Good morning, everyone, and welcome to Meridian Energy's interim results presentation for the 6 months to 31st of December 2025. I'm 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. What are 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 Motu, 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. There was some sound decisions made by Rory Blundell and his portfolio team over the period as well.

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. This slide touches on that as well.

Over the next 12 months, Mount Munro, Te Rere Hau, and Te Rahui solar stage 2 will be set for investment decisions. 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. 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 TWh 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, 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. 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. You can really see what a fully fueled renewable electricity system produces, particularly in the spring of both years.

Now 2025 was a recovery year, and while it didn't go perfectly, it demonstrated that progress was being made, with a key marker 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 to 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 Ruakākā solar farm and the Te Rahui solar farm being delivered through our joint venture with Nova.

When complete, they'll add 702 GWh 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. 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. 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 would 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, 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. 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.

It'll continue to increase, most likely until demand falls for it materially. That will only happen if people can no longer afford it, 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. 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. 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.

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.

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, as that's what will drive actual outcomes, and will determine whether my forecasts that I just mentioned is accurate.

Now I like this graph cuz it's really clear. Since 2024, Meridian's added 542 GWh of new generation to the electricity system.

As I mentioned earlier, there's 702 GWh under construction. Looking forward, I anticipate we'll commit to all consented projects, or just over 1,300 GWh, inside the next 12 months.

Meridian's pace of investment is increasing. To provide context, the total gigawatt-hours of constructed, in construction, and consented projects is over 2,500 GWh, which will grow Meridian's business by more than 15% when complete.

Beyond this, projects and timeframes are ultimately in the hands of consenting authorities. We have 720 GWh in the consenting process, and expect projects totaling just over 2,900 GWh 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. The sector's 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. 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 timeline 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 Tōhei, a 200 MW solar farm that's being 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 Ruakākā is an integrated energy park. It'll have both a 100 MW, 200 MWh battery and a 130 MW solar farm connected to the grid through one transformer.

We've done this as we don't think the economics of standalone 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 one transformer for two assets, then the economics change, and collocated batteries and solar arrays work really well together.

As the picture shows, construction of the solar farm is well underway at Ruakākā. 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 Ruakākā.

Stage 1 of the solar farm at 200 MW will ultimately be larger than Ruakākā, it's important. Completion of stage 2, which is another 200 MW, will make the farm nationally significant.

We, Meridian and Nova, have begun a conversation on how and when to approve it. 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. It wouldn't make too much sense to have a gap between delivery of the stages, take that for what you will.

Mount Munro is a cracker of a little wind farm, and it's good to see that it'll 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 Manawatū solar and battery park will largely replicate Ruakākā, which is why we can push this development along so quickly. I'll finish with Te Rere Hau.

It's a magnificent site, and it'll become the most productive wind farm in New Zealand when complete. It's frustrating that it's taken 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 Manawatū is designed for solar farming.

Waikato's no different. Consents for these assets are not controversial, unless something unexpected plays out, the timeframes for consenting them will be pretty quick.

Manawatū will be first cab off the rank given its colocation with the battery. As for Waitaki 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. 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.

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'll do this at the stroke of a pen. It's had its challenges.

To be clear, we must get system security settings right as we unlock this value for consumers. We must also make sure that our neighbor's assets remain operable if it's ever used.

From where I sit, both can be managed. 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. We've been working with everyone who'll present their views to the panel, and we're up for compromise to get this through.

Hopefully consumers will be the beneficiaries in July. 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. 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 two 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, they're longer-term commitments, but they are important if we're to grow this economy and manage the transition to even greater electrification. 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's still finalizing details, a final investment decision will likely be in the second half of 2026.

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 suggests we're doing a decent job.

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'll be crucial in delivering on our strategic ambition to make electricity cleaner and cheaper for all. 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.

We're never bound by a June date, and it won't cost us any more money, it'll 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.

Over to you, Mandy.

Ngā mihi, Mike, and kia ora, 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 2026 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 2025.

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 2024, 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 close out 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 6.15 cents per share to 6.40 cents 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 Windfarms into the Meridian result. 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 two green movement bars.

