Contact Energy Limited (CEN) Earnings Call Transcript & Summary

Good morning, and welcome to Contact Energy's Interim Results Presentation for FY '23. We're joined today by Mike Fuge, our CEO; and Dorian Devers, our CFO. Over to you, Mike.

Yes. And Kia ora tatou. Welcome, everyone. Good to have you on. And just before we start, a big shout out to obviously those in the north of the mountain at the moment, who it's going to probably be a pretty tough 24 hours. Look, let's get right into it. The usual disclaimer and just noting that, moving into it. So, I'll cover the highlights and give you a bit of an update on the market, where we see that. Dorian will take you through the details of the financial results and what we see as the outlook and supporting materials are there in the appendices, which hopefully, give you an abundance of information if you have any questions. We'll give an opportunity for questions at the end and happy to take those. So look, the performance, underlying EBITDAF and actual EBITDAF, underlying has itself dropped given the hydrological conditions, very strong hydrology in the North Island, obviously, weaker hydrology in the South Island where we got less inflows and obviously, as a result, lower thermal generation getting lengthened to the market. And behind that also thermal generation costs remain high and our ability to dispatch into the market over that period was very limited. The other thing, obviously, there is the declaration of onerous contract on Ahuroa, which Dorian will speak to more later. That's around getting the portfolio in shape and the go-forward and quite simply, given the shift in the portfolio that we see less value from that facility than what we are potentially going to pay for it over the coming years. Dividends and operating free cash flow, dividend remains as per the formula, which I keep presenting to you all and is robust in that regard. Look, how are we responding, we expect a much stronger second half. But the focus is very much on, if anything, this result just bears weight to the rebalancing of the portfolio through new renewable generation. And so continuing that, the clear an deep focus on delivery and the go-forward is that absolutely critical. And recognizing that NZD 120 million onerous contract as part of that, getting ready for the future. The strategy remains the same; growing demand, growing our renewable development pipeline, which will give you a bit of an overview of today, decarbonizing our portfolio and creating outstanding customer experiences. You'll see all those today underpinned by ESG. You'll have seen our entry into the DJSI last year. Operational excellence and transform ways of working. Just on a key part of that, we do see improving demand outlook for electricity. I know commentators are commenting on the fact that it remains flat, but you remember that's masking the fairly significant exits of both Norske Skog and New Zealand refinery. In the meantime, you have seen some large-scale data center announcements from Microsoft and Amazon. Industrial process heat conversion, we continue to work with C&I New Zealand. We do see with industrial users, the likes of New Zealand Steel, working with them on interruptibility and the likes. Road transport, EVs appear to be going gangbusters on the basis back of the government's announcement. And we do see opportunity also for green chemicals, particularly both domestic hydrogen, but also using CO2 from our geothermal plants to provide a more sustainable solution for New Zealand. Otherwise, we are facing flat there. So we are working with BOC Linde about how we can do something in that space. The big elephant in the room on demand is, of course, the smelter, and I just want to give a bit of our perspective on that. Look, we have really tested other uses for our electricity in the south, such as hydrogen export, processed heat conversions, data centers. And what it is telling us is aluminum is the highest value user. So, we're comfortable that any new deal with NZAS will comfortably pass an EA test. It's good to have the alternatives. The work has been worthwhile as a backstop and who knows with the extent of renewable development we have available to us in this country, they may come to pass. And look, from our engagement from Rio, they appear ready to do a long-term deal at a reasonable price. Importantly, they've made clear their commitment to New Zealand to South [indiscernible] and to broader stakeholders as well as the commitment to global decarbonization. And in that regard, the carbon efficiency of the smelter at 2 tonnes of CO2 per tonne of aluminum versus 16 global average. There is also a moral imperative to get this right. Wherein, for our existing base load or volume of 100 megawatts, which aligns with our generation market share. We don't need to do any more as the South Island transmission upgrade is in place. From our perspective, it would be good if the deal gets done as soon as possible. So, we can all get off the transitional pricing we're on and move on. It is in the interest of us, the country and the broader market that we all move. The other big highlight of the last 6 months, aside from the DJSI entry is the reconsenting of Wairakei. And I just want to spend a few minutes on that. So, 35 years. This will enable us to proceed with our plans for the replacement of Wairakei A and B legacy power stations. It's a commitment that increases the offtake we can. The planned redevelopment up at Te Mihi will be -- will use this team more efficiently. There will be an increase in output in the order of 0.4 terawatt hours per annum and it has reinvigorated our partnership with local hapu and iwi, which we're delighted with. On a whole range of things, this is a good, if not great, project. It enables us to get off the Waikato River and to stop our discharge into the river. It enables the further development of the 60-year-old Wairakei field, which will further reduce carbon emissions for the nation. It's a good use of the resource for us as Contact. It's a great project, and we're looking forward to advancing it such that we're ready. It's up and running second half 