendar year alone, retail has grown by 70,000 customers, half of that is organic and the other half as a result of the Flux transaction and subsequent migration. Powershop has the most significant growth, but we're really pleased that we've also been able to grow the Meridian brand. Now this hasn't been at the expensive value and that's evidenced by the 63% increase in our net back growth.

So while serving a much larger customer base, we've also successfully reduced our cost to serve on both an absolute and relative basis. That cost reduction has largely been driven by reduced headcount, but also on the optimization of spend on acquisition and retention of our customers. In recent years, we've really built up a strong data and digital capability in the retail business, and that's enabled us to be much more effective using data to acquire and retain customers.

It's really helped us in making more effective decision-making and reduced our reliance on costly third parties to optimize processes and build those experiences and products. We have created real efficiencies by bringing our 2 retail brands together at the back end, operating like a true multi-brand retailer through our whole business. The net result is that we've demonstrated that we've got the ability to scale our business without the corresponding increase in costs.

And finally, it's very important for us to be a leader in the industry. And so increasing community good is really critical. As we grow, we're determined to support our customers, the end communities and the climate. In fact, we think that, that's our license to operate. Two programs that we've seen really tangible outcomes from are our energy well-being program and our community and business decarb fund. So in our energy well-being program, we've helped over 3,000 households since inception and with just nearly 2,000, we've assisted just over the last year.

How we run that program is that we work directly with community energy partners right across New Zealand to provide in-home energy assessments and interventions that are providing long-term sustainable solutions for energy usage and efficiency with an aim to reduce energy costs.

The second thing is our decarb fund which is powered by the net revenue from our certified renewable energy product. That means that every certified customer is helping make that possible, which we're really thankful for. This year alone, we've supported 37 community groups across New Zealand, and we've invested $1.8 million in helping them further decarbonize and put more of their resources back into the communities that they're serving.

Since we started that $4.7 million has been invested in 80 different community projects, helping them to cut costs and emissions. So we're incredibly proud of what we've been creating. And since 2023, we've shared those stories through our annual certified impact and transparency report that's highlighted the difference the fund is making for people and communities around the country.

So that is my story. And now I'd be happy to take any questions.

Probably [indiscernible] a little bit with Rory's presentation before as well. Can you just run through why now is the time to focus on upweighting retail and think about down weighting C&I?

I think -- I don't think we're doing it today, but what we're trying to do is maintain the flexibility we've got to make that call when the time is right. So the beauty of having a book that is spread between C&I and mass-market is that we're able to manage that very regularly. So as contracts come up, we can make that call. What we know is it's easy to shrink your C&I book, but it's really hard to grow your mass-market book. And so we've made a decision as a business that we want to be consistent, and we're just growing as the time is right. And that's working for us. So we're certainly not jumping out of C&I overnight. We'll make those decisions as we get the signals from the market about when the time is right.

And second question, just on the migration of customer cohorts to Kraken. Can you just run through what the staging of that actually looks like? You're at 34,000 customers now. I think you've got, call it, 400,000.

[453,000]

To go -- just an overview of the staging of that would be helpful. You obviously can't do it all at once. Why is that the case?

We've chosen to do it in a really iterative way. So how the migration for Kraken works is that we do customer cohorts. We build out the product for that particular cohort and then we learn from that and then we do the next one and so forth. So the general plan is that we will have all of mass-market done by February. We moved our first Powershop customer today in test. And then we're -- a very ambitious goal is to have the program completed by June next year. So we're doing C&I. We're building the C&I component now, but that C&I migration will start in April.

[Audio Gap]

Just a quick question on EVs. Obviously, a pretty core part of the strategy moving forward. Just wondering if you can talk to a bit of the economics behind charging stations and sort of what's the average cost to build a charge point and maybe a bit about the utilization as well, please?

Yes. So it depends. So every site is different. Every site has different requirements, but it ranges from, say, $70,000 to $150,000, I would say, per site, and we have a utilization hurdle dependent on the site. And it starts around 3% to 5% in year 1, and then we're rising up to 20% by year '20, sorry, 20-year payback.

[Audio Gap]

Welcome back. I'm Jason Woolley [indiscernible]. I'm the General Counsel and Company Secretary of Meridian. I also have responsibility for regulation, which means I get to present the highlight presentation of the day on regulation that I know everyone will be looking forward to. The electricity sector is pretty heavily regulated. It's part of what we do. We're used to it. It is kind of our bread and butter. In my kind of what feels to me a relatively short time in the sector of 14 years, electricity is, if anything, just become more and more fundamental to everything we do in our lives. And that means it has and always will be a focus for politicians.

With appropriate acknowledgments to Forsyth Barr from whom we borrowed liberally, there is a summary of some important electricity sector reviews since 2000. I could probably name a few others that sort of loom pretty large to us working in the industry, but those are the key ones. And you can see even focusing on the key ones, there's quite a few. They seem to show up every couple of years or so. And certainly, when you get a change from one stripe of government to the other, you typically get a review into the energy system.

Winter 2024 obviously prompted the most recent one of these reviews. But as the slide says, we've been here before. The results of the reviews almost uniformly over the years have tended to confirm that the broad structure and design of our market is a pretty good one. And the New Zealand electricity sector does work in the interest of consumers. The review of Winter 2024, and I'm referring here to the Electricity Authority review of 2024, found that high prices reflected scarcity and were driven by fuel shortages.

Nevertheless, we got the frontier review and that was a pretty -- that was -- when you look at the terms of reference, that was an enormously wide-ranging review of the sector and whether it was working in the interest of the country. Frontier was supported by Concept Consulting, who did the modeling for their work and their work was peer reviewed by a group of four academics and another separate international economic consultancy NERA from the U.K. They completed that report of the first 4 months of this year. And then the government took some months working out what it was going to do with it and what their response was going to be and the initiatives they're going to take off the back of it.

1 October, they released it. And I think it's worth highlighting and dwelling on some of the points that they found. So there were some areas for improvement, but they made important conclusions in three areas, essentially saying the sector is doing well and working in the interest of consumers in the country. First, they said the fundamental design of the market is sound. There's no need for structural reform. They noted while uncertainty around demand supply and in particular, government policy, regulatory policy had influenced investment in recent years, a strong pipeline of new generation was now being built by both generator retailers and independent generators in the sector.

The review concluded that New Zealand's energy-only market design was working well and should be preserved. In fact, they said the core problem was the impact on investment from government policy volatility. Frontier said that as this was a problem caused by the government, it required a government solution as there was no means for the private sector to address it. The second main finding was that competition in both the wholesale and retail markets was strong with multiple large and small players and concentration rates well below internationally recognized thresholds.

Having four vertically integrated entities of a similar size, we're seen by them as a positive indicator of effective competition as well as evidence of substantial new entry in the market on both the retail and supply side. Frontier concluded that recent market outcomes have been the result of a lack of investment in firm capacity driven by the aforementioned uncertainty in terms of government policy rather than any indication of anticompetitive behavior of some kind. Thirdly, the review was clear about the benefits of vertically integrated electricity companies. It noted that this structure increases operating efficiency and that in a competitive market, these benefits are passed on to consumers at lower prices.

Frontier found that any claims of a market squeeze were simply not credible. In fact, their analysis indicated that across the years where data was available, independent retailers were achieving higher margins than the gentailers. And they found that in a demonstration of the price smoothing benefits that firms like Meridian could bring, they concluded that rather than misusing market power, the gentailers were likely acting to present -- to protect residential customers from some of the volatility in pricing in the market at the expense of their own margins. They were quite critical of the Energy Competition task forces level playing field proposals. That's an initiative of the Electricity Authority and the Commerce Commission, which I'll talk about in a second.

Noting that rather than resolving any underlying issues, those measures would only impose higher electricity costs on to consumers in the industry. The peer review has supported the Frontier conclusions. They found there was not any evidence that the market was not addressing dry year risk. To the extent there was a dry year issue, they said it was more about prices than reliability. So affordability rather than whether the lights would stay on. And they recommended interventions targeted at the gas sector.

Now the public debate has quickly moved on from those conclusions from the Frontier report. I think a lot of people pushing for reform of the sector were left underwhelmed, but they're pretty strong findings. And as I indicated on the first slide, they're kind of consistent with the findings from numerous reviews over the years, which have reached broadly the same conclusions.

Now these are the government's proposed actions off the back of the Frontier report. Meridian supports -- I think there's 10 on there. Meridian supports them all. There's a couple where we're saying our position is neutrality. One, an LNG facility, I think we've got an issue. I think much remains to be seen about whether that is going to be the least cost way of addressing dry year issues to the extent we need more to address that or at least to address affordability during dry years.

And then also, I think we've got a concern that once you establish an LNG import facility, you need to try and do that in such a way you're not permanently joining New Zealand gas prices and also electricity prices, energy prices more generally to world LNG prices and query whether the LNG proposal is currently being progressed can find a way to do that. The other one where we're neutral is Action 2.5, which is about strengthening the dry year regulatory risk framework. And there's very little detail on what this means. We know there's going to be some tweaks to the way Transpower does its forecasting in respect to dry years, and you're starting to see some indications of what they might be with a greater focus, not just on what people's actual thermal capacity is, but to the extent they twitch their contracted gas or other forms of thermal fuel to support that capacity.

And we would broadly support that or strongly support that. But what more there is in mind is something that's being worked on held closely by the government at the moment. We know that there's a targeted consultation of the sector on that issue coming up, but we have not, at this stage, heard anything. In relation to the dry year risk framework more generally, we would say that when you look at the combination of Meridian's demand response agreement with NZAS, the Huntly Strategic Energy Reserve agreed between us and the other gentailers and provided better access to contingent storage or actual viable feasible access to contingent storage can be secured in some way, coupled with the amount of new generation that's going to come online in the next couple of years, we think we are a long way towards better managing dry risk and better managing it at more affordable levels.

I think we would caution that further interventions need to avoid imposing additional costs on consumers unnecessarily and/or crowding out private sector investment. So I adverted to this previously. These are the -- the next slide is about the level playing field proposals pursued by the Electricity Authority and the Commerce Commission and in particular, the nondiscrimination measures, which are currently on the table and moving towards implementation around middle of next year.

The idea of these is to address perceived competition issues between generator retailers and independent retailers and in particular, give the independent retailers a leg up to enable them to better compete, notwithstanding they've chosen not to [own] generation. There's a current set of refined proposals that the electricity authority is currently consulting on. And essentially, these principles would require that we -- that the gentailers, the four large gentailers do not discriminate in our dealings with independent retailers between them or against them and in favor of our own internal business unit, our own retail business unit. We would maintain that, that is already the case.

As I said, the authority has got a more refined proposal on the table at the moment, and it's definitely an improvement on where they were. But I think there remains some risk of unintended consequences even with the proposal as currently set forth and proposed by the electricity authority. In particular, they have this proposal relating to what's been called a retail price consistency assessment that will compare the prices at which we sell hedge contracts to independents and other third parties and the level of our own retail pricing in particular segments of the market and under different brands. And the risk with that is it may end up forcing the generator retailers to increase retail prices to the extent the authority believes the current margins being achieved on the retail sides of our business are insufficient.

There's a lot of [indiscernible] in the details still to be worked out and further consultation will take place over the first half of next year. We'll have to see where it ends. I think the slide says it will come in midway through next year. It will cost us some money in terms of implementing that. There's quite a lot of process to be observed, and we'll just have to see how that goes. Another major sort of regulatory initiative or issue that we're pursuing, and as I indicated earlier, we think it can make a massive contribution to our ability to deal with dry year risk in an affordable manner is to better enable or actually enable, I would say, access to contingent storage.

Contingent storage is the 832, I believe is the number, gigawatt hours of storage spread across three South Island hydro Lakes Tekapo, Pukaki and Hawea. And you can see each of them illustrated at the top of the slide there with the relative amounts they hold. There's two colors on the Pukaki slide because the dark blue is water that becomes available when the -- when Transpower deems there to be a 4% risk of supply shortages. So still very conservative, a 96% risk or 96% chance of no shortages, but 4% chance of shortages. You get access to up to 220 gigs at Tekapo at certain times of the year, 331 at Pukaki and 67 at Hawea.

And then at the 10% risk curve, i.e. 10% risk of shortages, access is enabled to a further 214 gigs at Pukaki. And what we're talking about there is water that currently sits between -- in terms of Lake Pukaki water that sits between 518 meters and 513 meters above mean sea level. It's water we can generate from. To contextualize what we're talking about in terms of the impact on those lakes, Pukaki has been raised by 46 meters from its natural level. So between 518 meters and 513 meters is a difference between 46 meters and 41 meters above its natural level. We think the environmental impacts of that can be managed. And our suggestion is we should be able to use that water to generate through the Waitaki Scheme as we do the water above. 518 meters, Transpower has released what is sort of a -- was a fairly positive proposal.

They propose to increase to some extent, the buffers, which is shown on that graph there to push up the point at which access is granted. But the currently proposed buffers are probably insufficient to give us the confidence we need to change in any substantial way the way we generate and use more of the range in Pukaki, i.e., there's still a risk in our view that when access to contingent storage is really needed, it will not be available. So we're pushing them to go further, and we will have to wait and see how that turns out. Separately, by way of a completely different process and the way this works is the relevant, the relevant restrictions are contained in our resource consents. So our resource consents say we can only go below 518 meters when we -- when Transpower says you're at the 4% risk curve. So there's two ways to attack this. One is to push Transpower to properly model the 4% risk curve, we would say, and to draw it at the appropriate place. And if that's done, we can get access that way.

And the other way is to have the consent conditions actually removed from our consents, and we're pursuing that route as well via the Fast-track. Humphrey is going to talk later about the Fast-track process. And that would be for the next 3 years, temporary removal of constraints on contingent storage while we -- while the market moves through to a point, where a number of the projects that are currently being built come online, and there's less tightness in the supply-demand balance, if you like. That's all I was going to say on that.

This is my last slide. Obviously, as we look ahead to the election next year, it feels like electricity is going to remain in the spotlight for no other reason than as a reasonably chunky components of the cost of living that everyone faces. So to the extent we are looking at a cost-of-living election next year, electricity will remain a part of that. New Zealand first have signaled that they will go to the '26 election on a platform of renationalization and vertical separation of generation and retail. At the other end of the political spectrum, the ACT parties wants to see a further sell-down of the power companies, greater use of thermal plant, and even removing barriers to nuclear generation.

A number of the other parties we're still waiting for details with their proposed policies. But the balance of perspectives and what exactly is going to win out in any future coalition party or coalition government remains uncertain. At this stage, as we look ahead to Winter 2026, the outlook, as we've illustrated on the right there, is currently looking pretty positive. The continued operation of the third Huntly unit, the full coal stockpile they currently have sitting there and currently pretty healthy lake levels means as we sit here right now, the SO, the system operator is looking pretty low risk for the next [indiscernible] while. But obviously, a lot will depend on rainfall or lake thereof in the first half of next year.

Another important factor is Meridian gets access to our larger demand response options. We've been on a stand-down period with NZAS. We haven't been able to call those for some time, but those come back online, I think, in April, May next year. So to the extent there's tightness, those large options are available to us. An important factor that will keep the sector in the -- in the spotlight, if you like, in relation to cost of living is there are another 4 years of regulated price increases to come, sort of 3.5% to 4% on average, I think, from the -- just from the regulated side of things, even if we impose no price increases on our own.

And you add that up and cumulatively, it's a chunky amount to come. So this means -- me and my team have a lot to do in continuing to engage with regulatory political stakeholders right across the spectrum and try and ensure they have the facts they need to make good decisions and that they are appropriately focused on the long-term interest of consumers. I think that's all I was going to say. Has anyone got any questions? If anyone is going to ask me about what was it? Enable the MoM companies to raise equity with expectation. These companies seek out and bring forward opportunities for new generation. I'm just going to punt the touch and hand that over to Mike. So maybe I had that one off right now. Yes.

Just one quick question. So that EA gave an estimate of $2.2 million. This is a levelized playing field cost, $2.2 million in the first year and $0.9 million thereafter. Has Meridian done their own internal estimates of what the costs might be?

We haven't. I have to say, looking at that, that feels possibly a little strong, but they know more than us, and they're going to consult with us further in the next [indiscernible] while. So those -- this will be a significant reform. Those numbers don't look crazy to me, but we haven't done the work and we won't until we get a better handle on exactly what they have in mind, and there's a lot of details still to be worked through.

Just a quick one on the contingent hydro slide. Your consumer benefit of $527 million each year. Just wondering sort of what makes up that bucket? Any sort of big components you can break down in that?

I don't know that I can. Rory might be able to talk more to the modeling. But essentially, we've got a range. The maximum -- the max at the top of Lake Pukaki is, I think, 532 meters. I'm going to get these numbers [indiscernible], 532 meters, 533 meters. The bottom is 518 meters. We are very cautious. We don't ever want to -- so the bottom before you hit contingent storage is 518 meters. We are very cautious. We don't want to be pushing against that 518 meters limit and find that access is not available, and we can't generate. That gives us a real problem.

So if you look at Meridian's corporate history, we've always generally stayed above 520 meters. We've left a margin there to make sure that, as I say, there is generation there, and we can keep generating right through any dry period even as things look increasingly kind of dire and tight. If we are confident that we can access contingent storage, it will give us the confidence to use that full range to go from 532 meters right down to 518 meters and even perhaps below. So effectively, in a sense, the lakes are bigger, and we can just generate more right through the year. We're not holding back in anticipation of a dry winter or as things become tight, if that makes sense.

Yes. Just thinking it's a pretty good story to tell of, I suppose you're trying to get this across the line and convincing New Zealanders and regulators that's a good idea.

Yes. We're doing our best. We've certainly told Transpower. We put that $500 million number in front of Transpower, the electricity authority, all sorts of advisers, [MB] people, I think, sort of their eyes glaze over when I start to mention the number. I've bought on them so often about it. But I totally agree. It's a massive saving for consumers and why we're not doing it or why we haven't done it sooner is something I struggle with.

[Audio Gap] Just a quick question on the level playing field measures. I mean it could be quite a potentially large change to how generator retailers operate. Is there feedback going to the EA that the implementation date in mid-2026 is just isn't feasible?

Not at this stage. The feedback is more sort of focused on the substantive -- what do they substantively propose about which we're still -- there's a bit of detail to work through. Depending on what the final form of it is, I don't -- I have to say I don't think that's crazy. I think we could do that, so we'll just have to see.

