Contact Energy Limited (CEN) Earnings Call Transcript & Summary

[Audio Gap] And welcome to Contact Energy's interim results for FY '24. This morning, we are joined by our CEO, Mike Fuge, and our CFO, Dorian Devers.

[Foreign Language] and welcome everyone to our first half FY '24 results announcement. I'll just flick through to the next slide with the usual disclaimers around information, and then we'll get right into it. So this morning, I will be presenting the highlights, and some observations on market and external conditions. Dorian, then will take you into the details, of the financial results and anything that requires explanation there. And then there's a -- in the past, you'll have seen an amount of supporting materials, which again just gives you the details of how we have landed where we've landed. Going right into the headline results, it's a very strong result, certainly one of the strongest in the last 4 years for a half. And what characterized that is, a return to hydro volatility after FY '23, we saw very strong inflows. We've seen the El Nino start to bite with a reduction in hydrology. We've been running TCC harder over that period compared to first half '23. We actually took action to get ready for that. We brought the TCC outage forward, to make sure we could run it over January, February and also in response to the extended commissioning on Tauhara. The results themselves on a operating free cash flow basis, it's improved significantly. The other thing that Dorian will turn to is that we have successfully controlled our operating costs. There have been increases, but we understand where those are and the cost basis of the company remains well in hand. We'll talk a little bit as we go through about the reversal also of the provision on AGS. And just right at the bottom of that slide, our view remains that the long-term pricing is going to be in that 110 to 120 megawatt hour. We're making that 2024 real. That's consistent with what we've seen in the past, when we had it in 2022. We believe the volatility in the market, the need for firming and the fundamental structural change, and particularly wind costs, supports that long-term view and we're certainly seeing it play out. And as going through the presentation today, you'll see some supporting graphs, which just highlight that fundamental shift in the market from about '19 onwards. One of the things about the result also is that channel pricing is much closer to the market conditions that we now see. The next slide, I presented Contact26 almost 3 years ago now, and it remains and relevant today in terms of its strategic themes and what is being done. And if we go through each of those strategic themes, there are some important milestones from the last 6 months. In terms of growth demand, we continue the constructive engagement with Rio Tinto, around the future of the smelter. We continue to stand by our position that we see a long-term future for the smelter here. We can talk through the details of how we see that landing, what's required. And the other thing about the period is that we did develop proposals for CO2 -- food grade CO2 at Ohaaki. Why that is important is that, it ensures a sustainable supply of CO2 as an industrial gas to New Zealand that isn't based on thermal generation. It's also very important in terms of putting to use what would otherwise be a Scope 1 emission. In the growing renewable development at Tauhara, the team have worked incredibly hard over the last 4 months to put in place the modifications to the steam plant that are required as we speak today. We're boxing up hybrid testing, and getting ready, to recommence the steam blow sometime in March. So far, everything has gone well there. On GeoFuture, the drilling campaign is actually underway. We're seeing some good positive results. All the more significant given it is the Wairakei field of 60 years in production already. We're on the advanced stages of towards an FID for Kowhai Park solar and the same is for the BESS project. We've lodged the for a fast track consent for Southland wind, which would be up to 300 megawatts. In terms of decarbonizing our portfolio, we delivered on our promise in terms of the closure of Te Rapa, which has improved the thermal -- emissions intensity from our remaining generation fleet combined with the running of TCC. As I mentioned, we continue to assess the viability of a 100-megawatt battery at Glenbrook and that's been advanced again, taking -- on those lessons about advancing front end design for projects going into FID. And we remain on track for a TCC commissioning at the end of this year. One of the standouts for this half year that, I do want to bring is the performance of the retail team. We have expanded the telecommunications offering into mobile. Broadband we're approaching -- started approaching the 100,000 connections. Overall, we've drawn by 20,000 connections in the area, which has included some growth in electricity connections as well. And just to highlight the challenge in that business is that, the consumer has been largely protected from the absolute price shocks, caused by the last 3 years. And at the same time, bringing them to a realistic market price, has been a challenge. We appear to have been able to do that, without tipping the boat over, as it were. And if you think of the price shocks that have occurred, even in what we pay for, say, petrol, but certainly what the rest of the world has seen, we appear to have navigated both as a company and an industry well. We continue to expand our time of use offerings in terms of good weekends. We can now have over 84,000 households, on some type of time of use plan, whether it's good nights, good weekends, or good charge for EV charging. And we were an energy retailer of the year finalist for the second year running. Now, the elephant in the room. We continue to have constructive negotiations with Rio Tinto, and that only reinforces our view that the smelter is likely to stay open. However, we do expect any new agreement to be long-term. We don't need this hanging over us, as it has for the last 2 decades. It has to be at a fair price, which is obviously maturity above the current price. And it should include some form of demand response. Contact Energy, both in this, but in the New Zealand steel deal, have been a strong advocate of industrial New Zealand participating, and being part of the solution, to our dry year and intraday demand flex challenges. And so, we see that as important for this deal as well. What it would create is market certainty, which would significantly de-risk investment in new renewable generation. And that's for the whole industry. And we see that as incredibly important, as we turn our eyes forward to that de-carbonization challenge. And having a large scale demand response participant would significantly contribute, to a dry year risk mitigation, which would be significantly lower cost to the nation, compared to other solutions, which may have been proposed in the last 5 years. It is complicated. Multiple bilateral negotiations with multiple other stakeholders with an interest, along with other potential third-parties. This is not a straightforward deal. We have to acknowledge that. We are the only participant in the room, but we continue to be very optimistic about a long-term solution. It's important to the country in terms of its contribution, to an otherwise deteriorating trade balance. It's important to Southland in terms, of the employment and the contribution, to the Southland economy. It's important to the industry, in terms of its potential, to provide demand response, for dry years in particular. Just in terms of the geothermal investment program that we've got underway, Tauhara as I said, as we speak, the team are boxing up and getting, preparing themselves to provide steam again to the EPC contract scope. We expect that to be on in quarter 3 this year and we remain committed to that. The Te Huka 3 continues to make good progress. It remains on budget. And as we speak today, by the end of February, it'll be in excess of 80% complete. GeoFuture, as I said, we've made good progress on the drilling program and front end design. We expect to take FID on that first half of this year. But what is really important that we remain committed, to it being on stream by the