Contact Energy Limited (CEN) Earnings Call Transcript & Summary

Good morning, and welcome to Contact Energy's Annual Results for FY '23. Today, we're joined by Mike Fuge, our CEO; and Mr. Dorian Devers, our CFO. I turn to you, Mike.

[Foreign Language] and welcome, everyone to FY '23 results. First, the usual disclaimer on information that we pass over here, but moving on to the actual results. The agenda, we will give an overview of the highlights of the last financial year, Dorian will then take you through the details of the financial results and the outlook, and then we'll update you on the progress on strategy. Look, FY '23, solid performance, very much focused on delivering on the promises we've made in prior years. The underlying EBITDAF of $573 million given where we were sitting at the half year, we're delighted with, and that's in the face of some very interesting conditions with North Island rainfall the highest on record leading to lower wholesale spot prices, lower thermal generation and higher price separation. In a way, it's possibly a precursor to what we can expect in the future with higher volatility. We were able to respond to it. When we thought we were short of fuel, we did secure additional gas in quarter 2, FY '23. We did run short to take advantage of the market conditions, you've have seen that we did not start TCC up until after end of financial year, which led to our best carbon emissions on record below our FY '26 target indeed. What we expect over the medium term is increased volatility in the market, but we see ourselves as well placed both with the fleet we have with the generation coming on and the gas storage and gas peakers we have in place to sail through that -- sail through that well. You'll see, and Dorian will talk later to the dividend that we're declaring today, which was in line. There were a few preconditions that we need to satisfy for that growth, but no surprises there. In fact, what we hope with all of this is that there are no surprises. They have been -- all the results have been well signaled and the results that we see on the execution of our project pipeline have -- has also been well signaled. To remind you of our strategy, very much the same to support New Zealand's growing demand to get -- to enable electricity become the fuel of choice in this country, and in doing so, to get rid of coal and hydrocarbons from the New Zealand energy supply, as a whole. To grow the renewable development, you'll have seen, we were going on that to decarbonize our own portfolio and with the closure of Te Rapa this year, we're putting our money, where our mouth is and to continue to create outstanding customer experiences in terms of both our base of electricity customers, but growing the products we provide to those customers in terms of broadband and potentially and mobile, so we ease the complexity in their lives and ordinary kiwi households. All those underpin ESG. You'll have seen some great progress with [indiscernible] entry into the DJSI. Operational excellence, the teams continue to do a fantastic job in both the retail and operational arms of the business and transforming the way we work in this new age. Look, this is a very busy slide. It's been a very busy year. And I just -- in terms of what we have achieved in terms of growing demand, we continue to work with Rio on the NZAS extension. Obviously, there are other parties involved in that. We did sign that 10-year renewable attribute deal with Microsoft, which is underpinning the growth of data centers, renewable energy-based data centers in this country. Tauhara, we continue to expect that to come online in quarter 4. If you go to the plant today, you'll steam -- see steam everywhere, as we are well into hot commissioning, which we're delighted about. If you go 0.5 kilometer down the road, you'll see the Te Huka 3 plant, where structures have already started to emerge just over a year out from first commissioning, which we're delighted about. And as you'll have seen our commitment to GeoFutures with getting underway with the drilling program early with the $140 million pre-FID expenditure. Kowhai Park, solar farm at Christchurch Airport continues to progress well, and we have other opportunities there with the solar farm north of Auckland and Southland wind, and the battery feasibility we continue to work on. What you see on the right there is the ambition just get really clear on where we're taking investors. So the 100 megawatts of new demand, the 100 megawatts of demand flex and the new green chemical channel, whether that's food grade CO2 or something else, we see real opportunity there. Renewable development, 10.3 terawatt hours by FY '27, all of which should make economic and commercial sense and the batteries up and running -- well up and running. We set out earlier in the year our ambition around Scope 1 and 2 emissions, net 0 by 2035. And what we expect is that our run rate by the end of 2017 will be down below 300,000 tonnes per year of CO2 with the real opportunity, particularly in the geothermal space to capture or to simply not emit the geothermal -- CO2 emissions from geothermal and with the retirement of TCC. In terms of the customers, we expect to continue to grow. As we sit today, we're just a touch shy of 6,000 -- 100,000 total connections. We expect that to grow over the coming 3 years to 4 years, something closer to 700,000. We continue to hold on to our position with a leading cost to serve a connection, which remains at a global benchmark level, and we continue to grow both our brand and our reputation metrics. Just an update on the geothermal investment program. Tauhara, you can see the steam there. That is real. We are in the middle of hot commissioning. It is a process that we step through very carefully, but we're delighted to be at this stage, and that signals a strong intent. Project process -- progress at the end of June, 96%, we're probably closer to 98% as of today. I think you've seen that in the operating stats that really is just some minor odds and sods in terms of the EPC power station. We have signaled before what we -- where we expect the capital to land at the end. There is nothing to suggest that we're going to blow that in any way, form or fashion. As I alluded to, Te Huka 3, making excellent progress on site. You can see the coolers -- fin fan coolers, and they're going in place. They went up remarkably quickly. The project today is about 43%, which we, again, are delighted with the progress on site. A lot of the learnings that we got from Tauhara, a lot of the muscle fitness that we were able to build that's being applied. And then GeoFutures, one of the things we learned was the more mahi, you do upfront, the more it pays off. So we committed to that early drilling program. We committed to getting the front end designed well advanced, so that when we take FID, we know exactly what we're dealing with, and you can see the price expectation there. So that -- and all, if you take that, we're talking 3.2 terawatt hours, of which 1.8 to be up and running within the next 14 months, 15 months or so. And then GeoFutures will be a total capacity of about 1.4 net of 0.4 above the existing plant at Wairakei, which will retire. Demand, it has stayed flatter over the year that we actually take as a positive sign. It's been warm. It's been wet, and we have seen some significant industrial closures and the fact that it has stayed relatively flat is a good sign. We also see some signs both in the [ signal and the intent ] of the smelters to stay. And in some energy conversions, you saw the New Zealand Steel deal that we signed earlier in the year. You saw the announcement of the Fonterra tender for coal boiler conversion in the North and South Island, both of which we take to be very positive signs in the go forward. We also hearteningly see a stabilization in the large-scale industrial base in this country, where most of them are signaling that they are perfectly happy to stick around and not to close. Hydrology, yes, this has been an unusual year with North Island, an absolute record, South Island at exactly an average P50, and so overall, that led to the market being very long on hydro generation. It has swung very quickly. So July, I think in the Clutha catchment was probably the third drier since the market began, and we've certainly see a -- seen a significant drying up across the overall market with us at or very close to mean storage levels across the market, which is a remarkable turnaround and just shows how quickly in this country things can turn. Obviously, that impacted wholesale prices -- spot wholesale prices. The trading team had got ahead of that. They had contracted significant volumes at a higher price, which led to the much stronger result. But also on the positive side, it also led to the much lower carbon emissions, which [indiscernible] about, we'll talk about that a bit later. This graph -- this view graph I've shown for the past 3 years consistently. One, it speaks to the increased volatility in the market, and I don't think that's going anywhere soon compared to -- the last 5 years compared to the previous 10 years. We have seen a lot of pricing come off in terms of aluminum and methanol. Gas and carbon, we saw the disruption in the carbon market. Fortunately, common sense has prevailed, and those settings have been restored. We expect the volatility to continue. We keep a very close eye on these 6 input factors, and the way they affect fuel costs overall. We expect them over time to continue, and they continue to support our view of the market at that [ 100 to 110 real terms '22 ] price that we put out a year ago. We see nothing that would make us think otherwise. It's just going to be a bit of a bouncy ride on the way. Retail remains -- competition remains intense. We're delighted with the performance of the retail arm business, both in terms of the retention of customers and growth in core electricity connections, but also in the adjacencies of broadband and about to be launched mobile. We were able to put a -- at inflation price increase through, and the customer losses were much less than we anticipated, which we're delighted about, which says we're getting something right, in terms of the convenience, we're bringing to Kiwi homes, in terms of the strength of the brand and the brand trust. And if we can find that sweet spot, we will continue to be there. And we have protected Kiwi homes from the worst ravages of the rapid increase in wholesale prices, but the reality is, at some point, we had to increase prices, and we think we've got that balance right. Look, this is a very busy slide. And just in terms of regulatory matters, I think there's a couple of things, I do want to emphasize. The wholesale market is performing well. It remains one of the most robust and resilient markets in the world, that is because its settings are well understood. The market works well together, but also competes hard providing both that security, but also that intense competition that ensures consumers get the best value for money. And we have got through a whole range of crisis these last 3 years without having to alter market settings. And our plea and our advocacy is that, that continues. A well-working market is clearly attracting billions of dollars of investment in new renewable generation. In every other country, in the world, governments are having to reach into their taxpayers' pockets to fund that, and they don't have to do it in New Zealand, and we think that is a great outcome. We talked about the battery project, the battery project Onslow. Look, we are glad to see that the team are looking at alternatives. I was in media recently when we talked about the 100% renewable energy target. I fundamentally believe that we, as New Zealanders don't need to spend billions of dollars chasing after a sticker. What is important is that the planet is boiling, and we have to work together to reduce carbon emissions. And so every -- when we get to 97% renewable, every combustion engine that was retired will reduce its carbon emissions by 98%. Every filthy coal boiler, which is retired, will reduce its carbon emissions by 97%, and that is where we need to focus, and that it is not that I am against for the 100%, it's just we have to make sure that our money, our efforts, and our talents are directed to where they make the biggest impact. We also see there the resource management reform. Look, we are happier with the way renewable energy projects are being carved out in the proposed reforms. We are still deeply concerned about the bureaucracy and the unintended consequences, where overcomplicated planning and regulatory framework has been found globally to be able to be used by people, who don't particularly want renewable energy projects next door to them to the detriment of the planet. I think the other one that we've all learned from this year is the carbon market. As with all these things, as I always advocate once you form a market, keep your hands and your pocket, don't fiddle with it. We saw that risk that was brought into because people decide to press pause or introduce uncertainty. That sovereign risk, that propensity to interfere in well-functioning markets just adds a cost to all kiwi homes eventually. Dorian, over to you.