2026. The other piece of news is that over the last 18 months, we have been working hard on broadening the development pipeline, which now totals some 6 terawatt hours of real projects. You will have seen -- you obviously are aware of the 1.4 we have in progress with Tauhara, the 0.4 that we have in progress at Te Huka 3 and signaling that there's another 0.4 with the redevelopment of Wairakei. But beyond that, you saw the announcement last week of the 150-megawatt solar partnership with Christchurch Airport and Lightsource bp. We are excited by the progress the wind team have made at the same time. So, we actually see a development pipeline that it's broadened its scope to up to 6 terawatt hours over the next decade. Also within there, you'll see Roxburgh, which also signals we're looking hard at our existing operations and how we can get more out of them through improved efficiency. So all in all, with the combination of geothermal, what we already have, plus solar plus wind, we're excited about the road ahead and our ability to build in to the demand growth that we have talked about earlier. Demand, I talked about a little bit before, it looks flat, but it's actually masking some moves that I've already talked about with refinery and Norske Skog. We did see higher irrigation demand with the very dry November, December and indeed January, but we actually saw the smelter increase its load. Our assessment, as I said, is that there is an underlying trend for growth. Hydrology, quite frankly, it's not our half year. The rain as we've seen and we see, again, as we speak today, has been very much focused on the upper North Island. That's the way it lands. The portfolio remains robust. What it does mean is it limits the need for thermal generation. And you'll have noted already that November and December as a nation, we were up well over 97% renewable, which is a great outcome. Wholesale risks, they do remain elevated. What you're seeing is that despite the recent drop-off the coal remains at an elevated price, particularly with the carbon price sitting steady at around NZD 75.80. We do see continued track challenges in the supply of gas in the upstream. That just means we have to work harder. Methanol and aluminum both remain very healthy. And the hydrology in the short term looks promising. In the medium to long term, we always have to work hard to make sure the market is covered. And so in that regard, the ASX Futures appears to reflect the reality of what we face both in the short term, but over the long term as well. Retail intense competition. We have continued to grow our connections. You see there over the last 2 years, in particular, the bundle that we offer with broadband has continued to give us momentum. You'll see underneath the second part of that, the increasing electricity tariff. But the important thing there is that it's steady. We have shielded consumers from the rock and roll of the wholesale market with below inflation increases. But it's important that we continue just steady as she goes to make sure that we get the balance right between shielding consumers, but also making sure they are aware of the increasing cost of energy globally. Yes, I'm happy to take questions on that later, but the retail business all considered remains in good shape. On climate change and regulation, look, there is a consensus in this country to deliver net zero by 2050. There is consensus on the client change commission and the emission reduction budgets. There is consensus on the ETS. And the thing I would say is that as opposed to other energy markets globally, the New Zealand market is performing remarkably well on balancing that trilemma of balancing cost versus scarcity versus actually getting on and reducing emissions. So, if you look at the investment program and the go-forward, you can see the progress in emission reductions in the sector. But you can see, even in what I'm describing today, the concern about consumers that they do not experience price shocks at the same time. And you can see the overarching anxiety to ensure that our electricity supply remains viable, stable and secure. And we will continue to balance that. You'll have seen there in this graph, the developments where there have been announcements on net zero carbon emissions by 2050. Transport policies, government procurement has altered. What we do about Tiwai and you can see also very active engagement on other projects, which I'm happy to take questions on later. The thing I will call out is the fact that on resource consenting, as an industry, we did approach government on the trap we found ourselves in with wind farms taking up to 7 years, if not a decade, to consent. And the government responded on that in the RM reform program. And so we are grateful that this unity of earth pits that we have as a nation is resulting in fundamental change, people rethinking the way we think about how we respond to climate change. And you can see that in the RM reform, which we're very grateful for. Other regulatory matters, wholesale market security. We are reasonably comfortable on that. We've obviously -- this winter, there's been some noise in market. As an industry, we have responded. We continue to engage in the -- constructively with the EA, but we fundamentally remain of the view that the market is working well and the market where there are issues of scarcity will respond. For our own space, look, we've been leading on demand response, for instance, you think of a demand-side led solution. But I think the industry is also responding well. On the New Zealand Battery Project, we have made our views clear. We were part of the Boston Consulting Group. Our big ask in this space is that people are honest and transparent about the costs of significant investment like what is being proposed potentially at Lake Onslow. We don't believe, given the experience overseas, particularly on snowy scheme that it will be anything less than NZD 10 billion to NZD 12 billion, if not more, New Zealand. And in that context we asked people to exercise good professional judgment on whether it is the right thing for the market. And on that note, Dorian.