This is almost two-thirds 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.

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 also down more than 50% on last year.

Those lower spot market prices saw significantly reduced customer supply costs despite the higher customer volumes. Just on the small negative $1 million bar in the middle, that is NZAS sales.

Despite an Option 4 demand response call in the prior year, NZAS sales volumes were little changed from the first half of FY 2025. That reflects our volume under the contract reducing from 472 MW to 377 MW 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.

Overall, that has meant a $246 million lift in physical energy margin. Then on to financial energy margin.

Firstly, let me just say trading and 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 GWh 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 2025, we called the largest demand response from the smelter.

While the very early months of FY 2026 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 2025.

Now we'll look in more detail at retail sales, with mass market volume up 16% on the first half of FY 2025. 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. While you can't see it on the slide, this has extended into January.

Generation volumes were 892 GWh, 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 Manapōuri, but also at Pūkaki, 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 Pūkaki is entirely possible from an engineering point of view.

Throughout our most recent spill events, this would have more than halved the 521 GWh of spill, providing enough additional cheap, renewable generation to power the equivalent of a third of Auckland's homes for 2 winter months. From an asset maintenance perspective, GM of Generation Tanya Palmer outlined at last November's Investor Day the significant multi-year work programs underway around the Manapōuri 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 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 to $360 million. Of the $86 million capex in this period, $53 million was growth capex, with construction beginning at Ruakākā solar farm and the implementation of Kraken.

Stay-in-business capex includes work underway on the Benmore penstocks, replacement transformers at Manapōuri, 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 a $120 million gain before tax in this period versus a $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 2024, 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 2025 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 1.9 times, down from 2.5 times 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. With that, I'll hand back to Mike for his closing remarks.

Thanks, Mandy, and well done. Hey, 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.

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 Pūkaki is full late February. The investment profile remains strong, and while Te Rere Hau delays are definitely frustrating, they've opened a door for Mount 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 and the country faces is reducing significantly.

While up to 4 TWh is required to mitigate national risk today, by 2028 that drops below 3 TWh, and by 2035 falls to around 2.5 TWh. This factors in the Huntly strategic reserve and Pūkaki contingent storage, touch wood.

The key is the huge volume of current and planned renewable buildout. The more renewables we build, even if they're intermittent, the more we protect our lakes and the Huntly stockpile.

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. 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 seven times what China is, and to have a competitive country competing against China when your electricity costs are seven times more doesn't seem very sensible, especially with regard to the renewable 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.

I can't understand why the government doesn't try and go for the cost of lines companies given that 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 our lines costs, and can Meridian lobby the government with other generators to try and address the lines charges with respect to people's power bills?

That's the first question.

Thanks, Peter. I think there were maybe a couple in there, but I'll try and take the two that I think I heard.

I think, first, for an economy to prosper, you've got to have reasonable or low energy prices. That's how economies perform.

New Zealand's been really, really fortunate historically that we have had low international energy prices. 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.

That is driven by the fact that we've got a whole wealth and bounty of renewable assets to deploy. As you saw, we've been through some challenges with gas, but we are deploying more of that renewable asset base.

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. 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. 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?

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.

As a company, we are really placed with a strong balance sheet to support the investment that we've just framed. As we look forward, we can see capital constraints possibly beyond 2030, but that'll depend on what we're able to do before then, and that's some time away.

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

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.

There's nothing in our current investment profile that requires that. Then

the last question is with regard to baseload and New Zealand independence, Ohai 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, if we have dry problems in the South Island, is a baseload available if the Whiti doesn't make wind and hydro possible, or solar? 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?

Again, Peter, providing forecasts is 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. It's certainly not in our plan to invest in some form of coal backup in the South Island.

I think what will play out is, as I kind of talk 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 TWh today to around 2.5 in future. 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.

Morning, Mike and Mandy. Can you hear me okay?

Yep. Got you.

Brilliant. Thanks for the presentation.

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 that, though.

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. Next time we catch up, I'll probably be able to give you a bit more info.

Perfect. Look forward to it.