[Technical Difficulty] Mike, and everyone. Just to start off with, as I usually delve into the high spot of some of the key themes that are going to come out, as we go through the next few slides. So starting off with some accounting topics. We've adopted the proposal IFRS 9, which means any of our trades that we enter into [ that aren't ] in effective hedge relationships. We no longer report financial impact of those within EBITDAF. Pretty simple change for us because most of our trades are actually in effective hedge relationships and have all the accounting documentation to back that up. So for us, it really just means we take the market making and their losses in this instance because they're not hedge effective by their nature, and we disclose them. It's a fair value of financial instruments outside of EBITDAF that pushes up our underlying FY '23 EBITDAF to $573 million, by underlying, I mean, that's before the impact of the AGS onerous contract. The bigger topic here is we had $27 million of market making losses in the period, which is too high. What happened there is that's a function of the fact that we had some buy positions in the market, when there was a lot of fuel risk at that time, but that turned very quickly. There was an -- very suddenly a lot of renewables available. You could argue that's a natural hedge there because with more renewables available, our fuel costs in our portfolio goes down, but it's definitely fair to say there's some learnings for us around that, and we've already built that in. You can see our guidance in FY '24 is for market making losses of between $10 million and $15 million, and that's actually what the electricity authority pays the commercial market maker to do a similar amount of volumes to what we do. The other accounting topic is our AGS onerous contract provision. The impact on our EBITDAF for the full year is $113 million, down from the $120 million that we talked about at the half year, and that's a function of that high-pressure operating regime that AGS has been operated under, which has been pushing out some of that water that was previously ingressed in and creating more storage capacity there, which is good to see. Next topic, we had a very good second half of the year. If you look at our numbers on a consistent basis, so -- put the market making losses back in and before the AGS onerous contract provision, we almost met our original $550 million EBITDAF guidance, and we exceeded the more recent guidance of $530 million. And what's happened here is our CFD volumes in the second half of the year were 50% higher than the first half of the year, the pricing was 40% higher in the second half of the year relative to the first. We were selling risk management products to Meridian, and we sold a lot of CFDs before the pricing came down. And we were able to do that because we were a lot more comfortable in our gas position for the second half of the year. Third topic was around the repricing of our channels. It's good to see that happen in FY '23. But -- the average price that we're selling electricity of -- across all of our channels is $121 a megawatt hour, which is still quite a long way below where the ASX curve is, which is at least well over $150 for the next sort of 3 years. So that does talk about the opportunity. Just to put some details on that. We have 3 relatively large contracts expired quite recently. The collective load of that worth 276 gigs and the pricing that we were getting on that with the legacy contracts was $84 a megawatt hour. So you price that up to market, and that's $18 million of EBITDAF there. And that's one of the reasons why we've increased our guidance for mean hydro year. EBITDAF for FY '24 up to $600 million from the $550 million that we guided to at the beginning of FY '23. I should just say those numbers, the like-for-likes don't include any benefit from Tauhara coming online. The other thing to point out is, we've seen a big increase of provisions on our balance sheet. The onerous contract provision is obviously part of that, but the provisions have gone up by $100 million more than just that. Half of that is just the fact that we're using a lower discount now rate to value future liabilities. That's the fun and games, you have when you change auditors. They have a different way of looking at things. But the other half of that is actually a true future cash costs, and it reflects some updated costs that we have around decommissioning, as our portfolio changes into the future, and we shut thermal assets like TCC and shut Wairakei A and B and replace it with GeoFutures. The -- those portfolio changes will provide benefits, so [ I think by ] surface, land and topics like that, which we'll look to optimize to offset the decommissioning cost. But this just goes to show, this is why measures like return on invested capital, which we've talked about a few times are very important because they ensure that we have the right capital discipline and focus on our balance sheet, as well as just driving earnings growth. Fifth topic is around our operating free cash flow, as a percentage of EBITDAF, as we've signaled for this year, it was down from the sort of historic levels of 60% plus. It was just a little bit under 50%. That is the highest stay-in-business CapEx that we've guided to, our acceleration program, which is driving more resilience around our renewable assets and that SAP upgrade to S/4HANA in there. And also, we got impacted by lower thermal generation, but we still have to buy the carbon and the natural gas associated with that. So we see our inventory go up. We'll get that back in future years, where we'll be able to operate thermal for free to all intents and purposes then leverage that inventory. The sixth topic is just a bit of a longer-term awareness topic, which I know, some of you are probably aware of anyway, but we do see future cost pressures from regulated asset-based price changes coming up. They're not going to happen until about 1st of April 2025. So no FY '24 impact, but wanted to make you aware of it because of the potential magnitude of it. So when you consider electricity networks, the indications are that the WACC is going to go up by about 200 basis points. And when you couple that together with all of the other changes that get made when the price falls get updated, it's not inconceivable that a consumer could be paying double for the networks, what they're currently paying at the moment by the time he get to 2030. And in absolute terms, that's well over $1 billion across the market that gets recovered from consumers between now and then. So I wanted to make you aware of it because that obviously has inflationary impacts across New Zealand, but it's also -- it could be a little bit of a dampener on decarbonization. On to the profit. The profit after tax, so that came down from $182 million in the prior corresponding period to $127 million this period. However, that's impacted by that AGS onerous contract provision. When I talk to the numbers, I'll talk to them on an underlying basis, so excluding that. And if you do that, our profit was up by $29 million to $211 million. [ Within that ], our EBITDAF was up by $27 million. The -- whilst you've seen exceptional hydro inflows across New Zealand, the volatility of those and the constraints that we have at Contact around the amount of hydro storage we've got and generating capacity has meant that we saw our hydro generation in line with mean and roughly in line with the prior year. We did see a lot of spill though, I think, about 1.6 terawatt hours, but that's just the nature of our business, unfortunately, and our assets. We did see renewables drop though year-on-year by [ 119 gigs ], and that reflects a few operational issues on geothermal, which I'll talk about later. And on a fuel replacement basis, that cost us $14 million. Those exceptional hydro inflows depressed the wholesale price. So we flex down the amount we sell by just under a terawatt hour in response because any thermal backed sales were uneconomic because the margin that we're making on thermal backed sales in the prior year was quite slim, [ they ] only had a $12 million impact on our EBITDAF. We did see some quite strong pricing coming through, getting closer to the ASX, which was good to see. So our market channels, which is C&I repriced up by $24 million and our REIT -- our long-term channels, which is largely retail repriced by $46 million. And actually, one of the key things there is we don't see ourselves taking the price leadership position here within the market, that was generally us catching up with what other retailers are doing regarding price. Thermal fuel cost, the cost inflation was $9 million adverse for us. This is the cost of carbon within our portfolio. As Mike mentioned, there has been a bit of volatility in carbon prices due to the sort of regulatory uncertainty. We weren't impacted by that because we were hedged. You could say we had a lost opportunity there because prices did drop, but that's not the purpose of hedging. Other income was favorable by $18 million. Within that, we've had the Te Rapa site has closed. And linked to that, we've sold the auxiliary boiler there to Fonterra and made a $7 million profit. We're also seeing higher margins across retail in gas. Our fixed costs were up by $27 million, $23 million of that is OpEx, which I'll talk about later. And then we had a $4 million increase, which is basically higher electricity levies and higher cost of gas storage. So that's the EBITDAF movement. So back to things that have driven our net profit. Depreciation was down by $38 million. We had, if you remember, some accelerated depreciation in the prior corresponding periods, that was some components of SAP that wouldn't be required in the new S/4HANA environment. And TCC, this financial year has seen lower depreciation because there are components of that, which get depreciated based on operating hours, and we've used it a lot less. Our interest costs were up by $2 million, and that reflects the rising interest rate environment we're in, and the fact that we've got some interest linked to floating. Our debt levels are up quite a bit linked to all of the growth CapEx that we've got. But from an accounting basis, you don't see any of that come through the income statement at the moment because that all gets capitalized against the projects, whilst we're in a construction phase. Tax was higher by $11 million on higher underlying profits. And the fair value of financial instruments in total was adverse $23 million. We split it out that between realized and unrealized losses, and that's where those market making losses that I talked about earlier end up. So across our 3 business segments, the wholesale EBITDAF was up by $75 million, that's about fuel savings offset by lower