Thanks, Mike. Hello, everyone. I just wanted to start, as usual, just by highlighting some of the key themes that are going to come out as we go through the rest of the pack. Mike mentioned that NZD 120 million onerous contract provision that we've made. That leads to our contract with First Gas for gas storage. And the reason why we've made that is because what we have forecast to pay for that storage between now and the contract finishing in September 2033 is more than the forecasted value that we're going to get for it. There's a couple of things that are driven that. Our decarbonization of our own portfolio is happening at a pace quicker than would have been envisaged when that contract was originally struck a number of years ago. So, you've seen the announcement around the closure of Te Rapa in June and then we expect TCC to exit the portfolio at the end of 2024. If you've got less thermal in your portfolio, you don't need as much gas storage. And then secondly, we put that announcement out on the NZX just before Christmas. The storage facility itself has just got less capacity than everyone expected as well. So, those are the 2 drivers. It is a non-cash provision. And remember what we pay for the storage facility is a function of the price that we actually sold it to First Gas for a number of years ago. And then from an operational perspective, we're comfortable that in most scenarios, we've got enough storage there to support our portfolio. And in the extreme scenarios, we're putting mitigations in place around that. So, pretty comfortable all around on that. Next topic is going into FY '23, everyone was talking about fuel risk. It was going to be really dry. [ Lenino ] weather patterns. From a contract perspective, we had that technical working group looking at AGS, and we were worried about our fuel for that reason, but also we had deliverability issues we can see with OMV's fields. And there was an indication we were going to get less gas in 2023 than we got in 2022. So, that's why we weren't selling into the high prices at the beginning of FY '23. And then everyone got it wrong. We ended up with a deluge, [ P96 ] inflows, which for people that don't understand that terminology, it means it's only 4x in the last 100 years that we've seen a wetter weather in that 6-month period. So, that has a pretty major impact. And you can see the impact it had on our financials as prices dropped significantly, in particular in Q2. But we're still very comfortable with our trading strategy overseas operate with a lower level of fixed price variable volume sales. And the reason for that is it gives us space to participate on the -- and sell on the ASX. That's important for us because that allows us to seasonally shape ourselves into the future, so they better align with our generation portfolio. That's becoming increasingly important as we bring more baseload geothermal into our portfolio and offset flexible thermal generation, which then shuts down. The other topic is we see the cost of risk management going up. Whilst we have seen international coal prices drop a little bit, they are still relatively high. And the other topic we've got here is we believe the Genesis swaption which expired at the end of 2022 has been shielding the market from those high international coal prices. Remember, that was relatively cheap, 250 megawatts of swaption that was provided to the market and it was cheap because the pricing was set in a completely different environment to what we're in at the moment. So, for those 2 reasons, we're pretty comfortable with our trading strategy in keeping that level of fixed price variable volume sales lower. It also sort of ties in quite neatly with our future portfolio where that's going because when Tauhara and Te Huka 3 are all online, getting towards the end of calendar year 2024, our mean hydro year generation -- renewable generation is going to be about 9 terawatt hours. We've only actually sold about 7.6 million of that through fixed price variable volume channels through PPAs that we have or expect to commit to and then covering our location losses. So, we've got about 1.4 terawatt hours that we need to work out the most optimal way to place that into the market. And I think you'll agree, based on the market that we see in front of us, when you look at the ASX curve, for example, that's a pretty good position to be in. In terms of the fixed price variable volume sales, we are -- as expected, they are repricing. There is still quite a big gap between those though and the ASX going out to 2026. And just to put that in perspective, the average -- weighted average price that we sold our electricity for in the first half of the year was only NZD 112 per megawatt hour, which, as you all know, is considerably below the ASX going out to 2026. So, that does highlight the extent of an opportunity there. And the last point, as we were talking about for the call, we're going to have another Capital Markets Day, so Investor Day in May. We're going to have it in Taupo because for us, that's where all the action is, opportunity to take you through Tauhara, which will be nearing completion. And then at the other end of the scale, we can take you through Te Huka 3, which is starting. Good opportunity to take you through how we're deploying our strategy. And some of the topics I've just talked about, which are quite important and structural in nature. We can put a bit more color on those as well. So, on to the financials. I mean we're coming off the prior corresponding period where our profit after tax was NZD 134 million to a loss of NZD 7 million in this period. That's not about the onerous contract provision, though. And I will -- when I talk about the numbers, I will generally talk about it before the onerous contract provision because it has nothing to do with the underlying trading of the business in the last 6 months. Within all of our commentary, we're very clear as to what the numbers look like with and without. So, the biggest component of the drop in profit before the onerous contract provision is EBITDAF, which is down by NZD 76 million. As usual, we've got that chart on the right-hand side of the slide, which explains what's driving that. We can just talk through it quickly. In the prior corresponding period, Contact had relatively high renewables. Remember, it was very dry in the North Island, so prices were high, and we were able to sell into that and get the financial benefit from that. This year, though, we've seen very strong hydrology across the whole of New Zealand, which has seen prices a lot lower. We've also seen our inflows actually higher, but the problem we've had is the inflows have been very concentrated into short period. So, very high inflows in July, August and November. And the issue is those inflows have often been a lot higher than we have capacity to generate into because we're a run of river catchment, we're sort of limited in our ability to store those excess inflows so they do get spilt. The other topic is because there was just so much inflows across the whole of the sulfide and the HVDC was also a constraint because you couldn't get all that water into the North Island, so that drove spill as well. So, this sort of manifested itself in our numbers with our renewable generation being down 392 gigs and that has a fuel replacement cost of NZD 51 million to us. We actually then reduced our sales position down by more than the renewable generation. It came down by 539 gigs, and that reflects the fact that with those very low market prices, it wasn't economic for us to run our thermal generation as well. So, the overall impact of that drop in sales and also the reduced market pricing and how they impact our market channels of short-term CFDs and merchant length was a further NZD 25 million reduction in our EBITDAF. Going the other way, as I said, the fixed price variable volume channels are repricing upward. There's