second half of 2026. And we've been able, to maintain that commitment, through the early drilling works, and advancing the front end design. And on the cost at the moment, we have 2 bids from high quality international tenders for the power station. When we have more information, we'll be able to update you. In terms of the enablers and the strategy, which we outlined to you 3 years ago, our ESG commitment remains strong. We now top New Zealand companies with the DJSI and we got the sustainability leadership award in the Deloitte 200. In terms of operational excellence, the team were able to give early delivery on the 50 gigawatt hours that was enabled through the Wairakei consents. They were able to make that a reality. You can see how they responded to the challenging hydrology, by bringing the TCC outage forward, and TCC has started very well over the last couple of months. And we have worked to accelerate the return of GT22. It was expected back sometime next year. We're now expecting it back in the first half of this year, in time for the bulk of winter. In terms of our transformed way of working, the thing I do want to call out, is the much improved safety performance of the company in these first 6 months. That was a result of hard work and significant investment and training of our leaders and frontline leaders as well as a re-platforming of the business, to enable safety observations to be recorded much more easily and acted on. We won the Wellbeing Award in the New Zealand Energy Awards. And certainly what we're proud of is, that investment paying off in the well-being and health and safety of our people. Now we've talked about this for a long time, demand. And finally, we can see some increased demand from the underlying. Certainly underneath this, in terms of the retail arm of the business, we see the number of ICPs growing, as well as the usage per household growing again, as households go on that de-carbonization journey. In commercial industrial, we've now seen a stabilization, where there was downward pressure from the closures, of the refinery and Norske Skog plants. And now with New Zealand steel future secure with OG Pan Pac coming back online later this year, and an expected long-term security around the smelter, we expect the demand growth to start picking up, as well as the de-carbonization initiatives in terms of boiler conversions and dairy factories, meat processing and of course, New Zealand steel electric arc furnace. So it looks positive on that front and that emergent demand growth is very much welcome. I talked about the hydrology, impacting the generation mix. You can see there, first half of 2023, we had virtually no coal-fired generation as an industry. It's kicked up a bit in the first half of this year, with an increased gas-fired generation as well. You can see in the graph on the right, how we are sitting now below mean, compared to what was a very wet combined FY '23. What that means is increased volatility. It means that typically the market is pricing at thermal dispatch. We do see increased volatility also from the additional wind coming on. You really notice it in the market, on a day-to-day basis when the wind is there, and when it drops away, the effect that it has. And we expect that volatility only to increase. And that in terms of the market and the market forces, this is a slide that we have presented consistently, as what we see the overriding influence, of on the wholesale electricity price here in this country. Aluminum prices remain largely flat. Hydrology is, we're sitting at about 80% of mean. We're seeing a decrease in coal prices, but gas prices remain reasonably elevated. Methanol prices are best described as steady. And in terms of gas and carbon, you've seen a recovery in carbon prices. The AGS facility remains constant and it's both its storage, and its deliverability. Demand as I said, was up. That graph on the right hand side, talks to how the market has shifted. It is a fundamentally different market, from what it was 6 years ago in terms of the volatility that we all have to manage through. And that speaks to both the demand, the supply side challenges that ageing thermal plant has built, as well as the increasing penetration, of wind and solar into the market. And that is something that we all have to manage and go forward. We do expect future marginal prices and higher renewable development costs, play through into the market in the go forward. The reality is, is that wind is not as cheap, as what people globally assumed. That it is more expensive. I think wind turbine suppliers have discovered that, to their chagrin that, it is an expensive option, and it's more expensive than what anyone assumed. And that is going to play through into electricity prices. In terms of retail, it's important to acknowledge that, we have one of the most competitive retail markets in the world, which has protected the consumer from the price shock. That graph at the bottom tells that story in terms of, when inflation has been going at a CAGR of roughly 4.5% per annum. Electricity prices have increased 3% per annum. And what we've seen at the fuel pump, by contrast, within a neighboring, or adjacent energy market, has been completely different from what we see on that graph. We have seen different strategies play out. We see the competition in the market continuing in terms, of churn rate remaining at 19%. We remain third best in market, in terms of doing better than that, in terms of our own churn rate. We have seen consolidation in the telco market, with 2 degrees and -- focus merging and that provides, they're also slipping into the energy space as well. So the competition remains intense and our ability to compete depends on our ability to both control costs and innovate, as the team has certainly done over these last few years. There is a challenge in the go forward, which we'll talk to, in terms of network costs and transmission costs, are expected to increase substantially, with the resetting of the WAP for the industry. And also, as was highlighted in the BCG report, that the cost of transition, the additional connections required, will mean additional costs flowing forward. It's important as an industry that we face into that challenge going forward, particularly as inflation subsides. Which leads to, where we're sitting with the regulatory matters, as we see them to play with the change of government, we have seen a refocus. Security of supply remains top of mind, and is even more top of mind for the incoming government. It's important that we as an industry, continue to ensure that New Zealand has, continues to maintain one of the most reliable electricity supplies globally. We are paying attention to this, our investment in base load generation, Tauhara, GeoFuture and Te Huka 3, remain part of that story. We do see electricity price pressures in the go forward, as increased lines and transmission charges flow through, both to pay for the transition, but also reflecting the higher WACC. We continue to look after our vulnerable customers, and to help people step through that transition. Another part of that is giving households, the ability to control their energy costs, through those time of use products, which is very important. We saw Lake Onslow being put on the shelf or cancelled. We think that's the right solution, but that requires us as an industry to now step up, and come up with innovative solutions around how we can provide both the manifest, but also that dry year cover, which as I intimated before, may require commercial and industrial New Zealand, to be part of that solution. I've talked already at length about lines assets, regulation and investment. That additional investment is something that we need to, as an industry, turn our minds to. We are pleased with the incoming government's attention to Resource Management Act. The fast track for renewable projects we see is absolutely vital, and it's great to see that legislation introduced. And it's great to see a degree of pragmatism, about how we can achieve that. That, of course, is going to put the challenge back to the industry to actually step up to the mark and mature and deliver these projects. But it's a challenge that I think we're all up for. And on that, I'll hand over to Dorian to go through the results. Thank you, Dorian.