volumes. The thing that's actually driving the EBITDAF up there is the repricing of the channels. You can see the retail segment there, we're seeing its EBITDAF dropped by $31 million, that's our arms-length transfer price that we've got, which escalates with the wholesale prices, and there's a lag there in terms of wholesale prices have gone up faster than tariffs to consumers. The important thing there is sending the right commercial trigger to that part of our business, and they are -- it is causing an escalation, as Mike said, in the level of tariff increases. And then corporate costs are up by $16 million. That's a large part of that $23 million of OpEx increases that we've seen across Contact, and I'll talk about that when I get to that part of the presentation. So on to the wholesale business now, generation costs are down by $81 million. So the strong sort of natural hydrology that we've seen and the lower wholesale prices at mean that we've needed less thermal and acquired generation for risk management. So the volumes there are reduced by 849 gigs, which is a huge reduction, that's 56% reduction, and that reduces your cost of carbon, thermal fuel and risk management, generally by $91 million. Offsetting that, we've seen $10 million of increased fixed costs. So transmission is actually flat year-on-year, but I'll just explain it because there's a lot of things going on there. We don't have ACOT benefits anymore, which we had in the prior corresponding period, but we got increased loss and constraint rebates from Transpower just because of the amount of price separation that there was between the islands because of all of the -- all of the water. So electricity transmission, therefore, is flat. Gas transmission is flat, but you've got a big 13% rate increase because the [ ComCom ] has signed off that accelerated recovery of capital costs for those asset owners. But that was offset by the fact that there's a volume component in gas transmission and our thermal generation was down a lot year-on-year. It's the thing that's caused our -- the transmission and levies to go up, is the electricity levy, which is up by [ $2 million ], which on a percentage basis for levy, it's been a very big percentage increase. Gas storage is up by $2 million. That reflects the contract and the escalation, which is linked to PPI. And then our other operating costs, the OpEx is up by $6 million. We've got a retention payment to staff at Te Rapa, which ensured the smooth closure of that site. We had about $2 million of costs associated with repairs linked to cyclone Gabrielle. And as you know, we're in a high inflation environment at the moment, so the rest of it's just natural inflation flowing through there. Just in terms of the performance across our generating assets, I mean, the important topic down at [ Clyde ] is the transformers. We replaced 2 of the 4. The first one got installed a little bit later than we hoped. So we were down a unit in July and August when inflows were quite high. So that loss of capacity would have contributed a little bit to higher spill. Second unit went in fine, and the third and fourth units are scheduled to be installed in 2025 and 2026. So no asset issue is expected for FY '24, which is good. Geothermal was down by 98 gigs. What's happened there. So when we had the statutory outage at Wairakei, some of the generators didn't come back online as quickly as we would have hoped. That's a function of the age of the assets. They are [ 65 years old ] and coming up to end of life in 2026 when they were replaced by GeoFutures. So it's likely you're going to get a few teething problems around those assets between now and then, but you're talking a few gigs here and there. One of the other topics around Geothermal was that we lost a bit of capacity around a reinjection well, which meant we had to turn back production at Poihipi. There was a bit of a scaling issue on that well. We've done a chemical clean on that, and it's all good for FY '24. Good. And then in terms of thermal TCC had its radix repaired and assuming we get the extra 2,500 hours signed off by GE, which we're not envisaging any problems with. That will mean we've got 7,500 hours left, which is -- it should be easy enough to get us through winter 2023 and winter 2024. In terms of our contracted -- wholesale contracted revenue is up by $43 million in spite of volumes being down by 437 gigs, and this talks about the strong pricing movement that we've seen across our channels. CFDs were down by [ $101 million ] with volumes being down by 660 gigs. This is all a function of what happened in the first half of the year. We went into the year with far less contracted CFDs than we would do normally because you remember back then we were a little bit worried about thermal asset availability, and we just been told by OMV that we were going to get less gas, so we were worried about fuel. That will change by the time we got to the second half of the year, which gave us the confidence to sell more CFDs, and importantly, before the pricing dropped, and we also sold those risk management products to Meridian. Offsetting the lower CFD revenue, we saw $130 million increased revenue across C&I and sales into the retail business. You've seen talked -- I talked about earlier about the repricing of C&I with net price up by $22 a megawatt hour, and then, we expect that to continue into the future. The sales into the retail business is a bit of a left pocket, right pocket thing. But as I said earlier, the good thing is, it does trigger the right commercial behavior within that business, which is important. Other income is up by $9 million. This is where that profit on the asset sale to Fonterra ends up. Our wholesale trading and merchant revenue, so this was a bit of an odd year actually. You can see on the chart, we had very little merchant length. Normally, we have merchant length to offset our location losses, but because wholesale prices were so low for most of the year, we were running almost 100% renewable generation and trying to limit the amount of merchant length we had. Indeed, in some trading periods, we were even running short and acquiring cheap electricity from the grid, allowing us to save money on fuel. So whilst there's an adverse $49 million impact you can see on this slide, it did enable fuel savings in other parts of our portfolio, so, for example, those generation savings of $81 million that I talked about earlier. The other thing to point out, if you look at the merchant net price in the prior corresponding period of $138 a megawatt hour, at that price, you can run thermal fuel into that and make a spread. We didn't have that as an opportunity in FY '23, [ at least ] the prices were so low. Retail business saw its EBITDAF dropped from $17 million to a loss of $14 million. However, that's not a surprise. It does reflect the long-term nature of this business. As we said a number of times pricing aligns to CPI environment, but we've seen an escalation in wholesale prices, which drive the transit price, which have been higher than that. Overall electricity performance was very good. As Mike said, tariffs were up almost 7%, which aligns to the CPI environment we see ourselves in at the moment. Whilst it's a strong performance, as I said earlier, we don't see ourselves as leading from a price perspective here. We're actually just catching up with the other retailers, which is important regarding risk because it shows that this magnitude of price increase should be able to stick. It would also be one of the reasons why with such a -- with a price increase of that magnitude, we only actually saw 1% of our electricity customers leave us. And actually, we've recouped all of those in the first few weeks of this financial year, and that's because -- well, there will be number of reasons, but one, because we're catching up on price; and the second reason, I believe is the fact that we've got quite good products in the marketplace, [ time-of-use ] products that allow customers to offset the tariff increases by shifting loads save money that way. So this is like of [ green ] charge and good, nice products that we've got in the marketplace. We do expect retail prices to continue to rise. I mean, one of the drivers that will be the largest retailer in the marketplace has got a large PPA to acquire generation, which escalates every year, so they will have to increase prices to recover that from the market. Gas margins for us were up by -- from $3 million to $9 million, very happy about that. We finally got our SME segment back into profit after a number of years of losing money on that. It did take quite a big tariff increase. But one of the reasons why the tariffs had got so much again was that regulated sign-off of the accelerated capital recovery of gas networks, where we're seeing the magnitude of the increase coming through, there has been quite material. Broadband was the only part of the retail business that was disappointing. Connections went up from 71,000 to 86,000, but we saw our profit drop from $7 million to $6 million. We know exactly what's caused that. Local fiber companies increased their costs, and we were so to pass that on. I mean, local fiber company costs are about 50% of the revenue for that business. So as you're probably aware, when you're a distributor of a low-margin product like broadband recovering cost inflation in a timely manner is absolutely critical. So we have learned from that. And as Mike said, our cost to serve -- leading industry cost to serve has continued to get better, $120 per connection, and that's being driven by those fixed cost leverage, as we've increased our customer numbers again. In terms of OpEx, so a $23 million increase. It is a large increase, but very explainable. So we've seen adverse impacts of one-timers of $7 million. So remember in the prior corresponding period, we had the Holiday Act change that allowed us to release that $6 million provision there. We've also seen some one-time costs in FY '23. I talked about the retention payment to staff at Te Rapa, which helped facilitate the sale of that asset to Fonterra and the $7 million profit there. So that's a good piece of business. We've also invested in transforming the way in which we prioritize and execute on initiatives, which is important because that helps derisk our ambitious 5-year plan. We've had actually had those $2 million of costs associated with cyclone Gabrielle, but we've been able to offset by the retiming of some of our less critical OpEx spend into FY '24. Other big component here coming through is higher inflation, $12 million of higher inflation, so wages and salaries up 5%, insurance 8%; CPI 7% across the period, which means, in today's supplier discussions, we've seen some headwinds. The biggest is actually travel up by $2.4 million, 160%. This