NZD 33 million of benefit there. Other income is down by NZD 7 million. There's some market making losses within there, which I'll talk about later. Fixed costs are up by a lot. I'm not going to hide from that. They're up by NZD 24 million. We did have that Holiday Act provision release in the prior corresponding period, which artificially reduced our OpEx by NZD 6 million. We are seeing higher transmission. Remember, there's no ACOT benefit in this period. There was in the prior corresponding period. And then you've got higher OpEx overall inflation, some strategic investments in OpEx to drive our strategy and things that we'll talk about later. So overall, that gives you the NZD 76 million reduction in our EBITDAF. Other topics that have impacted our net profit. Depreciation is lower. Remember, we did accelerate the depreciation in the prior corresponding period for some parts of our SAP system that wouldn't be required in the new S/4HANA system. The interest is flat period-on-period, even though net debt levels are up by about NZD 300 million, and that's because all that extra debt is driven by our major projects, Tauhara and Te Huka 3 and therefore, the interest associated with that gets capitalized against the projects. Tax is down, as you'd expect, based on the lower profits. And then fair values of financial instruments, this is quite a topical area with IFRIC that got released recently, which all of the technical accountants in the room will understand. I love talking about this topic. Adverse NZD 18 million for us. So, we had a favorable NZD 10 million position in our prior corresponding year and then we were adverse about NZD 8 million this period. That relates to some unrealized market making losses, but also the swaption that we've got in place with Meridian as they have the option to call it, it's not in a hedge relationship for us. And hence, we have to put it through the P&L and the market pricing has moved up since we entered into that arrangement. So, it's slightly out of the money. In terms of our performance across our 3 businesses, so the wholesale business is down by NZD 48 million, so that reflects the lower pricing, reflects the lower renewables and reflects high locational losses. We'll talk about that. Retail is down by NZD 16 million of EBITDAF and that's the fact that we have that arms-length transfer price into the retail business, reflecting the higher wholesale market. And the fundamental issue here is the tariffs aren't going up quick enough to offset that cost increase. But the good news is, and you'll see this when we get to the retail side, it is sending a signal and there has been a step-up in the level of tariff increases going through that business. And then the corporate costs are higher by NZD 12 million and this reflects some one-timers and some other cost increases, which again, we'll cover when we go through OpEx slide. So, on to the wholesale business, generation costs are down by NZD 11 million period-on-period and this reflects less need for risk management. So, we had less acquired generation and thermal generation. They were down 147 gigs collectively. That saved us about NZD 22 million in terms of thermal fuel costs and acquired generation costs. Within that, our cost of -- marginal cost of thermal generation remained flat, NZD 121 a megawatt hour, there's a few offsetting things going on here. The cost of gas actually reduced in the period because the market had excess fuel in it because of [Technical Difficulty] hydro, but we've continued to see higher carbon prices. Naturally, our thermal portfolio, we saw the heat rate move against us from 10.7 to 11.5. And that reflects with the very low prices that we were seeing in the marketplace we were running to Te Rapa in turn down mode because we didn't want it to get merchant-led for those low prices. Offsetting the NZD 22 million of lower fuel costs, we've seen fixed costs up from a generation perspective by NZD 11 million. That's a transmission cost increase of NZD 4 million. So ACOT, the fact that, that's been discontinued, is feeding through here. But also the regulators signed off a whopping great 13% a year increase in the gas transmission rate and that will carry on for the next 5 years. So, that will be feeding through as well. Luckily, that is largely offset in the period because our generation -- gas generation volumes were lower and we have a variable component within our gas transmission, but just to heads-up that we are expecting gas transmission rates to be higher into the future. On top of the higher gas transmission costs, we've got other operating costs that are up by NZD 7 million. Within that, we've got development costs for our renewable pipeline by NZD 2 million. This reflects the less mature part of that pipeline where we can't capitalize those costs. We've got NZD 1 million just under that we are paying to staff at Te Rapa. This is a retention payment to ensure that we have a smooth process around the closure of that plant. And then you've just got higher inflation flowing through here. There's a lot of people in this part of our business and on average salary costs are up by 5%. Because those development costs, by the way, have got nothing to do with the day-to-day running of our renewable and thermal plants, we have started to split them out on the slide for you. And I should also just talk about our renewable costs, which were up by NZD 6 million because normally, those costs are relatively flat. So what's happening here, the cost of carbon has gone up, which obviously impacts the geothermal business. You've also got one of our geothermal plants Te Huku was getting benefits from the ACOT in the prior corresponding period. There's a couple of million dollars there. And again, just salary inflation feeding through here. In terms of the overall performance of our assets, we got the -- one of our new transformers installed at the end of August down in Clyde, which was great. The issue, though, we had is -- that meant we were down a unit for most of August and all of July when inflows were relatively high, and a unit is worth 108 megawatts for us, so down there. So, that's -- that would have contributed to some spill. We've got the second unit that's being installed as we speak, but we expect to get that back into action in May, so before winter, which is important. In terms of geothermal, geothermal volumes were below average generation volumes and that reflects that we had that 5-year statutory outage of Wairakei, it also reflects that we've been able to build some more flexibility into our geothermal operations. And with the prices being so low in the first half of the year, we were able to conserve some fuel, which will get the benefit from in the second half of the year. And then the other big topic here is the news that Mike mentioned, getting the reconsent of our fluid take on Wairakei for the next 35 years is very, very important. But the team have done an amazing job and also got an extra 5,000 tonnes a day of fluid of that, which just goes to show how strong the relationship is and the confidence that the various stakeholders have in our ability to operate that reservoir up there. So, that 5,000 tonnes per day is worth about 20 gigs of increased geothermal generation and that kicked in from January. Thermal assets were working after a bit of a torrid time, let's face it in FY '22. So, they're all up and running and working. They weren't needed a great deal with all of the water we had. That's always the way. We are taking TCC down for its annual outage in February and that we'll repair the [ Radix ] through that process. And we're actually hoping to build in some more flexibility, which means when it comes back, we'll be able to turn it down to 100 megawatts overnight. Currently, it only goes down to 160 megawatts. In terms of our wholesale contracted revenue, that was down by NZD 47 million. And this is all about