Meridian Energy Limited (MEL) Earnings Call Transcript & Summary

[Foreign Language], and welcome to Meridian's interim results presentation for the 6 months to December 2022. I'm Neal Barclay, Meridian's Chief Executive, and I'm joined here by Mike Roan, our CFO. Firstly, I'd like to acknowledge those people impacted by Cyclone Gabrielle and Hale. So those who have lost their lives, their homes and the many thousands of kiwis who are doing their part to support our regions to get back on their feet, our thoughts and our hearts are with you. I'll start by talking to some of our business highlights in the last 6 months, and then I'll hand over to Mike to talk you through the financial results. After Mike, I'll be back to provide an update on a few different fronts, and then we can get on to the questions. So we're very pleased to announce another incremental lift in interim dividend on the back of a lift in cash earnings. Mike will provide insight into our earnings lift shortly. And it's fair to say that there are a few one-offs that affect this result. But importantly, the underlying drivers of value have shown improvement over the last year. Also very happy with the progress we've been making towards our strategic goals. Committing to the construction of our grid scale battery at Ruakaka is the first significant milestone for our ambitions in Northland. Over the next few months, we will back that up by progressing the consent for the accompanying Ruakaka grid scale solar farm. Preparations to lodge consent for the Mount Munro wind farm and the Wairarapa is also tracking well. So by the end of the calendar year, we expect to have those 2 projects consented. And at this stage, it's likely we will progress both through to construction. Beyond that, the team has more than doubled the size of the renewable development pipeline. For some context, the new build options available to us are equivalent to the size of all the electricity generation in this country produces each winter, and it needs to be that size, given Aotearoa's decarbonization goals. Just prior to Christmas, we announced Woodside as our preferred partner for the Southern Green hydrogen project. They bring extensive capability and experience in operations, process safety and energy marketing to the development phase of the project. Mitsui also, engaged and offer strong marketing capability with 50 years of experience in the ammonia business, including having the largest share of ammonia imports into Japan. We're working closely to with Ngai Tahu to progress the project activity and to confirm their ultimate involvement in the project. Our Harapaki wind farm-in Hawkes Bay has been plagued by the winter's to summer construction periods in living memory. The actual damage to site as a result of Cyclone Gabrielle was less than we feared. The damage to State Highway 5 and the grid means there's still a lot to assess. And as of today, we don't have a firm read on the impact on the overall project time line and cost. The state of the wind farm, to be honest, there's been a second order of importance to us over the last 2 weeks. The human impact and property damage as a result of Cyclone Gabrielle, as we all know, has been catastrophic. Meridian's on-the-ground efforts are centered on the Hawkes Bay because we're physically there. We're focused on that, we will focus on the safety and well-being of our team and the surrounding communities. Through our own people and our construction partners, we've provided support to Unison, Civil Defense and Waka Kotahi taking supplies into remote areas, restoring power and clearing the roads. We're also working directly to support customers through all affected regions and have a dedicated customer team leading those conversations. I want to commend the Meridian team and their partners for doing what was needed in these challenging times. They truly are good humans. In total, we've allocated around $1 million to our immediate relief efforts on top of the work we're doing on the ground. Some funds will be deployed through CT scan in the Red Cross and some will be used to provide targeted support to [ EV ] local communities and, of course, our customers. I'd like to call out the Electricity Retailers Association for coordinating the electricity retailers to deliver a consistent response for all affected customers, and Transpower and the network companies, particularly Unison. I mean we have some highly skilled electrical experts in our team and they've been astounded by the speed of response restoring services to homes and businesses given the massive amount of damage done to the network. Those organizations and their people are doing an amazing job. There's still many customers without power across the North Island without homes, but everything humanly possible has been done to restore service. Conversation around resilience has already started, and there will be many learnings for our industry from this event. But that must wait for the time being as the recovery stage is still well in progress. Now on a more positive note, our push in to public EV charging space has ramped up considerably in the last 6 months, and our customer teams shift and focus to creating energy solutions that support customers to decarbonize is also building real momentum. And my final point than the one you're probably all interested in. We remain in discussions with NZAS on potential contractual arrangements beyond 2024. The discussions are complex, and I expect they will continue for some time. And despite the best intention of all parties involved in the continuation -- involved, the continuation of the smelt for beyond '24 is still far from certain. And we'll update the market once the discussions are complete. I'll now hand over to Mike to drill into the numbers.