[Audio Gap]

[Foreign Language] I've got the privilege of leading Meridian's autumn generation team and our outstanding portfolio of what we think is New Zealand's BESS generating assets. And with me today is [Yanosh Irani], better known as Yani, who I've recently appointed into a new role leading our initiative to digitize the generation business, and he's going to talk a little bit about that with me today. So last year, which I think was the first year generation stood up and talked about operations at an Investor Day, and I talked a bit about our generation business transitioning from a focus on cost optimization and asset life extension, which is still really important, obviously, but to a broader strategy, which included growth from our existing assets, flexibility and innovation in our maintenance practices, all the while continuing that focus on asset health and reliability. And this change was sort of -- it was driven by the rising electricity demand, the need for more dispatchable, flexible capacity as the energy landscape is evolving in New Zealand. And that made it increasingly harder to get access to the assets to do the work that we need to do. So we had to get clever and innovative about how we actually did that.

Our hydro and wind fleet are iconic. They're supported by very skilled teams and really robust planning. In recent years, we've completed some significant upgrades, remediation. We've ensured high availability and reliability despite challenges such as transformer failures. I don't like to say the [ T-word ] too much anymore and increased maintenance needs because the hydro assets in particular and some of our older wind farms are aging, and they need more work on them. We've also brought 2 new assets into the business this year from my dear friend Guy and his team, Harapaki Wind Farm, which has seen exceptional availability of 99% plus most months, which is outstanding. And more recently, our grid scale battery at Ruakaka.

So the generation business back in 2023, we set a clear goal. We wanted to deliver 300 megawatts of new capacity from our existing assets and return 200 megawatts of parked capacity by 2028. And that 200 megawatts of parked capacity, I think about a month later from that baseline date, Yanni, became 328 when we lost another Manapouri transformer, so that was pretty frustrating.

And that strategy is sort of underpinned by those 4 pillars that you can see here. Growth and flex. How do we focus on asset health and reliability and also grow the capacity from our assets. For a long time, the generation business was quite divided over. It's one or the other. And what we've done as a leadership team has really said, actually, we need both, and we need to do those things really well.

Operational excellence, obviously, and part of that, what Yanni will talk a bit about is actually digitizing generation and getting improved productivity out of the assets.

Climate action, very important. A lot of the half by 2030 halving our climate emission sits with generation.

And people and safety, obviously, is pretty important.

So our progress in performance has been pretty solid since then. Part of our transformation, which was an operating model change and sort of rethinking our practices, we've delivered 112 megawatts of new and increased capacity so far from the assets with further hydro uplifts and upgrade investments in the pipeline.

And the team's efforts have resulted in increased output and increased revenue at a very low capital cost, less than $2 million, we achieved that 112 megawatts, which is outstanding. And I very unfairly say compared to Harapaki, which for a little few more megawatts cost $450 million. So you can really see the value and just really applying some good thinking and innovation to our existing assets.

Most of that work because the reason it was low capital cost it was just good engineering studies and reviews and changing some constraints. There's also been some further operational changes to reduce our outage days, and that's delivered some real value and choice to the business. So to date, the team has removed more than 200 outage days permanently from the system, which is an outstanding achievement and it hasn't increased the risk and it hasn't compromised safety.

And there's been some challenges along the way. As I said, technical complexities like transformer gassing have been really irksome. They've impacted time lines on some of our projects, but they've also driven some innovation across our portfolio on other projects to sort of optimize some of the downtime, which has been fantastic. We're committed to still delivering the 300 megawatts of new in the 200 megawatts of returned by 2028.

And I guess with all of that work, there's been a big cultural shift. We've invested quite a bit in our leadership capability. We've driven a real cultural shift in the business. And with that and the operational gains we've achieved, we're sort of now ready to accelerate our transformation to a more fulsome digital program. And Yanni will talk a bit about this later, but we believe we can deliver $25 million to $45 million of value back to the business. Yanni will talk a bit more about that, but that's a mix of O&M efficiency but also increased availability. So that's pretty exciting.

This slide here talks a little bit about our strategic investment pipeline, and Owen will talk in the next slot about capital expenditure and sort of deep dive into this a little bit more. But every year, the generation business would probably invest about an average of $15 million of stay in business CapEx on what we call core or recurring projects, and that's to achieve things around asset health, upgrading equipment, maintaining compliance and safety. And then additional stay in business CapEx will be committed for what we call periodical priority or lumpy projects that are very large, often multiyear, very complex. And these projects occur maybe once in a decade or once every 40 or 50 years. They generally extend asset life. They improve asset reliability and performance. They strengthen seismic resilience because there's a lot of value, as you know, sitting in concrete and steel across our asset portfolio. And they modernize our plant.

And we generally have discretion on those projects in terms of timing. And the amount that we spend has ranged from, say, $10 million in FY '24 to $30 million in FY '25 with an uplift this year because we've kicked off the Benmore penstocks, seismic strengthening, which Owen will talk about in the next section.

But what you see on this slide here is what we're calling our baseline view of what those periodic projects will look like over the next 10 years. Not all of them are fully costed yet. But the baseline here and has been for many years, informed by good engineering practice and standards. You should generally replace your turbines at about 45 years old.

What I'm really excited about with our digital generation program is that it will provide us with alternative views of that baseline, what work could we push out? What could our data tell us about asset performance and a more comprehensive view of actual time to intervention versus a conservative engineering standards type view? How might we better optimize the timing of the work to maximize revenue opportunities versus our traditional approach of avoid winter and don't have any more than 400 megawatts out and we should be all good. How do we get a lot more granular and refined about flexing and valuing where we might do work?

And we're going to be using data to better predict asset failure to finesse how we might time and prioritize that work. So you'll see there, there's 3 kind of buckets. There's wind, hydro and the sort of what we call civil and seismic resilience. You can see the wind one here. Obviously, Guy's team. We work very closely with. Our focus in generation is around what we call end-of-life studies. So when you sign the contract for the wind farm, it will have a certain life. Towards the end of it, we get the OEM to do a study and say, right, can we get an extension? And we did it for Te Apiti. We got 10 years out of it. So it's really valuable. It's very valuable to keep running those wind farms as long as you can. We're currently undertaking those end-of-life studies for White Hill and West Wind. So that will tell us how much longer beyond the data on return can we get out of that wind farm.

So I will now hand over to Yanni to talk a little bit more about DigiGEN.

[Foreign Language] I think Tan has already introduced me, I'm Yanosh. I've been at Meridian around 9.5 years and in a number of roles. And the part of my job that I enjoy the most, and I get to talk to you about today, is deploying new technologies that support our people to look after our aging assets. And this is a really interesting area to work in because you can deploy technologies just for the sake of them, but what we're doing here is trying to target it towards value.

So the first thing about this is what is the value? What is the size of the prize? And when you're trying to do an assessment like this, it's pretty good to get an external perspective. So just like our retail team did last year and they told you about with their base camp program, we're in a similar sort of space with the digital generation program. So we've got McKinsey consultants, and this is their view of the size of the prize in our business in generation. And the value pools that we're targeting with this program are in a few areas. So the main one is in a reduction in our costs and an increase in our revenue. Now that revenue increase, we're looking at monetizing that flexibility and availability that a few of the previous speakers have talked about.

You heard Rory say there's a lot of value and flexibility. You've heard Lisa highlight all the work they're doing to shift demand out of peak times. We're trying to do the same thing, and we're trying to do it with our downtime, so shift some of our downtime out of peak times and into areas where the prices are low.

And the other part which Tan has talked about which we're targeting is to find alternate scenarios for our stay in business CapEx spend. So currently, our one is quite conservative. It's a world view driven by fundamental engineering principles, and we believe we can do a better job by informing what work we do and when we do it using as much hard data as possible rather than some of our historic practices. So that's what we're going after.

And the next thing I want to talk about is how we're doing it. So we've got a 4-year program, which we've just kicked off about 8 weeks ago. So everything I'm presenting to you is pretty hot off the press. And a big part of how we're approaching it is we're leveraging what our retail team did.

And I'm hoping that next year, I'll be able to stand here, just like Lisa did, and tell you how that's how that's grown and what impact that's had. But we're already seeing some of the early signs of the sort of experiences that they had and leveraging a lot of the same resources that they used.

So the sort of areas we're focusing on is how can we inform the work that we do on our assets and drive that work and trigger it more with data rather than some of the traditional ways we've done it, which is usually a calendar, something as we've done every 6 months, every 1 year. Tan has mentioned stuff that has to be done every 45 years.

Another area that we're investing in is how can we optimize our outages? So many years ago, probably 10 years ago, we optimized how we use water. So a lot of you would have heard of Mercury's Digital River project. We've been doing that for the last 10 years with our hydro optimization tool. So now everybody that sits at a Meridian control desk and controls the water flow through our Waitaki system does it in exactly the same way.

And all the improvements that are made to that approach are made consistently across anybody that sits at their desk. We're trying to achieve the same thing with the way we schedule our downtime.

And the guidance we got from McKinsey, who came in and gave an external perspective, is that there's actually quite a bit of value in that. And that's their view. And through this initiative, we're looking to try and validate that.

The other thing we're looking at is where we feel we'll get the most short-term gains is in our procurement. So we buy a lot of stuff across the generation business from a lot of different suppliers. So we're looking at using, I guess, the data on our spend and to understand our buying power and then to leverage it. And that, we feel, is going to deliver a lot of value early on that we can then recycle back into this program for further improvements.

And overall, there's this sort of general theme of shifting the way we do our maintenance work. If you look at it on a bit of a spectrum from how sort of your family car mechanic works, you drop your car off in the morning and you pick it up in the evening, to more like a Formula One pit crew where we shut the plant down for exactly the amount of time that we need to shut it down. And everything we do to their plant, we do it based on data that we've already seen before it comes in.

So that's our approach, how we're going about it. And I can give you guys some examples. So in the last 8 weeks, we've been traveling around the country talking about this program. So a lot of our people at different sites, collecting ideas from them. And I'm pleased to share some of them -- some of those ideas with you today. So we were just at Manapouri the other day and we've got people telling us, I have to walk around and check these gauges.

And that's a really good example of the type of manual work that you get in a utility such as ours. Lots of similar businesses would have inherited those sort of maintenance practices from their predecessor companies and cultures. And here, we got our people themselves saying, look, I've got to go and check this gauge. I've got to write the data down and I'm going to go back and type it into a maintenance system. Is there some better way we can do it?

So in a short space of time, we've gone and put in sensors that collect that data automatically. We've used the same data platform as our retail team is using to pull that data to our analysts. They've quickly developed analytics that can make sure that, that data finds the right person at the right time.

And in the hardest part, the part we actually work on is the cultural change to be like cool, how can we change our behavior to deliver that value back to the business in the form of that's increased time available to do something higher value? And what we're finding is this is as much a cultural change as it is a systems' one within the generation business.

So in the short space of 8 weeks, we've found and actually tried and implemented ideas that have saved time, they've saved money and they've involved technology investment that we are going to leverage and reutilize on an ongoing basis going forward. We've really learned how to pull those value levers where you are actually reducing downtime. We're reducing the time taken to do outages. We're reducing the time in our maintenance system required to actually conduct tasks and manage the risk that we have to manage. And lastly, we're also really focused on, through these initiatives, proving out and validating whether we're going to see the lagging indicators, which are the value pools. Are we seeing the reductions in OpEx? Are we seeing those alternative scenarios for stay in business CapEx? And that is effectively further funding for this program is contingent on us proving that value is there.

So yes, that's -- I think our current investment, we've got this year is about $4 million. We're looking to generate a return of about $2 million at least on that. And the early signs is that, that value is there. And then basically further funding on this program is contingent on us actually proving that, that's the case going forward.

So yes, I think that's all we have to share with you today and happy to take any questions.

The Waitaki replacement looks to be one of the larger items on the maintenance slide. Any idea of cost for that at the moment?

Yes. So [ Mark ] is actually working on it for us at the moment. He's sort of -- we're aiming to hopefully get to FID next year. And costs at this stage, Mark, is that $300 million, $400 million, I can't remember?

[Technical Difficulty]

$400 million, yes. What we've chosen to do with that station upgrade and actually, we've had some good conversations with Mercury and kind of -- they've got some good learnings from Karapiro. And one of the ways to derisk it is to -- is everything from heat gate to draft tube brand-new, don't try and integrate new stuff with old stuff and make yourself a big mistake, and it will cost you. It's cost them a little bit on Karapiro in terms of issues they've had to sort out with old automation trying to integrate with new kit.

The bits that we will recycle obviously, is the civils because it's pretty expensive. And we would only adjust the civils if it was economically worth it, which Karapiro did. There might be a, what's it called?

The draft tube.

The draft tube because it got more capacity out of it. But other than that, you don't want to do anything with the civils. There's a little bit you can see on the seismic resilience, the Waitaki doing uplift management. There's a little bit of what we need to do on the Hornell Gallery, we have to strengthen it.

So it's like when you renovate your house, if you piles need a little bit of work, it's important to do that before you spend a whole lot of money on renovation. So there's a little bit of that, that we'll do concurrently, yes.

Just to clarify, you mentioned you spent $115 million on core SIB CapEx. So these projects are obviously on top of that.

These are over and above. And the sort of core recurring average of $15 million is the stuff you're generally having to do every single year. And it's mainly on hydro. The wind is pretty OpEx hungry. But these are over and above, and we sort of had some choice around it. And the choice is really driven by timing. So that's part of the DigiGEN. Actually that was actually how do we kind of stretch that timing out and create more choice for ourselves and increase that flexibility we have on the discretion.

I'm not sure if it's coming up later in the presentation, but is there a SIB CapEx pathway over the next few years?

Yes, Owen is going to talk about, yes.

Okay. Cool. Thanks.

It is a great segue. Owen, over to you.

Kia ora. It is a great segue. Credit for the person who planned the agenda. Hopefully, it's obvious to you that I am not Mandy Simpson, nor am I the CFO. Unfortunately, Mandy has laid up in Wellington with something called COVID. Who knew that was a thing. But she is listening in, so Mandy, kia ora and best wishes for a speedy recovery.

I had this session of mind because we quite often get asked about our stay in business CapEx even as most recently as 30 seconds ago. I thought it would be a great idea to put someone up to talk about it. I never envisaged it would be me.

So welcome to a session on stay in business CapEx. And the question we usually get is why does it keep going up. Before I get to that, I just want to talk a little bit about what it is or isn't. And in very broad terms, it's the capital expenditure that we make or choose to make to maintain both our asset base and our systems.

Now the great thing about stay in business CapEx is there's no formal definition of it under accounting standards. So our stay in business CapEx may be quite different to some other large electricity generator, for example.

Typically, what goes into it is the investment into asset and technology life cycles. Think about things like major repairs or replacement of components that extend existing asset lives. To be very clear, what it does exclude is asset investment that we make that either adds new or additional installed capacity into our portfolio and results in higher generation output. That for us is growth CapEx.

There are a few wrinkles or uniqueness about it. One is in relation to wind. So same business CapEx excludes major wind component repairs. So we'll recognize and capitalize the 2 main components of a turbine, which is the turbine itself, everything above the ground. And the foundation, which is everything below the ground, excluding the cabling.

Any repairs we make to components of the turbine itself over the life of a wind farm asset are treated as OpEx. So you won't typically see a lot of wind stay in business CapEx. Why does it matter? Well, it's a component of our operating free cash flow. That's the basis by which the Board pays a dividend on. So it does have a direct relationship with the yield that we're able to produce. And it's a factor in how the market values Meridian, but also how Meridian values itself. So Rory's team do a lot of work with Mandy's team around an annual accounting valuation of our asset base, which can result in quite large swings.

And yes, it's going up or has been going up. So I'm just going to step through a few of the components. But as Tan has alluded to, we are trying to frame up our stay in business CapEx along the lines of that, which is reoccurring, and that which is periodic. And I'll just mix and match a bit between the 2, but just touching on a couple of points.

Our dramas with our Wellington corporate office on the Queen's Wharf waterfront are pretty well known, as has been our long-awaited move into new premises in the Old Bank Arcade. And we made a significant investment in our people to provide them with what is a world-class office, I think. So -- and that's had tremendous feedback and sort of positive engagement sentiment.

So you will see periodic property investment by Meridian. We are moving into downtown Auckland offices. We are planning some refurbishment of the interior of our Christchurch offices. So there is an ongoing program of work there. And we put more and more charges into our assets. So those sorts of costs come through.

What you might not know is Mike runs a forestry business. Not necessarily for the product, but we're building a carbon sink with the intention of being able to offset our residual operational emissions beyond 2030.

Now what that means is we'll build and manage and maintain a continuous forestry model, where we will steadily transition away from what is predominantly early planning of exotics into more native timber over time and achieve a much better biodiversity outcome in our portfolio.

At the moment, that's about 14 planting projects. We've got 750 hectares of forest recognized in the ETS and we'll add another 250 hectares of that. What that means is currently, we've got about 8,500 credits per annum in the ETS and we're looking to almost double that from 2030 onwards. And I think we're unlikely to stop. So we're currently considering further afforestation initiatives. So you are likely to see forest creation as an ongoing line of stay in business CapEx.

SCADA, I'll talk to in a little more detail later. Flux, obviously, is an investment, ceases with our selection of Kraken as a technology partner.

Tan has touched on generation investment on a reoccurring basis. We had the same thing with IT. So there's just an ongoing program of work about improvement replacement, cyber resilience of a complex set of systems. Again, that kind of level in the mid-teens is something you can expect to see going forward.

Vehicles for us is an investment program that's part of a long-term commitment to 100% EV fleet. We've got close to about 100 either pure EV or hybrid vehicles out of a total of 150 passenger and commercial vehicles currently. And we're aiming for full electrification by 2028. That is a challenging target. Not so much for passenger vehicles, we are at 100%, but the New Zealand market is still very limited for commercial pure EV models. And we imposed some pretty strict safety conditions. So some of the 4-wheel drive requirements that we have aren't yet met by available stock.

In relation to periodic generation, I am going to mention the T-word. It's -- we've talked a lot about our transformer issues. But that cost will continue to hit our business until we are through a full replacement of transformers. We are having an ongoing discussion with the provider of our transformers around the situation we're in.