the fact as I said earlier, we had lots of renewable generation in the prior corresponding period when prices were high, because of the dry North Island effects. And therefore, we sold a lot of high-priced short-term CFDs. For all the reasons I've already outlined, that didn't happen in this period. So, the revenue that we got from short-term CFDs has dropped down by NZD 114 million, has been offset partly by NZD 74 million of increased revenue across C&I and sales into our retail business. Great to see the C&I business repricing quite significantly with the net price there up by NZD 38 a megawatt hour. And whilst the increased price into the retail business, as I said earlier, is just a sort of left pocket, right pocket thing, it is sending the right signal into that business to look at tariffs. Unfortunately, we saw a NZD 12 million adverse movement in our other operating income, and this is all about the market making that I mentioned earlier. The problem you've got is when you're a maker of a market, you're taking all the positions other people don't want. And when the market is both high-priced and volatile, it does have adverse consequences, which is what we can see here. I'm going to be very interested when I look at the other gentailers and how they're going with this as well within the results. But I think the problem is it's always difficult to get an underlying view of market-making because people do move market-making positions into the portfolio. In terms of our wholesale trading and merchant revenue, there was a loss of NZD 17 million here, which is an adverse movement on the prior corresponding period of NZD 12 million. We aim for this to be 0. We aim that the money that we make from merchant length to offset the location loss or some people call it [ LWP, GWP ] loss. And the reason we do that is because there's a natural hedge between them. As wholesale prices go up, your merchant length goes up and your location loss goes up and the vice versa happens when wholesale prices go down. The reason why they didn't offset in this period is because the spread of the location losses increased quite significantly. We normally expect it to be about 6%. It went up to 13%, and that's because of the disconnect between pricing between the North and the South Island because of all of the water in the South Island and it couldn't get across the HVDC. In terms of the retail business, as I said earlier, the EBITDAF has dropped from NZD 16 million down to NZD 1 million. This reflects a contact and the rest of the market, to be honest, has been slow to pass on those cost increases to consumers. At the full year FY '22 results, I did talk about this market. Netback is now relatively low and it would need to improve to continue -- for it to continue to be an attractive market for us to sell electricity through. And I guess for that reason, we're not overly concerned at the moment that we've seen our electricity connections drop by that 2% since our full year results, it's about 10,000. It is -- the good news is though we are seeing the repricing. So, tariffs are up NZD 10 a megawatt hour, which is about 4%. From what I know of tariff increases that we've already put through when we look at this for the full year, we'd expect about a 6% tariff increase on average. We do recognize this is a long-term channel. We don't do knee-jerk decisions around this. We keep pricing changing at or around the level of CPI. We do recognize that any increase in price is obviously difficult for people in the current environment. But we do run this business as an arms length business because it's competing with independent retailers. And so it's important that we do look to recover costs and keep the business profitable. Gas transmission and gas costs have gone up significantly over the last few years. We don't have any position in those, either upstream or on any gas infrastructure. So, any costs that we see increases there, we have to pass through to consumers, and that's led us to a 20% increase in our gas tariff in order to maintain gas margins. What we're actually seeing is we expect gas tariffs to actually outpace electricity tariffs going forward because of the exposure to carbon, but also those electric gas transmission increases that I talked about. And the fact that you're going to see gas generation shutting down, which means the gas transmission is going to be recovered over a smaller and smaller amount of volume leading to even bigger increases in gas tariffs. So, we're actually trying to encourage customers as much as possible to get off gas on to electricity to avoid all of those cost increases into the future. In terms of our broadband, the margin there has remained flat, even though our tariffs went up -- even though our collections went up by 30% and this reflects the fact that we've been in growth mode. We haven't been changing our broadband tariff. That's been fine when inflation has been relatively low, but it started to kick up. And the biggest cost that we have is the local fiber companies. And for example, in 2021, the cost increase was 1%. That's now gone up to 4% in 2022. So, we can't absorb that and we have to pass it through. Unfortunately, with that timing difference that we've seen in these financials, which will be sorted out going forward has meant that the additional margin we got on those extra connections has been offset by the under-recovery of cost inflation. In terms of our cost to serve per connection, that continues to go down, which is great as we leverage our fixed costs with the 20,000 extra connections that we have seen. OpEx, as I said, I'm not hiding for this one. It's up by NZD 20 million. There is NZD 9 million of adverse one-timers in there. So, NZD 6 million of that relates to the prior corresponding period, OpEx being artificially low due to the Holiday Act provision. And then we've got NZD 3 million of one-time costs in this period as well. Remember, we've got that retention payment to the staff at Te Rapa, which is about NZD 1 million. We've got the costs associated with that industry report by the Boston Consulting Group, but we've also spent some money transforming the way in which we prioritize and execute on projects. So, we've had some consultants in helping us out with that. We'll see the benefits of that because we have an incredibly ambitious 5-year plan and making sure that we have the right resources and the right process around prioritizing executing those initiatives is very, very important. From an underlying perspective, we've seen inflation tick up significantly. You've got staff inflation there with wages at 5%. Insurance has gone up by 6% for us and we all know that CPI, which feeds through here as well is tracking above 7% at the moment. We talk about headwinds, but that's actually all travel. That's -- our travel costs are up by NZD 1 million. We know airfares have gone up significantly. But actually, the level of activity around travel has gone up as everyone gets out of COVID lockdowns and is looking to reconnect. To be honest, I think we will rein that in a little bit and bring the travel expense back a bit going forward. And then we've got some growth and sustainability. And this is the money that we're investing to mature that 6 terawatt hours of renewable development pipeline that Mike talked about. This is the money that we are spending to cover that 20,000 extra retail connections. We're also investing in sustainability topics. So, this is things like Whanau Growing Your Whanau policy, which a market-leading policy. We're investing in things like training, we're investing in safety leadership and also improving compliance, which we have no compliance issues, but it helps us tell our ESG story a lot better going forward. And those types of investments are the things that actually helped us scale entry into the Dow Jones Sustainability Index, which is also -- which is obviously very important. So