Meridian Energy Limited (MEL) Earnings Call Transcript & Summary

[Foreign Language] And welcome again to Meridian's Interim Results Presentation for the first -- for the Half-Year ended 31 December 2023. I'm Neal Barclay, Meridian's Chief Executive and I'm joined by Mike Roan, our CFO. I'll touch on some highlights for the last 6 months, hand over to Mike to drill into the numbers, and then I'll round out by covering our progress against strategic direction along with some market and regulatory updates, and we'll have plenty of time for questions at the end. I think the top line is performing well. The volume of energy sold was up 3% from the same period last year. For several years now, we have been consistently improving our retail market share and lifting netbacks across all customer segments. Whilst [ EBITDAF ] between retail and wholesale can move around between years, our retail performance is ultimately fueling the bottom line and progressive dividend and -- sorry, and progressive growth in our dividend. For the first time in many years, monthly demand numbers have a positive look to them. When we look through irrigation swings, which are a feature of this time of year, we do believe demand has lifted by around 1% over the last 6 months or so. We're super pleased with progress on the electrification of process heat. The Fonterra and Open Country Dairy deals referred to on this page are sizable, and we now have new demand under contract or MoU totaling 891 gigawatt hours. Operating costs have lifted and inflationary pressure is certainly a factor, but some of our key growth initiatives are causing a sizable and hopefully temporary bubble in the cost line. Mike will break that down shortly when he talks to the cost forecasts. This week, we commissioned our 20th turbine of the 41 at Harapaki, and we're on track to complete construction within the next 6 months. Progress has been exceptional of late and a stark contrast to a year ago when we were in the thick of Cyclone Gabrielle devastation. At that stage, we were not even sure how or when we would be able to get turbine components to site. The Ruakaka battery is also progressing well, and we've materially improved our near-term development pipeline through our joint venture with New Zealand wind farms to repower the Te Rere Hau Wind Farm. I'll provide some thoughts on the new coalition government's energy focus a bit later, but suffice it to say, we think the policy direction is positive for the sector and ultimately for customers. There's probably 2 issues that are causing us headaches right now, and transformers are certainly one of them. Two of our 7 Manapouri transformers are on extended outages. They were both removed from service last year due to elevated gassing levels. These are relatively new transformers being less than 10 years old, and they shouldn't be misbehaving. Finding the root cause of a transformer issue without destructive testing is notoriously difficult. But we think we've zeroed in on the issue of one of them and we may be able to [ affect a fix ] on site. No guarantees at this point, but we're certainly hopeful that we'll have at least 6 units available this coming winter. We've also written off the faulty West Wind transformer and procured a replacement. Unfortunately, there's long lead times on transformer deliveries. And the reality is we probably won't have the wind farm up to full availability until early 2025. The other key issue is the situation with NZAS. For quite some time now, we've been in negotiations with Rio Tinto and NZAS to agree long-term energy contracts beyond 2024. Those conversations have been constructive, but at this juncture, we do not have agreements in place, and we're not able to provide any meaningful update or guidance on the likely eventual outcome. Now we understand this continued uncertainty is frustrating, most acutely for the smelter employees and for the people of Southland. But I think all parties involved are working hard to get a resolution as soon as possible. On a much more positive note, Meridian and NZAS have signed an additional new peak demand response agreement, covering a 12-week period for this coming winter. The agreement will allow Meridian to require the smelter to reduce its consumption of electricity by up to 20 megawatts over 4 trading periods a day and up to 20 trading periods over a fortnight. The entire industry is very focused on ensuring we don't have any security of supply issues this winter, and this agreement will certainly help reduce pressure on the electricity system over the peak periods. This agreement is in addition to the larger demand response agreement signed in 2023, which allows Meridian to require NZAS to reduce its consumption of electricity by up to 50 megawatts over a longer period of time. I believe these agreements are a sign of more constructive, a more constructive relationship between the smelter, Meridian and the sector. With that summary, I'll now hand over to Mike to talk to our financial results.