Second question, do the economics of the Manawatū battery make sense alongside Manawatū solar alone, or do you actually need some of your other projects to maximize the value of that battery? Hey,

the economics standalone solar farm in the Manawatū 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 Ruakākā. It does come down to the cost of the transformer to connect it to the grid.

Preference would be to invest in both, but as we'll only make investments if the economics make sense for us. We would need to see better battery pricing certainly than we saw at Ruakākā, and we would want to see the benefits of ongoing improvements in battery economics before we make that decision.

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

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

Oh, sorry, Josh. No.

Or

does Manawatū solar do it alone?

Manawatū does it alone.

That's helpful. Thanks.

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.

Brilliant. Thanks very much, guys.

Cheers, Josh.

Morning, Mike and Mandy. A couple of questions.

First one, just looking at the cost of the wind projects, and particularly Mount Munro actually. 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 here? I do realize that both of these wind farms have got circa 50% capacity factors, so that does help the LCOE numbers.

Are there any particular sort of one-off costs associated with those projects, or do you sort of see this is 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. 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. The dynamics, particularly in the turbine space, have changed a little bit from Harapaki.

We'll see. It's like everything: if you can get a bit of competition, you can get a better 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 assumed the difference between Mount Munro and Te Rere Hau, though, is that I think you're probably looking after the cost of moving the Airways site, for example, which would be a few million dollars, I imagine.

It is, Andrew, but it's not substantial, it really isn't. Those costs, it's more frustration in the time that it takes to effect those outcomes at Te Rere Hau.

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. You've been up there, it's an unbelievable wind site, 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. Yeah.

Okay. A couple of questions on batteries.

I'd be interested the Ruakākā 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 EBITDAF 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. 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. 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.

From that perspective, it's delivering as we expected, but the arbitrage hasn't been there. I don't have a number for you, Andrew.

Yeah. Okay.

That would be interesting. Last question also just around the Manawatū battery, it looks like you're talking about a 4-hour battery there, which I think will be the first one in New Zealand.

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 being mostly on the sort of protecting the retail side of things. Is that sort of a fair assessment?

There'll still be a benefit in that battery in helping manage that portfolio optimization 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. We've got a bit of a trade-off to make ultimately between a 2-hour battery, what you've seen at Ruakākā and elsewhere, and can someone make a 4-hour battery economics work.

We'll see. Don't know the answer to it yet, Andrew.

Yeah. Okay.

All good. Thanks for that.

Cheers, mate.

Good morning, Mike and Mandy. Can you hear me?

Yep. Coming through loud and clear, Grant.

Yes.

Fabulous. Contact and Mercury came out, and they've both indicated that they're expecting about 3.5 TWh of demand through to 2030.

Does that sit well with you guys?

Yep, I reckon we've got

something

very, very similar. Then

about 2.5 TWh of thermal displacement?

Our number might be a little lower on that, Grant. Oh, I'm not going to give you a number,

but

we'll get you one today. I think slightly lower.

That's all right. Less than 6 TWh of renewable availability.

You guys have 2,000 GWh penciled in and part share inked in till 2030. Contact's 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 GWh of potential by 20 30. Who's going to get out the way?

Oh, we'll wait and see. Good question.

It's funny, hey, how these things move from undersupply to oversupply very quickly. It happens, right?

You're a capital-intensive industry, is you deploy, as Grant's 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. 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. It's early days, they are actively looking for new sources of consumption that are not in that demand forecast that you mentioned, Grant.

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. 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.

As I say, I don't want to talk that up here and now. I just wanted to answer the question.

It is something that we are working on in parallel with investing in new assets on the supply side.

Thanks, Mike. 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.

Thanks. My final question, a bit for Mandy, but for yourself, that dividend is up 4%, but only less than inflation over the 2 years since the last normalized year.

Should we interpreting that as a board's conservatism, or should we expecting that cash flows will convert into dividend, meaningful dividend growth, in the second half?

I can't comment specifically on the second half. It obviously depends on the result for the second half of the year.

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

Thanks, Mike. Thanks, Mandy.

Thanks for your answers.

I think I'm done with closing remarks. Thanks for the questions, everybody.

Thanks for your attendance. Hope you got something valuable from it.