Interim Results Announcement transcript

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

It is great to be back talking to investors and media about the performance of the business, and doing so with strong, or what I would term as more normal, financials to support the conversation.

So, what are the key elements I would like you to walk away with today?

First, this result was supported by the fact that it rained a lot in the Southern Alps through Spring and Summer, and that it was windy through the motu, as Spring tends to be.

But 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.

But the result frames historical performance, and while that should provide confidence what also matters is how we set the business up for future success. And that success relies on growth.

So, this slide touches on that as well.

Over the next twelve 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 will also start to see the early impacts of the Generation team's efforts to move its

practices to predictive maintenance. But we will do that slowly given the value at risk.

And it is 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 $1.2bn on those investments I just mentioned.

Once completed they will 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 very 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 am 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 has been achieved, but more importantly will be, delivered.

P4 Wholesale Electricity Pricing

And what a difference a year makes.

As the graph at the top of this page shows, wholesale electricity prices over the past twelve months were a lot more tolerable than the previous year. You can really see what a fully fuelled, renewable electricity system produces, particularly in the Spring of both years.

2025 was a recovery year and while it did not go perfectly it demonstrated that progress was being made with a key marker being 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 JV with Nova. When complete, they will add 702 GWh to the electricity system.

In 2026, 2027 and 2028 we will 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 - futures prices - the fully fuelled renewable theme has flowed into the 2026 contract.

And while 2027 and 2028 prices have come off, they remain stubbornly high. Now I do note that this graph was last updated Monday and prices have fallen since then. So, even as market participants remain concerned about the risk of price spikes and droughts it seems that they are increasingly aware of the avalanche of investment that is 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 2028 and 2029 prices in particular.

While on LNG, I will talk to it quickly here.

The Govt 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 is 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.

P5 Residential Electricity Pricing

While the electricity sector is a key enabler of a green economy and growth, we do recognise 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 ten years before 2024 that is exactly how it played out.

As I mentioned earlier, the best way to do this is to invest in new generation. So, 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 cannot talk to Rates increases but gas is increasing quickly as it is the fuel that is in short supply. So, it will continue to increase, most likely until demand for it falls 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 is a tough truth for gas users - residential or not - but it is an honest one.

So, if you can get off gas.

Electricity inflation, on the other hand, is being driven by the factors on 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 are not the key contributor to the overall increase.

And if you remember my point earlier, we will 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 three years at least.

So, all going well, in my view we will be able to bring the energy portion of 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 that I am not trying to point the finger at others here. We are going to need stronger transmission and distribution networks, but as the costs of those activities are regulated and tend to flow through electricity bills before the benefits show up, I suspect ongoing lines and transmission increases will become a regulatory/political issue as the heat comes out of the energy component.

P6 Meridian Construction s Development

Which brings me back to the pace of investment as that is what will drive actual outcomes and will determine whether my forecast above is accurate.

I like this graph as it is very clear.

Since 2024, Meridian has added 542GWh of new generation to the electricity system. And as I mentioned earlier, there is 702GWh under construction.

Looking forward, I anticipate that we will commit to all consented projects, or 1,302GWh, inside the next twelve months.

So, Meridian's pace of investment is increasing.

And to provide context, the total GWh of constructed, in construction and consented projects is 2,546 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 720GWh in the consenting process and expect projects totalling 2,920GWh 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 are 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 will see further downwards movement in forward electricity prices.

P7 Renewable Development Pipeline

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 on talking to it in detail but if you look closely you will see that the wind pipeline has been upweighted. You may also have picked up Tauhei, a 200MW solar farm being built in the Waikato, that was not captured in earlier slides. We do not own that farm but we are taking the electricity produced from it for 10 years.

I will now cover off each development in turn.

P8 In Construction

First, those in construction.

As you know, Ruakākā is an integrated energy park - it will have both a 100MW/200MWh battery and 130MW solar farm connected to the grid through one transformer.

We have 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. But if you can buy one transformer for two assets, then the economics change and co-located batteries and solar arrays work well together.

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

The picture of Te Rahui also looks great but it's a stylised representation of the farm, rather than a real one, as it's construction window runs through mid-2027 as opposed to Q1 that year for Ruakākā.