on this, we've got an ambitious strategy. We just need to make sure we're resourcing it appropriately to put us in the best position to deliver it at pace and effectively. The delivery of our strategy, which is decarbonizing New Zealand, obviously touches lots and lots of stakeholders. So, it's important we do that. And also, we have to be mindful of the well-being of our employees and therefore, making sure that strategy is properly resourced is key. Just a few examples of some of the value topics that we've got from these investments. That fast decision on Te Huka 3 FID was a result of having the right resource in the right place. The fact that we've now operationalized carbon capture and reinjection on Te Huka, that's 10,000 tonnes of carbon that's now coming out of the atmosphere and being reinjected again. That's about NZD 1 million of savings at the current carbon price. From a standing start, we've created what we think is actually quite an impressive solar and wind pipeline, picking the right partners as we do that in Roaring40s and BP Lightsource. And then that consenting at Wairkei incredibly important for the next 35 years that underwrites our geo future investment and getting that extra 5,000 tonnes per day is a brilliant outcome. So, that's what we're getting in terms of that extra resource that we're putting into the business. In terms of our cash flow, at operating free cash flow of NZD 60 million, that's a relatively low conversion of EBITDAF into cash for us at 24%, but there's a very good reason for that. It was very wet and we didn't really run our thermal assets and our commitments around natural gas and carbon purchases were put in place a number of years ago. So, what that means is you can see the trade working capital has gone up by NZD 43 million because we have acquired NZD 27 million more carbon in the period than our liability went up by. And equally, we've seen that the amount of gas that we've got stored in AGS has gone up by 2 PJs, which is NZD 16 million. We'll get that back in the second half of the year as that trade working capital unwinds because we'll be running thermal generation more, but we won't have to buy as much carbon in natural gas. And then the other topic, I mean we're going to pay about NZD 110 million of tax for the year. And you can see we've already paid NZD 76 million, and that's just the way the tax payments are skewed towards the first half. So, we're comfortable with those timing topics that the full year conversion of our EBITDAF to operating free cash flow will be in that 50% to 60% range. In terms of our balance sheet, we are seeing debt levels increase, which we're happy about. It means we're getting closer to the completion of Tauhara and Te Huka 3. We raised NZD 250 million in October with a retail bond heavily oversubscribed. So, we're very happy about that. That was NZD 150 million refinancing, but NZD 100 million of that was for growth. And we're going to be back in the market towards the end of March, raising a further NZD 250 million to support our renewable development pipeline. Great to see our average interest rate at 5.4% is relatively flat in a high interest -- increasing interest environment and that reflects the great work the treasury team have done here, increasing the amount of funding that we have through commercial paper, which is on a very tight margin. And then more broadly, as we support our strategy around decarbonizing in New Zealand, which obviously means building a lot of renewables, it's important that we can finance that. We've got net debt-to-EBITDAF at just 2.2x, so well within that sort of ceiling of 3x, which S&P has set for us in order to retain our investment credit rating. Remember, we've already got a lot of the debt of Tauhara in that number, but we've got none of the EBITDAF from Tauhara in that number. So, we're comfortable that our geothermal pipeline, we will be able to build on balance sheet with our existing balance sheet capacity. And then when you look at things like solar that we're getting closer to fits on with the joint venture arrangements we've got with BP Lightsource, we're comfortable that's going to be off balance sheet and require minimal amounts of capital from Contact's balance sheet. We're also pretty underutilized in our use of capital bonds. So, that's another option for us. So, we are very comfortable from a financial perspective that we can fund our strategy. In terms of dividend, we sort of guided that the dividend was going to be flat for FY '23. So, it won't be a surprise that the interim is flat at NZD 0.14 per share. NZD 0.12 of that will be imputed for qualifying shareholders. We're going to continue with our undiscounted dividend reinvestment plan, easy way for shareholders to reinvest into Contact, but obviously, it doesn't dilute shareholders that don't want to do that. I know dividend growth is a key topic for our shareholders. So, there's a couple of things that would cause a dividend to change and go upwards. Linked to our dividend policy, the -- and operating free cash flow is going up in a structural way. So, that's one topic. And obviously, we're not far from that happening with Tauhara coming online this calendar year. And then the other topic that sort of Mike mentioned earlier on, it's Tiwai, long-term Tiwai deal. That will reduce market risk and will mean our Board, that's what I suspect, all-in, Board within this sector will be comfortable with dividends being higher in that operating free cash flow range. And as Mike has said, our engagement with Rio Tinto, they appear ready and willing to do a long-term deal at a reasonable price, which will increase sector earnings and should lead to higher dividends too. In terms of a bit of guidance here, we talk about our NZD 550 million for FY '23. So, that's what we guided in normal hydrology based on our assumptions around the market pricing and channel pricing and stuff like that, that's where we got to. We're tracking below that for the first half of the year by NZD 34 million. Renewables were slightly higher than a mean year, but it's been offset by the market pricing was considerably lower. So the pricing you're getting on short-term CFDs and merchant length linked to the wholesale market. but we expect that to reverse a bit in the second half of the year and outperform by NZD 14 million, and that reflects renewables will be lower than mean and that reflects the very dry January that we've seen. But based on the ASX curve and also what we're seeing in terms of the net pricing that we're getting on mass market and C&I, we expect that outperformance of NZD 14 million. That leaves us at about NZD 530 million for the year. It's also worth mentioning, though, in terms of future guidance. There's a couple of good sort of structural things there. The ASX is higher in the future than what we had assumed in our original NZD 550 million guidance and also the netbacks that we're getting on mass market and C&I are also higher. So all things being equal, you would expect our guidance for FY '24 to be higher than FY '23, and that's before you consider the impact of Tauhara coming online. Then we just got a bit of an update on our guidance confirmation, sustainable business CapEx is coming in a bit faster than expected, a bit higher than expected, and this links to the fact that that NZD 100 million of additional capital that we guided that we were going to spend on improving our renewable resilience in the S/4HANA projects, we're spending that a bit quicker than expected. There was a little bit of CapEx associated with getting that reconsenting of the Wairkei fluid type, which is obviously very -- very wise investment. And then we've seen a little bit of change linked to interest to do with unwinds of provisions on onerous contracts, but also the floating rate of interest, as we all know, is higher than everyone would have been expecting as we entered this financial year.

