Kia ora koutou, welcome to Meridian Energy's interim results presentation for the six months to December 2022. I'm Neal Barclay, Meridian Energy's Chief Executive, and I'm joined here by Mike Roan, our CFO. Firstly, I'd like to acknowledge those people impacted by Cyclones Gabrielle and Hale. To 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 six 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.
We're very pleased to announce another incremental lift in our 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. Importantly, the underlying drivers of value have shown improvement over the last year. Also very happy with the progress we've been making toward our strategic goals. Committing to the construction of our grid-scale battery at Ruakākā 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 Ruakākā grid-scale solar farm. Preparations to lodge consent for the Mount Munro Wind Farm in the Wairarapa is also tracking well.
By the end of the calendar year, we expect to have those two 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 this country produces each winter, and it needs to be that size given Aotearoa's decarbonization goals. 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 are 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 too with Ngāi Tahu to progress the project activity and to confirm their ultimate involvement in the project. Our Harapaki Wind Farm in Hawke's Bay has been plagued by the wettest two 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. As of today, we don't have a firm read on the impact on the overall project timeline and cost. The state of the wind farm, to be honest, has been a second order of importance to us over the last two 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 have centered on the Hawke's Bay because we're physically there.
We were focused on the safety and wellbeing of our team and the surrounding communities. Through our own people and our construction partners, we provided support to Unison, Civil Defence, 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 NZD 1 million to our immediate relief efforts on top of the work we're doing on the ground. Some funds will be deployed through KidsCan and the Red Cross, and some will be used to provide targeted support to iwi, 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. 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 or 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. That must wait for the time being as the recovery stage is still well in progress.
On a more positive note, our push into public EV charging space has ramped up considerably in the last six months, our customer teams' shift in focus to creating energy solutions that support customers to decarbonize is also building real momentum. My final point, and the one you're probably all interested in, we remain in discussions with Genesis on potential contractual arrangements beyond 2024. The discussions are complex. I expect they will continue for some time. Despite the best intention of all parties involved, the continuation of the smelter beyond 2024 is still far from certain. 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 their seats like they were last night at the Basin, that was a strong open nonetheless. Thanks, everyone, for joining the call this morning. As Neal mentioned, I'm gonna talk through our financial statements for the next 15 minutes or so, as you'd expect. Before doing that, I wanna spend a couple of minutes providing some context for them. Simply put, the electricity industry is in the early stages of 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 three or four 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 that security of supply is 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're 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 MW Ruakākā battery is an example of how investment commitments are changing.
Grid-scale batteries are new to New Zealand, this one's 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. 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. I can't remember a headline drumming up the same level of hysteria since. Anyway, as I noted earlier, the world's moved on. As we enter 2023 with two 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. Relying on them more heavily seems right as the role that demand response plays in a decarbonized economy will only get larger.
The existing NZS agreement ends in 2024, relying on those provisions makes commercial sense as well. Two small but real examples of an industry that's transitioning. There are many others. 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, I'm pragmatic enough to know that we will have challenges. Transitions are never linear, the industry is definitely out 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'd use some of the proceeds from the Meridian Energy Australia sale to support dividend flow through 2024, or at least up to the point where Rio Tinto makes it clear what it intends to do with the Tiwai Point aluminium smelter. That's what you see on this slide. A lift in the interim ordinary dividend of 2.6% from NZD 0.0585 per share to NZD 0.06 per share. It'll be imputed at 80% and paid to shareholders on the 23rd of March. Pretty straightforward. We're also extending the dividend reinvestment plan, as we did for the final dividend payment last year, participants in that dividend reinvestment plan will not receive a discount to market for the shares purchased.
There are no changes to the dividend policy, 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 lift, the fourth bullet on this slide is equally important. That is the NZD 61 million lift in energy margin that you see on the graph was supported by NZD 51 million of profitable ASX closeouts. I'll talk to why we're able to close out those positions later, for now, if we remove the NZD 51 million of closeouts from the headline figure, then underlying EBITDAF was actually a little lower than last year's result.