[Foreign Language] everyone joined the call this morning. As usual, I'm going to talk to our financial statements for the next 15 minutes or so. To kick things off, I'm going to talk about dividends. The lift in interim dividend shouldn't be a surprise. While we don't provide dividend guidance, we have said that we'd use some of the proceeds from Meridian Energy Australia sale, support dividend flow through 2024 or at least up to the point where Rio Tinto makes it clear what it intends to do at TY. And we've been doing that, lifting the dividend. Today is no different. What you see here is a lift in the interim ordinary dividend of 2.5% from $0.06 per share to $0.0615 per share. The dividend will be imputed at 80% and paid to shareholders on the 26th of March. We're also applying the dividend reinvestment plan to this interim dividend. But as we did for the final dividend payment last year, participants in that plan will not receive a discount to market for the shares purchased. Now for those who do choose to participate this year, you should also consider the fact that NZAS will need to make a decision to stay in or exit New Zealand this calendar year as part of your decision. And before I leave TY behind, the only thing I wanted to reinforce is that regardless of which way the decision lands, Meridian and the electricity sector will have certainty, and that's incredibly valuable given the large investment decisions that have been made by many participants. Pretty straightforward, so on to EBITDAF. Headline EBITDAF lifted by 4% on the first half of last financial year. The graph to the right of the slide shows a fulsome breakdown of the drivers behind the lift. But to summarize, energy margin lifted faster than operating expenses. And as I'll explain shortly, the lift in energy margin is likely a durable outcome and one we've been focused on, given our cost base is lifting. I will break down energy margin in a minute, but before I do, the last bullet and the graph below that bullet deserve a little attention. Second half of this financial year started with good inflows. Yes, you heard it correctly, good inflows. I know that might be surprising as the last time we had above average inflows in a January was 2019. Anyway, it had become increasingly dry in the South Island catchments in the lead up to Christmas, but in mid-January, the [ heavens ] opened. Now that doesn't mean we're set for the year, but it does mean that the business has a decent shot at a strong second half result. Roll forward today, and it's got a wee bit dry again, so the wholesale team is rightly cautioned me not to count my chickens and I'll do the same for investors, but it's nice to be in the position that we are, particularly as during the last 3 interim announcements, I've had to pour cold water on second half expectations. And the team is off to a good start with the January operating report recording the strongest January performance the business has ever seen. Now if I jump to the graph at the bottom of the slide, as you expect, operating cash flows lifted alongside EBITDAF. And at year end, I'll switch my commentary to the cash flow statement a little more directly, given the changes made to the income statement last August. The inclusion of unrealized derivatives in that statement complicate investors' line of sight in my view, whereas there's nothing complicated about the cash flow statement. Investors get to see operating, investing and financing cash flows directly, but more on that then. Energy margin. Summary is that energy margin lifted by $31 million on the prior comparable period. And within that result, you can see that retail fixed price sales revenue lifted by $70 million, while financial contracts supporting the wider portfolio also lifted by $54 million. To be clear, we don't enter into financial contracts to make money in their own right. They're entered into to support the wider portfolio. Some periods they'll make money, some they won't, but they do provide balance and stability to energy margin delivery. This is different to retail sales that are put on specifically to lift revenue beyond what would have been possible in wholesale markets. And the $70 million lift in sales revenue you see here is as impressive as it is durable. It was a bit inconvenient, the spot market prices took away some of the gain this year, but that won't be the case every year. Now move to customers. You can see from this slide that the $70 million lift in retail sales revenue was driven by customers once again switching to Meridian, as evidenced by increasing sales volumes and increases in price. Overall, customer sales volumes grew by 136 gigawatt hours when compared to the first half of the last financial year. That volume growth continues to slow as the team pushes up against portfolio limits, but it remains clear that products and services offered by the retail team continue to hit the mark. And given this ongoing success, we've asked our retail team to grow the range of products it offers. At the interim result last year, I mentioned demand response from large industrial customers and I referred to demand response from residential, small business and corporate customers being just around the corner. I know that we intended on buying these services from customers in the coming years. I'll talk to this a little more when I get to costs, but simply put, we've decided that we need to begin investing in this proposition. There's a bit of water to flow under the bridge, but the role of electricity consumers is changing, and we want to be a big part of that change. Production volumes were 266 gigawatt hours lower than in the first half for the previous financial year. As noted on this slide, this was largely because inflows were 5% lower than average, whereas in the comparable period, they were 14% above. Lower production volumes were offset by wholesale prices that were 150% higher than in the 6 months to December 2022. And while it may not be as obvious from this slide alone, when you compare first half performance this year to last, the large differences between periods provide you with a glimpse of a portfolio in action. Last year, there's a lot of water, but with low prices. This year, there wasn't as much water, but wholesale prices were higher. When you think about the energy margin graph that we showed you a couple of slides ago, you can see that these 2 elements tend to balance each other out unless hydro storage is at the extremes. So if you want to durably improve portfolio