Thank you, Mike. So first up is, I'll mention a few topics that will come out as we go through the financial and operational performance and so any relevant market insights. So within our financials, we've got a $29 million positive before tax fair value adjustment, a bit of a mouthful, that relates to the AGS owner's contract provision. What's happened there is the actual expected inflation has come in lower, and therefore the escalation on the contract is going to be lower than we previously modelled, meaning the contract, becomes less onerous. And also, we're using thermal generation more than we anticipated, because of the course of the Tauhara delay. And again, whenever you're using thermal generation more, it makes the gas storage more valuable and the contract more valuable. So that reduction in the owner's contract provision shows up with a $29 million non-cash increase in our EBITDAF. We'll do what we did in the prior year. We strip that out of the numbers, when we talk to them, because it's a non-underlying topic and we refer to that as the underlying performance. Unfortunately, we do have $8 million of write-offs within these numbers. $4 million relates to some work that we've been doing, developing a new CRM solution. Our current system will be end of life in the next few years. The path we were going down, though, looks like less likely that we will actually go down that route and therefore you have to write-off the cost associated with that. So that's $4 million. The other $4 million relates to the Peaker breakdown GT22. Components of the Peaker haven't lasted as long as they were expected to, so you have to write-off the costs around that. There is a broader Peaker reliability topic, which we are looking to address. Some of the things that, we're looking to do around that, is replace the component paths more frequently, and actually changing how we operate them as well, which puts less stress on the assets. Both those things, we think will contribute, to improved reliability. They will come at an additional cost, though, because these are key assets supporting the energy system. We'll look to ensure that we recover those from the market. Those write-offs show up as OpEx, and you'll see that in the OpEx side, when we get to it. There's a further write-off, which we're likely to do at the full year. We don't have all the information yet, which is why we haven't been able to do it yet. It won't surprise you to do it with Tauhara. We've had that steam hammer event, which caused some damage, and we're also reworking the water handling system. No extra cash costs associated with that, because that was all covered in the $40 million increase in the project CapEx that we announced a few months back. But this is obviously adjusting our asset base accordingly. So you'll probably see something on that at the full year results. Our view is that Contact's retail tariff is sort of historically been at the lower end of the scale regarding market pricing. We've worked very hard, actually, over the last few years to close that gap, and you've seen that within our performance. The reason why we're working very hard on that is, because the industry is faced with a major headwind, which is those regulated increasing network costs that have been signaled by the Commerce Commission. Whenever you've got a major increase in pass-through costs, particularly to a consumer facing business that comes with risk, and it's important you don't go into that process with a tariff that's already discounted to the market. So that provides you a little bit of insight as to why we've been behaving the way we have been behaving. It's also one of the reasons why we've been keeping our retail load flat, because not only over the last few years has the retail channel been discounted, to more market-linked channels, which makes it less attractive for that reason, but also going forward we've seen more risk around it, because of that pass-through recovery that's, going to be required linked to those higher network costs. The EBITDAF performance, or underlying EBITDAF performance has been strong for the first half. We're expecting it to soften just a little bit in the second half, and that's as we've acquired generation to manage months, where we see there being more risks, for example, when the HVDC is down on an outage, or a gas-fueled outage, and also covering some of those Tauhara or whether those sellers that we thought were going to be backed by Tauhara volumes. But overall, we still see a strong result for the year with underlying EBITDA up from $600 million, which is what we previously guided to $620 million, and that's due to improved thermal efficiency and pricing. That's also net of those $8 million of write-off. So if you adjust for that, it's actually at $628 million. And Mike mentioned we've got a sort of increased confidence on our view of long-term pricing, so we're not actually changing our view when we say it's $110 to $120, 2024 terms, that's just adjusting the previous number that, we talked about for inflation over the last couple of years. So I should just remind everyone that the average spot price over the last 10 years was $103 so that sort of puts in context what we're talking about here. The reason why we're growing confidence, as Mike said, the increase in renewable bill cost doesn't seem to be just an impact of a COVID recovery and a few supply chain issues, it looks like it's here to stay. I mean, interestingly, when I entered the industry back in 2019, as a rule of thumb, people used to talk about geothermal costing $4 million a megawatt, wind costing $2 million a megawatt and solar costing $1 million a megawatt to develop and you guys, everyone knows what that's moved to now, so you can see the impact of the higher bill costs flowing through there, which obviously needs to be recovered in terms of wholesale pricing, otherwise people will stop building. So, we're also getting signals others believe have similar views to us, even if they don't say it publicly, you can see it based on the PPAs, they sign up, to and the investments they make, knowing that they need a price like we've suggested in order for them to be economic. So that gives us a bit of confidence around that price level. Last thing I'd say is, there's a lot of renewable development opportunity in the South Island, it's been constrained obviously over decades, because of the uncertainty around TY. If a long-term TY deal is announced, you'd expect FIDs to be announced on the back of that. Batteries will help with this, but it is important that transmission keeps up with the renewable build, we're blessed to have all of that resource, we just need to make sure we do it justice and ensure we can get it to where the demand is. So on to the financials, so the AGS owner's contract revenues have gone up here in the net profit, we've had an adverse impact of it of $86 million in the prior corresponding year and a favorable impact after tax of $19 million in the current year. Chart on the left back those out, so you can see our underlying net profit is up by $55 million, the biggest movement there is underlying EBITDAF, which is up by $68 million to $325 million. Chart on the right explains what's driving the year-on-year movement, so hydro inflows trusts have been pretty erratic, we've had extreme dries and extreme wets in the 6 months, but overall renewable volumes have been down by 91 gigs, which on a fuel replacement basis cost us $11 million. We guided to a step up in sales volumes of half a terawatt hour and that aligned to us anticipating that Tauhara was going to be online in Q4, 2023. We've had to back those sales by risk management and thermal fuel, obviously with Tauhara being delayed, so the impact of those sales volumes is minus $10 million. However, even though we had that delivery risk associated with Tauhara, it's important that our diversified asset portfolio and fuel mix allowed us to make those sales, because it gave us exposure to that $57 million increase in market channels and that's the repricing of short-term CFDs. Remember, the market pricing was very depressed in the prior corresponding period, because of all of that water that we had naturally. We've seen a $39 million improvement in our long-term channels and this is about the retail channel slowly repricing, getting closer to market pricing. $18 million improvement in our thermal generation efficiency. This is 2 topics driving this. Firstly, we've shut Te Rapa, which was our least efficient thermal plant and also, as Mike said, there's been less hydro in the system year-on-year, so we're stepping up our thermal to support the system, and as you will know, whenever you run those plants at high capacity factors, they're more efficient. Also the carbon intensity dropped, linked to that as well, 30% reduction, so good social topic there that was supporting energy security and a good environmental topic that we're doing it in the most sustainable way. Other income is down by $9 million. This is where we had $17 million of steam sales on the back of Te Rapa going to Fonterra, so they obviously don't have that anymore, but partly upsetting that we are making some risk management sales, backed by thermal generation to the market, and this is where the premium on that goes, and we've also seen improved margins on our retail adjacencies. Fixed costs, before those write-offs are up by $9 million. We've got a bit of inflation on gas storage and transmission and then some higher OpEx, which we'll talk to you later, and then obviously you've got those $8 million of write-offs. So that explains EBITDAF, back to net profit depreciations coming $15 million higher. That reflects the higher cost of thermal, you know, if we're replacing components of the thermal asset more frequently, there's a higher depreciation charge associated with that. Interest, it's dropped a little bit. Remember all of the interest expense associated with debt to build all of our renewables gets capitalized, until the projects come online. Taxes higher, reflecting higher profits and the fair value of financial instruments, always a complicated one, that's shifted favorably $22 million. Really happy about this. Remember we had some discussions at the full year about our market making. This is where market making goes. They've leveraged technology and process improvements and actually beaten our expectations on that. So that's largely driven by improvements in realized and unrealized market making gains. In terms of our EBITDAF or underlying EBITDAF across our 3 segments, you can see wholesale is up by $75 million. Retail has moved from $1 million to minus $1 million, which doesn't sound like a big thing, but then we look at what's in the middle there and all the effort that goes into recovering $45 million of higher energy transmission and network costs, the judgment that's involved in ensuring it's done in a fair way and also managing risk to maintain a low level of customer churn. So great performance there, I'd say, for our retail business. And in terms of the corporate costs, they're up driven by some higher OpEx, which we'll talk about when we get into the OpEx section. So just onto the wholesale business, we're expecting a big increase in sales back from thermal fuel and risk management. Our generation costs are up by $67 million -- that is $59 million and that's linked to the risk management of thermal fuel. This is where you actually see the adverse impact of the Tauhara delay coming through, because had Tauhara been online, those sales would have been backed, or some of those sales at least would have been backed by geothermal fuel at a marginal cost of $5 a megawatt hour, as opposed to thermal fuel at a cost of $96 dollars a megawatt hour. The remaining $8 million of the increase is that $4 million write-off linked to the Peaker, and then some cost inflation on our fixed costs. Just to talk a second about our actual assets. So hydro performance has been good. The only outage of note in the second half of the year, has been cleverly aligned to the HVDC outage. We've also got the last of those 2 transformers that are being replaced at Clyde showing up, but that's until January 2025, so no impact on this financial year. We've got our 4 turbines that we're replacing down at Roxburgh, so that ultimately will have an extra 45 gig hours of generation. That process is starting in May with 1 turbine replaced every 6 months. Big news on geothermal business as usual, geothermal, I should say, was that re-consenting of Wairakei that we announced last year, and the extra fuel associated with that. Just to double down on what Mike said so people don't miss it. So we've sort of formally said that, based on our current geothermal footprint generation, will go up from 3.25 to 3.3 terawatt hours a year now, and that's before Tauhara and Te Huka 3. That's very valuable for us, because minimal investments and ongoing costs are required to deliver extra 50 gigawatt hours of baseload renewable generation for the country. Regarding thermal, we talked about peak reliability issues, what we're doing to deal with that. Some good news on TCC, we were able to take advantage of the weather conditions and retime the radix repair. So we did that in the first half of the year, so TCC is up and running and available for HVDC outage, and also GE signed off the extra 2,500 hours. So we've now got a run TCC baseload for 7 months for this calendar year, which hopefully won't be required. From a wholesale contracted revenue perspective, it's up by $126 million, volumes up by 529 gigawatt hours, and pricing has the line to market conditions. Biggest topic is around our CFD revenues and volumes, which were up $116 million and 697 gigawatt hours respectively. As I've said previously, we went into the financial year expecting Tauhara to be online in Q4, 2023, and therefore we contracted up load, to manage price risk. We also had some legacy strategic fixed price sales that were coming up to end of contract, and rather than recontract them, we actually moved them in 121 gigawatt hours into short-term CFDs, in order to get a market price for those. So that explains the