I don't wanna create a new reporting category, I do want investors to know that we focus on underlying performance and positive ASX closeouts are not a typical or repeatable component of energy margin delivery for us. In saying that, there's nothing wrong with realizing NZD 51 million in cash either. Moving on, I'm sure that you will have noticed the NZD 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. In that prior period, New Zealand operating expenses did not include NZD 4 million of Marsden call center costs, but they did capture the reversal of a NZD 7 million holiday paid provision that we'd held on the balance sheet. The real comparative lift in operating costs for New Zealand was more like NZD 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 full year 2023 operating cost guidance of between NZD 242 million and NZD 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 basking in sunshine. Ask anyone living in Southland or Wanaka how their summer's been, and they might say too sunny. Maybe not, and I know that's likely cold comfort for those living in Auckland, Northland, and the Hawke's Bay right now. My point is that the summer storms have hit the North Island, not the South Island again this year. It's possibly been a bit of a miserable start for everybody. What might any of this mean for the second half of the year? 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 Niña on Meridian's financials in the last two financial years.
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 NZD 42 a megawatt-hour lower than they had 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, it's worth repeating again. The lift in fixed price customer volume, which totals approximately 3,200 GWh over the past five years, continues to be the driving force behind growth in energy margin delivery. As you all know, we initially targeted this growth to mitigate some of the earnings risk associated with the 5,000 GWh 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 NZD 51 million in positive ASX closeouts fits in. Let me explain. A lift of 3,200 GWh 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. Recognizing that our physical portfolio would not support this growth by itself, they bought a sizable ASX position for both 2023 and 2024. As it's turned out, the wholesale team has found alternate ways 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 NZD 51 million in closeouts has been realized. I hope that was useful.
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, 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. The exit of thermal generation can be managed effectively. I mentioned demand response from large industrial customers at the start, but demand response from residential, small business, and corporate customers just around the corner as well.
We intend on buying these services from customers in the coming years. 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 NZD 500 over a calendar year for doing so. This two-way relationship will fundamentally change the way we interact with customers. 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. The role of, and relationships with electricity consumers are changing. We wanna be a big part of that change.
Overall, if I was to sum up this slide, we've improved portfolio resilience, seen small but meaningful improvements in energy margin delivery, and we've developed a stronger, broader relationship with customers that will benefit us all in the long run. Not bad. Talking to customers, you can see from this slide that overall customer sales volumes grew by 218 GWh 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. It's clear that products and services offered by the retail team continue to hit the mark. 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 folk 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 six as a differentiator, the timing of those inflows was pretty important as South Island hydro storage entering winter 2022 was well below average. The early, largely unexpected winter rain that set the really set the business up to hedge customer sales. While NZD 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'll be a small percentage of folk, those that chose not to hedge via the OTC or ASX markets will be happy for a bit of relief. As the slide says, though, as we stepped away for some Chrissy cake and a bit of rest and relaxation over the holiday period, spot and ASX prices began to climb as South Island hydro storage started to fall. In January, for example, the average generation spot price lifted to NZD 114 a megawatt hour. If that feels a bit like deja vu, you're right. As I mentioned earlier, the last two financial years have had very similar trajectories. Also want to provide an update on volumes traded on the ASX over the past 12 months.
As I noted a couple of minutes ago, this market's become increasingly important 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 TWh was transacted on that platform. That's up 40 TWh on the previous 12 months and represents more than 2.5 x annual physical consumption of electricity in New Zealand. That market remains liquid. As noted, observed here, and signaled 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.
We put NZD 9 million aside to make sure we paid people appropriately. We also wanted to continue to build capability in our development team and within our subsidiary, Flux. We committed an additional NZD 7 million to those two activities. Finally, this year is the first year where NZD 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-over-year comparison of New Zealand costs only, and the Masterton cost only sits in the last bar, full year 2023. That distinction is important. Of course, the Masterton call center cost is recovered through a contract we have in place with Shell. Costs are offset by revenue, they show up in operating costs nonetheless.
The key point I want to leave you with is that other for retaining people, we're putting funding into growth activities, Flux and our development team. 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 NZD 242 million-NZD 247 million range this financial year. Not too much more to add to this slide. As for CapEx, at the start of the year, I suggested we might spend between NZD 410 million and NZD 435 million. That remains a valid forecast subject to where we land in relation to Harapaki.
For the first time this year, we broke out generation team total cash costs or OpEx and CapEx combined. They totaled NZD 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, the generation team workload tends to accelerate as the year progresses. The market forecast of NZD 83 million-NZD 88 million for generation team totaled cash costs remains reasonable. There's plenty on this slide for the pointy heads amongst us. First off, net profit after tax lifted by NZD 56 million or 39% over the previous comparable period.