performance, you need to see lifts in retail performance, and that's what was demonstrated this year. Now in January, the average generation spot price lifted to $188 a megawatt hour on similar levels of generation production to the same month last year. So we had higher prices and stronger generation volumes, hence the stellar January result. As usual, before moving off this slide, I also want to provide an update on volumes traded on the ASX over the past 12 months. As this market has become increasingly important to us and others a mechanism to manage risk. While we haven't shown a table here that captures ASX trading volumes, over the past 12 months, they continue to represent more than 2x the annual physical electricity consumption in New Zealand. So there's plenty of liquidity for us and others to manage risk at those sorts of levels. So all good. As signaled last August, operating costs continue to lift. The graph at the bottom right provides detail on why that is. First, we continue to build capability in our development team and within our subsidiary Flux. So we committed an additional $4 million to those 2 activities. And like all businesses, we need to attract and retain good people. So we paid our people with $3 million more to ensure they were compensated competitively. We're starting to see inflation flow through a little more generally into areas like rates, wind generation components, contractors and ICT costs. The key point I want to leave you with is that other than for retaining good people, we continue to put funding into growth activities in Flux and our development team. And our development pipeline continues to benefit from this, as Neal will talk to soon. Now I know that what you really want me to talk about is the lift in operating cost guidance from last August. In August '23, I noted an operating cost guidance range of $268 million to $274 million. Today, I'm lifting that guidance to $276 million to $282 million, and there are 2 reasons for this. First, when I talked to you in August, we didn't have the Te Rere Hau development on the box. Second, we hadn't agreed internally that we needed to grow retail product offerings. We've now confirmed both and have allocated $5.5 million to the retail team to focus on technology-led retail offerings that will integrate home, small business and C&I, solar battery and EVs into its product offerings. We'll unpack that focus properly at an Investor Day that we're tentatively scheduling for May, assuming NZAS has made a decision by then. At the same time, Te Rere Hau development costs that we would capitalize if we're the sole owner developer, will be expensed. And the same will happen with Southern Green Hydrogen. The best estimate I have for now for both is $4.1 million this financial year. It's important to note that we'll be reimbursed for half of the Te Rere Hau costs should it reach final investment decision or FID and entirely for Southern Green Hydrogen. But those reimbursements flow through other income, so matching them to costs can be difficult. Now for CapEx. At the start of the year, I suggested we might spend between $420 million and $445 million. That's looking more like $345 million to $370 million today. The primary reason for this change is that the Ruakaka solar farm has been pushed into fin year '25 given consenting delays. To a smaller extent, the fall also reflects that we've not purchased land to support solar developments, rather the team has been able to enter into royalty arrangements with landowners. There's also a bit of [ minutiae like ] Southern Green Hydrogen costs that were initially captured in the CapEx forecast, but it will be expensed. Also I want to point out that the generation team total cash cost here. We've lifted this -- to between $95 million and $100 million, given the Manapouri transformers have caused us some grief and that was unexpected. Given the lift in generation costs that are largely capital related, we've lifted the stay in business CapEx forecast to $70 million to $75 million for the same reason, but time will tell how both these elements play out. As I've said any number of times, net profit after tax moves around as a result of unrealized fair value movements in electricity and interest rate derivatives. So until you strip those items out, it has limited value as a measure of operational performance in my view. But we show it here as it's a GAAP measure. We also provide a non-GAAP measure underlying net profit after tax in an effort to remove the effect of unrealized derivatives. That measure was lower than the prior comparable period, even as EBITDAF and operating cash flows lifted, which is interesting, as typically movements in EBITDAF operating cash flows and underlying net profit after tax are aligned. Yet, in this instance, underlying net profit after tax fell as depreciation and amortization was $20 million higher than last year, driven by an increase in generation asset values of $1.1 billion. Actually there's one more interesting element on this slide tucked away in the bullets. We received a $9 million windfall following a protracted stamp duty disagreement with the Australian Tax Office. Jason Woolley and his legal team were resolute that we should chase that issue as we exited Australia and the fact we received cash signals they had a point. Thanks Australian taxpayers and thanks to the Meridian legal team, that closes the latest chapter on Australia. A couple of things to note on this one. The value of generation assets did not change. The balance sheet remains in a healthy state, and the net debt to EBITDAF ratio sits at 1.3x at the end of December. All going well, we'll move into a new Wellington office at the Old Bank Arcade in April. This follows 2 years of temporary accommodation from Meridian's Wellington team. That isn't actually on the slide, but it's relevant to staff and investors who might want to visit. And as announced this morning, we're considering a green retail bond issue in the coming weeks that will replace an expiring green bond while supporting growth. Look out for confirmation of that green bond on the 11th of March. So to summarize all of that, the operating business continues to deliver strong results. And when you add in the progress growing the business, it felt like a superb 6 months. [Foreign Language] I'll now hand back to Neal so he can shine a torch on growth more directly, the regulatory environment and other elements that drive our strategic ambition and influence performance over time.