Thanks, Neal. People may not be on the edge of the seats like they were last night at the basin, but that was a strong open nonetheless. Thanks, everyone, for joining the call this morning. As Neal mentioned, I'm going to talk through our financial statements for the next 15 minutes or so, as you expect. But before doing that, I want to spend a couple of minutes providing some context for them. Simply put, the electricity industry is in the early stages of a transition that will ultimately flow through to the wider economy. In fact, the industry is preparing to support and drive decarbonization of the New Zealand economy. Anyone reviewing the competitive strategies of the listed electricity businesses would see that over the past 3 or 4 years, strategic ambition has largely converged. Each business is now focused on building renewable assets to support decarbonization, and the conversation on thermal fuels is limited to ensuring the security of supplies managed as that transition plays out. That convergence and reasonably singular focus may worry some, but the reality is that all the energy that we can individually and collectively muster will be needed over the next 30 years or so if we are to achieve that goal. Our forecast suggests that there's room for many to participate in the growth that will emerge. Our commitment to the 100-megawatt Ruakaka battery is an example of how investment commitments are changing. Grid scale batteries are new to New Zealand, and this one is being brought to bear, to help manage capacity or peak constraints that might emerge as thermal generation exits the system. Neal will talk to this investment in more detail shortly. Another example that signals the winds of change is the fact that we haven't entered into a swaption with Genesis as we enter 2023. The first incarnation of that agreement was entered into way back in 2009, and it was instrumental in supporting our business and the industry to manage dry year risk. While large contracts between entities get reasonable scrutiny from time to time, that one did its job remarkably well. From a commercial perspective, it was good for both Genesis and Meridian over a long period of time, but more importantly, it was largely responsible for eliminating a loss of national confidence in the sector during dry years. In the early 2000s, dry years were front page news and potential national calamities. Dry years didn't disappear in 2009, but I can't remember a headline drumming up the same level of hysteria sense. Anyways, and as I noted earlier, the world's moved on. As we enter 2023, with 2 gas back swaptions with Contact and Nova while looking to more readily use the demand response provisions contained in the existing NZAS agreement. Those demand response provisions have always been there but relying on them more heavily seems right as the role that demand response plays in a decarbonized economy will only get larger. And the existing NZAS agreement ends in 2024, so relying on those provisions makes commercial sense as well. Too small, but real examples of an industry that's transitioning. There are many others. So it's an exciting time for our industry and improving operational performance is not enough on its own. We're committing investor money to grow while finding new ways of solving challenges. I'm incredibly optimistic about the sector's ability to chart this course, but I'm pragmatic enough to know that we will have challenges. Transitions are never linear, but the industry is definitely up for it. Right, back to results. The lift in interim dividend shouldn't be a surprise. While we don't provide dividend guidance, what we did say last year was that we used some of the proceeds from the Meridian Energy Australia sale to support dividend flow through 2024 or at least up to a point where Rio Tinto makes it clear what it intends to do with the Tiwai Point Aluminum Smelter. And that's what you see on this slide, a lift in the interim ordinary dividend of 2.6% from $0.0585 per share to $0.06 per share. We'll be imputed at 80% and paid to shareholders on the 23rd of March. Pretty straightforward. We're also extending the dividend reinvestment plan, but as we did the final dividend payment last year, participants in that reinvestment plan will not receive a discount to market for the shares purchased. There are no changes to the dividend policy, so on to EBITDAF. Headline EBITDAF lifted by 8% on the first half of last year. The graph on the right shows a reasonable breakdown of the drivers behind the left, but the fourth bullet on this slide is equally important. That is the $61 million lift in energy margin that you see on the graph was supported by $51 million of profitable ASX closeouts. I'll talk to why we're able to close out those positions later. But for now, if we remove the $51 million of close outs from the headline figure, the underlying EBITDAF was actually a little lower than last year's result. I don't want to create a new reporting category, but I do want investors to know that we focus on underlying performance and positive ASX close out and not a typical or repeatable component of energy margin delivery for us. In saying that, there's nothing wrong with realizing $51 million in cash either. Moving on, I'm sure that you will have noticed the $25 million lift in operating costs, and you might be scratching your heads a little to reconcile it. The key is that this graph simply compares categories with the prior period. And in that prior period, New Zealand operating expenses did not include $4 million of Masterton call center costs, but they did capture the reversal of a $7 million holiday paid provision that we held on the balance sheet. So the real comparative lift in operating cost for New Zealand was more like $14 million. Given I'm talking to costs and to unwind any confusion, it is probably a useful time to say that I remain confident that we'll land inside the fin year '23 operating cost guidance of between $242 million and $247 million for the full financial year. Right. As the last bullet on the slide says, the second half has started off in a similar fashion to last year and the year before, a bit challenging. While the January operating report showed that we started the second half of the financial year positively, conditions started to bite during the month. As everyone knows, the North Island has been very wet, unhelpfully so. What may not be as well known is that the same conditions that brought rain to the North Island left the South Island bask in sunshine. Ask anyone living in South in Wanaka, how the summer has been and they might say too sunny. Maybe not, and I know that's slightly cold comfort for those living in Auckland, Northland and the Hawkes Bay right now. But my point is that the summer storms have had the North Island, not the South Island again this year. So it's possibly been a bit of a miserable start for everybody. What might [ into ] this mean for the second half of the year? Well, that story will be told in August. For now, it's too early to tell. That said, the graph at the bottom left provides insight into the impact of La Nina on Meridian's financials in the last 2 financial years. And that's a nice segue to energy margin where once again, customer sales supported revenue delivery while spot exposed generation revenues fell given wholesale prices were $42 a megawatt hour, lower than they have been in the previous period. Operating conditions did support strong production volumes again in the first half. However, with similar production in the prior period, so generation volumes don't really show up as a factor here. I've said it a few times at results announcements now, but it's worth repeating again. The lift in fixed price customer volume, which totals approximately 3,200 gigawatt hours over the past 5 years, continues to be the driving force behind growth in energy margin delivery. As you all know, we initially target this growth to mitigate some of the earnings risk associated with the 5,000 gigawatt hour contract terminating at the end of 2024. Over time, it's had additional benefit that I'll talk to soon. It's also where the $51 million in positive ASX closeouts fits in. Let me explain. A lift of 3,200 gigawatt hours of contracted volume is not that easy to accommodate within an existing portfolio. To support that level of growth back in 2020, 2021, the wholesale team turned to the futures market for support. And recognizing that our physical portfolio would not support this growth by itself, they bought a sizable ASX position for both '23 and 2024. As it's turned out, the wholesale team has found alternate ways to build a portion -- to manage a portion of that portfolio growth. So the ASX position hasn't turned out to be entirely necessary. Hence, that