is the first full year out of COVID and COVID lockdown. So the level of activity has definitely gone up. But as you're probably all aware, the prices of air travel and hotels has also gone up quite considerably, too. We've deliberately invested $4 million into growth and sustainability. So the growth is helping cover the connection growth that we're seeing and contributing to that 6.5 terawatt hours of renewable development pipeline we've got. The sustainability element is all about safety, compliance and training, and that's one of the reasons why we got into the Dow Jones Sustainability Index. Look I -- this is the large increase in OpEx. And as a CFO, I sort of scrutinize this quite a bit. And you'll see when we get into FY '24 guidance, we've got a similar size increase in OpEx. The reason why I get comfortable with this is, we've got a very ambitious strategy, which we are delivering at pace. You think about it, we're building Tauhara, we're building Te Huka 3. The Board just signed off a very large pre-FID scope of work on GeoFutures $114 million, which will derisk that investment for us when we get to a final investment decision. We're taking -- looking to take 3 major final investment decisions in FY '24, grid, scale, battery, New Zealand's largest solar farm and GeoFutures. If you think back historically, we've probably taken 2 major FIDs in the last 15 years. So we are doing a lot and we have to do a lot because the country needs it around decarbonizing itself. So the -- all of our stakeholders will get a lot of benefits for us delivering on these things that we need to deliver effectively and also with the well-being of our people in mind. So putting extra resource into this area makes absolutely sense at the moment, and it's very considered in the way we're doing it. Cash flow, operating free cash flow, $282 million. As I said, cash conversion from EBITDAF of 49% was lower than historic levels, but I've already explained the reasons for it. Inventory higher due to lower thermal generation and that higher stay-in-business CapEx that we're seeing at the moment. For FY '24, we expect cash conversion to be about 60%. And then when you go into the future, it will go back up to historic levels because the accelerated stay-in-business capital program comes to an end. This is a new slide we've added. I recognize it was a little bit of an oversight on our part. We're spending $0.5 billion on growth capital, but we won't [ give ] you any insight on what it was actually being spent on, we were just leaving it as one number. So we're now providing a breakdown of what we've spent historically, what we spent in the financial year and what has to be spent to finish the projects off. I'd encourage you to actually look at this, but also look at the capital work in progress on our balance sheet as well. We've got about $1 billion sitting there. That's unproductive asset at the moment. But on the basis that these are all above WACC investment, that shows the potential in terms of the extra EBITDAF that you're going to be seeing in the future when those assets come online. In terms of our balance sheet, I guess, it is strong. The debt is going up both in the [indiscernible] of Tauhara and Te Huka 3 in particular. We've been funding that. We've done $550 million of domestic bonds in the marketplace in FY '23, heavily oversubscribed, which was pleasing to see. And to the extent we actually took $100 million of oversubscriptions on the last one because that was an efficient way of financing. We have seen our interest go up a little bit, 50 basis points to 5.8%. We're using a lot more commercial paper because that's the cheapest form of financing in the market. So our margins are actually coming down. But because we've got a chunk of our portfolio, which is exposed to floating rates is pushing our interest rates up. We've also got quite a lot of liquidity at the moment. So some of that is just a timing topic, but the other part is quite deliberate. When you're in a high-growth phase of CapEx like we're in at the moment, where the burn rate is quite high, it's prudent to have liquidity to back that up. Also, there's a lot of volatility in wholesale electricity prices, as Mike mentioned. So your prudential can go from $0 million to $200 million just very, very quickly. So again, you need liquidity to back that up. The other thing is we're going to use more and more commercial paper going forward because the margins are so attractive for us. But the issue with commercial paper is not a long-term financing solution and it can disappear very, very quickly. So what we find is the combination of an undrawn bank facility in commercial paper eliminates the financing risk, but it's also a lot cheaper than a drawn bank facility or another long-term financing arrangement. So we need the liquidity in place to allow us to move and use more commercial paper into the future. In terms of funding our strategy, net debt to EBITDAF of [ 2.2x ]. We indicated at our Capital Markets Day that FY '27 EBITDAF was going to be $850 million. So those 2 things mean that we're very comfortable financing our geothermal pipeline, up to and including GeoFutures on balance sheet. We've already talked previously around our solar is off balance sheet through the joint venture we've got with Lightsource bp. The one thing that we're looking at actually, and it's going to be a few years away still is wind and how we finance that and what structure we use. But overall, very comfortable with our funding position regarding the delivery of our strategy. In terms of our dividend, we guided to [ $0.35 ] for FY '23. So it won't surprise either we're declaring a final dividend of $0.21 per share, which brings the dividend for the year up to $0.35. Of that $0.21, $0.18 per share is imputed for qualifying shareholders. We're going to continue with our undiscounted DRP. It's an easy way for shareholders to invest back into Contact. That leaves our dividend at 83% of the average operating free cash flow that we've had in the preceding 4 years, which is within that 80% to 100% range, and I'll update on the FY '24 guidance in the next couple of slides. In terms of our EBITDAF guidance for FY '24. This is a mean hydro year one. It's up to $600 million from the $550 million that we indicated for FY '23. These are underlying numbers, as I said earlier, don't include any benefit from Tauhara. What we have done though is we've increased our sales position to cover the expected Tauhara volumes. We're just assuming here that it's backed by thermal generation. I think that goes to show our confidence in the project, but also in our fuel position and the flexibility we have around that. That's important because it then allows us to sell the expected Tauhara volumes and take that price risk out of the equation, which is good. So this is -- what we plan to do then is when Tauhara comes online, we'll just update this guidance to reflect that. It will be very simple because within these numbers, you've got the fixed cost of Tauhara already. We've already sold the Tauhara volumes, so it will just be a fuel substitution. You'll take out thermal fuel at $120 a megawatt hour and replace it with geothermal fuel at $5 a megawatt hour, so $115 per megawatt hour fuel savings. In terms of what's driving the underlying profit up by $50 million. So we start to ramp up, and that's 200,000 tonnes of Scope 1 carbon emission savings, but it doesn't actually impact our financials. We're assuming, the gas that was going through Te Rapa. If it goes through TCC, there's some upside to what we're talking about here, because of the heat wave, benefit of heat TCC. You can see price improvements coming through there across long term and market channels of $86 million. Just to talk about the risk of that, so $25 million of that has already been delivered, because our retail pricing in FY '23 was better than the FY '23 guidance. And we generally -- when we talk about pricing, we can consider the retail channel to already be contracted, because there's less risk around it. And when you consider that where we are at the moment, 95% of the sales for FY '24 are already contracted. So that helps you around -- understand the delivery risk around that $86 million. Another thing to call out, we're selling a lot more because as I said, we're selling the expected Tauhara volume, but it only drives up EBITDAF by $16 million, and that's because it's backed by thermal fuel. When that gets displaced by Tauhara coming on, that will be quite a big number. And then you've got the higher OpEx, as I said earlier, it's $24 million. It does reflect the high inflation environment, which we're expecting to continue into FY '24. So you've got $14 million there associated with inflation. You've got some on costs for the new S/4 HANA system, licensing and things like that, $3 million, and then you've got $7 million for investments in productivity and growth. So we're standing up the procurement team that helps us from a compliance perspective, deal with things like modern slavery and supply code and conducts and stuff like that, but it also helps from a productivity perspective, as we can deploy best practice around procurement into the business. We've also got some costs associated with launching adjacencies and supporting the marketing and the promotions around our mobile offering in there. But as I said earlier, it's an area that we do focus on. These are big increases. I'd like to think this will be the last year of big OpEx increases. Certainly, the business is now resized for growth, assuming inflation comes back in FY '25, which we all hope, that coupled with the fact that we are getting productivity benefits coming through from procurement and digital investments that we've made, should mean that you start to see a more sort of steady-state OpEx going forward. Last thing to highlight on this slide is on the left-hand side. We're pretty good at hitting our EBITDAF guidance, which I just pointed out. Last bit of the guidance. So we split out the stay in business CapEx -- from a stay in business CapEx that accelerated programs, so you can see how much of the $150 million we've spent already and had still to go. Market making is split out there, as I said, the growth CapEx there only includes what the Board has actually signed off. And then the last topic there is around dividend. So FY '24 is a very important year for us. So we're comfortable around the delivery of Tauhara. But whilst it makes sense for TY to read contract and we fully support that, and we think that, that will happen, [ rightfully ] within our control. And therefore, I think it's prudent to update on the FY '24 dividend when we got more information on the TY outcome. But until we get to that point, we're guiding that the dividend for FY '24 will be a minimum of $0.35.