As net profit after tax contains fair value movements of derivatives, which is a non-cash 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. 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, please remember that EBITDAF and by definition, net profit after tax and underlying net profit after tax, also include the one-off NZD 51 million injection from the ASX closeouts. The result is skewed a little. A couple of other things to note. The value of generation assets lifted by NZD 740 million.
We don't typically revalue assets during the interim periods, but over the past six 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. The balance sheet also remains healthy, with net debt to EBITDAF ratio sitting at 1.3 x 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 to the business was NZD 6 million. 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 6th of March.
Last but not least, the operating cash flow graph is there to confirm that 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 six months. I'll now hand back to Neal so he can shine a torch on growth, the regulatory environment, and other elements that drive our strategic ambition and will influence performance over time.
Thanks, Mike. Let me put the graph up. The wholesale market continues to see a forward price curve significantly higher than historic levels. 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 risk still appears to be priced in. Ahuroa storage degradation, Methanex running at near full capacity, both reduced marginal gas availability. Despite the Māui 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 it 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 five market makers engaged in price discovery, so it's difficult to suggest that a forward price reflects anything other than the value of risks that buyers and sellers are accepting. All of 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 NZD 80-NZD 90 per megawatt hour range in real terms. That may be cold comfort to corporate customers contracting electricity supply for the next few years, as prices are significantly higher than that at present.
We still see the transition of the energy sector to electric being affordable and cost effective for 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. It's difficult to see that intention in the suite of legislative changes currently working through the select committee. In fact, the Natural and Built Environment Bill puts natural values ahead of climate change.
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 Aotearoa gets a good outcome. 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. We do expect these effects to be balanced against the climate benefits that renewable energy brings. Now to what I hope is a final mention of TPM changes. The final pricing under the new TPM framework has been confirmed by Transpower for the 2023/2024 pricing year.
For Meridian Energy, that means a NZD 12 million reduction in transmission costs on a like-with-like basis. That starts to be eaten into with the NZD 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 six transformer at Manapouri, we made a market announcement around that issue. The observation was part of our condition monitoring regime, 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 six generator out of service, 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 six months.
Most importantly, the work we've done over the last couple of months suggests we're not dealing with a fault that is likely to affect all seven units, and the loss of this unit can be managed comfortably within our portfolio. As Mike indicated earlier, the Waiau catchment has gone through another very dry patch, and we don't have the water to generate from all seven Manapouri units, even if they were available. The unit one transformer had previously indicated a similar gas signature issue, although not nearly as significant, and following inspection, that unit was returned to service in late December as it was safe to do so. I mentioned earlier, wet weather has been our major issue at Harapaki. Even before Gabrielle's Cyclone Hale dumped around 1 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. Whilst the first set of turbines are sailing to New Zealand now, our ability to get them from the port in Napier, sorry, 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 Hawke's Bay remediation works before they can turn their attention to commissioning the Harapaki 220 KV substation. I do really feel for our construction team, as they've been doing an amazing job managing through very difficult conditions. 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. The Ruakākā BESS, situated just south of Whangārei, 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. It took considerable effort to stitch a supply deal together. Fortunately, we and staff did get it done. A North Island battery was originally part of our response package to the NZAS contract termination. As we developed the opportunity, the BESS business case proved to be an economic investment from 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 MW solar farm planned. The grid connection assets built to connect the BESS to the grid 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. Together, we are moving into the detailed design stage of the project. We're also working closely with Ngāi Tahu through Murihiku Regeneration as that project aligns with their vision, their energy vision for the region.
Now we have, in principle, reserved combined equity participation rights for Meridian and Ngāi 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 MW facility, Southern Green Hydrogen will be capable of producing around 500,000 tons of green ammonia for export each year. Importantly, the facility could meet up to 40% of our electricity system's dry year flexibility needs by providing flexible demand response. Demand response will be a significant feature of our future low-carbon energy system. We believe for 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 five successful years of organic customer sales growth. For context, that growth is equivalent to around 65% of the current NZES 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. In our drive to support enabling light vehicle electrification, we are committed to being a substantial EV infrastructure owner. 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 wellbeing pilot during 2022. We learned that we can make a long-term and meaningful difference to households who are struggling. Now we're looking to scale up that program to reach a sizable 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. 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're committed to getting on with Ruakākā developments in the Mount Munro Wind Farm. The gap on the slide between 26 and 29 reflects the risk of an NZAS exit. Obviously, if 13% of the country's demand gets turned off at the end of 2024, the timing of all new builds beyond then, 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. Certainly, we're working hard on options to do that. 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 Ruakākā battery, have been or are targeted to be delivered before the Smelter closure date. Whilst the actual sign-up for process heat volumes has plateaued over the last six months or so, the pipeline that our sales team are looking at is improving. While our forecast still sits at 600 GWh, I think we will land more than that.