portion was sold and the $51 million in closeouts has been realized. I hope that was useful. Anyways, the portfolio rebalance away from wholesale and into retail is important for a couple of other reasons beyond immediate financial return. In the medium term, and as new renewable generation is commissioned, we expect spot prices to become more volatile than they already are. Stepping into new customer relationships will help smooth out any earnings volatility that would otherwise emerge in that environment all other things being equal. The last reason is probably the most important of all. In a reasonably short space of time, electricity consumers will begin to directly participate in the wholesale electricity market. So the external thermal generation can be managed effectively. I mentioned demand response from industrial -- large industrial customers at the start, the demand response from residential, small business and corporate customers is just around the corner as well. We intend on buying these services from customers in the coming years. And while it might seem like pie in the sky stuff right now, there are real-world examples of these schemes operating already. In California, for example, customers who provided these services were paid up to $500 over a calendar year for doing so. This 2-way relationship will fundamentally change the way we interact with customers, but you need a decent sized customer base to do it effectively, and we now have that scale. There's a bit of water to flow under that bridge, excuse the pun, to facilitate it, but the role of and relationships with electricity consumers are changing, and we want to be a big part of that change. Overall, and if I was to sum up this slide, we've improved portfolio resilience, seen small but meaningful improvements in energy margin delivery and will develop a stronger, broader relationship with customers that will benefit us all in the long run, not bad. To the customers, you can see from this slide that overall customer sales volumes grew by 218 gigawatt hours when compared to the first half of the last financial year. That volume growth has slowed markedly on previous periods and signals that we've reached our portfolio targets. But it's clear that products and services offered by the retail team continue to hit the mark. So we may reengage the retail team to grow depending on how the future plays out. Average prices also lifted, although I will note that for mass market customers, this was largely due to coming off fixed-term contracts. Corporate market pricing continues to reflect strong ASX prices, and Neal will talk to that soon. As I noted earlier, inflows were surprisingly strong in the first half of the year. And while that didn't show up in the energy margin graph on Slide 6 as a differentiator, the timing of those inflows was pretty important as Southland hydro storage entering winter 2022 was well below average. So the early largely unexpected winter rain that -- really set the business up to hedge customer sales. While $51 a megawatt hour, spot prices used to be normal when I ran the wholesale business,, if you look at this chart, you can see that they look a little depressed today, even though it will be a small percentage of folks, those that choose -- that chose not to hedge by the OTC or ASX markets will be happy for a bit of relief. As the slide says, though, as we stepped away for some Crissy cake and a bit of rest and relaxation over the holiday period, spot and ASX prices began to climb as Southland hydro storage started to fall. In January, for example, the average generation spot price lifted to $114 a megawatt hour. And if that feels a bit like déjà vu, you're right. As I mentioned earlier, the last 2 financial years have had very similar trajectories. Also, I want to provide an update on volumes traded on the ASX over the past 12 months. As I noted in a couple of minutes ago, this market has become increasingly to us and others as a mechanism to manage risk, and it continues to go from strength to strength in terms of volumes traded. While we haven't shown a table here that captures ASX trading volumes. Over the past 12 months, 113 terawatt hours was transacted on that platform. That's up 40 terawatt hours on the previous 12 months and represents more than 2.5x annual physical consumption of electricity in New Zealand. That market remains liquid. As noted, observed here and signal last August, operating costs have lifted. For those that weren't on the August call or do not remember the reconciliation, I'll quickly summarize it here. We, like all businesses, need to attract and retain good people, and the employment market was pretty tight entering the financial year. So we put $9 million aside to make sure we pay people appropriately. We also wanted to continue to build capability in our development team and within our subsidiary flux, so we committed an additional $7 million to those 2 activities. And finally, this year is the first year where $6.6 million of Masterton call center costs flow through the New Zealand cost line as opposed to Australia previously. It's not a new cost as such, but as the graph shows a year-on-year comparison of New Zealand costs only. And the Masterton cost only sits in the last half in year '23, that distinction is important. Of course, the Masterton call center cost is recovered through a contract we have in place with Shell. So costs are offset by revenue, but they show up in operating costs nonetheless. The key point I want to leave you with is that other than retaining people, we're putting funding into growth activities, flux in our development team. And our development pipeline is benefiting from this lift in capability, as Neal has talked to and will continue to expand on soon. As I said earlier, I continue to expect group OpEx to fall in the $242 million to $247 million range this financial year. So not too much more to add to this slide. As for CapEx, at the start of the year, I suggested we might spend between $410 million and $435 million. That remains a valid forecast, subject to where we land in relation to Harapaki. And for the first time this year, we broke out generation team total cash costs or operating and capital costs combined, and they totaled $40 million in the first half of the year. Given this level of spend, the forecast range provided in August might seem a little high, but the generation team workload tends to accelerate as the year progresses, so the market forecast of $83 million to $88 million for generation team total cash costs remains reasonable. Now as planning on this slide for the point in here amongst us. First off, net profit after tax lifted by $56 million or 39% over the previous comparable period. However, as net profit after tax contains fair value movements of derivatives, which is a noncash item and moves materially period-on-period, we also present underlying net profit after tax, which in my view, allows both better comparability with prior periods and insight into business performance. So the value of this slide, in my view, is the table on the right. It shows that while net profit after tax lifted by 39%, underlying net profit after tax lifted by 25%. We're pretty happy with those outcomes, but please remember that EBITDAF and by definition, net profit after tax and underlying net profit after tax also included the one-off $51 million injection from the ASX closeouts, so the result is skewed a little. A couple of other things to note. The value of generation assets lifted by $740 million. We don't typically revalue assets during the interim periods. But over the past 6 months, there was enough movement in the likely costs of new investment to warrant an update to price paths. The adjustments to price paths drove that lift in asset value. Balance sheet also remains healthy with net-debt-to-EBITDAF ratio sitting at 1.3x at the end of December. We agreed to surrender the lease of our Wellington premise at the end of October 2022, as you can see here, the impairment cost of the business was $6 million. And we're considering a green retail bond issue in the coming weeks to replace an expiring green bond while supporting growth. Look out for confirmation of that green bond offer on the sixth of March. Last but not least, the operating cash flow graph is there to confirm the cash delivery and the accounting metrics are heading in the same direction. They are. From my perspective, the operating business continues to perform well, and that alongside the progress we're making to grow the business means it was another sound 6 months. I'll now hand back to Neal, so we can shine a torch on growth, the regulatory environment and other elements to drive our strategic ambition and our influence performance over time.