Okay. Right. Just updating you on the strategy and just noting that the photo of Tauhara that I suspect is [ already updated ]. That's a wonderful thing about projects, particularly at a stage, as you can go there every second week and look, feel and see a completely different plant. One of the things that we are lining up is at grid-scale battery investment for 100 megawatts that we estimate in the order of $170 million to $190 million. We expect to take the decision on that in the coming months. We've got 2 outstanding locations, one already consented at Stratford, which would just tie into existing connection and transmission capacity that we had there, with a fully consented site. The other one at Glenbrook, which has not yet consented, but it's going to be built in its own industrial land. So we don't expect any problems. And again, very close to outstanding transmission and connection. And so what we see is that will both support the retail growth in the Auckland region in particular. It will take care of some of the North Island location issues, some of the separation that we saw earlier in this year. It will reduce our reliance on gas peakers. We're going to see how far that goes. And obviously, given its location close to any potential constraints in central North Island transmission, Glenbrook remains the preferred site. And would support new wind and solar. It certainly runs on the ability to make sure that, that electricity is available at the time the consumers need. So we're excited about that prospect going forward. I talked about the development pipeline, and this sort of gives you an outline of where we are going. So over the next -- in the coming months, we should see Tauhara online. By the end of next year, you'll see Te Huka 3 online. You can see the refurbishment of our existing plant in Roxburgh going on at the same time with the battery up and running in 2025 and then GeoFuture is coming online after that. Below the line, you can see Kowhai Park and Glorit planning to bring 0.6 terawatt hours on before 2026 or within 2026. We closed Wairakei. Southland Wind between 0.9 and 1.2 terawatt hours in '27. And we're now talking about Tauhara Stage 2, remembering that, that would consume the last 0.7 terawatt hours, which has consented steam offtake. And so we're starting to look beyond Contact '26 now, what is in that next 5-year period and what in terms of investment in terms of geothermal, wind and solar. These projects are very real. They either have consent or have a relatively straightforward path through [ consenting ], including the wind project, which obviously got approved for fast track. They are not [ braggarts ]. They are real megawatts, which can and will be built. We continue to maintain a very high level of capital discipline. We will do them if they make commercial and economic sense and are in the best interest of our shareholders. But that being said, we're excited. When we started this journey in 2021, our development pipeline was not that full. The team have done a cracking job of getting some really exciting opportunities across the [ motu ] across all types of energy into the development pipelines, introducing at the same time real competition for capital, which is important for any healthy company on the go forward. What you can expect in the near term? FY '24 we expect the -- to get absolute clarity on the NZAS extension, and we expect to further develop what we can do with green chemicals in terms of Central North Island, reusing the CO2 to provide sustainable CO2 for the country where that is needed. We expect new demand to be facilitated, further deals with the retirement of coal boilers. In terms of growing renewable development, we expect GeoFutures will take FID on that second half of this year. We expect Kowhai Park solar to be taking FID on that. We expect to be working hard for the solar and wind projects that sit beyond that. Tauhara operational calendar Q4 '23 and taking that final investment decision on the battery in the coming months. Decarbonizing look we have delivered on this in the roadmap we set out 5 years ago. We will continue to deliver. We'll set out that road map to Net Zero for Scope 1 and 2, which will have that investment program both in the reuse of CO2 and in the -- making sure the CO2 doesn't exit our geothermal operations in particular, and we're excited by that in the go forward, and they will be economic projects. Retail look, I'm excited by what we've got in retail. We've got 50,000 customers on time-of-use plans now, which is absolutely awesome, which means that they are shifting their load away from those peak periods and extinguishing thermal generation, which is great. We expect to grow those product maps. We expect to go out into mobile plans, but we also expect to be able to do more in that decarbonization space in ordinary Kiwi homes, whether it's supporting the likes of virtual power plants or the like. And we expect to continue to grow both our connections, but also the number of connections in each home, so that we can enable Kiwi homes, both to decarbonize their homes, but also to control their costs, their household costs and the cost of living crisis. And we're proud of the role that our retail arm played in that. We're excited by what's ahead of us. It's great to be in the middle of execution. It's great the team are delivering on their execution. And with that, very happy to take questions.