As the NZD 650 million GIDI Fund funding starts getting released, we expect the number of announced thermal to electric conversion opportunities to increase quickly. The data center opportunity is the most challenged of our mitigation plans. While 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. It's fair to say our confidence in that project is diminished. Of course, the big-ticket new demand opportunity in Southern Green Hydrogen is still well on track for delivery by 2028. To wrap up, Cyclone Gabrielle, and before it, Cyclone Hale, have 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. It's too soon to quantify it in terms of time and cost. We had a strong financial outcome for the first half of the year. Hydro storage is about average for this time of year. The forecast in Southland looks dry again. NIWA's outlook suggests a La Niña influence prevailing into autumn. It will be what it'll be. We've done a good job securing our risk position and appropriate hedge cover. 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. That will continue.
For Meridian, you can expect to see consents lodged for Ruakākā Solar Farm and the Mount Munro Wind Farm this side of June. A decision to build one or both of those projects by middle of next year. The Ruakākā 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. 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. You'll know all about that almost as soon as we do, I promise. 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 fairer, healthier world has never been greater. Thank you all for your attention. We can move to questions, and I think we'll start with those in the room first off. Andrew.
Morning, Neal and Mike . A few questions from me. First of all, obviously understand the issues around Harapaki and not being able to sort of know when you might be able to get back on site. 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? I guess at what point does that actually start being a real issue for you?
We've got appropriate laydown 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 kit up there, and we can stand it up. Forecast on when that road will be available for heavy transport and to the extent of, you know, 80 meter blades, it's just an unknown at the moment. 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. You know. We're 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. 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 increased quite considerably. Can you give us a little bit more color in terms of what an advanced prospect actually means? Then in terms of, you know, what's the expectation around these actually being built and I presume time frames, we're looking into the 2030s before any of that pipeline would be coming to market.
Yeah. An advanced prospect is one where we've got a landowner agreement in place, and we've got a good handle on the resource. We've actually 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 particular list of projects will change around. Some will come further forward, some will get pushed back. 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. Bit too early to call out exactly how it'll play out in 2030- 2040 at this stage.
In terms of the solar 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. 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 aren't on this list yet.
Yeah.
We're open to procuring good options as and when they become available.
Yeah. Okay. Thank you. Our last question for me, just, I guess your comments around the long run marginal cost of new generation in real terms being NZD 80-NZD 90. Unfortunately we have inflation, so I'd just be interested in trying to anchor that statement a little bit. Am I assuming if we roll forward, say, five years, you're talking about current CPI, maybe another 10%-15% on that, in sort of the mid to late 2020s? Is that kind of the looking at sort of NZD 90-NZD 100-ish?
Yeah. Yeah, probably. I mean, look, I wouldn't, I mean, I wouldn't want to try and predict inflation outcomes at this point. 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, you know, technology improvements driving costs down. I think of that order as seems about right.
Okay. That's, that's all from me. Thanks.
Hi, team. Just three from me, and just following on from Andrew's question to start off with. The NZD 80-NZD 90, you probably said it, and maybe I missed it. Should we think of that as long run average price? You know, if you like, a time-weighted average price, or is that the sort of range of cost for new projects, breakeven revenue they need? That is a price.
Yeah, long run average price.
Great. Thank you.
Yeah.
Other two questions. Not much commentary.
Just in this, just that's lifted a bit from where we've been in the past. They were probably in the NZD 75-NZD 85 range. We've ... We have seen, what we consider to be a sort of more of a permanent shift upwards.
That's very helpful. Thank you. Other two questions. No mention in here about demand outlook, obviously, Tiwai hydrogen are two big swingers there, but if you take those out, kind of what's your view on demand growth underlying for the, you know, for the, from here to the rest of the decade?