Thanks, Mike. The wholesale market continues to see a forward price curve significantly higher than historic levels. Now with some of the underlying drivers, such as carbon price and coal futures, have moved off the high levels we saw last year, gas supply still appears to be priced and our [ hydro ] storage degradation, Methanex running at near full capacity, both reduce marginal gas availability. And despite the [indiscernible] infill program delivering production gains, new upstream exploration is yet to be proven. The recent years, reliability issues remain a risk as does the timing around the aging thermal fleet retirement and the country's ability to attract the capital needs for future gas exploration. We're also seeing a cyclical commodity price uplift, and an element of that is likely to be sticking to the forecast marginal cost of new renewable builds. At the end of the day, the energy futures on ASX, as Mike said, are liquid and trading around 2.5x the volume of the physical market. We have 5 market makers engaged in price discovery, so it's difficult to suggest that a forward price reflects anything other than the value of risk that buyers and sellers are accepting. All that said, as momentum continues to grow in new renewable investments and as dry year firming solutions emerge, Meridian's in-house wholesale market outlook still has long-run price expectations in the $80 to $90 per megawatt hour range in real terms. That may be called comfort to corporate customers contracting electricity supply for the next few years as prices are significantly higher than that at present, but we still see the transition of the energy sector to electric, being affordable and cost-effective consumers in the long run. Now the legal framework governing resource management in this country is complex, and I've heard no one suggest that it wasn't well overdue for reform. We believe it is an intention of government and officials through the current reform process to support efficient renewable energy development that will enable New Zealand's low-carbon future. But it's difficult to see that intention in the suite of legislative changes currently working through the select committee. In fact, the natural built environment bill puts natural values ahead of climate change. And in the absence of a national planning framework, that is yet to be developed and that may help guide local government to look to the greater good. We do have concerns with how this reform will be delivered. Accordingly, Meridian is working with the other large generators through the select committee consultation process to ensure that [indiscernible] gets a good outcome. And to be clear, I don't believe anyone expects renewable development to get a free hit. Developers must work with communities and environmental agencies to mitigate the local effects of large-scale infrastructure development, but we do expect these effects to be balanced against the climate benefits that renewable energy brings. And now to what I hope is a final mention of TPM changes. Final pricing under the new TPM framework has been confirmed by Transpower for the '22 -- sorry, the '23-'24 pricing year. For Meridian, that means a $12 million reduction in transmission costs on a like-for-like basis. But that starts to be eaten into with a $5 million increase in Transpower's asset replacement costs also flowing into that pricing year. During December, we identified an abnormal gas signature in the unit 6 transform at Manapouri. We made a market announcement around that issue. The observation was part of our condition monitoring regime, and it potentially indicated a high temperature fault within the transformer. Because of the risk of transformer failure in an underground powerhouse environment, we have taken the unit 6 generator out of service, and it will remain that way until the issue and the resolution to it are fully understood. Indicatively, that could be an outage of up to 6 months. And most importantly, the work we've done over the last couple of months suggests that we're not dealing with the fact that is likely to affect all 7 units. And the loss of this unit can be managed comfortably within our portfolio. Also, as Mike indicated earlier, the way our catchment has gone through another very dry patch and we don't have the water to generate more 7 Manapouri units even if they were available. The unit 1 transformer had previously indicated a similar gas signature issue, although not nearly as significant and following an inspection that units returned to service in late December as it was safe to do so. As I mentioned earlier, weather has been our major issue at Harapaki. Even before Gabrielle cyclone hailed dumped around a meter of rain at the site. The good news is the enhanced roading design that we signed off in August last year seems to be standing up well to the conditions. And whilst the first set of turbines are sailing to New Zealand now, our ability to get them from the port to Napier -- from the port and Napier to the site is our next big problem to solve. We'll have to wait to see how quickly State Highway 5 can be restored and how quickly Transpower can complete the Hawkes Bay remediation works before they can turn their attention to commissioning the Harapaki 220 kV substation. I do really feel for our construction teams. They've been doing an amazing job managing through very difficult conditions. But for the time being at least, further progress is mostly out of their hands. We'll inform the market of the impact on the project timing and cost as it becomes clear. Ruakaka BESS situated just south of Whangarei will be New Zealand's first large-scale grid battery and adds significant versatility for Meridian and for the system as a whole. As you may be aware, the market for battery componentry became white hot last year, and it took considerably to stitch a supply deal together. But fortunately, we and staff did get it done. North Island battery was originally part of our response package to the NZAS contract termination. And as we develop the opportunity, the BESS business case proved to be an economic investment for Meridian irrespective of whether Rio Tinto stays or goes from New Zealand. The BESS offers multiple new revenue streams, providing the ability to load shift between price periods and to participate in the North Island reserves market. Site works are due to start in mid-March. We also have an adjoining 120-megawatt solar farm plan. The grid connection assets built to connect the BESS to the grid will -- can be shared with the solar farm, and that materially improves the economics of that project. As I mentioned earlier, it was great to select our partners for Southern Green hydrogen, Woodside and Mitsui are genuine heavyweight partners with massive capability. And together, we are moving into the detailed design stage of the project. We're also working closely with Ngai Tahu through Meridian regeneration as that project aligns with their vision -- their energy vision for the region. Now we have in principal reserved combined equity participation rights for Meridian and Ngai Tahu of up to 40% of the eventual project. We're assessing both domestic and export markets for Southern Green Hydrogen products. Assuming a 600-megawatt facility, Southern Green Hydrogen will be capable of producing around 500,000 tonnes of green ammonia for export each year. Importantly, the facility could meet up to 40% of our electricity systems dry year flexibility needs by providing flexible demand response. Demand response will be a significant feature of our future low-carbon energy system, and we believe those industries that can provide flexible demand response over a season, the market will reward them well. We expect to reach final investment decision for Southern Green Hydrogen, hopefully in the early part of 2025. The next two slides focus on changes in our retail strategy. 2022 marked 5 successful years of organic customer sales growth. And for context, that growth is equivalent to around 65% of the current NZAS contract volume. That means our sales portfolio has become fairly full, and we're now executing a shift in our retail strategy towards growing the size of the pie, not just our share of it. Our certified renewable energy product is now well established and provides meaningful value for customers, particularly those involved in export markets. And our drive to support enabling light vehicle electrification, we are committed to being a substantial EV infrastructure owner. And we're building out a broader customer proposition alongside our EV plans. The cost of living is a major pressure point for so many kiwi households, and the energy hardship problem has become widespread and is complex to solve. I'm committed to seeing our company lift its level of support for customers experiencing hardship. We completed our energy well-being pilot during 2022, and we learned that we can make a long-term and meaningful difference to households who are struggling. So now we are looking to scale up that program to reach a size portion of our customers who are dealing with the energy hardship in their homes. We have bold ambitions to grow our energy solutions focus and to be a major electricity retailer to electric vehicle owners and distributed generation customers. We also plan to grow the customer value and support security of supply by landing industrial demand flexibility alongside what we're already targeting in terms of process heat conversion. We've shown some initial targets on this slide, but you can expect to see more in the KPIs addressing the shift in retail strategy later this year. As I mentioned at start, we have more than doubled our renewable development pipeline since the middle of last year. The portfolio comprises mostly onshore wind and solar options. Now I have triple checked that claim because I was struggling to believe it myself, and it turns out our prospecting crew have been doing an amazing job. We are committing to getting -- we are committed to getting on Ruakaka developments and the Mount Munro wind farm. The gap on this slide between 26 and 29 reflects the risk of an NZAS exit. Obviously, a 3% of the country's demand gets turned off at the end of 2024, the timing of all new builds beyond them, including ours may face reassessment. On the other hand, if NZAS continues and Southern Green hydrogen also gets financial close, then Meridian and the market most probably will look to further accelerate developments. And certainly, we are working hard on options to do that. And this slide should be familiar to you. 2.5 years down the track. I think we've done a pretty good job mitigating against the planned closure of NZAS. The transmission solutions, including the Ruakaka battery had been or a target to be delivered before the smelter closure date, whilst the actual sign-up for process heat volumes has plateaued over the last 6 months or so, the pipeline that our sales team our look is improving. So while our forecast still sits at 600 gigawatt hours, I think we will land more than that. And it's a $650 million GIDI fund funding starts getting released, we expect the number of announced thermal go electric conversion opportunities to increase quickly. The data center opportunity is the most challenged of our mitigation plans whilst Datagrid submitted a land-use consent application in October last year, we note that Rémi Galasso, their founder and their apparent passion behind the concept has left the business. So it's fair to say our confidence in that project is diminished. And of course, the big ticket, new demand opportunity in Southern Green hydrogen is still well on track for delivery by 2028. So to wrap up, Cyclone Gabrielle and before it, Cyclone Hale has had a devastating impact on many homes and businesses. I'm confident that as an industry, we're working hard and in a coordinated fashion to help support people through that crisis. There might be an impact on project Harapaki, but it's too soon to quantify it in terms of time and cost. We had a strong financial income for the first half of the year -- sorry, outcome for the first half of the year, and hydro storage is about average for this part of year. But the forecast in Southland looks dry again and news outlook suggests a La Nina influence prevailing into autumn. It will be what it will be, but we've done a good job securing our risk position and appropriate hedge cover. And as Mike indicated to you earlier, you can expect us to lean more heavily on our existing smelter contract should hydro storage continue to decline. We've made a lot of progress moving our strategic agenda forward, and that will continue from Meridian. You can expect to see consents lodged for Ruakaka solar farm and the Mount Munro wind farm this side of June. The decision to build one or both of those projects by middle of next year. The Ruakaka battery will be operational by the third quarter of next year. All going well, we will have made an investment decision on Southern Green Hydrogen early in 2025, and our Energy Solutions customer strategy will be gaining strong traction. And I guess at some point over the next year, it is likely to become clear on whether NZAS will continue to operate in New Zealand or not and on what terms. And you'll know all about that almost as soon as we do, I promise. It's -- I mean, look, it's certainly an exciting time to be in this industry and to be in this company. The potential for growth and to make a real difference to people in the environment by living to our purpose of clean energy for a [ fair ] healthier world has never been greater. So thank you all for your attention. Now we can move to questions, and I think we'll start with those in the room first off. Andrew?