All right. Thanks, Dorian, and Mike. We'll go to questions now. We'll go to the line first. So, Grant Swanepoel from Jarden.

Can you hear me?

Yes, we can Grant. Thank you.

It's so, a bit clumsy this process. Just a few questions around CapEx. So on Tauhara, what have you spent at the end of FY 1H '23 and what's left to spend on Tauhara -- I'm just going to -- probably be easier this way. And then when are we going to expect first use from Tauhara? Is that still going to give us about NZD 80 million of EBITDA uplift. What CapEx have you spent on Te Huka so far? What's left to spend? And when do we expect [indiscernible] from Te Huka? What is the CapEx expected for the solar JV? Is it around about NZD 100 million from your side? And then adding this extra 1.4 PJs of short-term gas, are you paying over NZD 10 a PJ for gas? Or is it less than that of PJ?

There's a lot to unpack in there Grant. I'm sure some are in the appendices as we go scrambling through or find it. So, the CapEx guidance for Tauhara remains as before in terms of what we've signaled to the market, we took the increase, I think it was 780...

880.

880 and the team are tracking well within that, noting that the project is now 84% complete. So, there is increasing confidence around that. And our guidance for it starting up later in the year also remains the same. The team have worked incredibly hard to secure that start-up within this calendar year, and they continue to track towards that. And hopefully, you can see from the photos of the site, the physical progress, you can see the lower half of the turbine has started to be put in place. And when you see the turbine in the turbine hall, you know you're getting to the interesting end of the project. So, that remains on track. Te Huka 3, we went to market with an FID of NZD 300 million. The contracts, both the EPC contract and the supporting contracts for our works have come in within our expectation range. So, we remain confident of that capital as well, and that is on track I think October '24?

Yes.

October '24, and we're getting ready to hand over the site to Ormat. So notwithstanding weather events, as it's been a very interesting time for obviously, the Tauhara team and the Te Huka 3 team, both those projects as we stand today are in very good health. Yes, we don't normally disclose, but your question is an interesting one, and I think we've got a reasonably positive view on that. What was the other questions here?

How much are we spending on gas? The gas price?

The gas price.

Yes. I mean the gas price, we've locked in, it's within our contracts with OMV, and that's sort of NZD 8 to NZD 9. That does have an escalation in it, which is why it goes up every year, but it's there or thereabouts. What we actually report in terms of our gas can be different from that because obviously, we're buying spot gas all the time as well on EMS and there were some pretty good deals in place, obviously, in the first half of the year we've ordered the water around. And actually, we can still get some quite good deals at the moment, which we're looking into as well. But it will be there or thereabouts, Grant. In terms of...