I'd love to really tell you what wicked gates are, but I think there was a picture at the start of Tan's presentation. But essentially, there are adjustable veins that sit around a hydro turbine that control the flow of water. They are reasonably important pieces of kit.

Manapouri automation is a long-term project doing what it says on the [ TIN ], which is automating control systems and operating systems at Manapouri. But if I stand back from the CapEx picture, yes, it's more than doubled in the last 5 years. But within that 5-year period of spend, we are doing a 1- and 10-year SCADA replacement. Property investment and Manapouri automation that probably occurs in the 20-year time horizon. Transformers are meant to last something like 40 years. And Benmore penstocks is a once almost in a lifetime project.

So that's what it's looked like. What it's going to look like is a likely peak this financial year. And then for the first time, we're giving you some direction around where we see it going in FY '27.

So a lot of the inflow programs will continue -- will reach a natural end of transformer replacement, hopefully, for a very long time. But we'll also add into FY '26, some other periodic generation projects at a number of hydro stations and at the Manapouri Lake Control facility.

What I would say as a general guide is that we expect to see all recurring expense. So generation, IT, corporate, property, vehicles, et cetera, probably falling into the medium term $40 million to $50 million bucket. And then just depending on the decisions we make around periodic spend, so reference back to Tan's slide on strategic investment. That might average out over time in the order of $20 million to $30 million. So broadly and as an indicative number over time, probably in the $60 million to $70 million of stay in business CapEx, caveated by the fact that some of this periodic investment will turn up in significant chunks.

And if you take the example of Waitaki station replacement, it's likely to be both growth and stay in business CapEx as we get into the project. So we won't suddenly hit $400 million of stay in business CapEx in 1 year.

A little bit of a dive into 2 current projects. To monitor and control our generation assets centrally without the need for having operators on each site, we use a generation control system using SCADA technology. It's a reasonably standard thing globally. It does reach end of life in about a 10-year period. So we've operated the Siemens system since 1998. The last significant spend on that was completed 12 years ago.

So we're into a new system or new investment in a new system from Hitachi. That will total about $55 million. We started that work late in 2024, and we're aiming for go-live in 2027. And the very best project outcome is that no one notices we make the change.

And it's progressing well. So the key elements of the system are tested. We've set up a security facility in Twizel and we are doing a bunch of work along with third-party organizations, including PwC on a continuous review of the work that we're doing.

So it is complex. There are testing delays and integration challenges along with it, but we're pretty confident about the mid-2027 deadline.

The second project, I just wanted to lift the hood on a little bit is Benmore penstocks. I actually sit on the project steering committee for this. And it's not because I bring an enormous amount of unique engineering experience. After each monthly meeting, I usually go and have a lay down. So what I'm going to do is being Mike Wright into the room. He's our project manager, and he's going to give you a little bit of a flavor for what we're doing with the Benmore penstocks.

[Presentation]

So back, Benmore was built for economic and labor reasons and a bit of key ingenuity, we bypassed the steel option in terms of penstock construction and elected prefabricated concrete. I guess New Zealand seismic maturity has evolved since those penstocks were built, and it now looks a pretty interesting choice with the benefit of hindsight. It does give us a fantastic engineering opportunity to improve the seismic resilience. And without steering the horses, a 75% chance of a magnitude 8 or higher earthquake on the Alpine Fault in the next 50 years. The whole country is operating under that risk. It's not just a Meridian-specific one. So it is going to happen.

It's just a question of when. So what we are really doing with this project is ensuring that we can seismically shore up the risk to the penstock so that we can get Benmore up and running in a large quake. And the reason for the focus on Benmore is it obviously sits at one end of the high-voltage DC link between the North -- South and North Island.

So we can power up Benmore and get that generation north. And typically, with our hydro stations, the structures have a very high level of resilience to earthquakes, but our investigations have revealed that the concrete penstocks are a critical vulnerability. So we've done an enormous amount of work on this project without having actually changed anything yet.

But what we have plotted is a way through that complex engineering so that we are able to minimize outages. What that will mean is that we will replace bearings essentially without a station outage, and that's 636 replacements will avoid close to 42 months of station outages doing the approach that we're doing.

It will cost us on -- depending on the current design, probably in the order of $110 million, $111 million. Don't hold us to that number because we are not yet at final design stage. The first question I asked when I got on the project was why don't we just replace them? And without doing any deep financial analysis, that's probably $0.5 billion and 8 years of a station outage.

So I've already asked my dumb question on the project on the first day I sat down. So it's likely that we will business case this with our Board probably early 2027 once we have completed the detailed design and we've got more cost certainty. And then the project is probably likely to be carried out from that point, culminating mid- to late 2029.

And that was really it. I'm loath to ask for questions, but please. And I bet the big first. I'll just put a caveat and I may find a friend actually and divert quite a few of these over to Tania because she's the gatekeeper to the decent chunk of our stay in business CapEx.

A quick one. Just a little bit more color on the FY '28 and '29 numbers sort of talked CapEx in FY '26. I just take Waitaki's number of $45 million and $35 million based on $10 and then add on $70 million per year for the Waitaki [indiscernible] so just wondering if that's the number on average for the next 7 years. .

I think your Waitaki's numbers are a bit hot. So some of that will be growth CapEx as the replacement spend effectively builds further generation capacity out of the asset. So I think we're reasonably comfortable with where we kind of touched the longer-term view.

That obviously is the most significant project on Tania's pipeline. So it has the potential to move our stay in business CapEx around a bit. But I think what we will do is continue to put forward a consistent view of spend that's reoccurring and then specific projects that are periodic. So you get a bit of flavor for it.

Do you know how much of the Waitaki is growth?

Not yet. When we do, I think we'll provide some direction on that. Mike is probably a better position to give you a sense of the type of spend that goes into it or that will go into it. But it's pretty early days on that project [indiscernible] is going to ask me a question.

No, not. Just to add to that on the 1 page sort of investment pipeline you saw for generation, you might have noticed there's a couple of Ohau pieces of work. So the Ohau A and then B and C, you might remember a few years ago, we started a refurbishment to extend the life on Ohau A. We did 2 units. And then with the smelter issues, we sort of pulled out and pivoted to Manapouri. So those 2 bits of work might not be a refurb. We might do upgrades.

We're just doing a study at the moment. So as with Waitaki, some of that might be growth. You can see there the team is sort of saying we might get 80 megawatts additional uplift across those 3 projects, Waitaki and Ohau chain. We're just yet to quantify that, but some of that will be growth as well.

Excellent. Thank you.

[Foreign Language] I'm Meridian's GM Development. I've been in this role for nearly 5 years. So it's -- I feel very fortunate. It's a fun role to have. It's one that there's a lot of scrutiny within the company, but also externally around the industry's ability to fill the void that's been left by gas and to accelerate our run rate. So it's a lot of fun doing that.

I have -- I've got 3 of my crew here. Rebecca -- she's our Head of Renewable Development, responsible for the front end of our pipeline, making sure colloquially, we're doing the right projects. Chris Moore, the back end, you would have met him yesterday after your [indiscernible]. And similarly, doing the projects right. And then Murray is going to talk later about hydro dev, so I won't steal his thunder.

We're about 70 people in Meridian now plus a bunch of contractors. So we've really put our money where our mouth is around this, and it's great to see the new generation of young people coming through the sector in the dev space. It [ Te Rahui ] in the kind of heat of battle, they're learning a lot and they're growing and developing. It's really fun to watch that happening. So the purpose of my presentation is to take you through some numbers because you all like numbers.

A few years ago, when we set up our team, we, Meridian, is 30% of the market. So we thought what's the aspiration? What's our responsibility in terms of growth? And consistent with our market share, we came up with this tagline 7 x 7, which was a proxy for kind of gets it done. We had no idea what the 7 projects was going to be apart from Harapaki. That was our only development option that we had in our portfolio in those days. So the rest of it was wait and see.

So now we've got a really clear view of 7. I think -- and I think by the time you get to this, you'll see we will outperform that number by a decent margin. So the executive summary in construction or constructed, so constructed is Harapaki and construction is Ruakaka Solar, Te Rahui Solar, that's our half of the joint venture with Nova and have also included the Tauhei Solar farm because we're taking all the offtake of that solar farm.

So between those 2 in construction, we've got 1.25 terawatt hours of new generation coming on. Consented, we have Te Rere Hau, we have Mt Munro, and we have the second phase of Te Rahui. So combined, that's another 1.3 terawatt hours of new generation. And contrary to what some people might say externally, we're pushing all of our consented projects to fit. So I'll talk about that a bit more on those slides.

In the consent, we've got another 3/4 of a terawatt hour of solar projects. And then behind that, we've got a couple of real big projects in Waiinu Energy Park, that's a wind and solar play and also Western Bays solar. I'll talk about those as well. So you quickly get up to a number. It's hard to move the dial in Meridian because it's such a big base.

But by the time you get through that first phase, there's 3 terawatt hours of projects we can actually look and see and touch. And then the ones going to the fast track takes us up towards 5 to 6 terawatt hours. So it's a big numbers. Okay.

Let's start with the built ones. Harapaki, you guys will be familiar with Harapaki, many of you will be. It's just done a year, and we do -- after a year of everything that we've run, we do a post-project review. Pleasingly, this is the best project Meridian has done in the wind space. It's hitting its numbers tonnes. It's hitting great availability. The Siemens machines are fantastic. We've rated up about 3% of its P50 output to 558 gigs. Its revenue is up 50% on the business case. So she's paid off a student -- a big chunk of the student loan already, which is also very pleasing.

And that's despite us sharing some of that revenue back with Siemens to encourage them or incentivize them to get that project to hit an accelerated time frame. We actually hit our original time frame on that project despite Cyclone Gabrielle and other events we navigated. So pretty proud.

The Ruakaka Battery, we commissioned that in May. We've had a couple of equipment issues to fix, and we're through that now. Then we've had a period of where a peaking plant doesn't really like the market as in lots of water, lots of wind, not that much volatility. So we haven't really got to see yet how this asset will operate as a real peaker. It's different than an energy producing machine.

But the pools of value for the asset are, firstly, arbitrage, charge low, sell high. The reserve market, it participates in the reserve market, so it gets reserve revenues, but also Transpower to allocate through the TPM to Meridian, a decent chunk of HVDC reserve charges. So us being in the reserve market is reducing reserve market costs, but that's also reducing the cost we pay on the HVDC reserve charges.

North Island portfolio hedge cover. So this is kind of ROE space, but to cover our portfolio, the wholesale team by cover peak cover usually. So the fact that we've got a battery available to cover peaks means we can reduce our hedge cover. And then there's the stuff that you guys can't really see, which is the tighter connectivity between our South Island generation portfolio and the North Island market.

So those are all the sources of value that we attribute to the best. So in construction, Ruakaka Solar, we're moving dirt now. The EPC guys are on -- the equipment is coming into New Zealand. So that will -- like solar does, that will start to take shape really quickly in the new year. The real pleasing part of this is because it's part of our Ruakaka Best Energy Park, we've done all the plumbing into the national grid. So the grid has been -- our grid connection we size for both assets. We built the substation for both assets, all the switchgears in place.

So as soon as these things come online, we don't have to wait for the whole grid connection process, which means first power in a year's time, which is remarkably fast. And as you all know, early revenue is gold for power projects. Te Rahui Stage 1, Nova are actually the on-site project managers for this project. So we've come in -- it's a JV. Rebecca and I are both on the JV Board on behalf of Meridian.

They had obviously had enough confidence in their partner to start construction before we hit FID. So that's why that project is looking a lot more advanced than you would think for the FID date that we took. So again, really pleased that things is up and running. And we both have to decide about Stage 2. But given the fixed costs that are going into Stage 1, that Stage 2 gets a free ride over, I think we're both encouraged or incentivized to pull the trigger on Stage 2 pretty quickly, which will take that up to a 400-megawatt solar farm. That's in construction.

So consented Mt Munro, which is just on the other side of the Tararua and Wairarapa, closest town is Eketahuna. That was consented in February. We've got the full 80 megawatts of turbines consented, which is great. The project economics look really sound. It's a Class 1 wind site, and we are working hard to take that to FID next December. That's a stretch target, but that's our target is to try to do that.

And similar to Te Reo Hau, we will look to put a package of enabling works ahead of that FID date because the economics look so good, which will mean when the project moves into construction, we get a really good clean run at the project site. Te Reo Hau, look, most of you, I won't go over this again. We've got a good run through with Chris Allen of the project yesterday. It is super energy productive.

This will be the most productive power-to-weight wind farm in the country by our kind of data. Capacity factor over 50%, that's unheard of. And I think we will do the -- we will probably do that 40th turbine, which will take the combined output up to 70-ish gigawatt hours.

In consent, we've got 3 solar farms currently in consent. It's one another that's just out of Christchurch. We got the regional consent last week, I think. So that's pleasing. We need regional councils and district council consent. So we've got 1 out of 2 for both the Swannanoa and Waikato, one is near Morrinsville. That's a plug into the local PowerCo network. So it's pretty easy, close grid connection. That's the reason why we really like the Morrinsville option.

So hopefully, we'll get the district consents on both of these. And they're of that size that we can kind of fit them into what we're doing around the rest of our portfolio. And the last one of this is Manawatu solar. We've got a consent for a battery at Bunnythorpe. We have got an option to purchase the land adjacent to that battery adjacent to Bunnythorpe substation. So a pretty simple plug into the national grid.

And again, the Energy Park idea, you get 2 assets for the same fixed cost of 1 transmission connection. That looks pretty economic as well. So if you kind of go back through Harapaki, Ruakaka BESS, the 2 we're building now, which is Ruakaka Solar, Te Reo Hau, that's 4 out of 7. Then you look through this, you quickly get to kind of close to 10 projects rather than 7 that all look in really good shape.

And following these guys is are the 2 really big projects within our portfolio. So why any wind farm, that looks to us like it will be Meridian's biggest wind farm probably ever in that kind of 300-plus megawatt scale, so a massive wind farm by any stretch, well over a terawatt hour and still has the space and we will consent the option to have solar plumbed into that as well. So again, it will be a substantial substation.

So if we can do 2 large facilities for that kind of transmission connection for the price of one, it really, really helps the economics for both. We should be ready to submit that by the end of the year. We've got one landowner to get -- to sign up to the transmission easement and then we are clear and all the paperwork done.

Western Bays Solar, we've got a little bit of work around landowner connection assets for the access to the national grid. But again, pretty large 400 to 500 megawatt scale solar farm on quite difficult unproductive land otherwise on the shores of Lake Taupo, and it's a part of the country where people are keen on retiring land from farming to reduce the nutrients into the lake. So there's a lot of good about that option as well.

Okay. So that's our kind of wind solar portfolio. A quickly touch on Waitaki reconsenting because our hearing wrapped up. Was it last week, Humphrey? It was last week. Times -- who knows where time goes. We had a really good run, a really good run, I thought, at the Environment Court. We had super high-quality evidence providers on behalf of Meridian. Largest RMA consent ever given the Waitaki first consent was done pre-RMA.

So it's a substantial consent and to only have one opponent as in Forest & Bird at a consent hearing that's that large kind of shows the work that was done prior to the hearing to get all the stakeholders in EV on the bus. So it's in the hands of the judge and the panel now. I feel good about it, but it's their decision ultimately. The Genesis Fast Track decision, even though that's a different construct, the concept is very, very, very similar. So we feel like that's a really good precedent for the Waitaki.

And finally, Jason talked about this a bit and Humphrey is talking about fast track. So I won't go into this too much, but we have got the Pukaki Lake lowering in the fast track. It's a 3-year ask for unfettered access to that contingent storage. And myself and another guy called Grant Telfer around, and we set this trigger, and we didn't -- we expected last year that, that trigger would have been triggered, and we would have had access to that water.

So a, it was surprising it didn't work and annoying, and it makes sense to kind of get rid of that in our view, for this interim period until we go through the next few years while all this new generation comes online. So that's our ask, and we're hoping we get a really good hearing. That's me.

Just 2 questions from me. First one on the -- was the Northland -- sorry, the solar project -- sorry, one second. Te Rahui, so Meridian's contribution to the equity $55 million, the whole project $350 million CapEx -- sorry, is that equity Meridian's contribution? And then that debt probably roughly 2/3 of the project, that's all off balance sheet. Is that how that works?

Yes. Look at Patrick. Yes. That was a plan. So...

So those sorts of projects with the PPA backing can get 2/3...

This is the Meridian PPA. So Meridian is underwriting the entire project. That was part of why we were selected. We offered to underwrite the entire project and tip in equity into half. So it looks pretty good. The banking process, I think, was pretty competitive.

Great. Second one on the Waiinu Energy Park. That's a huge amount of energy. I was sort of wondering if that starts to impact, I suppose, market pricing when maybe it's phased, but a huge amount of energy in that one project. Just wondering if that impacts -- start to impact a few things if all that's coming online at one time.

Yes. And look, who knows exactly how that will -- how many gigs or megas that will be. That's our kind of footprint going into the consenting process. That's possible we'll be pared back a few turbines here and there because it's -- these are really big. Yes. But it's not too dissimilar to Tararua. Tararua is a gig. So -- and that didn't really move the dial.

So we'll see closer to the time, and we'll see how things look and what makes sense. I don't think we'll do the solar and the wind together. I think that will be -- those will be staged for sure. But yes, it's good to have a bigger option. You can always walk back from that if you think it's a bit overcooked.

A couple of questions. First one, I guess, when we look at everyone's sort of development plans over the last few years, it would be fair to say there tends to be more delays than there are anything -- I don't think I've actually heard of a project coming forward. In terms of the time frames that we've put up here, what do you see are the risks to those time frames? How confident are you, I guess, about delivering some of the time frames here given what's happened, I guess, over the last 2 or 3 years?

Yes. That's a good question, as you know, Andrew. And we typically put up a bullish view of what we're trying to achieve. And when I say shoot for the moon or whatever, shoot for the stars and land on the moon, that's our kind of attitude with us. The Mt Munro piece is fully within our control. So as fast as we can work, that one feels okay. It's when things move outside of your control is when you start to get a little bit about timing.

Today, however, there's a few other counterparties. We've got this airways facility to move. We talked to you guys about it yesterday. That involves Palmerston North anyways. And we've got a lot of paperwork to pull together before we can do that thing. It needs to be consented and agreement with Palmy for the land and airways to move it. But we've got draft for all of those in place.