Stage 1 of this solar farm, at 200MW, will ultimately be larger than Ruakākā so it is important. But completion of Stage 2, which is another 200MW, will make the farm

nationally significant and we - Meridian and Nova - have begun a conversation on how and when to approve it... but it is too early to provide certainty today.

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.

PG Consented and FID

Mt Munro is a cracker of a little wind farm, and it is good to see that it will get a green light later this year, all going well. I am really looking forward to progressing it as it has 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 will finish with Te Rere Hau. It is a magnificent site and will become the most productive wind farm in New Zealand. It is frustrating that it is taking longer than

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.

P10 In Consent

Now for the longer dated list - as the pictures show the geography for both Swannanoa and Manawatū is designed for solar farming. Waikato is no different. And consents for these assets are not controversial, so unless something unexpected plays out, the

timeframes for consenting them will be pretty quick. But Manawatū will be first cab off the rank given its co-location with the battery.

As for Waitaki reconsenting, the formal process is complete and we expect a decision later this year. There is always a risk of appeal but if that plays out, it won't have any impact on operations, because our existing consents rollover, but we'll have to work through more red tape and legal fees to secure the new consents.

Progressing contingent storage has been more difficult than I expected.

When the Frontier Report was released last October, one thing everyone agreed on was that New Zealand needed to find more firming solutions.

So, I thought that this one would be straightforward as it is 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 has 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 neighbours assets remain operable if it is 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 is the only option that will create

immediate consumer benefit.

And we have been working with everyone who will present their views to the panel, and we are up for compromise to get this through.

So hopefully consumers will be the beneficiaries in July.

And for anyone who looks at this cynically and thinks this is only about Meridian's 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 $400m.

The reason we are pursuing it, is that it is simply the right thing to do in the midst of a cost of living crisis.

P11 Fast Track

In the next few months, we will ask for fast track referral for two large energy projects -the integrated Waiinu wind and solar park and the Western Bays solar farm.

As you can see here, they are massive in NZ terms.

If approved, these investments will not produce electricity until 2030 and 2031

respectively, so they are longer term commitments but they are important if we are 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 it's capacity.

While the team is still finalizing details, a final investment decision will likely be in the second half of 2026.

P12 Our Customers

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 are able to provide the products and services that support and enhance the lives they lead and the businesses they run.

We are putting considerable effort into getting better at both and as the graph shows, the growth in customer numbers suggest we are doing a decent job.

But we do not take our relationship with customers for granted which is why we are 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 have slowed the migration down a little to make sure we manage that experience - there is nothing material that we have found, just your typical niggle as we cut in the new technology. But we were never bound by a June date and it won't cost us any more money so we 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.

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 FY26 first half year

operating cash flow of $336m and EBITDAF of $506m.

Putting that result into context is somewhat complicated by the difficult conditions faced by the company in FY25.

In a straight comparison with the previous equivalent period, July to December 2024, the current result shows operating cashflows $286m higher and EBITDAF $249m higher.

However, I believe it is more useful to compare to the year before that, the first half of FY24, when more normal conditions prevailed. In that comparison, operating cashflows are $33m or 11% higher and EBITDAF $63m or 14% higher. What we see is the growth trajectory returning as we bounce back from the unusual result last year.

Comparing the two, gross operating cash flows are $85m 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 cashflow component such as settlements of derivatives, or movements in cash collateral levels. These timing differences are expected to mostly wash through by 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 cps to 6.40 cps. 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 March.

Now onto 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 five 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 NZ Windfarms into the Meridian result.

So, coming back to energy margin in more detail.

Firstly, the increase in retail sales, a total of $133m - that is the sum of the first two green movement bars. This is almost two thirds driven by volume - that's $84m 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 $1m 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 FY25. That reflects our volume under the contract reducing from 472MW to 377MW from 1 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 Aluminium Prices in 2027 being higher than 2026.

And so overall that meant a $246m lift in physical energy margin. Then onto 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 953GWh 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 FY25 we called the largest demand response from the smelter. While the very early months of FY26 still had some demand response call fees included, overall you can see the demand response costs were down $72m.

With this included, financial energy margin lifted a total of $20m on the first half of FY25.

Now we'll look in more detail at retail sales, with mass market volume up 16% on the first half of FY25. 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 added a significant $117m of additional revenue.