Thanks, Mike. Very nice. I'll now round out a review of the business. As I mentioned at the outset, the success of our retail business has powered the company's earnings growth for at least the last 5 years. I believe this is underpinned by a winning culture, a strong service proposition, competitive pricing and a standout brand. But the competitive landscape and opportunities for growth are evolving rapidly, fueled by technology and an imperative to decarbonize our economy. The only credible way New Zealand can achieve its Zero Carbon aspirations is by electrifying everything that moves, spins and burns fossil fuels. So to remain relevant and successful as a retailer of energy, we must deliver greater value to customers through energy solutions that support the adoption of EVs and the electrification of in-home and business energy consumption. Accordingly, we have stood up a new energy solutions team within our retail business, and they are tasked with delivering cleaner, cheaper energy to customers. As Mike pointed out, there is a cost of this investment, but we do clearly see it as an investment. And again, you'll hear more about our next-generation retail plans at our upcoming Investor Day. We're making better progress supporting the electrification of process heat than we originally expected. The target we set in 2021 was 600 gigawatt hours by 2025. And today, we have 891 gigawatt hours either contracted or under MoU and likely to be commissioned around that time frame. The most recent partnerships with Open Country Dairy and Fonterra will remove around 90,000 tonnes of CO2 from the atmosphere each year. And this is the equivalent of permanently removing 40,000 cars off New Zealand roads. And there's still plenty more in the pipeline as well as further value-add opportunities and demand response. On the construction front, we have now commissioned close to half of the 41 Harapaki wind turbines, and I expect we will come inside both the September full power target date and the capital envelope. Our Harapaki team have really done a remarkable job given the serious challenges they've had to deal with. We've made steady progress at our Ruakaka battery site. The civil works and balance of plant construction activities are taking a little longer than anticipated. This is our first utility-scale battery. We have learned a lot, and it will take the balance of this calendar year to complete that project. Pleasingly though, the first batch of our battery containers has now arrived at Northport, and so has the switching gear. And you always worry about procurement lead times, however, these are landing as we had hoped. The JV with New Zealand wind farms to repower Te Rere Hau is an exciting opportunity. The site has an exceptional wind resource with expected capacity factors of around 50%. Installation of up to 39 modern 3 blade turbines by the end of 2027 should increase annual electricity production to around 750 gigawatt hours. So that's at least 7x more than the farm producers today. Meridian will have a 50% share of the redeveloped wind farm and 100% of the offtake agreement. We now have consent applications in play for both the 300 gigawatt hour Mount Munro wind farm and the 225 gigawatt hour Ruakaka solar development. I'll share some more thoughts on the RMA consenting process shortly, but it's fair to say these things never happen as quickly as we'd hope. The most significant consenting job on our books is the application to reconsent the Waitaki power scheme for the next 35 years. The scheme accounts for around 18% of Aotearoa's electricity and more importantly, around 67% of this country's average hydro storage. So it's clearly nationally significant. In support of the application, Meridian and Genesis have agreed a range of mitigation agreements with most affected and interested parties. Those agreements will improve environmental and cultural outcomes within the catchment for the next 35 years, while supporting the existing flexibility of the scheme. The new consents, if granted, are due to be in place by April 2025. And with a view to the longer term, we entered into an MoU with Europe-based Parkwind to explore offshore wind potential in New Zealand. Now depending on the outcome of that joint exploration, we may decide to work towards a feasibility permit. There's no doubt new generation capital costs have escalated in the short term, and the domestic part of the overall cost increases may stick around. Compared to our most recent build at Harapaki, we are seeing wind turbine components costing around 15% to 20% more today. But at the same time, we are seeing solar panel costs falling currently around 25% lower than they were at pre-COVID levels or around half of what they were in mid-2022. Now these are New Zealand dollar comparisons, so currency changes are part of the equation. The in-house Meridian view is still an expectation of a downward trend in real costs over time as technology and scale efficiencies improve. And in that context, we also still see quality projects still being viable now. As you would expect, our development pipeline is evolving. And as I mentioned, the most salient points is in the last few months has been the introduction of Te Rere Hau and our progress on consent preparation work for a large-scale Taranaki wind option. As Mike mentioned earlier, our balance sheet has significant capacity to continue to support investment in our development pipeline. The