So yes, that's probably the one that there's a little bit of outside of our control risk and time. But it's going to happen because the economics are really, really strong. So -- and we do really want to get access to that full next year summer construction window. So we'll move even to make sure we can kind of hit by Q3 next year. Further out, these ones that are still in the -- these things are still taking too long to come out of a pretty benign projects.

On farm land, they're in the middle, [ Bunny ] thought you could say is come down the road, but in the middle of nowhere, you could almost argue. And things just take a bit longer than they should for everybody. So it's hard to kind of pick some timings around these guys. But again, they all look pretty good economically.

And then for the bigger ones coming through the fast track, that will be a first for us. So we're not really sure how long it will take to get through that. But as you go further out, you have a little bit less confidence in time, but the front-end ones, we feel pretty good about. But Te Rahui 1 is all consented. So that's just an Nova Meridian conversation on that one, but we seem pretty much aligned. Provided the current project is executed well, the idea is we would roll the existing OEMs through to the next phase. It makes the most sense.

And the second question, I guess, is just around the capacity to be able to build all of these. And it looks like, I mean, all these solar projects, for example, having consent around about the same time. So conceptually, they could be being built at the same time. Are you looking at potentially phasing things to make the management a little bit easier, move teams from one site to another, et cetera?

Yes, we haven't thought about -- I mean, the good thing about these solar projects is we've got 2 in play at the moment. So we're learning a lot around how to manage an EPC construct. It's actually great. We've gotten Nova doing the boots on the ground work for Te Rahui. It means we get the benefit of that, but we don't have to throw a team of, say, 4 or 5 people at it because that tends to be a constraint as the human capacity to keep an oversight of these projects.

I think these are the ones we'll be able to layer in to the bigger wind farm projects and to make sure we kind of optimize the way our resources are allocated across the team as a whole. So I mean, to get to the point where we've got choices and options around consents and when to pull the trigger will be a great place to be. We haven't been in that place yet. So it's kind of a good problem to have having more on your plate than you can eat.

Just a quick question for me. In terms of the sort of solar projects, would you expect to do those on balance sheet? Or does that sort of special purpose vehicle highly geared model, is that a preferred way to build Meridian Solar going forward?

No, I think we'll do them on balance sheet as long as Patrick's call that. I mean having gone through -- we will use -- this is my view, having been through that JV negotiation and how long it took and how expensive it was to conclude. That was worth it because the project is great. It's good quality. They're a good partner. It's a big project. At that scale, I don't think the transaction costs, I think they're a bit high for projects of this scale. And they kind of add the Fed end of the year to a development process.

So I don't think we'd want to take that on ourselves unless we really, really had to -- if we were going to do some kind of move them on in the future, I think we would do the front end and structure them in a way that you could move them down the track and derisk them. But yes, I'd rather not have to do lots of JVs.

I see you've got the Transpower design underway on the bottom of those as well. I mean how much is the Transpower process? Obviously, they're looking for staff. They've got a lot to do. How much do you think that is likely to be a roadblock to developing projects even if you had the consent?

Well, it's not the reason why we're getting them underway early is because we want to get them underway early. And we're trying our best to make sure they've got a lot of people coming at them. So -- and they're doing a pretty good job in my view in trying to balance the old world, which was here's a project every now and again to here's 100 projects in the queue. And they don't really have the luxury of going all these companies aren't real.

So these things aren't going to get done. They've got to be pretty straight up and down with what they do for who. So our view never to get them off your critical path, but get that part of your project off your critical path so that you've got all the levers of control around time frame. And we're prepared to spend the money to do that because we can.

Okay. Nothing in the slide pack on the hydro development team or any of the options?

Yes. Murray is going to talk about hydro development later. All right. Looks like we're done.

Thanks, everyone. Good news. We're running slightly ahead of schedule, so long lunch time. But we will kick off 1:15. So that's 15 minutes early. So that gives us a bit over an hour to entertain ourselves outside. So for those of you online, we'll see you back at 1:15. Thank you.

[Foreign Language] My name is Humphrey Tapper. I'm in the legal team I work alongside Jace and I'm the Chief Legal adviser and specialize in environment and property. I've been at Meridian now for close to 18 years. So it's been a good fun ride. So I'm very happy today to talk to you about Fast-track consenting and the journey that we have been on in relation to consenting in New Zealand. So after lunch, I know that we've shut the doors.

Apparently, I've got 3 hours. That's what Owen has told me. We're going to do a page turning exercise section by section. We'll delve into the detail. We'll pull out some of the cases, and then we'll do a bit of a test at the end. So look, what I'll be looking at doing is providing a bit of background context and then I'll be outlining sort of from my perspective, 10 key points. And just believe it, when I wrote this presentation, the government has come up with a new amendment bill to the Fast-track.

So that came out on the 3rd of November. It had the first reading on the 6th of November and submissions closed on that on the 17th of November. I think the media announcement was more around grocery and supermarket competition, but there are a number of quite important changes to that act, which are actually beneficial to the wider sector, which I'll cover off as well.

So first point, background, consenting, the journey, as I was outlining that we've all been through. The RMA is a beast, and it has become increasingly complex and protracted like it is very difficult to get things done. And I'm sure everyone in the room is aware of people and developments and things having problems in relation to that consenting outcomes. And that has occurred in the electricity sector as well that you're seeing from time to time.

What's happened is that across the sector, both developers and also NGOs and environmental advocates agree that the RMA needs to be fixed. Everyone is of that opinion that is up for reform. And the fast track enables some of that and when you apply for a consent, one of the things to bear in mind with nationally important infrastructure under the RMA, you don't get an easier ride.

The RMA, if you're looking to do an extension to your house, it's the same framework that applies to a nationally important piece of cat. And so we've always been pushing for a separate process. And that has occurred overseas. So for example, in London, if you're looking at doing a large development there, they have major developments in Greater London. So they have the Town and Country Planning Mayor of London Order 2008, which enables different activities, so large activities.

So if you're building more than 28 meters next door to the teams, you go through a different process. In Australia, if you're doing a major project or you're doing a state significant development, or you're doing a development within a priority development area, you go through a different process. So this is what this Fast-Track Act is actually aimed at. It is aimed at infrastructure, which is of nationally and regionally important.

There is also separately, we're anticipating the RMA replacement to pop out shortly. So we expect there to be 2 bills to come out, and they're running out of sitting days now. So the expectation is either in the first week or second week of December, there should be 2 new bills coming out. So they will have to be introduced to parliament and they will have to do the first reading as well in order to get it through before Christmas.

Those 2 new builds, what we are anticipating, what people are thinking is that there will be a natural environment act and also a planning act, and they will talk to each other. And that will be what will replace the RMA moving forward. Submissions would likely be open. Hopefully, they don't close end of January because no one will get a holiday. We're looking possibly that it may be to the end of February when people can actually submit on it.

But that would be the new tool across New Zealand in relation to work development. The next point I'd also like to outline is current consenting options. So just to provide a little bit of the state of play at the moment. So when you're looking at this, you've got various avenues in relation to consenting. So you've got non-notified. So your non-notified consent is your standard consent process within 20 working days. That would be the gold standard. If you can get something through non-notified, that's brilliant.

And the consents that Guy was talking about earlier, the regional consents, they were all processed non-notified. So that makes life a lot easier. The next sort of consenting process, if you like, would be limited notified. So that's where a number of individuals or entities are identified as being affected. And so you have a limited pool of people who are involved in a process. That would be your next approach. And then you have the publicly notified approach.

And so that's when it's full blown, it's in the paper. Everyone can actually put a submission on, everyone can participate. And the RMA is all about public participation. And so the expectation is that everyone will jump in there and put a submission in. Those are all 2-step processes. So they would all have a council hearing and then someone appeals it, you go off to the environment court and you can appeal that and go on, et cetera.

An alternative option is the direct referral approach. So direct referral is a one-stop shop. So you go straight to the environment court and you have one hearing in that space. And the reason why you do that is because of costs and efficiencies because you know you got too many people, you're going to get an appeal. You may go to just cut to the chase and go straight to the court immediately. It's a double-edged sword though, because it's a first instance hearing. You haven't teased everything out. So you're going to have to call probably more evidence than what would otherwise be the case.

The environment court process will probably take possibly a little bit longer, and you also have to pay for everything. You then have a call-in process, which the minister can elect to do. And then you have the private plan change, which is another process that we actually did at Meridian. We did that for lowering [indiscernible]. So allowing to go from 518 to 513. It was a prohibited activity, so you couldn't actually apply for a consent for that, but you could apply for a plan change. And so that's how it got embedded in the plan.

The next option at the moment, the current consenting options, you've got the Fast-track approvals Act, which I'll get on to on the next slide. And then you have special legislation. So when I say special legislation, again, an example of that would be the Manapouri - Te Anau Development Act 1963. So that's the piece of legislation, which enabled Manapouri to actually be built.

The other piece of legislation that people will probably be aware of is the National Development Act. So that was sort of in the [indiscernible] about think big. And so that allowed the pathway for those big projects to get approved. And you also have resource management, the Waitaki Catchment Amendment Act of 2004, which dealt with Waitaki in relation to water allocation.

And then you've also -- most recently, there has been the resource management extended durations of coastal permits for marine farms. So that's -- which sort of puts my interest because it's a rollover. And so all those marine farms that had to go off and get resource consents. I think there were something like I think it was 1,200 consents that had to be reconsented, 200 within that year. The government decided that they should all just be rolled over. And so it saved a huge amount of time and costs in relation to that.

What I would also outline as well is the costs in relation to consenting. So back in 2021, the New Zealand Infrastructure Commission produced a report, and they looked at 186 projects across New Zealand, and they found that $1.29 billion is spent on average in relation to lawyers, experts and council fees. So -- and that is quite high in relation to benchmarking within looking at all the OCD countries. What they also found as well was that the cost of consenting has increased 70% since 2014. So it's going up like that.

And the other thing they looked at is they looked at a cohort of 4 years from 2010 to 2014 and compared it to 2015 to 2019, and they found that the time that it took to consent increased by 150%. So what they found was that you're paying more and you're getting slower outcomes. And that was also one of the catalysts in relation to looking forward to having a review.

And this is the Meridian time line, if you like, in relation to our current projects. So the first project there, I'm not quite sure if you can read it, but you've got Te Apiti down at the bottom there. So that's actually a wind farm here, 55 turbines. That was consented at a council hearing that took 76 days. So this is in 2003.

I'm told that there was then a race between Te Apiti and White Hill. White Hill was consented a year later. Ironically, it took 76 days as well from the date it was lodged to the date they got the decision. The hearing time took -- they had a 3-day hearing for that one, and then things start to blow out. You've got West Wind, about 2 years. The next 3, you've got North Bank, Hayes and Mill Creek works out to about 4 years.

Project Hayes, it was council hearing approved, declined in the Environment Court and then we put an appeal into the High Court, and that was -- we were successful with the appeal, and it was remitted back to the Environment Court and then we paused it. Central Wind was a 2-stage hearing. So that was a council hearing then to the Environment Court. That's about 2.5 years or thereabouts.

Hurunui, that was a direct referral. It took a little bit longer because it's the first instance hearing. So you actually have to go through a lot more material. And then most recently, Mt Munro. So Mt Munro was also a direct referral. And look, there's no finger pointing in relation to this. This is just the process. This is just how long it takes and we're hoping moving forward in relation to fast track that things will get a lot better, a lot quicker and a lot cheaper.

The ones on the right there, the low ones, you've got the batteries and all those batteries were processed non-notified. So they took 94 days, 106 days, 39 days and 132 and the Ruakaka Solar regional consent that was appealed by Forest & Bird as one of the [ talents ], and we had a 2-day environment court mediation, which resolved that matter. But again, that one took 503 days.

So moving forward, the expectation is that things should get better. So fast track. It is quite a brutal and blunt tool. It is -- once you're in the process, everyone is working flat out. It's all hands on deck and you get one crack at it. You are not -- it doesn't reduce the amount of work that you have to do upfront. So your comprehensive environmental assessments are still the same. You still have to do all the heavy lifting. You still have to do all the work, you still have to have all the answers.

So it's not a shortcut in relation to assessing environmental effects. You still need to do everything that you can. So when this act first came out, it was only end of last year. And then it was paused for new activities. So new activities couldn't get involved on the fast track until the 7th of February. So it's actually quite a short time frame unless you were already listed, which we weren't. There have been 5 projects consented to date, and I've listed them there. So you've got the Wharf up in Auckland. They're saying that it's a $200 million development that one, which brings -- they're talking about 160,000 jobs by 2053 is what they're suggesting.

You got Maitahi Village, which is 180 houses down in Nelson. You've got another housing development, Milldale, which is 1,100 homes. You've got the Tekapo Power Scheme. And most recently, the Drury Metropolitan Centre, which is a 53-hectare development. It's looking at the economics were that it was going to $1.45 billion into Auckland within the next 11 years.

So these are the things that the Fast-track has actually gone through a process and these things have popped out now, which is particularly good and particularly helpful in relation to that. We're anticipating another 4 additional decisions before Christmas. There are another 24 still being processed. And just before I checked on the Fast-track site for renewable projects, I see there are 30 renewable energy projects listed in that schedule that will be looking to be progressed.

What's Meridian doing with the Fast-track? So we have earmarked 3 projects, which Guy spoke about. But we've got the contingent storage referral application, which was launched on the 5th of November, the substantive application that is, which is Guy Fawkes Day. Hopefully, that's not a moment. Energy Park and Western Bays Solar would also be perfect developments to go through that particular process.

They do -- the anticipation is once you get to the substantive stage, time-wise, on average, you're looking at -- it's about -- at the moment, it's working out to about 36 weeks for a decision to pop out. So it's a lot faster compared to the charts that I circulated earlier. Fast-track proves that it's a different purpose. It's a different act.

It's -- you look at the RMA and Part 2 is often described as the engine room because it's talking about sustainable management. whereas the Fast-track Approvals Act is designed, its whole purpose is designed to facilitate the delivery of infrastructure and development projects. So that's what it's there for, and that's of significant benefit because you can anticipate that all the legal submissions home back into Section 3 of the Fast-track Approvals Act and signal that this is what it's designed for. This is what the decision-makers need to focus their minds on.

Not every project can actually utilize the Fast-track. So there is a threshold, if you like, to determine what a nationally or regionally important project is. And so there's a Section 22 of the act actually lists that -- it can either be identified in a plan. But generally speaking, it's about new nationally or regionally significant infrastructure or it's looking to maintain critical infrastructure.

It's more focused on the economics and it will be driven in relation to that. So the economic evidence that you attach to your applications from the outset is critical and particularly important. The fifth point is speed. So it does trade broad public participation for targeted engagement. So if you -- at the moment, if you're adjacent to a fast-track project, you can expect to be invited to make comments on it.

The panel have the ability to ask comments of any party that they like. So the panel who are selected, they have a lot of leeway themselves in relation to how they run the particular process. But you still -- like as an applicant when you're utilizing this, it's not a shortcut in relation to environmental assessments.

You still need to do the work. There's also ineligible projects. So there are some projects or some areas where you can't even apply. So if you're on Maori land, you need -- you must have the written agreement before you lodge your application. Otherwise, it won't even be accepted. So there's no point applying. The same with access arrangements under the Crown Minerals Act, some aquaculture activities and also national parks and/or national reserves, subject to Section 24, that's actually a carve-out for existing electricity environments or sectors or existing environment electricity infrastructure that's already in place. The other thing to bear in mind is point #7 now is that the fast track approval is a -- it's a one-stop-shop, which is particularly useful. So it includes everything. So if you need wildlife permits, it will get incorporated within your application. If you need concessions from the Department of Conservation, it's incorporated within your application. If you need archaeological approvals, it's incorporated within your application. So you get a broad suite of all your environmental authorizations, all at the same time, assessing all the information in front of those decision makers then and there.

So it's particularly helpful from a developers' point of view. Quite often, you will get your substantive consents and then there's sort of a dribble of additional consents that you need to get and you need a next one over here and you need to do this. This is intended to prevent that from happening and to provide a more sort of efficient outcome for everyone that's involved. Decisions. So the application is heard by an expert panel. The convener would appoint the panel. The panel would normally consist of a lawyer and technical experts to assist in relation to whatever the key particular issues are. So if it's ecology, you would have an expert in ecology if it's groundwater ecology, you'd have someone in that space. Hearings, the panel can determine whether or not hearing is required. Generally speaking, it's rare for there to be a hearing. The vast majority of matters will be determined on the papers, unless the applicant, the applicant can make a request for a hearing.

And sometimes, if there are matters which are more appropriately tested in an environment where you can have an exchange, that could be an outcome one would seek. But generally speaking, I can see 99% of these matters all just been determined with paper -- on the papers by the panel. And I guess point #10, the key tests. So this is probably one of the more important elements. And I've outlined below the 2 areas there. So you would have to ensure to have an application turned down that the adverse impacts are out of proportion to the regional national benefits. So that's the new test now. And the piece beside, it deals with the criteria. And you can see there that the first matter that the decision-maker must turn their minds to is the purpose of this act and then everything else follows below that. So as a decision-maker, the adverse effects would have to be so sufficiently significant to be out of proportion to the project's benefit for that to result in a decline.

So it sets quite a high benchmark from our point of view. This is the process. So it's a 2-step process in relation to the referral application. So -- sorry, in relation to the Fast-track Approvals Act. So you have to get referred first. So you will put an application in. The minister will look at it. They'll do like a checklist will get spun around within government for everyone to make comments on, then everything will come back to the minister. And then the minister, even though it's not provided here, the expectation is once the minister has all the information, they'd make a decision around 20 working days as to whether or not your application meets the thresholds and whether or not it can be included as a fast-track application. And there's broad discretion there, like there's a lot of movement and the minister can accept it or decline.

Once you're in, the next step is in relation to your substantive application. And so you've got 2 years after being referred. So you can't just sit on your hands. So the whole purpose of the Fast-track Approvals Act is actually to get things moving to help the economy to build stuff for things to happen. So this is -- you actually -- you can't bank stuff, you have to utilize it. The flow chart beside you there, that's simply from MfE. Again, it's an iterative process. The panel convener will select the expert panel. The expert panel will then go out to -- they can seek their own advice. So the expert panel can go, we want a legal opinion on this or we want further advice on additional matters. It's very flexible from the panel's point of view in relation to additional information that they can seek. They will go out and they will see comments. And after we get those comments back, the applicant will be able to make comments on those comments and then the panel will go off and make a decision.