overall volume change. The channel repriced up by $32 a megawatt hour to $140 a megawatt hour. Remember, that's what I said earlier, prices were depressed in the prior corresponding period, because of all the water that we had across the country. C&I revenue was down $6 million to manage fuel risk, when we found out about Tauhara, we stopped selling through this channel, so you can see volumes dropped off a little bit. Prices did improve, but not as much as we've guided to, and that reflects if you're not in the market repricing and recontracting, you can't get your price up. Interestingly, if you adjust for load shape, the net back on this channel has now dropped below retail, so we do see an opportunity in the second half of the year, to price that channel up. In terms of sales to the retail business, up by $39 million. Remember, we hold volume flat, for strategic reasons that I outlined earlier. This is all about the transfer price passing on those higher market costs, and the good news is the retail business is listening and it's adjusting its tariffs accordingly. Steam revenue is up by $17 million, sorry, it's down by $17 million. That relates to the Te Rapa steam sales to Fonterra. Just to say that relative to the counterfactual of keeping Te Rapa open, we're in a better financial position. We may well have lost those steam sales, but we've got improved thermal efficiency, less fixed costs, less stay in business, CapEx, and of course, you've got those reduction in Scope 1 emissions too. Other income is minus $4 million, and that reflects the regions that we're making by selling some risk management products to the market. Wholesale trading and merchant revenue delivered 0, which is how we like it. That's merchant revenue offsetting location losses, and that's as per our guidance. We had a loss in the prior year, but there was those unusual situations, because of all the hydrology impact that has on location losses and merchant length pricing. The retail business, it's good to see the EBITDAF from this business only dropped to a $1 million loss. This reflects that tariffs have been catching up, to the changes in the wholesale market process. As Mike said earlier, one of the things that we had been doing is, have been smoothing out the effects of that rapid change in the wholesale market costs to consumers by only increasing pricing aligned to the level of CPI. Obviously, we've got a bit of a tailwind with the escalations of CPI, meaning we've closed that gap now and getting closer back to profitability, which is good. Obviously, very mindful of the impact of higher prices on consumers, which is why it's great that 21% of all of our retail customers now are on time of use tariffs, because that gives them the ability to ship their load from peak to off-peak and save some money to offset that tariff increase. Obviously, it's good for the environment as well because off-peak electricity is less carbon intensive. Overall, our electricity tariffs are up about 8%, which reflects roughly what the CPI environment would have been at the time of those price increases being tabled. Pleasingly, we've held our customer numbers relatively flat through a period of relatively high price increases for us, and I think that talks about the types of products we've got in the marketplace, which seems to be resonating with consumers. That's our good nights and our good weekend products, for example. I've said previously that our tariffs have been lower generally than other retailers. I now believe we've actually caught up, and that's good because, as I said earlier, we're about to see this period of higher regulated network costs. The assumption is that these are pass-through costs, but the magnitude of the increase that's been signaled by the Commerce Commission, if they are to be pass-through, it will likely lead to tariff increases, to consumers for quite a number of years above the level of CPI, which obviously carries some risk. Just to put some context to this -- what a consumer pays, about 50% of what they pay goes to the network companies and the associated transmission. So whatever the Commerce Commission signs off, whatever percentage they sign off, you divide that by 2, and that's what would need to be pass-through in terms of a higher tariff to fully pass that through to consumers. They have used things like price shock caps before at 10%, not suggesting they'll use it this time, but if you did use that as an example of a 10% price shock cap plus inflation at 2%, then that would need a consumer pricing increase of 6% every year for the next 5 years to recover that, and that's before you consider the inflation on cost to serve, or energy. So it just puts into context the sort of risk around this. Gas margins have improved from $3 million to $10 million. It's good to get this back to a more sustainable level of performance. We're actually now at $20 gigajoule, that's the net price we're getting on retailing gas, which is the same value we could get, if you put the gas through a peaker and sold it into the wholesale market, which is good. Broadband margins are up from $4 million to $5 million. That reflects that our average number of connections across the year is up by 19%. I did talk about a little bit of under-recovery of the local fiber company costs in FY '23. We've caught that up a bit, so you can see a little bit of margin expansion in this product. And cost to serve is up by $2 million. We've invested a bit of money in advertising and promotion, linked to the launch, as Mike said, of our new mobile product, but also create more awareness around time-reduced products. And we have seen a bit of an increase in bad debt. I suspect a lot of businesses will be saying that, linked to the external environment we're in. But it is being well managed. And overall, our cost to serve per connection will continue to be the standout within the industry in terms of efficiency. But on to OpEx at a Contact level, $133 million. That does include those $8 million of write-offs that I mentioned. There was also $3 million of one-timers in the prior year numbers, just to be transparent. So that was the retention of staff at Te Rapa, ahead of that plant closing, and some consulting costs. So recurring OpEx has gone up from $115 million to $124 million, which is 8% or a $9 million increase. The biggest component of that increase is inflation within the base business, up by $6 million. Still got wage and salaries going up by 5%. You've still got insurance going up at significantly higher than CPI, and flowing through there. We are going through the renewal process for insurance. I'm sort of hoping that we've seen the last of it in terms of big insurance cost increases. We've also had some headwinds. I mentioned the bad debt increases. We've also got the tail end of the repairs associated with Cyclone Gabriel. But those headwinds have been offset by improved productivity, in particular in the retail business, which continues to leverage fixed costs, as we grow our number of connections. We've invested $3 million in what I've called growth and