next 2 slides summarize key policy positions and shifts from the new coalition government. My summation of the government direction is they have reaffirmed the importance of renewable energy and their commitment to electrification as part of New Zealand's net zero by 2050 target. But at a principled level, government want to rely on the ETS to deliver price signals that incentivize investment in green technology. And they want to avoid specific policy decisions that attempt to pick winners. Hence, their decisions to cease work on Lake Onslow, repeal the ban on offshore oil and gas exploration, withdraw the GIDI funding and wind up the clean card discount scheme. It's kind of hard to argue against the economic tourism of this approach, and so I won't. And net-net, I think the policy shifts are positive. Lake Onslow looked like a very expensive and risky option to manage dry year risk. It would also have had a significant dampening effect on other smaller but cumulatively more efficient and timely solutions. And most market participants and observers understand that gas must remain a feature of this country's economy for a while yet. And further investment in gas infrastructure is critical to support the transition to a more renewable electricity system. I suspect we will see a slowdown in momentum in both EV uptake and process heat conversions. However, I don't think that will be material in the long term, as the relative economics of electrification continued to improve against fossil fuel alternatives. In short, nothing in the government's energy direction has caused us to materially shift our medium to long-term view of demand growth or wholesale price electricity forecasts. Potentially very positive is the government's intention to introduce new legislation to streamline consenting of regionally and nationally significant projects. This proposed legislation will be introduced to select committee in March, and it will include a schedule of projects that will be referred to an expert panel for decision making. Something certainly needs to change here. The owners must remain on developers to bring all affected people with them and to mitigate adverse effects on communities and the environment. But at Meridian's experience, the current resource management regime is getting progressively less efficient and more difficult to reach sensible decisions. For example, the Mount Munro wind farm is set in a farmland with no natural landscape values. And yet on current course and speed, it will take Meridian longer to consent it than it will take to build it. So the proposed reform is most welcome. Lastly, it's pleasing to see hydrogen getting some prominence in the policy mix. We have a high conviction in this versatility and economic opportunity this future fuel office to New Zealand. Transpower submitted its next charging period proposal for April '25 to March 2030. This proposal is far from finalized and Commerce Commission's final determination isn't due until later this year. However, as the graph highlights, cost increases could be significant. A key feature of the current WACC based regulatory return model is that it heightens the cost imposition on end consumers during times of high interest rates. And Transpower's WACC is driving much of the proposed cost increases. Even more materially, retailers are expecting significant cost increases from distribution networks. We will learn more from the Commerce Commission later this year on where distribution costs are likely to go in the next regulatory period. Now we've been dealing with the NZAS uncertainty, it seems like forever. So as you would expect, we have continued to work hard on implementing the mitigation plan we developed when NZAS terminated their current contract in 2020. It is worth emphasizing that many aspects of this plan are now embedded in our BAU operations and will continue even in an [indiscernible] scenario. Most of the initiatives are looking good, albeit Southern Green Hydrogen has certainly taken longer to conclude the security holder agreements than we expected. This has proved to be a very complex process, but I'm hopeful we'll reach that milestone in the next couple of months. All up, if NZAS do decide to close the smelter later this year, I believe Meridian remains in very good shape. So to round out our story for the last 6 months, the financial performance has been solid, supporting continued growth in our dividend. Our construction program is on track and we've improved the quality of our development pipeline. I think with a strong balance sheet, we are well placed to keep investing in renewable energy solutions for our customers. Now obviously, the NZAS uncertainty remains a frustration, but we are hopeful that we will know the future of the smelter one way or another within the next few months. And to finish on a positive note, we're very optimistic about the government's proposed new consenting pathway for nationally and regionally significant infrastructure projects. We believe it is likely that many renewable electricity developments will fit within the scope of this new legislation. And ultimately, that must help accelerate our potential to build program, lower costs and ultimately improve New Zealand's odds of achieving Zero Carbon by 2050. Thank you all. That concludes our presentation, and we can now move to questions. We'll take questions firstly from the people here in the room in Wellington.