I was gonna say no real change from what you've seen in the past, Nev. you know, the timing of demand is probably the most challenging. Well, 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. and, you know, we've provide stylized graphs of demand growth, you know, through 2050. The timing of that, you know, over the next, kind of seven years through the end of the decade is always a little more challenging to go, "Here's the pinpoint for." Key point, nothing's changed from what we have presented previously.
Yeah. No concern or optimism from the track you're seeing today to natural demand?
No.
Okay, great. Thank you. Last question from me. Just to get some idea, not necessarily asking for a number, but do you see the net back 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. What gets it into the zone is largely around the ability to provide flexibility, back into the market, which depending on your view, you know, is circa NZD 20-NZD 30 a megawatt hour of value associated with that sort of level of demand response.
That's great. Thank you. That's it from me.
Cheers, Nev.
Just appreciate the sensitivities around Gabrielle and it's the extreme weather events. You know, when you look across your asset portfolio, an event that extreme, how close did that come to stressing or potentially stressing the assets?
Didn't stress Meridian's assets. Obviously, the event that would cause us stress is a major, probably a major earthquake in the, you know, in the Southern Alps primarily, or one of the related fault lines in the region. This one didn't stress our assets. Certainly stressed the overall region. It was a transmission distribution asset issue primarily. You know, I think Genesis has been called out for bringing Waikaremoana capacity on very quickly and that really helped. It wasn't a generation issue, but it was certainly a transmission distribution asset issue.
Probably other thing to add, David. You know, development options, how will developments, you know, face increasingly large floods and events like you've, you know, we've just seen in Ruakākā's, you know, a good example of largely at sea level. 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 plinths to house the battery and or the solar park. You know, we're confident in the analysis that we've done, but it does make you stress test those decisions as well. You know, future development, it does impact the decisions that you might make and where you place your assets.
Of course, we also look at maximum flood potential in the, you know, South Island hydro catchments. That's been an ongoing exercise and will be part of, you know, our asset management planning and programming forever. No one else in the room? I think we can go to the telephones. If you've got any questions.
Thank you. If you wish to ask a question, please press star one on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star two. If you're on a speakerphone, please pick up the handset to ask your question. Your first question comes from Grant Swanepoel from Jarden. Please go ahead.
Good morning, Meridian team. Can you hear me?
Yeah, we can, Grant. Loud and clear.
Oh, fantastic. Thank you. First question, just on hydrogen. You know, all these long-term studies support a view that gas should be part of generation over the medium term or as a change agent. If this is adopted with clarity, does it scupper the hydrogen prospect?
I didn't get the.
Grant, could you say that last piece again?
There's no demand response needed. Well, there's no demand response required because gas would supply the capacity shortfall in the market. Therefore, does that kill the hydrogen metrics?
No, I don't. 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 at much lower levels than there is today, obviously. I think a large demand response industrial customer like this hydrogen producer will bring a huge amount of value to our ability to manage through those dry year events, and it's complementary. I don't think it's an either/or. Obviously, if you go and build an [Onslow Manuherikia] thing, it changes that dynamic quite dramatically. At this stage, I think demand response is gonna have to be part of our future.
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 itch to call and to cut back a pot. How many megawatts is that, and for how long can you call it off for?
Is this the?
Yeah. Grant, the existing smelter demand response provisions allow us to request smelter to reduce consumption by 250 GWh over a six-month period. You know, the smelter makes the decision, you know, in relation to what they actually do. We get the relief as it relates to contract position.
What triggers that, Mike?
It's only exercisable if New Zealand storage falls below certain trigger levels, so largely are driven and available to us as hydro storage levels fall.
They are disclosed in the contract on our website too.
Yeah.
It's available.
Yep. The trigger level is disclosed.
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 at.
Thanks, Neil. Can I push you for one more on Tiwai? Are we talking negotiations three to six months still to expect something, unlike with Contact Energy pushing for a hard close on that deal?
Look, I mean, Mike, you're running. I think three to six months would be ideal. Even that might be optimistic, to be honest. 'Cause 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, you know, it'll all come down to price at the end of the day as well. We're, you know, there's still no certainty we can reach agreement on that.