Thanks, Mike. We're going to go to the phone first for questions. So we have online Grant Swanepoel from Jarden.

Can I just start with Tauhara. You've got a hot start already. When do you start accruing to EBITDAF? Is that from now or is it only once commissioned?

It's once commissioned. We continue to go through the -- introducing hot steam to various parts of the plants, we were introduced to the high-pressure system. In the next week, we'll probably introduce it to the intermediate pressure system, will then shoot across to the EPC contractor to make sure they can flush their pipes. And then towards the end of the year, you'll see the electrons, once we've got through the warranty run, then we'll introduce that to EBITDAF.

It's actually just on that -- the warranty run is when you it starts going to EBITDAF, which is the 1 month before commissioning, but the capacity factor on the warranty run will probably be quite low, which is quite normal.

Okay. So if your guidance is 4Q this calendar year, is that for us to assume that you get a ramp-up to about mid-November, and that's where we should take our number from? So around about 870 gigs we can assume at this stage until you guys update the market?

We're just saying it will be based on what we know at the moment, fully commissioned by the end of the financial year. Sorry, by the...

4Q?

Yes, 4Q.

Yes. And then with Genesis' Unit 5 out, your 1.8 terawatt hours ex-Tauhara. Does that assume you carry a bit more burden for this year or you're just assuming that Genesis uses their rankings more aggressively?

Say that again Grant, question?

Unit 5 is out. And it's out just before winter next year. Your 1.8 terawatt hours that you put into thermal, excluding Tauhara. Do you assume that you have to carry some of the country's burden with TCC?

Well, this was actually pulled together before we knew about E3P being out, so it doesn't take that into consideration. But I mean, what I can say is, we'll be absolutely doing everything we can to support the security of the system, because that's the sort of #1 priority. So we need to cover our own positions, and there's quite a lot of sales that we've already got contracted within there. So we need to do that first and foremost and also cover the security of the system as well.

And my final question just around TY. Are you -- as a Contact company still only committed to 100 megawatts contribution to that deal? And then chatting to the CEO of Australia [ earlier ] the other day, she mentioned that they want to get a deal done before the end of this calendar year. Do you feel there's a sense of urgency amongst them, or has it also gone quiet?

Look, I don't want to comment in too detail on sensitive commercial negotiations. Yes, our volume commitments are absolutely in line with what we have done historically. We obviously would like a deal sooner rather than later. I think everyone does. I think the good people of Southland would like to see that certainty brought to their futures. And so the sooner a deal is bought, we've been talking about it for over a year now. It's a complicated deal, but it's not that complicated. So without going into too much detail, you can probably hear a slight level of frustration there. But it's time for -- I think, for all of us that we just get on and get the deal done.

Even though Rio has alluded to a volume shortfall that somebody hasn't stepped in to pick up yet?

Yes. Well, hey if the volume shortfall is relative to existing contributions, then it's not coming from us. And we -- as we said, our contribution sort of aligns to our market share of renewables both nationally and the South Islands that makes a lot of sense. I mean, as Grant you'll have done this analysis. It's interesting, if you work out the impact of the Te Huia exit and who's impacted the most, it's actually some of the -- it will be the players that are exposed to fixed price large PPAs to acquire generation and also only one with upstream oil and gas, because that will be the fuel that gets displaced with all the hydro. So hopefully, people understand that and the shortfall can be made up.

We'll take questions from the room. Andrew Harvey-Green?

Got a couple of questions. First one just around the dividends, and just to clarify first of all market making losses. I assume you're just going to adjust for that even though it's now fallen out of operating cash flows and your policy.

Yes. Adjust for it in line with guidance, we're confident that the measures we have in place now, and you can see that they were much higher on a rate basis at the half year, they've reduced in rate, and we expect that to continue. So that's where we've arrived at the guidance. So yes.

So they're not included in operating free cash flow anymore.

Yes, that's right. So in terms -- so that effectively adjusts up your operating cash flow that you'll be using for calculation?

We do. We've only adjusted the prior year and this year, we haven't gone back to adjust third and fourth year previously, but mid of the market making losses in those years was relatively small. They might be mitigated in one of the years. So it's just not material.

Yes. Okay. And then there might be the answer for the second part. But I'm assuming there's no change to your dividend policy here at all, because historically, you said, I think it's a -- for year FY '24 dividend, it will be based on FY '23 earnings. So that's kind of already locked in. And so you're only basing it on, I guess, whether the smelter stays or goes in terms of where the...

If the smelter stays or goes, I think then, obviously, that will merit an announcement right -- in the market.

Next question I just had was around -- if you are able to give us a little bit more color on the SAP situation, sort of an update on that, and that was the reason I [indiscernible] update from the half year?

Yes, we're probably being a bit hard on ourself. S/4HANA, which is the SAP upgrade. We got into -- we've upgraded our financial systems, and we've upgraded our generation plant operating maintenance system at a cost of about $30 million, and the implementation went remarkably smoothly and without a bump, and we can see the opportunities going forward, particularly in the generation space for the application of some smart operating maintenance data and digitization and mobile applications. So that side of it, we're actually quite delighted with. We went off the rails a bit, was on the proposed upgrade to the CRM system, where we recognize very early days that there were problems with it. And so we just pressed pause on that, so that we could have a relook at the market. And in hindsight, that was actually a blessing, because what's clear is that internationally, the market and the energy CRM space with virtual power plants and interruptible load has really -- multi-multi-multi-products has really evolved literally in the last 4 years. And so that opportunity of a pause, just gives us the opportunity to relook at what we can do in that space and how we can make that quite special for the consumer.

And next question was just around, I guess, we've seen the ETS being reviewed at the moment. And just any sort of comment on your exposure to forestry credits, which I guess is the thing that is most...

We're reasonably comfortable with our exposure there. Obviously, Drylandcarbon became Forestry Partners Limited, has some exposure, but they were highly economic at prices much lower than the peak of the market. And we continue to expect that common sense will prevail in terms of grandfathering of those credits. Certainly, we welcome the commitment to the Climate Change Commission's recommendations of late last year. That market certainty, I think, is absolutely key in the go forward. I think the other thing that's coming out of the Climate Change Commission, is going beyond that Net Zero commitment to a commitment to gross zero. And that's where our focus is, the more that we can reduce our own emissions, the less it becomes an important conversation. But obviously, yes, people did inadvertently fiddle with a functioning market have responded and I think everyone takes the lessons from them.

In terms of the units that we own, and we've got forward contracts in place to buy units as well. They're all non-forestry units. We've received a very small amount of units from Drylandcarbon, which is the tiny fraction of the units we own. The rest of them are not forestry units.

Great. And last question was, I'd just be interested in comments around flexible geothermal, which is 1 of the 2 portfolio options that are being looked at, alongside the Project Onslow and yes, just feasibility from your perspective? Presumably, it requires new geothermal into the country, which is also a challenge [indiscernible].

Yes. So we've had a trial of flexing our geothermal summer/winter. So moving some of the loads, say, a small amount, 25, 30 megawatts from summer, just reducing the offtake in the summer and then increasing the offtake in winter. We've got the luxury of spare capacity in some of our plants and the wide Wairakei and Poihipi plants at the moment. The challenge for geothermal is always because of its capital intensity, that once you get those assets in, you want to be utilizing them as much as possible, but we can see some opportunity at a reasonably minor scale to flex between summer/winter, which is not insignificant. And we see it as part of that broader range of innovation, that will ultimately solve both the intraseasonal flex that's needed in the country, but also the dry year risk. And yes, watch the space.