Andrew from Forsyth Barr. Couple of questions for me. First of all, just on the pipeline, and I think it was Slide 18. It looks like the number of advanced prospects for wind has dropped quite a bit and solar has gone up. So it sort of seems to be a significant tilting towards solar away from wind, you're able to sort of talk to that?

Yes. When we look at the long-term price path, expected LOCEs we're seeing a lower price ultimately for solar and certainly beyond we think the inflection point is probably in the early 2030s. But from that point on, we think solar could be the mainstay new generation in New Zealand.

And I guess the follow-on question from that is, you're not too concerned about that curve considerations and things like that.

It will be -- it could be a feature of the New Zealand market and we'll have to manage that carefully and we'll see it evolve. But I guess the difference between New Zealand and where you see that quite acutely in other markets, Australia is we've got the flexible hydro fleet that can adapt and flex around solar, intraday solar or even intraday wind as and when it occurs.

And just a couple of questions, one around OpEx, one around CapEx. So just on OpEx, are you sort of seeing any easing of inflationary pressures at this stage and just sort of then thinking about is there more OpEx pressures we can expect into FY '25?

So I'm not seeing any easing Andrew, as evidenced in the increases in our numbers over the last few years, but you look more generally to economic conditions, inflation is slowing. So looking forward, you'd have that same expectation from our business. So I think on the OpEx front, assuming the Reserve Bank, which will come out later today, I'm sure, and [ swamp ] the news that we're giving you this morning continues to keep people focused, then inflation should be brought under control.

Okay. And last question is just on the CapEx. And of the $80 million that's been reduced, how much is actually, I guess, shifting into FY '25, which is related to Ruakaka, versus I guess, not buying land, which I presume drops out completely?

Yes, not buying land drops out completely as you say. We'll still have placeholder in there next year to ensure we've got the option to either buy land or enter into landowner arrangement. So that will be captured in next year's forecast. But it's about $15 million of the $80 million that you mentioned, so it largely is the movement of Ruakaka.

[indiscernible] Macquarie Asset Management. Just one quick question for me, you talked about obviously delays, projects coming through capacity constraints you're hearing from other people as well. In terms of being able to bring on renewal projects, does that change how you think long-term about them, in terms of bringing projects forward, knowing that it could be delayed longer, in terms of when you can get them kind of operational?

No, I don't think we're seeing -- we're not -- there's no massive change in our strategic direction in terms of the build program. Probably the critical decision that needs to be resolved is the NZAS [ stay ] will go, because that would either incentivize people to accelerate their build program or potentially delay it by a wee bit. But certainly the learnings we've got out of recent projects at Harapaki and Ruakaka [indiscernible] plus the development work we're doing on Ruakaka solar, assuming we can get those consents through, we think we can get them delivered within a pretty prompt timeframe.

We're pushing our development team as they would know if they listen to the call. We're pushing them along as hard as we can, because we've got to keep up with the expected growth that will come from decarbonization. So they're feeling it. But as Neal said, we've got this juncture with the smelter that we also need to balance and manage. As I said, we'll get certainty this year in relation to that and…

Probably, probably.

That would be disappointing but yes, there is always a possibility I guess, but that will determine the acceleration and or slowing the consenting delays as Neal mentioned, there's a new process that's being formed to help deal with some of the consenting issues that we've talked to.

Nevill Gluyas, Jarden. Three from me. The first one really, you mentioned a couple of months as sort of the timeframe you might expect NZAS outcome. Is there a reason for the couple of months?

I thought I said a few months actually, but…

You probably did. I was going to say I've been wrong in every prediction that I've made Nev, so couple of months.

No, it's just we're closing in on the end of the year, Nev. They've got contractual requirements that they'll need to meet. They've got a workforce down there that needs some sort of certainty. So common sense would suggest it's got to be within the next few months, but...

We can all hope so.

We're not making the decision, so we can't really put a firm time frame around it.

Second question, you mentioned the valuation uplift in this latest report. Is that due to a higher long run price on sort of the higher costs you're seeing for power stations, for new ones? And if so, what's your revised sort of broad view for what that long run price looks like?

I did wonder, as I was talking whether it might confuse people a little bit in those comments. So we didn't change the valuation of our asset base as part of the interim valuation this year, but over the past 12 months, we have seen a lift in -- so at interims last year and then at year end we did increased valuation of the asset base by about $1.1 billion over that period. We haven't changed our underlying price forecast Nev, since I think it was October 2022, I want to say somewhere in there, so we haven't updated it, but we're looking at that right now. So I reckon probably April somewhere. Early indication, but it's only early indication is there might be a slight lift in the price range that we've previously provided for all the reasons that, but as I say, we'll unpack that a bit more when we've got the real [indiscernible].

I think the near term, we're still seeing projects being strongly viable. We think good wind is probably in the $80 to $85 range and good solar is probably in the $90 to $100 range at the moment. That relationship will probably inverse, as I said, probably mid early to mid next decade.

And last one from me is obviously you've -- well, I would expect you've spoken just about everyone in terms of heat conversion, certainly in the South Island, maybe even the north. Do you have a view now for how much of the remaining heat conversion will go towards electricity versus biomass? Is it rough numbers there?