I wanted to outline costs. It's not cheap. So your referral application is just over $21,000. The substantive application is $448,500. So it is a user pay system. But in saying that, the costs that we've experienced on a 2-stage process have been quite high. Mount Munro, which was a direct referral application, you have to pay for the court. So for Mount Munro, Meridian paid $77,000 for an 8-day hearing in the environment court and that covers venue, accommodation mile. You pay for absolutely everything. That's nicely iterated like outlined. So you know exactly what you're paying for. You also have to pay for the council as well. You have to cover all their costs. There's no such thing as a free lunch with consenting under the RMA. The costs per day are also outlined there. And the reason I've done that is there was a difficulty initially when the fast track first came out and that it was hard for the panel conveners to find people because it's a small network of RMA practitioners.

They're all super busy. Why would I want to do this job if I'm getting paid doing more over here. And so they've actually introduced it. So it's at market rates now. There can be additional costs that the EPA can pass on to the applicant as well. And getting on to the amendment bill now. So I've only got 3 slides in this area. But essentially, the appeal rights are limited now. So you can't go to the -- after appealing to the high court, you can't go to the Court of Appeal unless you first get leave from the Supreme Court. So that's acting as another sort of a barrier there that you would have to jump through. The other aspect as well is that the amendment bill restricts other parties from appealing. So if comments are invited from another party, the panel must first go to the council and ask them if they are covering off those aspects. And if they're covering off those aspects, they're not allowed to then invite comments from this other third party.

So that could be an NGO, for example. If the council comes back and says, we're not going to cover that, well, then the panel can then ask that third party. So I can see that the councils are going to have a much greater role in relation to the Fast-track Approvals Act, and they will actually be controlling a lot more and be more heavily engaged in that space, I suspect. The other thing is that there is now going to be a general policy statement. And so I understand the first one is going to be about supermarkets, but the expectation would be, could there be one for renewable energy moving forward. And that would mean that you would get past the first referral stage a lot easier without having to do the work. And would there be a benchmark or a threshold in relation to that? I don't know, but it certainly makes sense to enable the government at the time to make those calls and to see what would be appropriate.

The other amendment they've made -- and all these amendments are particularly helpful and useful in the sense of when the Fast-track Act first came out, there were a few sort of teething issues with it. And so this amendment bill actually fixes up a lot of sort of teething issues that arose, in particular, one was rejecting application because if the application got rejected, it took ages to get your money back. You had to pay your check again and to go through the whole process again. It was very inflexible. More or less a grab bag of amendments, which are helpful moving forward from a developer's point of view. In particular, the Tauranga Wharf, you may recall they went off to the high court, and there was an argument in relation to whether the Stella Wharf and the Mount Maunganui Wharf, whether both wharfs were actually referred because they left off a few words when they listed it under the act. And the high court said, well, you can only apply for what was actually stated within it.

And so because there was an admission, that part of the application got rejected. So now they fix it up and the minister can actually amend those elements to ensure that things are a lot more seamless in that space. The minister can also determine a project as a priority before a panel is made up because there are delays being experienced in that area. But the whole emphasis has been trying to speed things up, which is certainly is helpful for us moving forward. Listed projects, they -- you may make a written request to the minister for stages. So that enables you to apply in various components, which is also beneficial. There's also the reduced consultation at the outset. So prior to -- currently, if you want to put a referral application you must first consult with counsel and iwi. But it was always sort of a little bit -- we're unsure as to what consult actually meant in that space and what happens if someone doesn't want to consult with you and/or you can't find the time.

Now there's a process there where you can consult and then the other party, they need to provide written advice within 20 working days from that consultation. So it means that things can keep on, keep on moving. There's also the ability for the EPA to request further information now, whereas previously, what would have happened is they would have chucked your application out and you would have to start again. Now they can actually sort of go well, hang on, you've got this missing. Can you please provide it. And then the last 3 bullet points are all about speeding the process up. The bill is saying that the efficiencies are likely to introduce up to 6 weeks being saved. And last slide, the -- an applicant or a local authority can raise concerns about a prospective panel member.

It's probably unlikely, to be honest. I don't think you'd be particularly successful in that regard unless it was something quite telling. And if it was quite telling, the expectation would be that, that member would remove themselves in any regard. But at least there's a backstop there. The referral application, sub applications are also speed up now, which is helpful in the sense of this complete and checking scope tests enable an approach whereby everything can be done very, very quickly, if you like. And the other thing is -- sorry, second last bullet point, applicants can continue with competing applications, which basically means like previously, you could only apply under the fast track.

You couldn't sort of simultaneously do other things under the RMA. Now you can do both at the same time, which allows avenues. It may mean that you can apply for some components under the RMA and other components under the Fast-track Approvals Bill. It will be actually quite beneficial in that space. So the submission is closed for this amendment bill on the 17th of November. So our submission just went in on Monday. The expectation is that these amendments would be passed before the end of this year. So they'll be pushed through as quickly as possible as well. And that's me. So I'm more than happy to take any questions about fast-track consenting and what's happening in that space and what people are up to.

Just a clarification, I guess, as much as anything. But you mentioned that if you go through the fast-track approvals process, you have to use that consent within 2 years. So I assume that means getting to FID within 2 years of receiving consent?

No. So you've got -- once you go through the referral process, you have to apply for the substantive step. So you go into the referral process, you get a tick. Then within 2 years, you have to apply for your substantive application. Once you've got that, you've got 5 years to actually then implement it.

To actually then go and build the project. Okay. I mean because I guess that was one of the criticisms in the past is that there was quite a lot of, I guess, wind farms consented but were never built and technology changed and they had to re-consent them all. So what are the implications if you don't use the consent it just lapse quite -- effectively it lapses faster than the old consents that the...

Yes, if you don't use it, you'll lose it.

And just a second question in terms of capacity within the system to hear all of the applications that are heading their way and I guess, the risks around sort of congestion in that space.

Yes. Yes, that's a very good point. And it was certainly something that we raised for the NBA when that first came out, it was going to be a complete new process there. There's new language and the expectation would be that there would be a bottleneck. With the fast track there is a risk in that space in relation to finding the appropriate experts to sit on that panel. And I imagine the panel conveners are running around furiously lining people up, getting them ready for the next step for those applications. So having people available has always been an issue. So yes, you're absolutely bang on in that. Great. Excellent. I'd like to introduce Murray, who's going to cover off hydro.

All righty. It feels like we've spoken a little bit about hydro already today, but [Foreign Language] Murray Hill [Foreign Language]. While this forum is new to me and for those that don't know me, I've actually been around for a little over 23 years, I think, in the company. And it's been a privilege. I've worked across many of our exciting assets in a variety of different roles, both operationally and a lot of time spent in development. Started out in hydro. And as [indiscernible] pointed out earlier, I managed to get back in there about a year ago as I progressed the Waitaki upgrade project. Now -- yes, and now taking on this newly formed Head of Hydro Development role presents another -- a really exciting opportunity for me personally, but also for the company. And I think more broadly for the nation, we're at a point in time where big decisions need to be made in regards to how we navigate through what's a relatively uncertain energy transition. In terms of the role, yes, it's pretty simple really, developing new hydro capacity both within our existing catchments and beyond. That's the remit.

And today, while there's probably not quite enough numbers in there for this audience, I am pretty keen to, I suppose, give a sense of our ambition, the pace at which we are looking to move this along and give you a bit of insight into some of the things we're looking at and how the pipeline may shape up over time. So to do that, look, there's a bit of context, and you've heard a lot of that from Rory and others that has helped pin down what our strategy is looking to achieve. A bit about our development approach and how we're thinking about this, a couple of the key aspects to our strategy and then, yes, some early insights into those projects. You might wonder why this photo is my starting point. And it wasn't to talk about Waitaki upgrade or initiate a discussion there, but this is, in fact, inside the scroll case of one of the units at Waitaki, which is our oldest hydro in our fleet, turning 90 years old last year. And as mentioned earlier, that is set for a major upgrade and modernization.

The reason I start with this image, I mean, it's really simply to reinforce, I suppose, and acknowledge how well hydro served us over many years. That really is the backbone of our electricity system. And to use one of my colleagues that you may be familiar with, Mr. Grant Telfar, he talks about hydro being our energy superpower, if not our energy advantage at least. So yes, that's the reason for the photo. And yes, as other affluent economies around the world sort of lean into their respective energy advantages, hydro is our opportunity. And it feels like now is the time to be thinking about that. So as we navigate the coming years and decades, yes, we firmly believe that hydro can continue on and be pivotal to our electricity system into the future. The challenge ahead of us, there has been a fair bit of talk about that today. I will cover that off somewhat briefly as it does form some of our numbers later in the pack. That challenge really is the significant growth required to electrify our economy.

And obviously, some of the security of supply challenges that have been mentioned today, resolving dry year energy deficits, potential retirement of a couple of gigawatts of thermal generation and the domestic gas supply and the decline we're seeing there. So that's some significant challenges there. From there, the requirement really is the system will need some significant growth, potentially up to 5 gigawatts of flexible generation and up to 3.5 terawatt hours to solve that deficit. And some of that will come from hydro, we believe. In fact, a large proportion of that. So my aim really and for the hydro development team is to build a pipeline of opportunities that provide a hydro-focused response to some of these challenges and the requirements that fall off the back of them. Now in terms of that -- our approach, we haven't pursued hydro development for over a decade. So part of the go forward is obviously around acknowledging the complexity and challenges of what's ahead of us.

These are big problems to solve and hydro is hard to get away. We know that. We've learned that. As I mentioned, recognizing the urgency and the momentum that we need to get some of these projects on the table, get them into the discussion about how they can solve some of these future challenges. To begin with, I was talking with someone earlier, a bit of unconstrained thinking. That's kind of the license. I'm not sure how long that window will stay open. But what I really mean by that is everything is on the table. There's old projects that Meridian has looked at a decade ago. There's things that are currently on our plate. There's other schemes that have been talked about historically. It's really a good time to take stock of all of that. run this new context or new ruler over those projects and for us, quickly get to a point where we understand where the valuable projects are, what the priority should be as we progress. And given we haven't been here for a good decade, we certainly have to build capability in hydro development specifically. We know development.

Rebecca has got a great team of developing wind and solar. We know how to do it, but that expertise, I suppose, in hydro development doesn't really exist in the business. But what we can draw on is a whole bunch of operational hydro knowledge and expertise, a whole bunch of consenting experience from the last time we revisited development with any sort of vigor. And beyond that, to get some real momentum on this, we'll lean on external expertise, people that have been developing hydro internationally over the last decade or so to really get the pace going. So yes, that's the challenge. Some big numbers there, as we've talked about earlier in the day. And I suppose a bit of a summary of how we're thinking of what our approach is really. So this slide here is really, I suppose, the strategic plan of the attack on a page. And as you can see down the left-hand side there, there's a couple of categories, one around flexible generation and one around storage, and there's some numbers attached to that. So they become, I suppose, the direction set is for us as a team.

Now those numbers are really based on the requirements that I spoke about earlier and Rory spoke about earlier in the day. To get to these numbers from those contextual numbers and system requirements, I mean, really what we're assuming is hydro plays a big part in solving those problems and Meridian contributes significantly to that hydro element. I suppose what's most important in those numbers is not the numbers themselves. I think it's really the magnitude of those numbers. What it means is while incremental gains either within our catchments or with new hydro developments will be important and will be valuable. I think if we are to change -- or sorry, if we had to really move the dial and solve some of these future problems and close that gap on those requirements, then we need to be thinking fairly boldly and we need to find some decent opportunities of scale. In terms of the rest of that slide, yes, 2 key pillars, I suppose, that make up the strategy.

Down the left-hand column there, the technical and economic feasibility, I mean that's almost table stakes. That's about finding the right projects that make sense economically and technically. We know how to do that. We do it now in wind, solar, batteries. That's a process that we know, and we're confident that those opportunities will exist. It's about getting in there, finding the right ones and progressing some engineering and some analysis. The right-hand side of that, the pathway to approval, I think that's really where the thinking needs to happen. And as you saw in Humphrey's last presentation, the dark art of consenting and approval. I think as we progress some of these hydro opportunities, we really need to do some solid thinking about how those projects progress in parallel to technical detail. And some of these projects could well require different approvals, different pathways.

And in fact, it's quite likely. So yes, I really see -- the left-hand side stuff we're comfortable with. That's what we do. I think the pathway to approval is where we really think -- need to think hard and develop good strategies to progress some of these initiatives. So moving on to this, which is probably the slide most people are wanting to talk about and see. This is really an early teaser for what a pipeline might look like. Down the left-hand side, that first column is some of the near-term activities that we're currently engaged in and currently progressing. At a high level, that's about building a quality pipeline, investigations, understanding priorities, et cetera. As you can see, the bottom half of this table is broken up into storage and flexible generation, which are the targets that we talked about just previously.

There's also a line in there for water diversion, which is another concept that is a concept that's come out of historical projects and is essentially about diverting water from beyond a catchment into an existing catchment, for instance. So across those 3 areas and in that first column, you can see the flavor of things that are currently on the table, some of which we've talked about today in some detail. So contingent storage, we've heard about that. If we're successful there, that secures that for 3 years. The next couple really is a single opportunity. Let's call it Pukaki raise. Now what does that actually mean? For me, I think Pukaki raise means a few things. What can we do at Lake Pukaki with minimal engineering. So what sort of raise can we get out of that lake without a lot of engineering, a lot of remedial work, a solution that sits well with the existing Pukaki dam and the structures that we have along that dam.

Now whether that's a 1-meter raise, a 2-meter raise, that's the work we're doing to understand that. I think a next level of detail there when you consider raising Pukaki is -- and a question I want to answer is, given the existing dam, how far can we take that? What engineering can we do to that dam to those structures that sit along that dam, what's the potential? And I think that will be an interesting exercise. Beyond that, you'll get to some point where the ambition triggers a new dam essentially. So understanding that as well is something that we will progress. So yes, when I think about Pukaki raise and Yes, it's really those sort of 3 steps really and those 3 separate opportunities. The next couple of lines really associated with the Way. That first one, Manapouri is actually Manapouri lower access and Tainui lower access. That's really about accessing more water in the lower band of those regimes. Pump storage gets to mention there.

Absolutely, we will consider pump storage opportunities, both within our existing catchments or beyond. The flexible generation at the bottom, and some of this is not new to us and some of the work going on within Tainui's team has already been seeking out additional flexible generation. So that first one is around Manapouri and looking at how we can increase flexibility at that power station, which involves putting water through that power station, pulsing it through the power station, but keeping water flows into the sounds the same as what is currently able to do. Pukaki Hydro, that's generation across the face of that dam. That's a project that's been around forever or a long time. And I think as a good example where a lot of these initiatives, as we really get into the detail, you can't really look at them in isolation. If you take the Pukaki opportunity more broadly and talk about raising levels, contingent storage, understanding the implications for the existing structures along the face of that dam and then considering an additional generation plant on the face of that dam, it all needs to come together.

So I think in all reality, we will probably look hard at some of those raise options, understand what they are before we dive too deep back into a Pukaki generation option. Yes, a few others mentioned there that have already been talked about. So the Waitaki Power Station upgrade, yes, I mean, that is part of the mix because we are looking to increase capacity of that power station. And that's potentially taking what is a 105-megawatt power station to 120 or beyond, 120, 130 is the current feedback we're getting from the OEMs that we're engaged with. And again, the reason is around that flexibility problem that we're trying to solve. As we move to the right across this table, the near term, I think, yes, it's about developing that pipeline, getting some good quant and quality behind what we put on the table. And I think there's a program of work now over the next 5, 6 months that really will help push that along. And potentially, the next time we're talking to these types of initiatives, you'll get to see some numbers alongside them.

In the medium term, locking in some of those incremental gains, those projects that start to move us in the right direction and provide some additional storage, more flexible generation is what we'll look to do. medium-term aspirations. And then the further out to the right you go, we get into vision territory, right? And this is, I suppose, the point I made on the last slide and the scale of some of those numbers to really move the dial on those numbers and make a difference, Hydro is going to have to find some decent projects of scale. When I think about the 2 existing catchments, they do present quite different opportunities and different complexities for us. On the one hand, Waitaki, you would say more modified catchment, less population. There's no town on the edge of Lake Pukaki very soon to be reconsented, a bit of certainty for us there. Then if you move to the Waiau catchment, obviously, more populated.

You've got the towns of Manapouri, Tainui on the Lake edges. You're operating a power station within a World Heritage Park. More stakeholders, more interest and 2 approval regimes. So yes, I feel the Waiau is more complex. There's certainly opportunities there that we will look at. Pukaki feels like it's -- some of those opportunities are probably easier to get momentum on is my gut feel. So yes, the work over the next 6 to 12 months, as I said, is about confirming that direction, picking those projects that are worthy of more detail and more work. And yes, it really is being bold enough to look at those schemes that really move the dial for me. Along the way, we will take those incremental gains. But yes, this really -- the opportunity for hydro and if it is to support our energy future mean that we can have some self-sufficiency in terms of our energy system and keep those LNG ships at bay, then we need to find some good sizable projects. And that's about me in terms of the slides, but I am keen to hear from you all for maybe one question.

Thanks, Murray. I get just one question. Then perhaps the one to ask about is the water diversion projects, presumably into your own existing schemes. Are we talking sort of some of the projects in the past, drilling holes through the ALPS and -- right. Is that the only one though? Are there other options?

That's the one we will take a look at, and that has actually started. And that's that project in and of itself. So this is related to the Pukaki catchment, taking water from adjacent valleys catchment, diverting water into Pukaki. I mean it's pretty obvious why we like that. We've got 6 power stations that can -- that are already built -- already have infrastructure to generate using any water that we can add into that catchment. And again, it does kind of tie back into the fact that a lot of these opportunities are linked, right? You can imagine if you're raising the lake, some additional water is going to make that project even more valuable and so forth. So yes, water diversion, it's a concept. I mean it's not a new concept, right? It's used in hydro elsewhere. And yes, that's certainly something of interest. But equally, that same concept that could be applied to our other catchment. And I think -- we will also look more broadly beyond our catchments as well. And so that concept of water diversion should probably be considered as we look towards more greenfield type opportunities in other parts of the country, which we will get to. Pardon me?

Lower Waitaki.