I was gonna say, Grant, I think you asked a similar question or someone did at the August results. No surprise. I said, "Hey, you know, three months is a long time," 'cause the target, you know, at that stage was December 2022. I said, "Three months is a long time if you know, put a lot of effort and time into it." We didn't deliver on that outcome. You know, we're committed to the negotiation. I think you. The best people to answer the question are Rio. You know, it's really, it's really hard for us to say it's three or six months. We took heart from what Contact said. You know, they're obviously all... What we took from that is they're looking to take a leading position in that negotiation.
you know, whether that gave Rio confidence or not, it certainly, we sat there and said, "Contact's pretty enthused and keen to deliver that outcome." you know, we expect them to provide a sizable part of that price.
Thanks, Mike. Can I just put the Harapaki delay into, or potential delay into context? Your last guidance was about a NZD 448 million of CapEx. Are we talking about a maximum blow out of another 10%? Then you're looking at first power roundabout during this year. Are we talking about a month or two delay? Not something that's gonna blow out out of proportion and cause material disruptions to earnings.
I can't see it being a material disruption to earnings, Grant. You know, we, we are, we are guessing. You know, we'd hope it's no more than a month or two. If that's the case, then it's not particularly material to either of the business case and certainly not to the company. You know, it really does come to that, down to the state of that road, because there isn't. I mean, we're testing it and we're looking at alternate options, but there aren't too many, if any, other viable options to get that size kit up to site other than upstate Highway 5. As we all know, it's a bit of a mess at the moment.
Yeah. Bit of a jigsaw puzzle for you guys.
Mm-hmm.
My final question, so a non-strategic-y sort of one. The other companies are talking about the C&I duration, or had been from about three, moving towards five years, 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 too soon I think for thinking?
Yeah. Grant, it's been. We might have stated it, 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 you know, we'll work with customers depending on their risk exposure. We have signed, 10-year deals with, C&I, participants in the C&I market. A number of them are looking at five years, but, the duration of our C&I book has extended. We've done that purposefully as part of our mitigation framework, so, you know, we'd like that contract volume sewn up as we approach 2025.
Mike, Neal, thanks for the update.
Cheers, Grant.
Thanks, Grant.
Thank you. Once again, if you wish to ask a question, please press star one on your telephone and wait for your name to be announced. The next question comes from Stephen Hudson from Macquarie Securities. Please go ahead.
Hi, Neal and Mike. Just four from me, if I could. Just firstly, active trading and market making. I just wondered if you can give us a feel for what contribution, Mike, your team made there and, you know, what we've sort of seen historically. Secondly, just on the revaluation, I saw that the assumption regarding German has come down 130 GWh. I don't know if that's a sort of a mechanical and or if 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? Just lastly, on the BESS, you've given an EBITDAF range of 20-35.
Can you give us a broad split of the assumption regarding your items and your ancillary services contribution?
It's on the BESS. BESS. Hey, Steve, I'll do my best.
You got all of those.
Yeah.
Yeah, I'll do my best. If I miss one of them, I can catch you afterwards to follow it up. Hey, market making, all we've seen from market, I mean, our contribution in that market stays reasonably steady. You know, numbers we've presented, we're with 25%-30% of that market. What we have seen, you know, the volume lift is driven by non-market makers. You know, non-market maker participation driving trading. The active trading going on in that market has, you know, driven the growth in volume. Our traders have had to get better at what they do over time to make sure that they manage the exposure we have.
We, you know, we release the numbers each month through the operating report, kind of what the cost of providing that liquidity to market is. There's no doubt that, you know, non-market maker participation has grown massively. Hey, on the, 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 GWh. I didn't write down the last part of your question, Steve, so you might have to repeat it.
Yeah. It looks like you've lost that 130 GWh out of your generation assets.
Oh, look, hey.
It's an assumption. I can take it offline.
Yeah, let's take it offline. It'll be a natural variation. You know, 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. It really will be driven by noise in the update as opposed to anything else.
The last question's-.
Not your snowpack gradually disappearing or anything. J ust to clarify, you've assumed NZAS exits, that feeds through into your NZD 80-NZD 90 long-term wholesale price assumption. That's right.
Yeah.
Yep. Our short-term, you know, there's a short-term impact.
If NZAS stays, then that's going to be a very different number, I would assume.
That's right. Yep. Our... The way to think about modeling NZAS has a short-run impact on prices, but over the long run, you know, we expect that demand will replace it, and as it replaces it, you approximate long-run equilibrium again.