I think we'll come back to you on that one. But I don't think we're spoken to everyone. There's a lot of customers out there that have the potential to electrify, but certainly the ones we are speaking to, the strong emphasis is on electrification. The availability of a viable fuel source in terms of biomass in the South Island is still to be proven out.

It was a study from a [indiscernible] that suggests there's about 4,000 gigs of consumption that might either electrify or move to [indiscernible]. And there's about 50% of that, that looked like it might electrify, maybe slightly less than that. I think those numbers are still about right.

Anyone else in the room? We can go to the lines, I think.

[Operator Instructions] Your first phone question comes from Grant Swanepoel with Jarden.

Sparkling result. First question just continuing on from the long run modules to cost conversation. So your consideration at solar and wind is [ 95 to 100 and 80 to 85 or 90 to 100 and 80 to 85 ]. That's unfirmed, I assume. And then I think back in October '22, you had 85 to 90 as your guidance on wholesale price over the longer term. So do we really inflate that to now for the starting point and you potentially could have a notch above that? And can you align that with Contact's view that is 110 to 120 if possible? That's my first question.

Okay, well, yes, that is unfirmed grants. That's just the LOCE of new developments specifically. And as Mike said, we're actually working through our price path views at the moment. We have signaled, I think it was 80 to 90 or 85 to 90 in the past. There's probably some upward pressure, is based on the early analysis I've seen, but so -- we might be calling out 95 to 100. I'm not quite sure though, but we'll probably provide a bit more clarity on that at the Investor Day again in May, I suspect. And sorry, what was the last -- how do we...

Just inflation adjustment, really.

Yes. So and then reconciling back to Contact's views, I mean, they're a wee bit higher, but when you take into account firming, I suspect we will be lower than their projections or their thinking. But it's a competitive market. We've all got views and what we're seeing in the market and our views about long-term trends in terms of technology improvements, scale efficiencies, all those sorts of things suggest that, I think a sub $100 average over the long-term seems still probably to be a reasonable assumption from our perspective.

Now, in demand simulation, that 900 odd gigawatt hours that you guys have confirmed, does that come online in kind of '25 and '26 and therefore add about 2%, 2.5% to demand?

Yes. Grant, that's about right.

Yes. That's gigawatt hours, actual demand.

And so it starts coming on progressively from calendar '25, I assume.

Some of it's already coming on Grant. It'll come on through the bulk -- through the rest of this year and then through the '25 year. I think most of the opportunities we're looking at, certainly the sizable ones, will be in place before the end of next year -- next calendar year.

And then with the [ lines ] cost increases going up materially from April next year, can we assume that you'll continue to push mass market pricing quite hard ahead of that?

We will continue to price appropriately, given not only the competitive environment that we operate in, but also our cost structures. So, I mean, typically retailers do pass on those distribution cost increases, but we also have to have a close look at the energy component and see what we can do there. Ultimately, we're trying to minimize the impact on particularly residential customers, but certainly also business customers as we manage through this transition. And we do take a long term view of customer relationships and price paths when we think about price changes every year.

And then on dividend, if there is a TY announcement ahead of the year end, can we continue to expect a lift in the dividend payout as we move into 2H dividend payments?

Grant. So I think I said it in my notes is, we don't provide guidance on dividend, but what we have said previously and then what we've done, you can take something from that as well. We do expect to go back to the drawing board in relation to dividend and dividend formation once we have certainty on NZAS either staying or leaving. So I'd say by year end, assuming that decision is made, you could expect us to come out with either confirmation of the existing policy or some changes in that space.

And then my final question, obviously on TY. So this latest deal of pushing your demand response to 70 megawatts, is the deal struck and you talk about demand response in the deal, are you looking for much more than 70 megawatts as a future type construct or is 70 megawatts the type of number we should be thinking about? And then you comment that you penciled in a May Investor Day as long as the TY deal has been struck, that implies that internally you think something's going to happen before May or am I reading too much into it?

Yes, you might be. We are ever optimistic, but we think it would be more valuable to investors to spend a day working through the business, updating you on the strategic direction if we had that level of certainty. So if it's not May, it might be November. The first part of that question was…

Demand response from Rio. And the answer there, Grant, is really simple, is we'd encourage them and others to think about the demand response that they can provide, as a country, we're targeting Zero Carbon. We need to supply the needs that the energy system has with new products and services. And so whether it's Rio or NZAS or anyone else's demand response is going to be a real important part of the equation. I'd expect that they can offer more than the 70 mgs that we've captured today.

Your next question comes from Stephen Hudson with Macquarie Securities.