A few for me, just following on some of those latter [ themes ]. Just following on the CO2 price sort of impact with the separation of Forestry. What do you think the futures curve we will see today, particularly in sort of the front couple of years? This pricing, in terms of CO2 and perhaps gas price, obviously seen quite a large dislocation in CO2, how much that you think is reflected in the future curve today?

The Climate Change Commission, I think, set a target price in excess of $100, and our expectation is that for high-quality units, they will continue to track towards that and provide a strong incentive to industry to decarbonize, to retire those [ coal boilers ]. So that's where we see it going. There is something to resolve on the forestry units. I think common sense will prevail there. But with that overarching commitment to the Climate Change Commission's targets, I think that's the pole that we should be holding to.

The price before all the regulatory uncertainty was around $88, $89, wasn't it? So you sort of think that's probably where it's going to go back up to relatively quickly. I think it has gone quite up there because there is obviously a little bit of uncertainty around the forestry stuff, but you've also got that September auction, which is still under the old sort of regime. You've got to get past that and then I expect prices will go up a bit after that.

Gas prices?

How long is a piece of string? We continue to see a reasonably solid floor on the gas price, which indicates that the contracts that we struck now 3 years ago are fair and reasonable. You've seen a downgrade in the [indiscernible] reserves in particular for the nation, which will put upward pressure on the remaining gas reserves. These things come and go, the next good well on Tauhara or Maui may see the situation turn again. But what's certain is that the contract that we signed up to on both Maui and [ Tauhara ] a few years ago, they seem a very fair and reasonable floor to the price.

And we've also -- you talk about flat gas, which is normally what you've got. You're prepared to pay a bit more for your gas if they can build some shape and stuff into it as well, which is some of the stuff that we'll be looking to do. Obviously, with AGS having less capacity than we thought it was going to have a few years ago, there are some of the things we're looking at, at the moment as well.

Segues quite nicely into the second set of questions around flexibility. So I think you've set a very clear path for us with what you do with renewables, demand response, flexibility there. But I'm still wondering whether or not, this is -- given you're already involved with gas storage, you've got Peakers, what you expect to see with those potentially developing going forward? Obviously, gas transition plan, [ out of ] consultation at the moment, talking about the potential for new gas storage. Or do you have any strategy of plans to sort of return to that topic yourselves or is that something that the industry...

I think there's a couple of things. #1, we see the retirement to baseload gas generation. So TCC will run a little bit [indiscernible] towards the end of next year calendar '24. And at this stage, we have no intention of doing that. And we've announced that we have no intention of doing that next refurbishment, for C6, I think. And then it's the gas peaking. We still see an important role for gas peaking. We had 1 or 2 operational issues with our gas peakers last year. We have resolved those. We flagged an issue with AGS. That issue appears to be resolving itself as the reservoir pressures up again. And we can see increased volumes going into the reservoir. So the important thing for us was before we start talking high polluting strategies, to make sure the assets are actually working. The assets are working. The AGS storage problem we're working through, and that appears to be going in a very positive direction. We've acquired some fantastic reservoir understanding of the dynamics. And so that was the first part of it. What happens in the future? We've made that commitment to keep the Peakers and the storage. If something changes again, we could dust off ThermalCo again, but it's not our focus at the moment. We've made that commitment to Net Zero by 2035. We know that with the Peakers running and with the credits coming out of Forestry Partners Limited that we'd meet that Net Zero, the Peakers would have a limit of about 200,000 tonnes a year. We'll be getting about 200,000 tonnes a year from Forestry Partners Limited. We think we can solve the geothermal emissions. So we can see a pathway to Net Zero, and then it becomes a question of, 1, we have an accountability and responsibility to ensure security of supply. So we've got the gas storage. It has to be working, got a good amount of gas in it, gas peakers are working. And so at this stage, let's make sure we maintain that state. If there are further discussions, there probably are discussions that need to be heard about the future of thermal plant in the country and providing that security for it to be there when we need it, but that requires a number of parties to come to the table.

Just on your point, the fuel cost is going to be immaterial in the future, because we're going to have Peakers, set maybe in a mid-year, 200 gigs of -- so what's that, 2 PJs, 3 PJs of gas. So the fuel cost is not really the relevant bit. There's still enormous fixed costs associated with having those thermal assets in the portfolio, and equally others will have a lot of fixed gas, and other costs with having those assets in their portfolio. So that's where the benefit is, optimizing those, which is why what we proposed, I think, is still the best overall outcome, but it does require everyone to be on board with that.

So [indiscernible], someone has got to turn this capital, because the [ baseload ], at a 97% or 98% level of renewability. I mean, can you run the big, large, slow plant and still have it serve the kind of function it serves today? So it's a question for another day and for potentially others.

A very long question.

One last one for me, and that's just on the change in the consenting regime. And it does seem 7 to 10 years, I think you flagged in the document, expecting for that to kind of resolve and finally become a standard that people knows -- will know how it works. In the meantime, for the kind of projects you want to get consented, you're effectively going -- I think, going, that process will be too hard, and so you'll effectively be asking a minister for approval. Do you think that's going to cause any problems with consenting?

No. So, I think there's a couple of things. One is, 2 of the sites, so the battery site is zoned industrial, so you don't anticipate any majors there. And the other side at Christchurch Airport, again, has a very special zoning as an airport, so we don't anticipate any major issues there. So part of it, as I suggest, is just being smart about the battles we pick. With the wind farm, Southland Wind, we put that into the fast track. You've seen signals from both government with the renewable policy statement, national policy statement on renewables, but also the Opposition National Party have signaled that they want to see a very fast track on that. I think the really important thing on that questioning is that, on the consenting then is if, and hopefully it does swing back in our favor, is how we then take the communities with us, so there isn't a legacy of hurt in my mind, and that becomes our accountability, and how we engage, and I'm very confident that the teams we have, we can take the communities with us. But actually, that's the way it should be. You shouldn't have local government or government getting in the way of that relationship. That relationship is our responsibility. We're going to be there for 30 years, if not 60 years. And so we need to make sure that even though we want to move at pace, that relationship is formed well, and that we're able to take community concerns. That's the really important thing about the consenting. And the more we can build that trust, then the more license to operate we'll get, and this bureaucracy that has built over the last 3 decades will be able to be swept away.

Just one question from me. Just any comments on the kind of recent BlackRock Infrastructure Fund? Was there much industry engagement with that? And in terms of -- does this have potential to marginalize domestic New Zealand players, with potentially the Minister deciding which projects get fast track, which projects -- where the investment comes from?

As I said, so there's a couple of things. [indiscernible] bit of a soapbox here. So there's a couple of things. #1 is we welcome capital investment into renewable development. And BlackRock are a savvy investor and they've signaled what returns they expect and they can make those investments. They're one of our largest shareholders, so they've clearly got good taste. And so we welcome their interest in New Zealand. I think as I started, we have a well-functioning, efficient market that has kept this country safe in very turbulent times over the last 40 years. And what you don't want is inadvertent screwing of the scrum, where subsidies are introduced for otherwise uneconomic renewable projects, through soft PPAs or floors on prices. We welcome capital investment and we welcome competition. And that sort of gives flavor to some of the comments I made around the Net Zero, is that we think that at the moment, that last 3% is going to be very expensive. So don't worry about it for now. There is a whole range of innovations coming our way on the international scene, you see in the U.S., which I think will solve it. And you will see the market solve it with demand flex and summer weighted load and all those good things. Don't overstress it. But the actual $2 billion, as long as it's capital, as long as they are turning up to the rugby field with 15 players, not 23 and 3 bureaucrats on the back, absolutely welcome the competition, absolutely welcome the capital.