sustainability. We sort of guided to this with the FY '24 performance, when we did the full year FY '23 result. This is about continuing to fund retail connections, investing in finance procurement, sustainability, corporate reputation. All of these things are important, for example, to ensure that we can deal with things like unrelated exposures. It ensures that for our stakeholders, we can tell our ESG story just as well as our financial story. I'm already getting good feedback on that, Mike mentioned earlier. Not only are we in the Dow Jones Sustainability Index, we're New Zealand's #1 ranked company within that index. I said it before, but I see this as being the last year that we're investing from an OpEx perspective in growth and sustainability. I see us, by the time we get to this year, we'll be right-sized for growth and the additional compliance that comes with ESG. In terms of our operating free cash flow, $187 million. That's a cash conversion of our EBITDAF of 58%. That's a very strong performance, because we have a number of cash outflows that are heavily weighted to the first half of the year, such as tax, and also we buy all of our carbon units. One of the reasons why the performance was so strong is EBITDAF is up, and a lot of our cash -- topics in our cash flow, like stay in business, CapEx, for example, don't flex up with higher EBITDAF. So therefore, the marginal operating free cash flow you get on that extra EBITDAF is a very high percentage. Just a reminder, the prior corresponding period isn't a good comparison. Cash conversion and cash flow was very low, and that was a function of depressed wholesale prices, the effect that had on EBITDAF, but also very little thermal generation was run, but our inventory went up, because you've still got the contracts in place, to buy the natural gas and the carbon. For the full year, we're expecting a cash conversion -- operating free cash flow conversion of EBITDAF of above 60%. Remember, 60% is a normal performance score for us. Our debt levels continue to increase, as we sort of highlighted at Te Huka 3. We entered the Australian bond market in November of last year, with a $400 million issuance. It provides more diversification to our funding sources, which is always good. It helped continue to support our renewable builds program, and also refinance the maturing USPP facility. We, like everyone else, have seen an increase in floating rates, but pleasingly our average interest rates only got up by 20 basis points to 6%. What's happened here is we've entered into fixed interest rate hedging in a lower interest environment. We did that in anticipation of our debt levels going up linked to our renewable build program. That actually means that our fixed interest rates are actually dropping as our debt levels are going up and that's offsetting some of the big increase in floating rates. Based on the market as I see it today, and the hedging we've got in place, I wouldn't expect our interest rates to go much above where they are today. But a caveat that far smarter people than me make a living out of strongly, predicting interest rates. In terms of funding our renewable development pipeline, we like others, have seen an increase in the cost of building renewables. As you'd expect, the wholesale price has adjusted accordingly. So since as the long run marginal cost of building renewables goes up, that feeds into highest wholesale prices. If it didn't, people would stop building renewables, because it wouldn't be economically viable. So returns are protected in that regard. It does create a short-term financing topic, because obviously CapEx is high, but we're comfortable with the levers that we've got available to us, like our dividend reinvestment and balance sheet as the hybrids that we can cover that. And that chart sets out why. In terms of dividend, you will have noticed that the Te Huka hasn't landed yet. And also, we're not expecting Tauhara online until Q3, 2024. So as we had guided to, we keep the dividend constant at $0.35 per share for the year, with the first interim dividend being declared at $0.14 per share, which will be 86%, computed for qualifying shareholders. We will, of course, look at the final dividend based on any changes within the environment, Tauhara and TY and things like that, and make a decision on that in due course. We continue with our undiscounted dividend reinvestment program. One, it's a good news is we're actually bringing the dividend payment forward 2 weeks. We've had a, for whatever reason, we tended to have a long drawn out dividend payment process. We're now condensing that -- and the payment goes out 2 weeks earlier, which brings us more in line to what normal practice is. But I suspect shareholders will be happy about that. And then this is just about our guidance. So we put out guidance, mean hydro guidance, of getting $620 million. And we've increased that to $620 million. I won't go through the half year topics, because we've already covered those. But what we're expecting in the second half of the year is, whilst we continue to see improvements in terms of thermal efficiency in the second half of the year that, benefit relative to our previous guidance is offset, by the fact that we've acquired more risk management. And so, therefore, those 2 things net off. So you get no further benefit in the second half of the year from that. We do see some price improvement in the second half of the year. What happened in the first half of the year is we saw improved relative to guidance retail tariffs, but it was offset by lower than guided pricing across market facing channels. We're expecting market facing channels to improve, and the retail above guided amounts to continue. And that gives you that $18 million upside in the second half of the year. I talked about that Tauhara write-off its non-cash. I haven't included that in here, but obviously whatever happens there will come off our EBITDAF. Just to say, I mean, there's a lot of work that's gone into adjusting for the Tauhara today. I think it sort of demonstrates the resilience of our business that, we're able to put out a first half of the year performance like this, and then also in a position, to update our guidance for the full year when we're mitigating -- the loss of that or the deferral of that fuel. There is obviously, the usual risks that go with going forward. We've got obviously this assumes you need hydro. The higher risk months are things like the months when you've got the HVDC outage happening in coal, for a gas fuel outage happening. And obviously when you get into winter, but we believe we've mitigated those well. And if you've had a chance to look at our January operating stats, we've started the second half of the year very well. So on this slide, I wasn't going to talk about this. This basically sets out what you'll see from us, for the rest of this part of the year. You'll be familiar with all the topics. There's a lot going on. The real reason of actually having this in is you can then hold us accountable, to delivering on that, which is important.