Probably less so. I think -- yes, it's a good point. What's not evident in our strategy is run-of-river hydro. We are really focused on hydro that does have some storage attached to it because that's what the system needs.

Although adding more generation at the bottom of the chain would mean the gigawatt hours store at the top.

Yes. It also potentially doubles down in terms of our dry year problem as well. So yes, it's about storage and flexible generation.

Looking at your rule of thumb there on that slide, it looks like that to get a terawatt hour of storage, you need about 5 meters or something at Pukaki. Is that right?

Yes. I suppose if you back calculate, yes, I think it's a little bit more than that.

What does that do to Pukaki from a -- obviously, there's significant costs involved from your point of view. But just from a -- how does Pukaki look 5 meters higher than it is today?

Quite different. I suppose there's -- and that's part of what we're getting to the bottom of. And that's not to say that all of that terawatt hour comes from a single project, too, by the way. But as you suggest, if it does come from Pukaki, then yes, then obviously, for us, there's an implication for gate 18, gate 19 across the face of that dam as a starting point. But yes, that's a significant change, right? At one meter, 1-plus meters, there's impact, but it's probably manageable with some engineering either along the dam face or around the Lakeshore. But once you're into multimeter territory, yes, certainly implications, and that's what makes these projects complex, but it's also the opportunity for the country, right? It's not -- it wouldn't be the first time that Lake Pukaki has been raised either.

Obviously, I've been waiting patiently all day and finally, someone has asked an online question. So here I go. First question from [ Ian ], also from [ Jason ], probably also. Any views on Lake Onslow being -- any views on Onslow really is a question.

Any views on Onslow? Look, certainly interested in how Onslow 2.0 progresses and what scale and size that ends up being. Yes, absolutely. interested. And yes, why not if -- those are the types of projects that the system will require in the future. So that's what we're all looking for.

One more for you, Murray. Any chance that Project Aqua will be reborn?

I suspect not for probably -- yes, a multitude of reasons, one we just mentioned, Nev. And perhaps if we did look at it again, we might get to the same conclusion we did last time. So I don't think so.

All right. Thank you, Owen. I think it's time to call on Mike now for some closing comments.

First thing is thanks, everybody, for your time. And I hope you heard what I heard from people, which we've got a bunch of incredibly experienced, capable and talented people within our business who are all committed to the success of it. And that's what we wanted to communicate to you today. My message is really simple. Meridian has got the strength, the resilience and the capability to lead and we will. I'm going to close it at that other than for one thing, which is I've got a couple of prizes of merch out apparently to some folks who I don't know. There were 2 Meridian folks who are on this, so I've scrubbed them entirely on the leaderboard because that just -- that doesn't sound right to me. I couldn't believe it when I saw that the leader by Country Mile was -- where's [ James ]? [ James Gill ], Country Mile, what did you do?

[indiscernible]

Anyway, there were a lot of people hurting golf balls out there at lunch. Sorry for those who are online. But [ James ], he's not only good at what he does, but he's pretty handy outside of work as well. And [ Nick Drvisky ], was one came in second. So there's a couple of winners. Thanks for that. It's nice to have a bit of merch, but thank you, everybody, for the day. I think everyone is going to -- we probably got a bit of time on how we're doing on time. We're probably about right as people start clearing out for transport. But feel free for those who are left to mingle and ask any residual questions that you've got. Otherwise, great to see you all. Thank you for questions and participation, and we'll see. We'll see a lot of you in the next few years.

[Foreign Language]

[Presentation]

[Foreign Language]

We welcome you all to Meridian's 2025 Annual Shareholder Meeting. Haere mai to those who are joining us today, both in person at Meridian's office in Wellington and to those of you online. And I'd like to say especially to the people that have braved the Wellington elements today, we do appreciate you coming. So thank you for that.

We welcome to the meeting Anthony Smith and Daniel Lock from our auditors, Deloitte; and Ian Beaumont from our lawyers, Russell McVeigh. Welcome also to Daniel Madley and Aaron Gill from Treasury, representing the Crown.

For those here in person, in the unlikely event of an emergency, please follow Meridian staff instructions. If the fire alarm sounds, our emergency exits are located to the rear of the seated area down the stairs and out the way you came in the building. Please don't use the lifts. Our staff are here to show you the way. Our fire evacuation point is on Customhouse Quay across the road on the foot path outside private restaurant. In the event of an earthquake, please drop, cover and hold. Once any shaking has stopped, please follow Meridian staff instructions. The bathrooms are by our reception area where you came in today. Our Meridian staff are here to help.

I declare the 2025 Annual Shareholder Meeting open. The meeting has been duly convened and a quorum is present. The minutes of last year's meeting have been posted on our website and are held by the Company Secretary. Today's meeting is being held in person and online via Computershare's online meeting platform. All online attendees can watch a live webcast of the meeting and read the company documents associated with the meeting. In addition, shareholders and proxies can ask questions and submit votes.

For those of you attending the meeting virtually, if you do have a question to submit during the live meeting, please select the Q&A tab on the right of your screen at any time. Type your question into the field and press send. Your question will immediately be submitted. Should you require any assistance, you can type your query and one of the Computershare team will assist via the chat function. Alternatively, you can call Computershare on 0800-650-034.

Please note that whilst you can submit questions from now on, I won't address them until the relevant time in the meeting. Your questions may be moderated or if we receive multiple questions on the same topic, they might be amalgamated together. Finally, if we do run out of time to answer all your questions in this session, we will answer them by e-mail.

At the conclusion of the Chief Executive's review, we will address questions on the operations of the business. Please keep any questions today on today's ordinary resolutions director appointments until we get to that part of the meeting. Voting today will be conducted by way of a poll on all items of business. To provide all attendees enough time to vote, I will shortly open the online voting for the 4 formal resolutions to be considered today. These relate to the reelection of current directors, Julia Hoare, Michelle Henderson, Nagaja Sanatkumar and Graham Cockroft.

At that time, if you are eligible to vote at this meeting, you will be able to cast your vote under the Vote tab. To vote, simply select your voting direction from the options on screen. Your vote will have been cast when the tick appears. To change your vote, simply select change your vote. You can change your vote up until the time I declare voting is closed. Persons attending the meeting who are not shareholders, proxy holders or corporate representatives of a shareholder may not vote. This includes bondholders. Voting is now open on all items of business. The resolutions are now open in the vote tab. Please submit your votes at any time. And I will give you a warning before voting is to close.

I'll begin my Chair's address by introducing the Meridian Board and some of the management team who are present today. This year, all Meridian Board members are present at our Wellington office. For those in the room, I ask directors sitting in the audience to raise their hands as I call their name. Julia Hoare, Michelle Henderson, Nagaja Sanatkumar, Graham Cockroft, Tania Simpson and David Carter. The Board has remained unchanged this year. Directors' extensive and varied range of experience has been invaluable in helping us navigate the different challenges, and we thank all Board members for the range of perspectives they've brought and applied to different situations throughout the year.

Also present with me today are Chief Executive, Mike Roan; Chief Financial Officer, Mandy Simpson; and General Counsel, Jason Woolley. The rest of the Meridian's executive team, apart from Bharat Ratanpal, are also in the room.

Meridian's purpose of clean energy for a fairer and healthier world underpins every action that our company takes and our intention to play a leading role in supporting Aotearoa to further strengthen the electricity system and [Audio Gap].

This year, we weathered a perfect storm. A combination of historically low hydro inflows, periods of low wind, 2 major droughts and a dramatic decline in gas availability made this a very challenging financial year.

At the same time, we've worked hard to strengthen the fundamentals of the business through sound investment for growth and delivering on our strategy. We secured 5 resource consents for new assets, invested $193 million in building and maintaining generation plant. We acquired 2 new businesses and undertook a strategic reset of our retail business, all the while growing our customer connections. For us, fin year '25 will be defined by Meridian putting our customers in New Zealand's security of supply first, keeping the power flowing for homes and businesses and the financial hit we took because of that.

Our balance sheet is structured to underwrite major droughts, and that is one of the ways our country benefits from having large and financially strong Gentailers supporting the economy. Bearing in mind, we supply roughly 30% of the economy, were we not to have done this, short-term prices could have been very challenging for many of our customers. It is important for us to take a long-term view. And as I will talk soon, we also strive to ensure that we continue to reward our shareholders for the trust you place in us during challenging times by investing, and we are pleased to have been able to show that our commitment to you by returning a dividend.

Fin year '25 also brought an intense amount of scrutiny of both Gentailers like Meridian and the wider sector as people dissected the events of winter 2024 and the government responded with a review by Frontier Economics and other international experts. After many years -- many years, many months of speculation, the Frontier report and the government's response were released at the beginning of October. The company welcomed many of the proposed changes, including the government's willingness to indicate that it would potentially participate in equity raisings by mixed ownership model companies like Meridian as a means of bringing forward investment in new generation and in particular, firming capacity.

This represents the biggest change to our capital investment settings since we were listed in 2013, and we acknowledge the government's commitment to help move the country forward. It has the potential to add even greater momentum to our currently strong development pipeline, building new generation is the best way to improve energy security and affordability. Meridian is also supportive of the government's focus on addressing issues related to gas supply, strengthening the powers of the industry regulator and changes to the security of supply regime to make it more robust.

The unexpected loss of gas has clearly been identified as a key factor behind fuel shortages in winter 2024, and Meridian was pleased to see the government is looking at initiatives to remedy this, such as improving initiatives around gas supply and considering the procurement of an LNG import facility. Whilst further details related to the facility will be confirmed in the coming months, the government wants something to be in place by the 1st of June 2027. Although this is particularly relevant for gas customers, any facility could add to the suite of solutions that ensure against dry year risk in the electricity sector, placing it alongside the Huntly strategic reserve, our demand response agreement with New Zealand Aluminum smelters and access to more hydro storage.

The energy task force is more advanced with its work and is close to finalizing its level playing field measures. In essence, these are about ensuring greater transparency in prices Gentailers offer to independent retailers as compared to the notional prices in place we have in relation to our own retail business units. From the outset, we've said that we'll be -- we are comfortable with these measures provided they are set up in a way that will benefit customers. Early in 2025, Meridian and others in the industry took steps to restore long-term confidence in energy security and improve affordability. On top of an unprecedented amount of generation development, a group of large electricity suppliers, including Meridian, signed an agreement to ensure the availability of 3 coal or gas-fired Rankine units and the necessary fuel at Genesis-owned Huntly Power Station. This agreement will ensure New Zealand will have continued generation capacity for the next 10 years.

Maintaining a secure energy electricity supply is what we must do as we find ways to use more hydro generation and accelerate the deployment of new renewable projects to meet our future energy needs. This was a challenging decision for us to enter into the Huntly arrangements given our commitment to decarbonization and renewable energy. However, the sudden loss of gas as a transition fuel meant that extending the life of Huntly and building a thermal fuel reserve is in the best interest of Kiwi homes and businesses and for the broader economy in the short to medium term.

The Huntly arrangements, which for us is a financial arrangement, alongside additional use of the country's hydro capacity are actions that will help make the country's electricity system more resilient and affordable. And the confidence it brings will allow the sector to continue to build new renewable generation at pace. An affordable, secure and highly renewable grid will enable future economic prosperity, allowing the country to take the opportunity to create and market green products internationally. And the facts are that New Zealand electricity prices actually do compare favorably with other countries. We're in the top 10% for both industrial and residential consumers as benchmarked across the OECD, i.e., that means lower prices.

We're keenly aware of our social license. It isn't in the long-term interest of Meridian to see customers disappear from the economy. That doesn't make a sustainable business. It is firmly in our interest to see customers succeed in the economy through competitive pricing. The work we do is intended to underpin this country's growth and prosperity and ultimately bring down prices over time.

During the past financial year, Neal Barclay's tenure as Chief Executive ended. Under his leadership, Meridian has grown a renewable development pipeline that will double the size of the asset base over time. We've refocused our business around customers. We've grown that business, and we've formed valuable relationships with a variety of stakeholders. Importantly, Neal led the team that secured a sustainable 20-year contract with New Zealand Aluminium Smelters or NZAS. The Board and executive team certainly thank Neal for his commitment to growth and sustainable practice and for anticipating how Meridian could play its part in delivering long-term value for customers, you, our shareholders and Aotearoa New Zealand.

On behalf of the Board, I would also like to congratulate Mike Roan on his appointment to Chief Executive and the strong start he has made in the role. I will conclude my address by speaking to Meridian's shareholder returns. We understand that you, our shareholders, are happy for us to continue to invest in existing and new assets on the firm understanding that, that will provide you with appropriate returns over time. Long-term investors in Meridian will know that nature doesn't always play us a kind hand, and that was certainly the case in the last financial year. But we have a strong balance sheet structured and maintained to manage the impacts of such conditions.

That strong balance sheet meant that the company was also able to continue to provide you with stable returns with the Board declaring a final ordinary dividend of $0.1485 a share. That brings total dividends for Fin year '25 to $0.21 per share. The Board approved continuation of the dividend reinvestment plan as well at a 2% discount.

Thank you for continuing to invest in and support our company. I will now ask our Chief Executive, Mike Roan, to address the meeting. Mike?

[Foreign Language] It's a real privilege to be speaking to you today in my first shareholder meeting as Meridian's Chief Executive. I've come into this role with tremendous faith in our people and our strategy, but also with a bold vision. I believe that when we harness -- when we properly harness the natural bounty this country has to offer, the electricity sector can help to underwrite the economic growth of the nation.

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 to Meridian to where it is today, and 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 seven new developments in seven years, that target was framed before the gas sector collapsed. So we need even more clean energy to realize that 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’'s electricity system, but there's room to further optimize this scheme to meet the challenges of 2025 and through 2055. The good news is that the Waitaki Power scheme has so much more to give. There's more water to be accessed, more megawatts to be achieved from existing assets and scope for a fundamental shift in the role that stored hydro plays. This can be done in a way that's aligned with our value set, one that balances environmental and community concerns. And I know the Meridian team is up for the kaupapa.

In my view, the route to global competitive advantage for our country can only come if we harness more water from existing hydro catchments. We've recently established a hydro development team to explore new opportunities, and we've received ministerial approval to have our application for access to Pukaki contingent storage through the Fast Track process. With the government's willingness to take part in equity raisings for new developments, we now have an opportunity to think even bolder and we will.

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 you serve. So as well as evolving to help our customers thrive in the future, we're highly tuned into how we can support industrial and residential customers in the current tough environment where cost of living is a key concern. Now Fin year '25 was a year where nature didn't help us. Our hydro storage was heavily affected by 2 consecutive record low inflow periods last winter and again through the most recent summer. Periods of unseasonably low wind and the country's declining gas production challenged electricity generation as well.

From a financial perspective, the business struggled to get out of first gear and even had to hit the brakes hard at one point. Shareholders in our business know that when it doesn't rain, it's tough to make hydroelectricity and turn that into profits, particularly when we exercise insurance to cover the loss of that generation. And each of those decisions hits our bottom line. Operating cash flows of $318 million for the year ended 30 June 2025 were down $349 million or 52% from the previous year. Net profit after tax, which also reflected the changed treatment of the main NZAS contract, was a $452 million loss compared with a $429 million profit in the previous year.

EBITDAF was down 32% to $611 million and underlying net profit after tax fell by 84% to $56 million. Now both EBITDAF and underlying net profit after tax are non-GAAP measures. But as Mark said, we did work through some challenges, and I'm pleased to say that we've made a strong start to the new financial year.

Now there are a few changes to our exec team announced during the year as well. Rory Blundell was appointed to the newly created role of General Manager, Strategy and Portfolio; and Chief Information Officer, Bharat Ratanpal, has returned from a comment as Interim CEO for the Flux business. More recently, Mandy Simpson has joined Meridian as Chief Financial Officer. The merging of the Wholesale Operations function into the generation team also saw Chris

Ewers leave the exec team to take up a new role in the company as Electricity Security Manager, reporting to Tania Palmer, our GM of Generation.

Now there's been a lot of talk amongst politicians in the media about the need to build more, and we are. We're doing it as fast as we can. Meridian's 7 projects in 7 years renewable build program is advancing at speed. This year, we met the first 2 milestones. The 176-megawatt Harapaki Wind Farm is now fully operational and the 100-megawatt battery energy storage system, or BESS, at Ruakaka Energy Park near Whangare was commissioned in May 2025. This BESS lift system capacity by allowing us to reintroduce stored power into the grid at peak times, and it's already making a big difference.

Now on the 29th of August this year, the joint venture with Nova Energy confirmed that the first stage of the 400-megawatt Te Rahui solar farm had met its financial hurdles and so moved into construction as well. In addition, we've got 4 wind, solar and battery projects consented. Another battery in the Manawatu, a wind farm at Mount Munroe in the Wairarapa, Stage 2 of Te Rahui and the first repowering with existing wind farm at Te Rere Hau.

And finally, with 3 consents currently being processed by councils, the Swannanoa, Waikato and Manawatu solar farms. The acquisition of New Zealand wind farms was approved by their shareholders in June and completed in July following approval of the High Court. This deal rewards New Zealand shareholders -- New Zealand wind farm shareholders for the value created to date and brings delivery of the Te Rere Hau repowering project fully into Meridian. A decision on that project is expected mid- to late 2026.

Some critics say the industry is holding back on investment, but the above list says something different. Meridian has invested over $1 billion in the last 5 years, and there's a further $2 billion planned in the project list I just talked to. This project started -- this progress started some time ago even when demand projections were flat, and there was considerable uncertainty over whether the Bluff aluminum smelter would remain. The development projects delivered so far and those to come in the next 3 years will deliver almost 2,500 gigawatt hours of new annual generation, a 6% increase on -- to the electricity system. And this is part of a wider industry effort that added up means New Zealand is now building new electricity generation at a faster rate than was capable at the height of the Think Big era in the late '70s and early '80s.

Now our existing assets matter too. In fact, they are the backbone of the business, and we're extremely lucky to have a world-class team working hard to maximize availability and output. This includes work to add new capacity to existing assets where we can and restore capacity through issues such as transformer outages. We're already delivering some exciting results, including 110-megawatt uplift of additional dispatchable capacity. This is the result of lots of small gains achieved through activities like unit upgrades and compressed maintenance windows, and it all adds up to more than we get from installing an extra unit at the Benmore Power Station. But it wasn't all play sailing. This year, we faced a few challenges with plant failures. And as we talked about last year, transformers have been a headache. Things are now looking much better on that front. We signed deals to procure 5 new transformers for Manapouri and earlier this month, completed the installation of a replacement transformer at West Wind.