It's very vague, actually, what is even going on. I mean, our interpretation of it, is the government's not putting any money into it. BlackRock's not putting any money into it. They're just encouraging institutional investors to invest. There's already a platform set up for institutional investors to invest in renewables. It's the NZX. You can invest in Meridian, Contact, Mercury. So, I agree with Mike. It's good to get more capital into the industry. But it's actually the one area which has been quite successful. I think the area, it'd be good if the area of focus was actually more around how we're going to solve the problem around $70 billion that's going to be required around transmission and networks, as per the BCG report. I mean that's a problem that's worth looking at. So it'd be good to get the attention onto that, rather than things that I don't think there's a problem to be solved.

We have a number of them online. So we'll go to Stephen Hudson from Macquarie. First is, how much of Tauhara is contracted currently and what percentage of that is indexed? And further, how much of that volume is included in FY '24?

So I think its -- 75 megawatts is contracted. 87...

87.

We don't -- we're not -- for -- if you're talking, Andrew, about FY '24, we don't sort of look at how much is Tauhara and how much isn't, it is part of the portfolio. None of Tauhara is actually contracted through PPAs in FY '24. And overall, of our portfolio, we've only got about 400 gigs which isn't contracted at this stage. By the time we get into FY '25, though, we've got the Genesis 1, which kicks in from the 1st of January 2025. And then we've got the MIG-1s, which are a lot smaller, which kick in a little bit before that.

And they are indexed.

Yes.

The MIG-1s kick in just in April next year. So there's a little bit. Next question from Stephen, lastly, what changes have you seen from S&P on the calculation of smoothed debt to EBITDA and where do you see yourself peaking on that basis?

I can take this one. So because we're in growth, they're actually changing the way they used to look at 2 years back and 2 years forward. And in the current year, for now, they just look current and forward, which means they're taking into account the EBITDAF growth when they're considering that. So that's good. In terms of where we see ourselves peaking, we can go up to 3 now with the measure. And I think we're sort of just below that when we get into sort of max CapEx around GeoFutures. So as I said, Stephen, we're pretty comfortable with where we are from the funding perspective and our pipeline.

Number here from Vignesh Nair at UBS. So the first is geothermal CapEx per megawatt seems to be falling with GeoFutures compared to Te Huka 3. Is this a site-specific factor or are you observing raw material CapEx pressures easing more broadly compared to 6 to 12 months ago? And that applies to wind, solar and batteries as well.

I think there's a number of aspects that need to be taken account of there. One is obviously GeoFuture is a much bigger plant and so there is a scale efficiency there. I think #2 is, that it makes use of fairly significant infrastructure, existing wells, existing steam field design, an existing site. I think the third thing is, as you alluded to, is that, touchwood, that we have seen the worst of the construction cost increases. And we certainly have a major project delivery team who are absolutely on the top of their game, which give us an increased confidence about where we expect those costs to land.

On TCC, without any more maintenance CapEx, how much more can you run it? Obviously, you've pledged the decommissioning in June '24. But given, A, the lack of use this year and, B, Genesis challenges with Unit 5, could we see that be extended another 6 to 12 months without any additional maintenance CapEx?

Look, we provided to the market an estimate that we thought the hours would run out at the end of '24, calendar '24. We expect to get through this winter and next winter. We have the gas for that. We have the hours and the spare parts available for that. We might get an -- there is always -- can we get extended hours, particularly with E3P out, we're required to run it more in the intervening months. We might -- we fully expect to be able to do that. So we're committed to -- we expect the hours to run out in '24. We've got a bit of flexibility in the interim about how we deliver those hours.

And just to clear it up, we are -- we do still spend money on TCC. It's just we're not doing the big C6 overhaul. So we'll still have CapEx maintenance that's happening in FY '23 and FY '24 around it.

Last one from Vignesh is, can we -- on the 50-megawatt invitation for RFPs, can we get more color on this? Why derisk even further, given where futures and wholesale prices are, especially when you have a bullish view on long-run wholesale price? Is this related to what would have been the merchant strip from Tauhara or is that still in place?

I think there's a couple of things in the near. One, we're keen to test the market to see what market expectations are on the long-term price by putting in our own longer-term deal. I think if you look at where we were, when we put out the -- when we awarded the PPA contracts to Genesis and Oji, Pan Pac, the capacity of the capacity of the Tauhara was 152.4 megawatts. The capacity of Tauhara is now 174. We've got the 50 megawatts that we've bought on Te Huka 3 where we've sold -- where Microsoft had the attributes. We're expecting a capacity increase of about 0.4 on GeoFuture. And then we've got another 0.6 terawatt hour of solar and potentially by FY '27, another 1 terawatt hour, let's say, of wind. So there's no lack of opportunity to supply that 0.5 terawatt hours, and there's no lack of opportunity to supply it and also participate actively in the merchant market. So in a way, we are having our cake and eating it too in the issuing of that tender.

There's one here from Cameron Parker at Craigs. Probably covered it, but I'll read it. With the potential for 7,500 hours runtime on TCC, which is about 300 days, are you still expected to retire this plan over the next couple of years or do you plan to exhaust all those hours?

The plan is to exhaust all those hours and to retire it by calendar '24. That's it.

Another one from Cam. Could you elaborate on the work you've recently committed to on Wairakei, which is $114 million? Is there potential for gains on the 180 megawatt expectation?

Well, I think we've already gained on that. I think we were sitting at a 150-megawatt expectation at one point. That's -- as we've engaged with vendors, that's come up to a higher number.

He's gone straight to the high end of the range and he'd like to [ get a bit ] more.

Yes. What the work is, it's drilling the additional injection wells, it's drilling the additional production wells, it's advancing the front-end design to a much further level of detail than we would have done in the past. It's pre-committing to, we've got a shutdown, as you're aware, on Te Mihi in November '24. It's pre-committing to the long-lead items to make sure that shutdown goes well. So yes, that's the rough outline of what that $114 million is for.

Okay. Lance, a shareholder. This is a slightly different take on the BlackRock question from before. With BlackRock ready to put billions of dollars into renewables, we hear, would you consider selling minority stake positions in your new generation projects at, say, a mid-single-digit EBITDA yield with an ongoing asset management fee to Contact?

It's not something we've considered at the moment, carving off our geothermal business.

The geothermal business is, one, it's not easy. You have to work hard. You have to work hard on the drilling. You have to work hard on the complex plants you build. You have to work hard in your relationships with communities and Iwi. We're proud of what -- the way we can do that, and we have access to capital. So, if we're going into a partnership with anyone, they have to bring something to the table. They have to bring either an expertise, as Lightsource bp have done, or Roaring40s have done, or they have to bring something special. So unless they're going to bring something special, then...

Yes, we've got access to capital. And I mean, it is a very good question. And we are always looking at sort of structural topics around that sort of thing. You would have seen on our Capital Markets Day, we sort of split out the geothermal business, and we were talking about the different characteristics of it. And it was more akin to an infrastructure type of investment. So we are always thinking lots about that -- those types of things. But at the moment, it's not something that we're looking at. And as Mike says, one of the drivers to that would be to the extent that we need more capital to support these projects. And at the moment, we don't -- we're comfortable. We've got capital from existing sources.

And one here from Tim Hunter. Do you think offshore wind is likely to be built?

One day. That's the economics and this is where it's important that people don't get distracted. And at the moment, we in New Zealand have a tremendous development pipeline of reasonably highly competitive, low-cost renewable development options onshore, whether it's geothermal, wind and solar. We know, and this was confirmed by the directors and the executive visit to Europe and the States, is that offshore wind remains a border of magnitude higher cost, and it's only getting away with significant government support, whether there are -- like in Europe, security or supply issues and a lack of other options. So one day, when we've exhausted the current development pipeline, it might indeed come off. But unless there is a dramatic government intervention, which, again, I've spoken about, then I can't see it getting away in certainly the next 5 to 10 years.

Okay. Thank you. There's no further questions online. So we'll draw that to an end. Thank you for joining.

Thanks, everyone.