CCI 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 onto 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 892GWh or 14% higher than the previous July to December period

This long period of high inflows has meant we have 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 metre 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 521GWh of spill, providing enough additional cheap, renewable generation to power the equivalent of a third of Auckland's homes for two winter months

From an asset maintenance perspective, GM Generation, Tania Palmer outlined at last November's investor day the significant multiyear work programs underway around 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 programme, 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, potentially into early 2027.

Increased wind component costs reflect investment in lifting wind farm availability. We have 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 $311m-$316m, 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 $330m to $360m

Of the $86m capex in this period, $53m 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 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 unrealised energy and treasury hedges moves a great deal year on year, and so stripping out this movement, which was a $120m gain before tax in this period versus a $154m loss in the first half of last financial year, is important in comparing performance between periods. Underlying NPAT shows $143m profit compared to a $5m loss in the prior first half year.

Looking back to FY24, two years ago, you will see underlying NPAT was higher than in the current period. That is the impact of the $2bn increase in the valuation of generation and plant assets at the FY25 year end, flowing through to a $36m increase in depreciation and amortisation.

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 will 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 MWh.

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.

P26 Closing Comments

Thanks Mandy.

It is very pleasing to have had a strong first half year performance. It's a great one for Meridian, and our shareholders, but also for the New Zealand economy. The country needs companies like ours to be performing well.

And the country can expect more of it. The business has not slowed down since December.

It is too early to tell how things will play out in Winter 2026 but it certainly feels good that Pūkaki is full late February.

The investment profile remains strong and while Te Rere Hau delays are frustrating, they have 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.

And 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 2.5TWh. This factors in the Huntly Strategic Reserve and Pūkaki continent storage (touch wood), but 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. 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 room, if you could put up your hand, if you would mention your name, and then ask the question, that would be great.

Peter Wakeman: 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 of 7x more, doesn't seem very sensible, especially with regard to the 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 commission at the time approve 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 is the first question.

Mike Roan: Yes. Thanks, Peter. I think there was maybe a couple in there.

But I will try and take the two that I think I heard. I think, first, for an economy to prosper, you have got to have reasonable or low energy prices. I mean that is how economies perform.

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

And while they have gone up over the last few years, we still compete really well for a small island in the middle of Pacific. And that is driven by the fact that we have got a whole wealth and bounty of renewable assets to deploy. And as you saw, we have 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 is 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.

Peter Wakeman: It is and the publicity does not seem to show with the low

electricity prices for generation at the moment. But lines companies seem -- 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?

Mike Roan: Yes. I mean -- so I mean, jump in, Mandy, if she something

you want to add here, but the simple answer is no. Peter, we have been peering for electrification of the economy 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 are able to do before then, and that is some time away. So I feel really good about the strength of the business, the strength of balance sheet and the need to invest in front of us, but...

Mandy Simpson: 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 is nothing in our current investment profile that requires that.

Peter Wakeman: And then the last question is with regard to baseload and

New Zealand independents. Over how 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 as a base load available the way he does not 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 is problems with the cable between the North and the South?

Mike Roan: Yes. I mean, again, Peter, providing forecast, it is dangerous

stuff, but I feel really good about the dry year risk that the country faces given the investment that is going on into renewable assets. I do not think we will need to - it is certainly not in in our plan to invest in some form of coal back up the South Island.

I think, what will play out is, as I kind of talked to, I think there will 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 current frame for investment being in renewables is what will support country and support the energy system.

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

Operator: Thank you. If you wish to ask a question please press star one on your telephone. Your first question comes from Joshua Dale with Craigs Investment Partners.

Joshua Partners: Good morning, Mike and Mandy. Can you hear me okay? Mike Roan: Yes. Got you.

Joshua Dale: 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?

Mike Roan: It's too early, Josh. It's funny you mentioned 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.

Joshua Dale: Look forward to it. And second question. Do the economics

of Manawatu battery makes sense alongside Manawatū solar alone? Or do you actually need some of your other projects to maximise the value of that battery?

Mike Roan: Hey. The economic stand-alone solar farm in the Manawatū

look pretty good. But we get that you can -- the benefit of scale and efficiency at that site if we deploy both battery and a solar farm, just as we do it at Ruakākā, it does come down

to that -- the cost of the transformation 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 Ruakākā, 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.