Neal and Mike, a few questions from me. First of all, obviously, understands the issues around Harapaki, and not being able to sort of know when you might be able to get back on site. But could you perhaps give us a little bit of color in terms of at what point does a delay become problematic? I mean how much can you handle? And I guess at what point does that actually start being a real issue for you?

We've got appropriate lay down space in and around the Port of Napier. So we can absorb the machinery out of Asia where it's coming from. I mean, it just becomes a time thing. As the road opens up and we can get access to site, then we can get the cut up there, and we can stand it up. And forecast on when that road will be available for heavy transport and to the extent of 80-meter blades, it's just an unknown at the moment. So I thought they were doing quite well, but we saw a picture the other day of a big washout that occurred just after the weekend. So we were exploring alternate routes as well, but we don't have a clear handle on that yet.

Next question, a couple of questions really around the renewable development pipeline. And I think to be fair that's probably the biggest change we've sort of seen in this set of results. Just be interested to know in terms of those advanced prospects, which have sort of increased quite considerably. Can you give us a little bit more color in terms of what an advanced prospect actually means? And then in terms of what's the expectation around these actually being built, and I presume time frame, we're looking into 2030s before any of that pipeline would be coming to market?

Yes. A vast prospect is one where we've got a landowner agreement in place, and we've got a good handle on the resource. So we've actually -- we've got it pretty well modeled in terms of the potential economics. In terms of timing, Andrew, there's so many things at play, and we've been in this game long enough to know that, that particular list of projects will change around. Some will come further forward. Some will get pushed back. But we're confident because we're starting to show it that we can build to a development pipeline in line with the projections on that page, but too early to call out exactly how it will play out in 2030 to '40 at this stage.

And in terms of the solid developments, I guess, in particular, are all of those prospects, things that Meridian staff have found themselves? Or are we looking at effectively acquiring some other projects that other developers have got to a certain point and are maybe looking to monetize their work today.

We've had an extensive study going on for years, actually across the country in terms of where the best resources, so we've developed most of that ourselves with landowners, but we're also looking to procure some. Some of the ones we're looking to procure around on this list. So we're open to procuring good options as and when they become available.

Okay. And last question for me. Just I guess your comments around the long-run marginal cost of new generation and real terms being 80% to 90%, unfortunately, we have inflation. So I'd just be interested in trying to anchor that statement a little bit. I'm assuming if we roll forward, say, 5 years, you're talking about current CPI maybe another 10%, 15% on that and sort of the mid- to late 2020s at that kind of looking at sort of 90 to 100-ish.

Yes, probably. I mean, look, I wouldn't -- I mean, I wouldn't want to try and predict inflation outcomes at this point. But -- and we've probably got relatively conservative assumptions in terms of when things will start to settle down and trend more towards the long-term trend, which is technology improvements driving costs down. But I think of that order as seems about right.

Just three for me and just following on from Andrew's question to start off with the you probably said it, maybe I missed it. Should we think of that as a long run average price, if you like a time-weighted average price? Or is that the sort of range of costs for new projects, breakeven revenue they need? That is a price.