It's also been a busy year for the retail team as they transform the operating model to deliver digital and data-driven customer experiences. And this year, our mass market volumes and market share grew about -- grew across both Meridian and Powershop brands despite lower market demand. Customer numbers lifted by 70,000 over the year. Half of this was a result of organic growth, which is amazing and half through our May acquisition of Flick Electric’s hedge and customer books. This growth reinforced our position as the fourth largest retailer by customer numbers. While Meridian's residential energy price increases were modest again this year, the regulated increase in lines and transmission charges that form part of the overall bill is going to impact all customers for a few years to come.

This is a difficult reality as we know many New Zealanders are doing it tough. Cost of living pressures are more than a media headline. They are real and they affect many Kiwi families. We're doing what we can to help. And part of that is building more generation capacity. But within retail, the focus is on reducing the size of a customer's overall energy bill. And we've made good progress this year with new products like 4 hours free and smart hot water that give customers more choice and flexibility. Smart hot water rewards customers with $10 off their monthly payment, allowing us to take control of their hot water heating and move the demand outside of peak periods to help take pressure off the grid. We now have around 20,000 customers on this plan and have shifted around 500 megawatt hours out of peak periods over each of the past few months. And this is just one of our initial steps.

Ultimately, we plan to create a variety of products that help customers work with us to manage their electricity use and budget. The retail team also began the rollout of a new Kraken platform and a new customer app. These changes are aimed to improve how we engage with customers and how we track and support them to save energy and money. We also continue to support customers in need through our Energy Wellbeing Programme. The goal is to support 5,000 of our most vulnerable households via this program by Fin year '28. This year, over 1,700 households were supported, and we've now assisted 3,185 households since the program was launched in 2023. Kiwis are facing financial challenges given wider cost pressures. So we'll continue to monitor how we can make a meaningful and sustainable difference for those in hardship. It was also extremely pleasing to see Powershop topping the Kantar Customer Leadership Index for 2025, which was announced just over a week ago. This is particularly special for us because this index spans multiple industries and ranks companies on how well they deliver for their customers across brand, service offerings and customer focus. Ka pai team.

This year, we conducted a review of the half by 30 emissions reduction target. Scope 1 and Scope 2 targets remain well on track at 50% reductions by Fin year 30, but the target for Scope 3 emissions has been revised. Halving these by Fin year 30 is now, in our view, not possible given the amount of sector growth the country is planning and the speed at which this needs to happen. From 1 July, we began using an intensity-based target for Scope 3 emissions. This involves a target based on dividing the supplier base emissions by the total installed capacity of Meridian's generating assets. It allows Meridian to work towards a target that means there'll be less emissions for each megawatt of capacity installed.

Meridian is targeting a reduction of more than 51% by 2030 and we will start reporting on this year. The refined Scope 3 goal remains credible, ambitious and science-based and has been independently verified by the Science-based Targets initiative. Pleasingly, Meridian was ranked #1 in the electric utility sector in the e Dow Jones

Best-in-Class Sustainability Asia Pacific Index, an independent global Standard & Poor's index that ranks our environmental, social and governance performance against companies -- like companies in the region. This is the 10th consecutive year we've been included in the index, but the first ranked #1 in Asia Pacific. And I hope this gives shareholders, customers and communities confidence that we're leading in sustainable practices as well.

Now I'm sure it goes without saying that we relieved to have last year behind us, and I'm pleased to say we're off to a strong start in Fin year '26. We're experiencing good spring winds and rain. We're benefiting from the introduction of the e Ruakaka BESS, and we have above average late levels in both in the Waiau and the Waitaki catchments. While another neutral to weak La Niña summer is expected, which can bring dry conditions, we're happy with how things currently stand. And as I've outlined, the business is extremely well positioned for future growth.

Mark touched on the Frontier Report and Government Energy Reform Package announced at the start of this month. I want to reinforce the importance to us and the industry of the clarity these reports provide and the significance of putting the uncertainty behind us. We've experienced 14 months of intense media and political scrutiny. But in the end, 3 world-class independent firms of economists concluded that our market is well structured and performing well, that vertically integrated companies like ours are positive for customers and that our market has healthy competition.

I cannot stress these 3 elements enough, particularly with next year being a general election and the likelihood that some of the tired old arguments about our sector will be recycled. We do expect the scrutiny to continue, but we'll have no hesitation in reminding the public of the facts presented by those expert international firms. While Meridian is laser-focused on continuously improving how we serve our customers, I also know that shareholder confidence can be chilled by the constant threat of major regulatory change looming year after year. The size and place of investment this sector is now delivering directly underpins the health of the broader economy. So let us get on with it. You'll see more evidence in the year ahead of Meridian team executing on our strategy, delivering for customers, working alongside communities and growing value for our shareholders. We appreciate your continued support for our business and enabling us to deliver on our purpose of clean energy for a fairer and healthier world.

Thank you for this and for your participation today.

Thanks, Mike. And now to question time. Before we open up to the live audience, I'll begin with the one written question that was submitted in advance by a shareholder. The written question comes from [ Mr. Jack Reden ], who asks, how long should customers have to wait on a phone call to be answered? And how long should customers have to wait for an e-mail reply?

[ Mr. Reden ], thank you for your question. We always endeavor to answer customer communications as promptly as possible. Over the past year, our average speed to answer for chat and calls was approximately 14 minutes across both brands for residential customers. That is an average, and it does vary week-to-week and seasonally. Our average e-mail wait times for residential customers was 4 days, again, varying week-to-week and seasonally.

As you will have heard in the session today and as written in our annual report, we have experienced unprecedented growth over the last 12 months, increasing customer connections by over 70,000. The retail team is also making significant changes to both our systems and operating model so that we can better deliver products and services to all our customers. While this is the current status, as I've outlined in terms of wait times, we are aiming to improve our response times considerably as we complete the migration of customers to our new Kraken platform and embed a new way of working.

From here, I will ask shareholders present today in the room first for your questions. If you have a question to raise, please raise your hand and wait for the microphone to be passed to you. Then if you could, before asking your question, state your name so that we can record it properly in the minutes.

And now we -- so the floor is open. Yes, sir.

My name is Thomas, and I saw you guys have a lot of investments on the [Audio Gap] But just wondering, do you have other strategy level to check how to do the things smartly like offload the peak time usage more. So that means you don't have to invest too much on the assets. And also the EV charger -- do you have any plan to kind of utilize the EV cars to backfill your peak usage time?

Thank you for your question. We are doing both. There is quite a prize for us in what we would call broadly demand response, that is where customers feed back into the system, which avoids the need at peak times to inject so much other generated power into the system. And part of the reason for moving on to the Kraken platform is to enable us to utilize that even more. We've already got people on smart water plants. Lisa, how many do we have currently?

20,000.

20,000 now. That number has grown considerably. We've also got EV packages for our customers. But the aim is to, over time, to the extent that customers will trust us is to help us manage their electricity consumption such that we can use it back into the overall system. So there's quite a big prize for us in that. So it's a very good question, but it's -- that alone won't solve New Zealand's issues. We've got to do both.

Any more questions from the floor? Yes, sir.

[indiscernible] Solar energy demands land. How competitive is this now becoming? And how is that affecting the prices of land given rural situations, in particular, the likes of farmers and farming sector and the forestry sector.

Right. Good one for you, Mike.

Yes. I mean solar development, I mean, solar is a technology and the cost of deploying solar arrays has come down massively, which is why the technology is being explored in the country. Obviously, when you build a solar array, you do affect the land use if it was current -- if it was previously farming land. Primarily dairy farming is it becomes harder to farm dairy. But people running sheep or beef, it's not as big a challenge. So the land use challenges aren't as significant. We haven't picked up any impact on competing land values, so driving cost of rural properties up.

Often, you can find marginal land that suits the purpose of developing solar farms and arrays. And where there are opportunities to use more productive land is we haven't noticed any impact on the competing uses of either farming or solar arrays.

With the solar plants in place, what additional use of that land is possible?

Are they often -- so what you'll see, as I say, for marginal land, what we tend to find is land that isn't used for farming is -- we'll tend to restore wetlands as part of building a solar farm. So we actually improve the quality of the land that existed before we put the solar array on. Where you're putting a solar array, say, on a dairy farm is you put the solar panels up. There's still enough sunlight to grow grass, but just not enough for milking cows. And so what they tend to do is replace the cows with either beef or sheep. So the grays underneath the solar arrays.

All right. Any more questions from the floor?

You've explained that you've had quite a gain in customers during the past year, yet there's been quite a substantial downturn in the financial accounts. But with respect of having more customers, have you become more competitive? And are your energy prices likely to remain? Or are they going to be less for the customers?

Do you want to give a go?

Yes. Well, I think we've got a stated ambition to, as I mentioned, to grow our relationship with customers. It's really important given the challenges that the country is going through that we are very effective in that regard, and we are very mindful of the cost of living challenges that people are facing.

Now the reality for folks out there is that there are 2 components of an electricity bill is there's a lines and distribution component and an energy component. Over the next 4 years, the Commerce Commission has approved increases in the lines and distribution charges. And so over the next 4 years, customers are going to see increases in their electricity bill. This past year, the increases in the energy component of the bill were -- we were able to maintain those at rates of inflation. So we are very mindful. And then the second thing that we're doing is we are introducing products that better cater to people's personal circumstances.

So you might have heard us talk to the hot water heating product where we'll take $10 a month off a customer's bill in return for having access to their hot water cylinder for short periods of time to move the load outside of peak periods. And so what we're doing is, one, being mindful of the circumstances that people are in. Two, we're honest that over the next few years, there are going to be increases in distribution and transmission rates, and that will impact people. But three, doing what we can to provide products that help alleviate those challenges that people are facing.

Yes. And it's important to bear in mind, we don't control not our assets or charges, the transmission or distribution charges. We pass that through as we're required to. Okay. Yes.

So what's your relationship with distribution company in the New Zealand? I mean, some things is beyond your control like the hot and other things. Actually, there's a repo relay control. But the investment on the distribution company will they put more investment on these [ repo ] control elements? Or what's kind of your relationship with?

Well, we naturally have a relationship with each and every one distribution company, which is interesting because they all often have different requirements. So it's a challenge for the retail team, but they do spend a considerable amount of time engaging with them and trying to influence how they invest their money. So it's not like we're just standing aside and saying, well, that's your responsibility. And it's important that we maintain a good relationship with them because when we want new generation assets connected, we want to be up near the front, if not at the front of the queue to be able to do so. So whilst ultimately, we don't have any control, we certainly endeavor to influence the outcomes in terms of how they spend and invest.

Do you put a proposal or something maybe stand some kind of like a standard because each distribution company have a different standard on their own.

Well, that's the challenge because they have their own different standards. So we're endeavoring across the industry, as I'm sure others are trying to get a common approach. But yes, it's work in progress.

Okay. If there are no more questions from the floor, we'll now turn to our online shareholders. I've got colleagues passing through questions from the online audience. 4, I'm told, 4 questions.

The first one, whilst Meridian ensures that the lead audit partner is rotated every 5 years as required by the NZX listing rules, it doesn't disclose if the audit firm is rotated at 10 years. Notwithstanding tenure, New Zealand Shareholders' Association also expects disclosure of the appointment dates of the lead audit partner and firm to improve transparency for investors. NZSA notes that under the Public Audit Act 2001, the auditor of Meridian is the New Zealand Controller and Auditor General.

The New Zealand Controller and Auditor General ultimately makes a decision on auditor appointments having previously appointed Deloitte to perform the audit of Meridian on their behalf. We would expect the Auditor General to provide some guidance via the company on policy around audit firm rotation and the process to test the market as regards audit fees. And that question comes from Riki Manarangi of the New Zealand Shareholders' Association.

I think, Riki, as you're recognizing, we actually don't have control over who performs the audit on the Auditor General's behalf. That is the mandate of the Auditor General, and it's governed by the Public Audit Act, I think it's called. We have made repeated requests on shareholders' behalf for the Auditor General to consider audit firm rotation. So we're not letting the issue go, but we haven't succeeded so far.

So I hope that answers your question. Next question is from Oliver [indiscernible]. Can you please provide an update on the solar farm at Ruakaka?

Well, I'm pleased to say that the work is underway. I understand the first shipment of kit panels has arrived at Northport and is in the process of being cleared by customs. So we're underway. That the answer to that.

A question from [ Mr. Alexander Glen. ] Mr. Roan mentioned expanding the power output of existing hydro lakes. How might that be achieved? Do you want to answer that?

Yes. I mean it's a great question. It's something that we, as a company, have just started to reexplore given the loss of gas that the country had relied on for many years. But what we're doing is we'll -- we're starting with what we know. So there's a form of existing storage known as contingent storage. So it's water that sits in the hydro lakes that has been historically tucked away for not a rainy day, but a dry day.

So we get access to more water when it doesn't rain or mother nature doesn't play nicely. And with the loss of gas, that the country has been through is we are seeking access to that additional water today through the fast track process. We're also exploring what we might do with our existing asset base, as I talked to a little earlier, like what capacity can we get from our generation assets, how might we upgrade our power stations to be able to use more water that's available to us and look at the existing structures, dam structures and go, could we reoptimize the use of water within those structures and effectively fill those lakes up a little more than they currently are. And then we're rolling our -- well, we don't have the expertise within the business, but we're stepping back to look at the role of hydro generation and particularly the role of Pukaki and Waitaki storage to meet the country's needs longer term storage to meet the country's needs longer term.

Now that's a longer-term challenge because you need to assess many things in making any call or decision in relation to extended hydro development, but it is something that we've started to explore as well.

Okay. Thank you, Mike. John White of Century Securities Limited. Why did you borrow $310 million to pay the dividend?

It's a good question. It's a fair question. Obviously, the extraordinary nature of the droughts last year were a challenge and impacted our cash flow severely. But the counter to that is the strength of our balance sheet gave us sufficient comfort that we could maintain the level of our dividends. In the ordinary course of business, of course, our policy is that we pay our dividends in the range of 80% to 100% of operating free cash flow. But we had the opportunity in this occasion to take advantage of our benefit. There's a reason -- it shows up why we want to maintain such strong settings. We're very conscious of not doing this on an ongoing basis, but it's certainly -- we thought it was appropriate to smooth the path of dividend returns to shareholders. So hence, the decision that we made.

Okay. Is that it? Two more. Right.

Again, from Mr. White, Century Securities. Why was your hedging so bad last year?

Well, one of our major hedge contracts was actually suspended by a counterparty due to unexpected gas availability. And that just required us to write new hedge contracts to support gas purchases from Methanex, and that came at a considerable cost, unfortunately. The long-term contract that we've just agreed through the Huntly Strategic Energy Reserve provides us with cover now that is not so vulnerable -- well, it's not vulnerable to New Zealand's declining gas supply. So we've taken steps since as have others in the sector to replace that. Really unfortunate set of circumstances, one that we do not wish to repeat. Okay.

William James. When does Meridian estimate LNG will be in operation? And would Meridian import LNG from Russia? You want to answer that, Mike?

Well, I don't think Meridian is in the business of importing LNG. So that piece of the answer is really straightforward. But the government is looking at the potential building of an LNG terminal as part of its proposed industry reforms. And we'll know a lot more about that as we near the end of this calendar year and as we step into next calendar year. But right now, the intent, as we understand it is, if possible, to have an LNG terminal up and available for operation before the winter of 2027.

Now with any large investment in infrastructure, there are obviously risks to time lines and timetables. So as we learn more, we will get a better understanding of when and if that LNG becomes available to New Zealand or to our market.

Yes. So we want to be a part of the conversation. We want to be involved in it, but it's way too early to ascertain how that's going to show up. And so we're reserving judgment.

Is that it? Thank you.

Okay. We now come to the formal resolutions set out in the notice of meeting. I'll outline the voting procedures again. For those of you online, you should note now a new icon has appeared on your screen. Selecting this icon will bring up the 4 resolutions and present you with voting options. To cast your vote, simply select one of the options. There's no need to hit a submit or enter button as your vote will automatically be recorded. For those of you who are present today, please cast your vote and place your voting form in the boxes that you will find located at the back of the room.

Persons attending the meeting who are not shareholders, proxy holders or corporate representatives of a shareholder may not vote and that includes bondholders. Many shareholders who are not attending the meeting today have already voted. At the request of the Shareholders' Association, the announcement of the proxy count will be deferred until after the formal resolutions have been considered by the meeting.

So to the first resolution, it's my pleasure to introduce and move the resolution to reelect Julia Hoare as a Director of the company. Julia joined the Board in 2019. She chairs the Audit and Risk Committee, and we consider Julia to be an independent director and unanimously recommend that shareholders vote for her reelection.

So Julia, I'll now ask you to address the meeting.

Thank you, Mark. [Foreign Language] It's a real privilege to be standing in front of you all today and obviously online as well as I seek reelection to the Board of Meridian Energy. Meridian is a really great company, and I've been honored to serve as one of your directors for the last 6 years. As you probably know, I chair the Audit and Risk Committee, which oversees and how we enhance the value of your investment in your company. And it's really important to make sure that we are thinking about you as shareholders.

I also really enjoy contributing to the strategic discussions that we have around the Board table and bringing my wide experience to the Board. In particular, through my governance insights that I have attained from our other 2 Boards, Auckland Airport and also Port of Tauranga. I've been very heavily involved in sustainability initiatives right throughout my career and prior to my governance career, and I still am today.

I'm currently a member of the Chapter Zero New Zealand Steering Committee, whose mission is to mobilize, connect and educate and equip directors to make climate smart decisions. And that really aligns very much with where Meridian is at and what we do. And as you all know, Meridian's purpose is to provide clean energy for a fairer and healthier world. This really aligns with my own values and was actually one of the reasons that I was really attracted to Meridian and was delighted to be approached to join the Meridian Board. I'm really proud of the fact that we produce energy from 100% renewable sources. As we've talked about today, Meridian has an incredibly exciting next chapter ahead. We've got a pipeline of really excellent renewable opportunities, and they will continue to enhance the value of your company. And I'd be very proud to continue to contribute to the team in guiding it to further success.

So [Foreign Language], thank you, and I hope I have your support to continue that journey. Thanks very much for your time.