Yeah. So Stephen, just to be clear, I think even in an NZAS exit, we still see long run, you know, costs, average costs coming out in that NZD 80-NZD 90 range. There would be some disruption either down or up if they stay in if Southern Green Hydrogen was suddenly to be launched into the market. 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.
Your last question was on the BESS, Steve. Neal's kinda reminded me while we've been talking. We split the revenue potential for that asset across three different categories. As we had arbitrage revenues, we had reserve revenues, so participation in North Island market, and then what we call portfolio revenue. You know, 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. I'll do a little bit of that in scenario where NZAS exits, where, you know, the battery is most valuable to us. In that scenario, about 50% of the revenue potential is from portfolio benefit, and the other two are split evenly.
Even if NZAS stays, that battery is still, you know, creates value for the business. They're split more evenly, though, across that scenario. As I say, we tested that one pretty thoroughly across our normal modeling, and we even updated our modeling framework to look at what we call hindcasting. Test the modeling framework against what we've seen in the past to test the arbitrage revenues quite carefully because a battery, as I mentioned, Neal said the same thing, is reasonably new in New Zealand. We wanted to make sure we're making an investment that benefited, you know, investors.
That's useful. Actually, I might just be cheeky and put one more in for Neal. We've seen some news recently around renewable contractors, you know, in particular, Downer. I know it's a pretty shallow market here with sort of Higgins, Fletchers and Downer, but as you stand today, are you 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. Capacity we'll 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 two, or speed them up. We need a consistent delivery path, I think over the next 30 years, if we're gonna get anywhere near achieving the sorts of outcomes we need to, you know, help this country decarbonize.
Yeah, a lot of work in front of us in that regard. What do you think, Stephen?
Yeah. Okay. Thanks, gents. It's useful.
Thank you. Your next question comes from Cameron Parker from Craigs Investment Partners. Please go ahead.
Who's that?
Hi, guys. Just a couple from me. Just wondering about if you've had any observations on the level of traction that EECA is getting through its GIDI Fund. Actually, you know, the first rounds of funding being transferred into an uplift in demand and any traction on that NZD 650 million bit of fund that was issued last year, I believe. Also, what your opinion on, you know, deemed realization risks...
I don't know if we got that last piece of the question.
Just what sort of risks that you see around in-industry at the moment and potentially industry finding it pretty tough with energy prices and under pressure, so, and potentially closing down.
Yeah. Look, the GIDI. The NZD 650 million, we're coming up to a funding round. I think it's like, I think it's March. It's certainly in March, and that will release a decent chunk of that. We expect it to sort of progress from there. The projects that we're working with in the sort of pipeline of sales that we've got, which, you know, exceeds the 600 GW target, are all leaning into the fund with applications. That'll become clearer I think over the next year. It. Put it, there hasn't been an uplift in funding allocated from where the GIDI, what fund was previously, which was NZD 65 million, and then it got ramped up to NZD 650 million.
It's quite a lot of work on behalf of EECA to get some momentum behind that. What was the second one?
Yeah. It was just industry generally.
Oh.
Is, it's probably hard, you know, it's a hard one for us to answer, at a very specific level.
I'd say, you know, 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. I guess that's pretty key for us. Obviously, you know, I look into the risk around from an asset management perspective, large scale sort of disasters of any sort of nature cause, you know, chaos. The price of new renewables and our ability to access them, going into the... I think in the future, the world's gonna grow the capacity to deliver. The next couple of years might be quite challenging.
We haven't been to market for a wee while. We went to market for the battery, that moved on us in a hell of a hurry. Things are starting to settle down again, that'll continue to be, you know, a reasonably. I mean, it's a challenging market out there globally.
Yeah.
Anything else you'd add?
I'll just say, you know, our job ultimately is to drive competitive advantage to, you know, New Zealand businesses that compete globally.
Mm.
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. When you look at electricity prices in Australia, Europe, U.S., wherever, they are worse. You know, there are challenges everywhere internationally for folk as. You know, 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. I'm probably optimistic in that regard, and certainly our job is to support business ultimately that needs to compete internationally.
Yeah. Great. Great. Thanks, guys. I mean, just the last one, really, obviously the OMV asset sale and our declining gas market and what your thoughts are on sort of say medium-term dry air risk and so forth around that. If, you know, if we've got the gas market potentially falling away, does that present more of a risk to you? What are the options that you see around that going through to 2030?