Long-run average price great.

Other two questions at commentary.

Just mentioned in this, that's lifted a bit from where we've been in the past. They were probably in the $75 to $85 range. So we have seen what we consider to be sort of more of a permanent shift upwards.

That's very helpful. Other two questions. No mention to hear about demand outlook. Obviously Tiwai hydrogen at typic swings there. But if you take those out, kind of what's your view on demand growth underlying for the -- from here to the rest of the decade?

I was going to say no real change from what you've seen in the past, Nev. The timing of demand is probably the most challenging. We see, when Neal talked to the changes in government policy and legislation that will drive changes in the way the economy works, we've got good engagement in the South Island through our process heat initiative. But -- and we provide stylized graphs of demand growth through 2050. But the timing of that over the next kind of 7 years through the end of the decade is always a little more challenging to go, here's the pinpoint for. So -- but key point, nothing has changed from what we have presented previously.

Yes. So no concern or optimism from the track you're seeing today, entering [indiscernible]. Last question for me. And just to get some idea, not necessarily asking for a number, but do you see the netback you could get from a hydrogen project as sufficient to pay for new renewables? Is it at that level?

That's clearly the objective, Nev. And what gets it into the zone is largely around the ability to provide flexibility back into the market, which depending on your view, the circa $20 to $30 a megawatt hour of value associated with that sort of level of demand response.

Just appreciate sensitivities around Gabrielle and it's the extreme weather events. But when you look across your asset portfolio and event that extreme, how close did that come to stressing or potentially stressing the assets?

It didn't stress Meridian's assets, obviously. The event that would cause us stress as a major, probably a major earthquake in the Southern Islands primarily or weather-related fault lines in the region. This one didn't stress our assets, certainly stressed the overall region. This is a transmission distribution asset issue primarily, but I think Genesis has been called out for bringing [indiscernible] capacity on very quickly and that really helped. So it wasn't a generation issue, but it was certainly a transmission distribution asset issue.

Probably the thing to add here. So development options, how developments face increasingly large floods and events like we've just seen in -- Ruakaka's a good example of largely at sea level, but we've had the opportunity to go back to our engineering analysis that already incorporates climate change and the impacts of climate change and assess the flooding levels and the development and design of the concrete plants to house the battery and/or the solar park. And we're confident in the analysis that we've done, but it does make you stress test those decisions as well. So future development that does impact the decisions that you might make and where you place your assets?

And of course, we also look at maximum flood potential in the South Island hydro catchments. That's been an ongoing exercise and will be part of our asset management planning and programming forever. No one else in the room? I think we can go to the telephones. Have we got any questions?

[Operator Instructions] The first question comes from Grant Swanepoel from Jarden.

Can you hear me?

We can, Grant. Loud and clear.

First question, just on hydrogen. All these long-term studies supported me that gas should be part of [indiscernible] change agents. If [indiscernible] clarity, does it scatter behind vision prospect?

I didn't get that.

Grant, could you say that last piece again?

Well, there's no demand response required because gases supply the capacity shortfall in the market. So therefore, does that kill the hydrogen metrics?

No, I think we'll need a range of particularly seasonal dry year response measures, Grant. We certainly see, and I think a lot of commentators see gas continuing in the New Zealand market for the foreseeable future a much lower levels than there is today, obviously. I think a large demand response industrial customer like just hydrogen producer will bring a huge amount of availability to manage through those dry year events, and it's complementary. I don't think it's an either and or. Obviously, if you go and build norms like [indiscernible] thing, it changes that dynamic quite dramatically. But at this stage, I think demand response is going to have to be part of our future. And at this stage, from what we're seeing, this is the most sizable and realistic demand response opportunity available to the New Zealand sector.

Next question, just on Tiwai. Just please remind us what triggers your need to call them to cut back a part? How many megawatts is that? And for how long can you call it off for?

[indiscernible].

Yes. So Grant, the existing smelter demand response allow us to request smelter to reduce consumption by 250 gigawatt hours over a 6-month period. So the smelter makes the decision in relation to what they actually do. We get the relief as it relates to contract position.

And what triggers that, Mike?

So there are -- it's only exercisable if New Zealand storage falls below certain trigger levels. So largely driven and available to us as hydro storage levels for.

They are disclosed in the contract on our website, too. So it's available.

So the trigger level is disclosed.

Plus typically, when we're getting close to it, we will start flagging that with some sort of chart so that the market can understand where that's it.

Can I push you one more on Tiwai. Are we talking negotiations 3 to 6 months, still, to expect something unlike with contacts pushing for a hard close on that deal?

Look, I think, I mean, Mike, you're running, I think 3 to 6 months would be ideal, even that might be optimistic, to be honest. But, because there's a lot of work to be done on behalf of the smelter. I mean, they're dealing with more parties than just Meridian this time around. It's complex. They've got a range of contractual positions to put together. And it all come down to price at the end of the day as well. And we're, there's still no certainty we can reach agreement on that. But on...

I was going to say, Grant, I think you asked similar questions as someone did at the August results, no surprise. And I said, hey, 3 months is a long time because the target at that stage was December 2022. I said 3 months is a long time if you put a lot of effort and time into it. And we didn't deliver on that outcome. So we're committed to the negotiation. I think the best way to answer the question [ are we are ]. It's really hard for us to say it's 3 or 6 months. We were -- we took heart from what contacts did, they obviously what we took from that as they're looking to take a leading position in that negotiation. So whether that gave Rio confidence or not, it certainly -- we sat there and said, contact pretty enthused and keen to deliver that outcome. So we expect them to provide a sizable part of that price.

And can I just put the Harapaki delay into context. So your last guidance about $448 million of CapEx. Are we talking about maximum line of another 10%. And then, you're looking at first power around about during this year. Are we talking about a month or 2 delay, not something that's going to blow out of proportion and caused material disruptions to earnings?

I can't see it being a material disruption to earnings, Grant. But yes, we are guessing, but we hope it's no more than a month or 2. And if that's the case, then it's not particularly material type of the business case and certainly not to the company, but it really does come down to the state of that road because there isn't -- I mean, we're testing it, we're looking at alternative options, but there aren't too many, if any, other viable options to get that size cut up to site other than upstate Highway 5. And as we all know, it's a bit of a it of a mix at the moment.