Thanks, Julia. I now formally move that Julia Hoare, who retires by rotation and is eligible for reelection, be reelected as a director of the company. Is there any discussion or questions? Okay.

I have moved the resolution. I now put the resolution so shareholders should complete their voting for the resolution. I will now pause to allow you time to just submit your vote.

[Voting]

Okay. Thanks, Julian. It's now my pleasure to introduce and move the resolution to reelect Michelle Henderson as a Director of the company. Michelle joined the Meridian Board in October 2019. She serves on the Safety and Sustainability Committee and the Audit and Risk Committee. The Board considers Michelle to be an independent director and unanimously recommends that shareholders vote in favor of her reelection.

Michelle, would you like to address the meeting?

Thanks, Mark. [Foreign Language] I appreciate the opportunity to speak to you today. Meridian Energy's purpose to deliver clean energy for a fairer and healthier world is something I remain deeply committed to. It's important to me that Meridian contributes to an affordable, secure and highly renewable energy system to ensure economic prosperity for Aotearoa New Zealand whilst producing appropriate returns for shareholders.

Meridian's investment and wider performance should contribute to growing our economy and in turn, that will benefit you as shareholders. My engineering background and lived experience from my executive career, including in the electricity sector, is particularly relevant at Meridian as we make choices to deploy capital on both new and existing assets. We're investing in and concurrently building new renewable generation sites under our 7 and 7 program. We're partnering with others in joint ventures, optimizing shutdown durations to restore generation more efficiently and finding new ways to maximize our generated energy. I enjoy guiding the team and working on these important strategic decisions for our business.

You've heard from our Chair and Chief Executive today, they've talked to the work underway to transform the retail operating model, delivering data-driven customer experiences, bringing a choice of products and flexibility, I think, will be a game changer in helping customers to manage their electricity usage and their budget. I support this really important evolution, and I think it will differentiate our retail offerings and bring value for shareholders as well as customers. I remain committed to my own professional development to ensure that I can deepen my contribution at Meridian and other companies that I serve.

Last month, I was confirmed as a chartered fellow of the New Zealand Institute of Directors. And I'm also studying towards the masters and information governance at the University of Auckland to deepen my technology base and expertise in the areas such as data privacy, cybersecurity, blockchain and artificial intelligence. It would be a privilege to continue representing your shareholder interest by serving as a director at Meridian.

So I respectfully seek your support for my reelection today.

Thank you, Michelle. I move formally that Michelle Henderson, who retires by rotation and is eligible for reelection, be reelected as a director of the company. Any discussion?

I've now moved the resolution, and I put the resolution, shareholders should now complete their voting for the resolution. I'll now pause briefly to allow you time to finalize your vote.

[Voting]

Thanks, Michelle. It is my pleasure now to introduce and move the resolution to reelect Nagaja Sanatkumar as a Director of the company. Nagaja joined our Board in January 2020. She serves on the Safety and Sustainability Committee and the Audit and Risk Committee. She has also chaired our Cyber Security Committee and serves on the People, Remuneration and Culture Committee. The Board considers Nagaja to be an independent director and unanimously recommends that shareholders vote in favor of her reelection.

Would you like to address the meeting, Nagaja.

Thank you, Mark. [Foreign Language] Good morning, everyone. My name is Nagaja Sanatkumar, and I'm standing for reelection to the Board of Directors. Thank you for this opportunity to speak with you and seek your continued support. Since transitioning from an executive career spanning retail, technology and general management to full-time governance in 2019, I have dedicated myself to guiding organizations that form the backbone of our economy and society. I have served on Meridian's Board since January 2020 and currently also serve on the Boards of ANZ New Zealand, Southern Cross Insurance and Healthcare and Tuatahi First Fibre.

My purpose and inspiration for my work in governance are to guide and grow infrastructure and core services organizations that are essential for Aotearoa New Zealand's economy to flourish and for our society and ecosystems to thrive. My international leadership experience in digital innovation and large consumer-facing businesses, combined with academic qualifications in engineering, business administration and sustainable development, enables me to contribute meaningfully in commercial strategy, talent development, technology innovation and operational excellence across Meridian's customer value propositions.

I bring a well-rounded and well-informed perspective to governance, helping navigate today's business challenges while positioning the company for its critical role in New Zealand's transition to a net zero economy. As a member of the People and Remuneration Committee and Chair of both the Safety and Sustainability Committee and the Cybersecurity Committee, I work alongside my Board colleagues and management to continuously develop the organization's capabilities, systems, processes and resilience that are imperative and best practice for our employees, customers, stakeholders and shareholders. I am deeply passionate about addressing the energy trilemma that our country faces, balancing security, affordability and sustainability. And I remain committed to seeking innovative and pragmatic solutions to this challenge, holding myself and others accountable to the highest standards of responsibility.

I humbly ask for your support to continue serving you as a director at what I believe is one of New Zealand's best organizations. [Foreign Language], and thank you. I'll now pass back to Mark.

Thank you, Nagaja. I move that Nagaja Sanatkumar retires -- who retires by rotation and is eligible for reelection, be reelected as a director of the company. Is there any discussion?

No. I have moved the resolution, put the resolution. I now put the resolution. Shareholders should complete their voting now, and I will pause to allow you time to do so.

[Voting]

Thanks, Nagaja. Last but not least, the fourth resolution, it is my pleasure to introduce and move the resolution to reelect Graham Cockroft as a Director of the company. Graham joined the Meridian Board in July 2022. He serves on the Audit and Risk Committee, the People, Remuneration and Culture Committee and the Cyber Security Committee. The Board considers Graham to be an independent director and unanimously recommends to shareholders that you vote in favor of his reelection.

Graham, I invite you to address the meeting. Thank you, Mark.

[Foreign Language] Good morning, ladies and gentlemen, and fellow shareholders. Thank you very much for joining us today. I'm very grateful for the opportunity to stand before you and seek reelection. It has been a privilege to serve on the Board for the last 3 years. During this time, I've been very impressed by the quality of the Board and management and by the company's commitment to safety, customers and local communities, including Eiwi. The energy industry globally is going through some significant changes, and New Zealand is no different.

We are trying to decarbonize our energy economy by electrifying as many of our activities as we can and then meet that increased demand through investment in renewable generation and the expansion of our electricity grid. While doing all of this, we also want to ensure we have a system that provides reliable and affordable power for our homes and businesses. Throughout this period of change, there are many opportunities and challenges for New Zealand and Meridian. Recent reviews of the sector by Frontier Economics and the government have described some of these challenges. And just to highlight a few of the examples where I believe there are significant opportunities for Meridian, I just highlight a couple of points here.

First, as electricity demand grows, there is a need for -- not only for more supply, but also for more flexibility and supply to balance the intermittency of wind, solar and hydro. Meridian has world-class assets and capabilities on hydro generation, and there are opportunities for us to build on this strength through expanding our hydro storage and generation capacity. Second, the customer-facing part of our business is also changing as new technologies transform the way electricity is used and even generated in the home and business. With our retail transformation project, we will bring new products and services to market and more quickly to help customers manage their power requirements.

At a governance level, these opportunities and challenges require thorough deliberation by a Board with a range of skills and experience. We have a significant investment program ahead of us, and we'll need to call on all the skills and experience of the Board to ensure we maintain a disciplined capital allocation and preserve the financial strength of our company. For my part, I bring over 30 years of international experience in the energy industry and a variety of executive roles in New Zealand, the U.K., South America and Asia. I'm now on my fourth year as a Non-Executive Director of AGL Energy in Australia. So I'm seeing the energy transition through an Australian lens as well.

Ladies and gentlemen, should you endorse me today, I would be honored to continue to participate in this Board and company and accordingly offer myself for reelection. Thank you.

Thanks, Graham. I now move that Graham Cockroft, who retires by rotation and is eligible for reelection, be reelected as a director. Is there any discussion? We do have a question.

What does the Culture Committee mean?

Well, it's the People, Remuneration and Culture Committee, but the culture part of it relates to the broader working environment that operates in Meridian. Simple as that. So I think I've answered that. Is there any other question? That was from [ Mr. Kelso ].

No. Any more discussion? Okay. I've moved the resolution. I now put the resolution. Shareholders should complete their voting for the resolution. I'll now pause briefly to allow you time to finalize your vote.

[Voting]

Thanks, Graham. Shareholders, thank you for your attendance to the resolutions and the meeting. As advised earlier, many shareholders have already voted by proxy before the meeting and at the request of the Shareholders' Association, we delayed the announcement of those results until after you'd considered the resolutions. You can see on screen now, I can now advise that just under 2.1 billion votes, representing 79% of shares on issue were lodged with Computershare, our share registrar 48 hours before the commencement of the meeting as required.

That concludes the discussion of our items of business. I will soon close the voting system. Please ensure that you have cast your vote on the resolutions. Just pause briefly if you require any more time. Okay. I will now close voting. Thank you for voting. For those in the room, the gentleman standing at the rear of the room has the relevant box to put your votes in. Once all votes have been cast, they will be counted by Computershare and scrutinized by our auditor, Deloitte, and results will be announced to the New Zealand and Australian Stock Exchanges later today.

Thank you for attending our annual meeting. I now declare the meeting closed. Thank you. Now for those shareholders who are actually with us in person today, we love it if you join us for morning tea. Thank you.

[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 [ iwi ] 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 [ path ] 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 shielded 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 we'll 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 dross 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 and 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 winds, 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 calls 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 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. 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 net 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 [indiscernible]. 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 of -- 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-EBITDAF 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 Mt. 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 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 [indiscernible] 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 as 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 [indiscernible] 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 [indiscernible] 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 was 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 giving you probably what you wanted to know anyway.

Yes. 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.

Okay. 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.

But it's good to know it's going to revert back to normal.

Yes, I can't see why it doesn't, Grant.

And in terms of the HFO costs that you've taken on now, how do those relate to your historical type of demand response costs and general swaptions that you used to? Is it a bit elevated because of the 10-year contract?

They're okay. I shouldn't say that, that's in front of the Commerce Commission, I guess they'll make the ultimate call. But I think at one level, you could say that the cost base for that contract is higher than some of the demand response and swaptions that we'd entered -- the gas back swaptions that we had, but not unrealistically or unreasonably so. So the Strategic Energy Reserve Agreement, it feels like a reasonable approach compared to the alternatives, whether that be demand response or trying to find some other measure. So not unreasonable, but we don't mind paying less.

A final question, you guys might not answer it, so I'll lowball it anyway. The consensus is sitting well above $1 billion. Are you happy with that on an EBITDA forecast to at least beat $1 billion if hydro plays a role?

I think I'd leave that to you, Grant, for that forecast. I mean, you know we don't provide forecasts, that...

But you're cognizant of where consensus sits and not too uncomfortable with that?

Yes. I think that, Grant, there are obligations on businesses to provide updates to the extent consensus and internal forecasts vary materially, and we're really mindful of those.

Your next question comes from Vignesh Nair with UBS.

A couple of questions. Firstly, sort of pointing to in the presentation, we've seen 2 One-in-90-year events from a hydrology perspective this year. I think anecdotally, you're hearing such events getting more and more frequent. Do you think there's a pattern emerging or a structural change in terms of hydro volatility in the business?

So I'd tell you the interesting thing is no. All our modeling shows that as climate change has a bigger impact on the country that the catchments in the South inflows receive more water in bigger doses. So that's what all the forecast, whether it's NIWA or any of the climate scientists, that's what they'll forecast and show and that's the advice that we get.

It just -- sometimes it happens, Vignesh. We know the risk. I think that's the key thing with our business. We know the risks. We know droughts are inevitable ultimately. And so we manage the business with a balance sheet and a portfolio position that can manage them, but that really hurt us this year was the fact that, that insurance, those swaptions that we bought, they failed. And that, as Helen presented, I think I did the same thing at interims is that costs a lot of money.

$300 million.

Yes. So I'll go back to my simple answer, Vignesh, no.

Okay. Perhaps it's just recency biased. I suppose the second question was just a clarification on CapEx over the next couple of years. I think last year, you talked to $3 billion in growth CapEx between 2024 and 2030. Firstly, is that still an appropriate assumption?

Yes. And sorry for any confusion in there, Vignesh, is when I talk to $2 billion or $1.6 billion, I use a couple of numbers in there. The ambition is still through 2030 to land $3 billion worth of capital. The numbers were just different periods.

And that's just purely growth, not...

Yes.

Not stay-in business. It's just -- yes. And so given that backdrop sort of implies your guidance into next year possibility as a result this year and last year, spend of about $700 million for the 3.5 years leading into 2030. Is that still fair?

Yes. Although some of the developments, they don't all come -- they're not all equal, Vignesh, is when you look at developments like Te Rere Hau, you do have to land a couple of big ones in there to get to those sorts of numbers. But look to those bigger developments that are flowing through our books and through the pipeline, you can easily see where that money comes from or that forecast comes from.

And the big one next is Te Rere Hau.

Yes.

Yes. That's very clear. And -- yes. And finally, is the balance sheet still structured in a way in which to support, I suppose, flat dividends for 2 dry years, I think, was the previous, I suppose, standard. Is that still going to be the case through this phase of elevated CapEx?

I think our reference to May in the statements is we would look at it carefully, Vignesh, if we saw another drought emerge in the short term. Like every balance sheet, you need to restore it. So that's what we were trying to get to was, we know what we have the capacity for, but when you do draw on that balance sheet, you don't have infinite capacity, and we've got this incentive and drive to invest while maintaining our credit rating. So we were just saying to people, if we had another big drought on our hands, we have to look at that big drought. But otherwise, we restore the balance sheet, build these assets and get on with business, which is what we're forecasting to do.

Your next question comes from Stephen Hudson with Macquarie Securities.

Just a few from me. Just the revaluation. I just wondered if you could call out any change in assumptions that are underpinning that $2 billion revaluation this year.

I can take that one. The increase for the generation assets is largely driven by the change in the wholesale market outlook price for the future. The only one change that we did have to our assumptions, which we've included in the financial statements is that we did change our depreciation from accounting to tax depreciation. And that there's a small note of that in our financial statements. But other than that, it's the same calculation and the same methodology that we've had in prior years.

And the wholesale price change, do you have a number at hand there, Helen?

Offhand, I don't have it. I'm just looking to Owen. I don't have that, but we can get it to you.

Yes. And remember we presented at our last Investor Day, we gave like a price range, and we've updated that since that's the latest variation of wholesale market outlook, has popped a little bit, not materially so. But again, we'll give you an update on that very openly and transparently as we did at the last Investor Day in November.

And then just talking of Investor Days, I think last year, the team sort of talked about the potential for a new power station on the Waitaki chain. I just wondered if you had an update on that potential.

So it's sitting in the pipeline, Huddy, is the best I can say, is we're trying to align that with the work that we're doing on wider storage options in the Mackenzie. And obviously, if you're looking at your structures and storage, any new power station that you might add to your structures has got to align with development of those options. And so it's connected to that work. In the meantime, what you might have picked up on today, and I can't remember how more widely we've referenced it, but is the Waitaki Power Station upgrade that's underway. And that's where you'll see a capacity uplift for that power station.

And just on contingent hydro, I think you mentioned the 545 number. There's an alert release and emergency release component to that, sort of 330 and 210 roughly. You've gone for the full 540 in your fast track application.

Yes, we have. But [indiscernible] reminder that it is from a physical perspective, just water flow is the lower that lake gets, the less flows down the canal. It's just friction slows water flow down. And so the deeper you go into that storage, the less water actually passes through the canal. So the first 300 gigs is straightforward operationally for us. The remaining couple of hundred gigs is -- no one's been there before, and so it just is harder to deliver. Our engineers are confident that we can, but the release of that water would be slower than what you would see under normal operations. So it's a great reminder, Steve.

Any -- do you have any clues on what's happening with the Tekapo contingent storage? Do you know if that's subject to fast track application as well?

We don't. Transpower are looking at their -- updating their SOSFIP as well again at the end of the year. And I should be clear, while we have tabled a fast-track application for contingent storage is we're supportive of contingent storage for the same reasons that we laid out for others, whether it's Tekapo or down in the [indiscernible] as you want a low-cost clean energy system to support the economy. The way you get it is you develop your hydro resources and that contingent water is just sitting there and available to us.

Makes sense. Just 2 more quick ones. It sounds like NZAS are in market for 100 megs to bring back Potline 4. Can you confirm that at all and give us any clues as to what they intend to do beyond Potline 4?

So Huddy, I think they're in the market for 50 megs for Potline 4. So Potline 4 is a 50-megawatt addition. We are working with them...

It's 50 plus 50 is what I've heard.

Yes. Look, they would love to expand that Potline and make it a full Potline. They'd love to get it to 180 megawatts if they could. The reality is, you've got to balance that increase in consumption with the development of your asset base. And so what is slowing them down is the same thing that has impacted the electricity sector is we felt good about the renewable investment going into the market as being able to accommodate new growth.

But when we lost access to gas and other fuel that we've had to recalibrate. And so the development that's going on is to replace gas for existing users. And so we're working with them to try and find an economic solution to them that aligns with the development pipeline that we've got. And I'm sure other people are doing the same thing is we've only got capacity to support them for a portion of that increase. And -- but we know they're in market talking to people about it. And we're keen to support it because it's economic growth, but we've got to balance that opportunity against making sure we deliver for people who are already here.

Makes sense. And just last one. We've seen one of your competitors sort of start to talk a little bit more openly about developing off balance sheet. I just wondered if you had some early views on whether or not we could see a similar change for you.

Yes. Steve, I mean, we already are. So Te Rahui is a development, it's joint venture development, it's a [ majority ] project finance. I think the total cost is $370-odd million. And for Phase 1, it's a 400-megawatt development. It's in 2 stages. Stage 1 is 200 megs. I think that first, as I said, the cost is about $370 million, but most of it is project financed. You saw us work with wind farms that would have been a joint venture. And we've got a PPA in place with Tauhei, the joint Clarus, Harmony solar farm as well. So we're open for business. And what that means is our balance sheet structuring with others in whatever way it makes sense for them and for us.

There are no further questions at this time. I'll now hand back for any closing remarks.

Thank you. Only closing remark is to close. Thanks, everybody, for your time this morning. Appreciate you being here and on the phones and for your questions, they were excellent. Thank you.

Thank you.

That does conclude our conference for today. Thank you for participating. You may now disconnect.