And with that, I'm happy to take questions.

So we're going to take questions on the line, on the phone first. Grant Swanepoel. Grant, are you wanting to start your questions? I think you've been admitted.

Can you hear me?

Yes.

Yes.

Okay. Sorry, there's a bit of a delay between the presentation and the call. So in case you're surprised a bit. Just a few questions quickly. Just on Tauhara, on your op stats, you were showing that you expected to be at 100% and those rounding errors there and you're only at 99%. Is there a little bit of delay within that 3 months to end of September we should be worried about?

No, at this stage, we've largely completed the reconstruction of the necessary modifications of the steam plant. And we expect to recommence commissioning roughly by about the middle of March. So -- we're still confident around that in the date, yes.

Perfect. And then your dividend, you were talking a little while back that if Rio had confirmed a changed contract, a bit more confidence, you would potentially up that dividend payout ratio this year. Does your outlook for comfortably holding your net debt ratios take into account a higher dividend, and would you still be considering a higher dividend at the end of this year, if Rio did confirm a contract before then?

Yes and yes.

Yes and yes. We've been very consistent on that messaging.

Can you just give a bit more color on the Ahuroa storage issue? You wrote down $120 million a year ago and now $29 million right back. Should we continue to be expecting write-backs until that contract expires?

Yes, I mean, that's the problem. It is quite volatile around this because some of the key things that sort of impact the value of that provision of things like the discount rate you use, which is linked to the 10-year treasury, it's the inflation, PPI, which is the escalation on the contract. And unfortunately, things like in treasuries and inflation rates at the moment, Grant as you know, are very volatile, which is why we're seeing this move around a bit. The other thing that moves it around is the amount that we use thermal generation. And if we step up the use of thermal generation, which we have done because of the Tauhara delay, that makes the facility more valuable for us at storage and therefore reduces the onerous contract provision. Once TCC is shut and our thermal generation drops to just a couple of Peakers, which would be, I don't know, 200 gigs a year, the volatility linked to thermal generation going up and down will reduce quite considerably, but you will still have volatility due to inflation and interest rates. Unfortunately, it's not -- it wasn't a great time to make an onerous contract provision. If it had been done sort of 5 years ago, when we had more benign interest rates and inflation, the provision would have barely moved.

And then just your organic earnings have been absolutely stonking. $638 million if you add back the hydro $10 million and the write-down, or write-off, sorry. Could we have even considered another $10 million or $20 million if you hadn't sold towards Tauhara contracts?

No, I don't -- they were beneficial to us, Grant, because of the fact that they gave us access to the repricing of the CFD. So whilst on the chart I showed it as being negative because they were backed by thermal fuel, the way I calculated that is I applied last year's CFD pricing to that, and then you get the uplift in the market pricing on that volume, which is within the $57 million. So overall, it's definitely financially beneficial for us to have sold those volumes.

Okay. So what you're saying is you've hedged that out pretty successfully to not negatively impact the EBITDA?

Yes.

And my final question is more a macro question on your $110 to $120 long-run marginal cost now. With Rio potentially coming on -- ratifying a deal, call it in the next few months, does this not put us at risk of a massive overbuild as not just yourselves, but everyone in [indiscernible] is now looking to build some renewable into a space that actually isn't seeing demand grow, to the extent that you would like to see it? And then also, can you talk to government's policy of using carbon tax as a driver of carbon conversion, and not using a giddy fund type tool anymore?

I think twofold. There's always a risk of under-build or overbuild. The requirement, I think was in the order of one large-scale wind farm every year for the next decade and we're nowhere near that at the moment. And I think as I intimated at the beginning of the presentation, is that we're seeing the demand growth start to kick up now, certainly in the retail market at a, per ICP and the number of ICPs of population growth. And on top of that, you're starting to see the industrial conversion. So there is always a risk of overbuild as there is always a risk of under-build, which -- that's why we're in this market. The second part of that is we do actually see some very positive signs on the demand growth, particularly if the TY deal lands. So we're comfortable with that risk.