Yes. Bit of a jigsaw puzzle for you guys. And then my final question, so a nonstrategic sort of one. The other companies are talking about the C&I duration, headroom from our 3 moving towards 5 year. But some of them are now talking about moving that to 10 years. Are you finding that your book is also rolling over to much longer durations and that's becoming a 10-year type or is it just 2 as most people thinking?

Yes, Grant, it's been, we might have stated that our average duration of contract in the C&I space. We've worked to extend not to the lengths that you're talking, though, as we'll work with customers depending on their risk exposure. We have signed 10-year deals with participants in the C&I market. Number of them are looking at 5 years, but the duration of our C&I book has extended. We've done that purposefully as part of our mitigation framework. So we'd like contract volume sign up as we approach 2025.

[Operator Instructions] Your next question comes from Stephen Hudson from Macquarie Securities.

Just four for me, if I could. Just firstly, active trading in market making. I just wondered if you can give us a feel for what contribution, Mike, your team pay there and what we've sort of seen historically. Secondly, just on the revaluation, I saw that the assumption regarding [ German ] has come down 130 gigs. I don't know if that's a sort of a mechanical [indiscernible] there's something behind that, but a comment there would be great. Also on the revaluation, do you assume a sort of an NZAS go or stay? Or is it a sort of a blended some sort of weighted probability assumption there? And then just lastly, on the -- you've given an EBITDAF range of $20 million to $35 million. Can you give us a broad split of the assumption regarding your plans and your ancillary services contribution?

Steve, I'll do my best. If I miss one of them, I can catch afterwards, to follow up. Market making, all we've seen from market -- I mean, our contribution in that market stays reasonably steady. So numbers we've presented where we're 25% to 30% of that market. The -- but what we have seen, the volume lift is driven by nonmarket makers. So nonmarket maker participation driving trade, and the active trading going on in that market has driven the growth in volume. And so our traders had to get better at what they do over time to make sure that they manage the exposure we have. And we released the numbers each month through the operating report kind of what the cost of providing that liquidity to marketers. But there's no doubt that nonmarket maker participation has grown massively. On the scenario and the assumption for price path and revaluation, that is that NZAS exits in 2024. So no change to the assumption that we've used. The only change really is the cost of investment over time. I missed the piece on the 130 gigs. And I didn't write down the last part of your question, so you might have to repeat it.

Yes, it looks like you've lost up 30 gigawatt hours out of your generation assets?

There will be...

Assumption, I can take it off line.

Yes. Let's take it off line, it will be a natural variation. So the way that we model and forecast generation participation, just the average outcome across your 85-odd scenarios just changes marginally every time you do an update, so it really will be driven by noise and the update as opposed to anything else.

Last question...

[indiscernible] gradually, but disappearing or anything. And just to clarify, so you've assumed then there's exits so that then feeds in $80, $90 long-term wholesale price assumption?

That's right.

Yes, our short term, there's a short-term impact...

So if end debt stays, then it's a very different number, I would assume.

That's right. Yes. So the way our modeling is, NZAS has a short run impact on prices. But over the long run, we expect that demand will replace it. And as it replaces it, you will approximate long-run equilibrium again.

Yes. I think, Stephen, just to be clear, I think even in an NZAS exit, we still see long-run cost, average cost coming out in that 80 to 90 range. There would be some disruption either down or up if they stay in a Southern Green Hydrogen was suddenly to be launched into the market. But over the long run, we still think the market will find its way back to the marginal cost of new renewable generation plus firming costs.

And your last question was on the BESS, Steve. Neal has kind of reminded me what we've been talking. But we split the revenue potential for that asset across 3 different categories as we had arbitrage revenues, we had reserved revenues, so participation in North Island market and then what we call portfolio revenues. So use the battery to ensure that prices between North and South Island didn't diverge. And we ran it across any number of scenarios. So it's hard to break down the actual percentages for each, but I'll do a little bit of that in a scenario where in the exits where the battery is most valuable to us. And in that scenario, about 50% of the revenue potential is from portfolio benefit and the other 2 are split evenly. But even if NZAS stays, that battery still creates value for the business. They're split more evenly, though across that scenario, as I say this, we tested that one pretty thoroughly across our normal modeling, and we even updated our modeling framework to look at what we call hindcasting, so test the modeling framework against what we've seen in the past to test the arbitrage revenues quite carefully because of battery. As I mentioned, Neal said the same thing, is reasonably new in New Zealand, we want to make sure we're making an investment that benefited our investors.

Actually, I might just be cheeky and put one more in for Neal. We've seen some news recently around renewable contractors, in particular, Downer. I know it's a pretty shallow market here with sort of [indiscernible] and Downer a bit. As you stand today, you're confident that there's capacity and appetite to provide contracting services for wind projects on fixed prices?

I think there is on the -- well, there is currently because we're building quite a few around the country, but there's more coming online. So capacity will have to build to meet the sorts of aspirational growth plans that we have and that others in the market have. There's no doubt about that. And probably one of the issues for the industry is ensuring that we can support that level of capacity growth through the lulls or the upsets that may sort of slow down a project or 2 or speed them up. So we need a consistent delivery path. I think over the next 30 years, if we're going to get anywhere near achieving the sorts of outcomes we need to help this country decarbonize. So yes, a lot of work in front of us in that regard, I think, Stephen.

Your next question comes from Parker from Craigs Investment Partners.

Just a couple from me. Just wondering about if you had any observations on the level of traction [indiscernible] is getting through its GIDI fund. So actually, the first rounds of funding being transferred into an uplift in demand. And any new traction on that $650 million fund that was issued last year, I believe. And also, what's your opinion on the realization risks?

I don't know if we got that last piece of the question. The....

Just what sort of risks that you see around an industry at the moment and potentially industry finding it pretty tough with energy prices and under pression, so -- and potentially closing down.