Yeah, it does. It does represent a risk, clearly. I think we'd all be more confident 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, you know, anything other than renewable asset generation. We certainly can and do and would and are interested in contracting with parties that are building capacity. Certainly we need to see more investment in the gas industry in the near term to help, you know, manage this transition in a way that works for all New Zealanders.
Great. All right, thanks, guys. That's all from me. Well done on a great result.
Thank you.
Thank you. Your next question comes from Vignesh Nair from UBS. Please go ahead.
Morning, Mike and Neal. Can you hear me okay?
Yep.
Yep.
Perfect. Hey, thank you for taking my questions. Just a couple today, likely aimed at Mike, perhaps. Firstly, just on Cyclone Gabrielle and Harapaki impact. I know you've talked about it at length, and I understand it's early days. Just sort of on the cost front from potential site remediation and other related expenses, is that at all applicable for business insurance cover? I suppose another way of putting it is this a cost issue, a timeline issue, or both?
We're working through, you know, again, a lot of it's too early to give you a definition, but we are working through insurance claims. Remember Neal's point, don't think I said it, but the site's actually in pretty good shape. I think it's had 1.6 meters of water since the start of the year, we made a pretty fundamental decision with that site last year to lift the cost base by NZD 50 million, so we could install roading up there that could, bad to use a pun, could weather a storm. You know, that's pretty bad. Couldn't think of anything else to say. It has, that decision has played out, you know, really, really well for us.
I think from a site perspective, the costs largely come down to now what plays out with State Highway 5 and the transmission infrastructure. 'Cause we've worked to get our team, you know, make sure the team's available and ensure they're ready to go back to site. It's simply just getting them back to site via State Highway 5 and ensuring that we can commission the substation, as Neal Barclay mentioned. I know it's just too early to provide some substance and frame to, you know, costs and or time.
I think 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. It's certainly more time that we're concerned about than a massive remediation job up at site.
Yeah.
Okay. That's great color side. Secondly, just on operating cost inflation, simple question. Is this is sort of as high as it'll go and whether or not there's sort of any embedded, you know, one-offs in the guidance number for the full year that may not continue into sort of FY 2024 and beyond?
That'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, you know, new sales, which is what its opportunity and future looks like. You know, those two businesses rely on good people, and as Neal and I both mentioned, the expansion in our pipeline's been due to the people that work within the business. Phenomenal to see. You know, I have no hesitation in continuing to, you know, present more cash to the extent the value is there in that regard. The only other place that we're seeing, you know, costs as everybody is again, all of us sitting in the room and on the phones is the cost of everything we buy goes up.
You know, we look for some support from our employers. Again, we've got great people. You wanna keep them. You know, we'll be driven by the employment market, immigration and, you know, cost of living indexes as it relates to future costs. Beyond that, the operating business is actually very, very disciplined. It's an example I think we used last year, where the retail business has grown its, you know, volume under contract by over 3,000 GWh that Neal and I both mentioned today, held their cost flat. You know, there are very, very disciplined people on the cost front within the business. We do have exposure to, you know, the employment market and no apologies for trying to grow the value of the business. Hopefully that's useful. Probably longer than you needed.
Yeah. Yeah. Awesome. Thank you. Great color. One final thing for me. I think you mentioned DataGrid, a little bit in the presentation. I think I missed that. Just wanted to clarify what the commentary around sort of, you know, the offtake, you know, from that contract was.
Yeah. I, my main point was that project is not progressing as we anticipated a year and a half ago when we started this. They have lodged for a consent. We understand that if the project gets up, it'll be done in 10 MW type increments. We were talking 100 MW back in the day. Our main concern is that the main guiding force behind DataGrid, the person that we got to know, built a relationship with, has left the business. I'm not particularly confident it'll occur, but if it does, it'll be incremental volume, probably not of a 100 MW type scale, and we'll treat it as a normal customer type arrangement. I hope.
Okay. That's fine color . Thank you, guys. That's all from me.
Thank you. There are no further questions at this time. Passing you to Barclay for closing remarks.
Okay. Well, thank you all very much for your attention. We'll see you all again in six months, and we'll do it all again. Yeah. Cheers. Bye