Joshua Dale: Thanks. I guess what I was asking is, do you need some of

your other solar projects to go hit in addition to Manawatū solar for that specific battery to make sense, or -- because Manawatu solar do it alone?

Mike Roan: Manawatū does it alone.

Joshua Dale: Okay. That's helpful. Thanks. And maybe last 1 just for

Mandy. The interim dividend being imputed at 85%. Do you expect the same level for the final, and your dividends going forward?

Mandy Simpson: Yes, I think that's -- that seems to be the level at which we're

likely to impute going forward.

Joshua Dale: Brilliant. Thanks very much, guys.

Mike Roan: Thank you, Josh.

Operator: Your next question comes from Andrew Harvey-Green with

Forsyth Barr.

Andrew Harvey-Green: Good morning, Mike and Mandy. A couple of questions. First

one, just looking at the cost of the wind projects, particularly

Mt Munro actually, I mean both of them are around about that 4 million megawatt, which is a reasonable step up on what we've seen other wind farms going forward.

Is there any sort of particular one-off costs certainly I do realise that both of these wind farms we got capacity factor that has helped 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 a new level for wind farm costs going forward?

Mike Roan: I think you've seen a lift up. 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 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.

Andrew Harvey-Green: Okay. I kind of assumed the difference between Mount Munro and Te Rere Hau is because I think you're probably looking at the cost of moving the way site, for example, which would be a few million dollars, I imagine?

Mike Roan: 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 area. I mean 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 as we'll get better if it ever plays out again.

Andrew Harvey-Green: Yes. Okay. Couple of questions on batteries. I'd be interest at

the Ruakaka battery I guess has been operational for circa 6 marks or so now. Are you able to give us an indication of what sort of EBITDAF uplift the F3 has delivered?

Mike Roan: 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'd be fair to say, if you remember that graph that showed spring in 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 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.

Andrew Harvey-Green: Yes. Okay. That will be interesting. And last question, also

just around the battery run, the Manawatu battery. It looks like you were 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 of that really is firming solar and I guess when as opposed to sort of a more wider portfolio benefits that you might see on the sort of the --particularly in the retail side of things. Is that's sort a fair understanding?

Mike Roan: Yes, there will still be a benefit in that battery in helping

manage that portfolio optimisation. I mentioned the South North Island. We can't assume that others who have batteries will operate them to help manage that price differential. 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 Ruakākā and elsewhere and can someone make a 4-hour battery economics work. So we'll see. I don't know the answer to it yet, Andrew.

Andrew Harvey-Green: Okay. All good. Thanks for that.

Operator: Your next question comes from Grant Swanepoel with Jarden.

Grant Swanepoel: Good morning, Mike and Mandy. Can you hear me? Mike Roan: Yes. Comes through loud and clear, Grant.

Mandy Simpson: Yes.

Grant Swanepoel: 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?

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

Grant Swanepoel: And then about 2.5 terawatt hours of thermal displacement?

Mike Roan: 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 on to a slightly lower.

Grant Swanepoel: So less than 6 terawatt hours of renewable availability. You

guys have 2,000 gigawatt hours pencilled in and parks partially 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 to 2030.

Who's going to get out the way?

Mike Roan: We'll wait and see. Good question. 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 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 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 than what we would look to do is to bring new consumption to the economy. And as I say, 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.

Grant Swanepoel: Thanks, Mike. 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?

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

Grant Swanepoel: Thanks. And my final question, bit for Mandy, but for yourself.

That dividend is up 4%, but only less than inflation over the two years since the last normalised 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?

Mandy Simpson: 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.

Mike Roan: Grant, the only thing I'd add is, I know you know this, but last

year we got slowed down a little bit by buyback conditions and that slowed down that that progressive dividend approach 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, the progressive profile and like everything you build confidence and you look at it a little more carefully next time you think about dividend.

Grant Swanepoel: Thanks, Mike. Thanks, Mandy. Thanks for your answers.

Operator: There are no further questions at this time. I will now hand

back to Mr. Roan for closing remarks.

Mike Roan: I think I'm done with closing remarks. Thanks for the

questions, everybody. Thanks for your attendance. I hope you got something valuable from us. I think that's us.

Operator: That does conclude our conference for today. Thank you for

participating. You may now disconnect.