Yes. Look, the GIDI -- the $650 million, we're coming up to a funding round. I think it's March -- it's certainly in March, and that will release a decent chunk of that, and we expect it to sort of progress from there. The projects that we're working with and the sort of pipeline of sales that we're -- we've got, which exceeds the 600 gigawatt target are all leaning into the fund with applications. So that will become clearer, I think, over the next year. But there hasn't been an uplift in funding allocated from whether getting what fund was previously, which was $65 million, and then it got ramped up to $650 million. So there's quite a lot of work on behalf of [indiscernible] get some momentum behind that.

It was just industry generally. It's probably hard -- it's a hard one for us to answer at a very specific level the...

I'd say we're all very concerned around capacity constraints, any sort of outage or impact on customers. That's a massive risk for the industry. If we lose confidence in our ability to deliver a reliable service and a fairly priced and efficiently priced service to customers, then the decarbonization thing will become an issue for some other generation. So I guess that's pretty key for us, obviously, and I look into the risk around from an asset management perspective, large-scale sort of disasters or any sort of nature caused, chaos. The price of new renewables and our ability to access them going into them. I think in it future, the world is going to grow the capacity to deliver. But the next couple of years might be quite challenging. We haven't been to market for a while. We went to market for the battery, and that moved on us in a healthy of a hurry. Things are starting to settle down again, but that will continue to be a reasonably -- I mean, it's a challenging market out there globally. Anything else you'd add?

I'd just say our job ultimately is to drive competitive advantage to New Zealand businesses that compete globally. There has been a hollowing out of manufacturing base that's had exposure. When you look at electricity prices in New Zealand, they are high by historical standards. But when you look at electricity prices in Australia, Europe, U.S., wherever, they are worse. So there are challenges everywhere internationally for folks. I think we're doing what we need to both help them decarbonize their businesses over time and ensure that they are and do remain profitable over the long run. We talked about the length contract that we've been entering into with customers to help them manage through the current challenges that they face. So I'm probably optimistic in that regard. And certainly, our job is to support business ultimately that needs to compete internationally.

And just the last one, really, obviously, the OMV asset sale and declining asset market and what your thoughts are on sort of, say, medium-term dry year risk and so forth around that. So if, we've got the gas market potentially falling away, does that present more of a risk to you? And what are the options that you see around that going through to 2030?

Yes, it does represent a risk clearly. And I think we'd all be more comfortable if there was more investment going into gas exploration, storage capacity in particular. I know there's plans afoot. We're not part of any of those directly because we're not engaged in anything other than renewable asset generation, but we certainly can and do and are interested in contracting with parties that are building capacity. But certainly, we need to see more investment in the gas industry in the near term to help manage this transition in a way that's -- that works for all New Zealanders.

Your next question comes from Vignesh Nair from UBS.

Can you hear me okay?

Yes. Yes.

Perfect. Just a couple today lastly end that Mike, perhaps Firstly, just on Cyclone Gabrielle and Harapaki impacts. I know you talked about it at length and it's early days. But just sort of on the cost front from potential the site remediation and other related expenses, is that all applicable for business insurance cover? I suppose another way of putting it is, is this a cost issue, a time line issue or both?

So we're working through, again, a lot of it's -- it's too early to give you a definition, but we are working through insurance claims. Remember, Neal's point, I don't think I said it, but the site is actually in pretty good shape. I think it's had 1.6 meters of water since the start of the year, and we made a pretty fundamental decision with that site last year to lift the cost base by $50 million, so we could install [ rolling ] up there that could, that is a time could weather a storm that's pretty bad. I couldn't think of anything else to say, but it has. And that decision has played out really, really well for us. So I think from a site perspective, the costs largely come down to now what plays out with State Highway 5 in the transmission infrastructure because we've worked to get our team to make sure the team is available and ensure they're ready to go back to site. But it's simply just getting them back to site via State Highway 5 and ensuring that we can commission the substation, as Neal mentioned. So i's just too early to provide some substance and frame to costs and/or time.

But I think the -- it's more of a time issue for us than a cost issue. Of course, time has a cost angle because you're not getting the revenues flowing into the project as soon as we'd like. But it's certainly more time that we're concerned about than a massive remediation job up at site.

Okay. That's [indiscernible]. And secondly, just on operating cost inflation, a simple question. Is this sort of as high as it will go and whether an alter sort of any embedded one-offs in that guidance number for the full year that may not continue in terms of FY '24 and beyond?

It's a great question. We will definitely continue to put money into our development business. and we'll keep putting money into flux as a business to the extent it delivers new sales, which is what its opportunity and future looks like. So those 2 businesses rely on good people. And as Neal and I both mentioned, the expansion in our pipeline has been due to the people that work within the business phenomenal. So I have no hesitation in continuing to present more cash to the extent the value is there in that regard. The only other place that we're seeing costs as everybody is, is, again, as all of us sitting in the room and on the phones is the cost of everything we buy goes up. We look for some support from our employers. And again, we've got great people, you want to keep them. So it will be driven by the employment market immigration and cost of living indexes as it relates to future costs. Beyond that, the operating business is actually very, very disciplined. As an example, I think we used last year where the retail business has grown its volume under contract by the -- over 3,000 gigawatt hours, and Neal and I both, mentioned today, held the cost flat. So there are very, very disciplined people on the cost front within the business, but we do have exposure to the employment market and no apologies for trying to grow the value of the business. So hopefully, that's useful, probably longer than you needed.

Yes. Yes. Awesome, great color. And one final thing here. I think you mentioned [indiscernible] a little bit in the [indiscernible]. I think I missed that. I just wanted to clarify what the commentary around the offtake from that contract was?

Yes. My main point was that project is not progressing as we anticipated 1.5 years ago when we started this. They have lodged for a consent. We understand that if the project gets up, it will be done in 10-megawatt type increments. We were talking 100 megawatts back in the day. But our main concern is that the main guiding force behind data growth, the person that we got to know, built a relationship with, has left the business. So I'm not particularly confident at all, clear. But if it does, it will be incremental volume, probably not of a 100-megawatt type scale, and we will treat it as a normal customer type arrangement.

Thank you. There are no further questions at this time. I'll hand you to Mr. Barclay for closing remarks.

Okay. Well, thank you all very much for your attention. We'll see you all again in 6 months. We'll do it all again. Yes. Cheers. Bye.