Just couple from me. Just firstly on NZAS, just going to potline 4. I think NZAS has talked about recruiting to get their workforce up to a position where they can reopen that potline. And I think when they last talked about it, they were 40 people short. Can you give us a feel for what you're planning for there whether or not your working assumption is that potline 4 will reopen post the December 2024 period. And then I've just got 1 other question on [ MfE units ].

Yes. We are not actively working with NZAS around a contract for potline 4, so we do not have an expectation that it will be fired up from '24 onwards. Not to say it won't, but it's not an active conversation we're working with them on, yes.

That mean that someone else mightn't be working with them on that, Steve. And ultimately, configuration, the physical configuration of the plants is, decisions are up to them. So whether they contract or not, if they can get the people and aluminium prices are reasonable, they might decide to run it or not. But as Neal said, we're not actively engaged in a conversation on potline 4.

And then just on the FE units, so your understanding, is that [ NB ] in conjunction with, I think the consultants concept, will review the contract for any reinstatement of that units. Are you aware of whether or not NB has actually reviewed any draft contracts to date?

No, we're not aware of exactly where that process is at, but we understand it will take place. I think it's MfE that will review that, the government ministry that have the mandate, and then it's the minister of climate change who will actually take it to cabinet if there's any sort of change in the government policy or direction around that.

Got you. And then just coming back to the [indiscernible] around long-term pricing, I mean, 2 questions. Your existing long-term pricing assumption, I think is on a 2-way exit basis. I just wanted to confirm that. And then secondly, I suppose it's a bit of a provocative question, but we're going to see a doubling in the allowable whack for lines companies next year, which reminds us all that we've been living in a world of artificially low discount rates for 15 years. Are you that -- certain that you've got the number right against that backdrop, and you're not going to let good projects go through to the keeper as a result of getting it wrong potentially too low?

It's interesting. We just -- we periodically review past business cases and performance of the existing wind farms that we've developed over the years. And in every single case, we have been materially out on our forward price path assumptions. Not materially enough to actually hurt the economic outcome, they've all paid back quite well, but we have been wrong, so we'll be wrong in terms of what we're projecting now for sure. I think it's based on reasonable analysis, but it's always anchored on what we see today. And what we see today is not a good -- necessary to a good guide of what will happen in the future. We will look at all projects, Stephen, and we will try very hard to get them over our internal hurdles, because we want to be part of the growth or we intend to be part of the growth in the sector. But we do have reasonably stringent hurdles and they have to be economic. I don't see us sending any through to the keeper at the moment, but we'll see how things play out over the next few years.

And just a confirmation of the 80 to 90 range that you've got, that is a TY exit range.

I think it's reasonably independent, Stephen, that it's a long run price path. So there are obvious immediate effects if TY exits, but you'll see a supply response. So when we talk to that $89 range, we mean medium to longer term as opposed to the immediate effect. So we effectively zero out what TY does in the longer term.

Actually, Stephen, just to add a bit of color too, when we do look at a business case, we don't just intake our internal view of future price paths, we take other views that are published and then we put a range of potential outcomes. So we just acknowledge that we can't pick the future. We try and understand what the range of the future potential outcomes could look like in the context of whatever project we're reviewing. And that gives us some confidence as to whether we're likely to get an economic outcome or not.

The next question comes from Cameron Parker with Craig Investment Partners.

Just the one question for me, really around your retail base in the North Island, you've got generation coming on with Harapaki. You've also got battery and some others in the [indiscernible] up north. So we're just keen to understand what sort of level of growth we can expect in your retail book and where you think that might drive pricing both in the West market and what you're seeing in the C&I price arena really?

So competition drives pricing in all markets, competition in residential markets is pretty strong. C&I market is pretty strong as well. C&I tends to follow ASX prices far more directly than residential pricing. And the reality is, as we both talked to, we've got a retail team that has shown time and time again that they can grow and they will continue to grow in the products and services and then the number of customers that we sell to. But we've also said that, that growth is limited to an extent by portfolio bounds and so we've slowed the rate of that growth down, I think I said 136 gigs or gigawatt hours of growth in the retail business over the last 6 months. And so that [indiscernible] but continuing to -- continue to grow and as we roll assets and contracts into our portfolio that will support them but hopefully that gave you a little bit of color.

There are no further phone questions.

Okay. Well, thank you all for attending. Sorry about the stutter start the beginning. We made a comment on it in the room here. Whilst we might have lost the telecommunications feed out of the place, the lights did stay on in our industry, that's important. Thank you all. We'll see you hopefully at the Investor Day, some of you, in May hopefully and if not at year end. Cheers, bye.