Christchurch Solar.

Christchurch Solar. This is -- from a Contact balance sheet perspective, we're receiving minimal capital is going to be required. This SPV, which we'll be building it will be highly leveraged based on the fact the quality of the counterparty that is going to be selling it, solar to is extremely good being Contact. It will be able to be leveraged up to about 70% or 75% and then obviously, we put our 50-50 equity in with Lightsource bp. We've done a bit of work actually with S&P on this just to make sure that none of that debt ends up on our balance sheet because, obviously, the fact that we are a 50-50 partner and the PPA off-taker is us. We want to be comfortable that the debt won't appear on our balance sheet and S&P have confirmed assuming that the way in which the Ts and Cs of all of those bank facilities work are aligned to what we've told S&P, it won't appear on our balance sheet, which is important. In terms of how much we've got left to spend on Tauhara Grant, is about sort of NZD 250 million, NZD 280 million between those numbers. I haven't got the precise number, but it's somewhere between those. And Te Huka 3, I mean we haven't spent a great deal on that, obviously, because that project is relatively new. And as Mike said, all-in, it's going to cost about NZD 300 million.

So just to conclude, with that NZD 30 million upgrade to retail pricing and wholesale pricing and the forward curve remaining strong, can we consider a run rate once Tauhara is up and running of the NZD 550 million plus the NZD 50 million improvement in retail plus the NZD 80-odd million from Tauhara, getting us to about NZD 660 million. Is that a normalized sort of expectation in a normal year?

Yes. All of those topics you've highlighted are being the things that cause are expected to normalize for FY '24 to be higher. I can't tell you exactly whether those numbers are right because I don't have them available to me, but those are the topics and they are all positive topics as you highlight.

And it fits with the guidance we gave for FY '25 of NZD 720 million.

Yes.

We'll go to questions in the room, questions in the room here. Andrew?

I have a couple of questions. First question is actually just around the Wairakei projects. And just want to clarify as much as anything else with the consensus you finish that on June 2026, and then it looks like Te Mihi comes in the second half of 2026.

Yes, there is some...

[indiscernible] get here?

No, no. We expect -- you're now within [indiscernible] of each other, and there's reasonable flexibility around that. So, we don't expect any gap.

So, you've got some flexibility?

Yes.

Second question, just in terms of SIB CapEx and obviously, that's [Technical Difficulty] a little bit of a step up than previous process, additive. But you're still going for 65 long term. I mean how comfortable I guess are you there? I mean we're looking 5 years out?

Very. So, I think there's a number of things. One is we've got the S/4HANA SAP upgrade, which will come to an end this year. The other thing is the [ Roxburgh ] project, which we have deliberately decided to step into, which gives us an upgrade and output from Roxburgh. That's a 1 in 60-year event. And the other one, which is playing through is the replacement of the transformers at Clyde, which is unfortunate. We're not happy that we only got 25 years out of them, but that should be a 1 in 50-year event. Once we get through those, as I said, as I indicated, you get to 2026, we've got a new plant at Te Mihi. Te Mihi remained in good shape, new Tauhara, new Te Huka 3 probably is in great shape. Your hydros are completely refurbished. The assets will be in very, very good shape, and so I'm very confident in that SIB CapEx level.

I notice a question [Technical Difficulty] inflation pressures?

Yes. It's -- we are going through a bit of what we call a surge at the moment. But once we get through to '25-'26, the base will be -- the assets will be gun shaped. So, the base will come down. Yes, there are inflationary pressures. But hopefully, it's being applied to a much lower base.

You make a good point because that 65 was -- you could argue it's a real number that was announced about 5 years ago. So yes, there might be some higher costs linked to that feeding through here as well. But I think it will be rounding in the grand scheme of things.

Yes. Last set of questions, I guess, is just around a couple of clarification things on the guidance and the second half increase. In terms of, quite good, I guess, mentioned sort of first half with long generation. What is the sort of assumption in there for the second half? Also, price assumption, I assume just straight of the ASX, So, [Technical Difficulty]

I mean basically, what we've got a dry January, very dry January, which we've taken into account. We then expect to sort of revision to mean hydro for the rest of the year, maybe slightly lower because we will use a bit of our hardware storage over the course of the year, but it won't be too far off mean inflows. From a contracted position, most of our sales are fairly contracted. We've got a small amount of -- very small amount of pure merchant length, over and above the location losses, which obviously we're still exposed to but that's not hugely material. And we've got sufficient -- expecting to have sufficient gas to run any thermal we need. The risk, therefore, to that number would be, as usual, will be hydro and where we're going to get the inflows. We don't see that being price risk from a sales perspective. And obviously, if you don't get as much hydro, the issue there is you're displacing low-priced hydro with having to run our thermal harder than expected. If there is a lot more hydro, then that's probably upside because we've contracted all of our sales positions. So yes, we think it's pretty balanced. But as is always the same with renewable operators like us, it will be -- it will all depend to a certain extent on the weather.

Actually -- and just one last question, which I'm not sure if I missed it, from Grant's question. In terms of Tauhara timing generation, maybe give us some...

Q4 this year.

Calendar -- calendar year...