Yes. And in terms of your spot on around, we're expecting carbon prices to escalate with that being the new government's mechanism to drive de-carbonization as opposed to providing subsidies like the previous government has been doing. We're still in a bit of a state of flux around that as to where that goes. You haven't seen -- you're still waiting for the old process to sort of clear before the new one kicks in. I was just checking actually carbon prices have dropped a bit in the U.K. and Europe as well. But even relative to those you're still with -- the New Zealand carbon price still looks relatively cheap. So we're expecting carbon prices to go up quite considerably over the next few years, which will be the mechanism to decarbonize.

Now we'll go to questions in the room.

And I have a couple of questions. First of all, I guess just following on around that $110 to $120, certainly you can see what's going on in the wind space and then doesn't look like those turbine prices are getting down particularly quickly. But the solar space is quite different. So can you just sort of talk to what you expect, I guess, solar prices to do and why they may not impact correctly on that long-term price which is what you're indicating?

I think for New Zealand, solar was always going to be a niche application. It has an attraction in the speed of deployment. And certainly there is always downward pressure on the cost of, for instance, panels, but the reality is, is that for any project there is always a balance of plant which is subject to the same inflationary pressures which we're seeing on geothermal and which we've seen on wind. Those balance of plant costs are endemic to New Zealand and they were put up with pressure on solar prices. The other thing about solar, as I said, it's niche. It will not play an overly significant role in the market in the longer term. And it more than anything needs significant firming where we only see upward cost pressures. So at best, the capacity factors you see in solar are between, let's say, 18% to 25% in this country. Something needs to firm it, for the other 75% of the time.

Okay. And next question, I guess was just around what you're seeing longer term, I guess, for your expectations on the C&I and mass market pricing relative to what the current ASX is. So I guess you're indicating second half, you still got some more increases to go through. And the fact that your retail profitability is basically zero suggests there's more to go on the mass market side as well. How far away though are we I guess, from these prices actually catching up to what the long day-to-day ASX curve is?

Well, as the outer periods in the ASX curve come in, we do see a tailing off in the outer years of the ASX at the moment. But of course, you get events like Ukraine suddenly that gets tipped up overnight. And so that's why we maintain that very long-term view of pricing. But of course, the ASX captures those near-term risks which just continue to surprise us all.

Okay. And next question I just had really was just around an update on the tender process that you did back in September actually, and how that's going and when we might hear something on that.

On the CFDs.

Yes.

We've got one that we're looking at this, my understanding. Obviously, the other topic that sort of -- that was done pre the delay of Tauhara. So then we had to adjust. We had less fuel to sell, so we sort of adjusted for that. My understanding is, we are following through with one of the proposals that was put to us.

Okay. And last question again, I think you alluded to it really on the January op stats were very strong and I think rolling 12 month EBITDAF I've got as circa sort of 660-ish. Can't remember the exact number, but it's sort of in that sort of order. So you still got, I guess, looks like quite significant headwind you're expecting to come through in the later months. Where is your degree of conservatism built in?

I wouldn't like to say that. I mean, it's -- a month, you can change very, very quickly. The numbers that we put together were before the January result. So in terms of context, that helps understand a little bit more. But yes, it's -- as I said, there is, we have got more acquired generation and at a higher price in the second half of the year, which does offset some of that benefits we get in the first half.

Right. A few questions. I'm just going to scratch a little bit at $110, $120 question as well?

Yes.

Different angle this time. I'm presuming you're giving us sort of a base load, a GWAP rise at Otahuhu?

Yes.

Obviously, there are lot of generation options being bought about in the South Island, and we see a very large spread between the North and South Island. What do you think the equivalent price is in the South Island?

Well, I should just say we're a buyer of the South. Yes, there is a current spread, which tells us that people are assuming there's going to be a lot of renewables built down there. And I think they don't believe the demand story as much. We do believe the demand story and we -- you do need a higher price of carbon, but we think that will come. But there's enough examples that we've got now with the Fonterra process that's going on. I mean, you go through other market participants and their investor presentations and they talk about all of the process heat conversions that they've done in the South Island. A lot of that still needs to come online, because a lot of it's to do with these boiler conversions, which takes time to operationalize. And then obviously, you don't need all of the -- you can still have more demand coming on the North Island, which will ultimately support the actual prices as well, which you can see through data centers. The electric arc furnace looks positive, and I think actually they've got more scratch steel than expected. So there's opportunities around that with New Zealand Steel. So we see a lot of stuff which gives us comfort that the demand growth is going to happen. But I caveat that we would like to see the carbon price escalate quicker. And I think that will happen as well. It's the -- if it doesn't, then -- and then we're going to struggle to hit our carbon reduction targets as a country, which isn't a option that anyone wants to consider. So I think everyone will do what's required and therefore -- and renewable energy therefore grows accordingly.

So to just follow-on to that. So confirming that basically your thinking is that you don't see that basis spread shrink over time. When you say $110 to $120, are you thinking nationally?

Yes, we base it on Otahuhu, but we do see that spread shrinking a bit over time.

And in terms of the carbon price, what kind of number do you have in mind?

I'm expecting it to escalate rapidly over the next sort of 5 years.

$100, $150.

$130, that sort of price that we see is required to get sort of economic-based switching, now that you don't have corporate welfare, if you like, supporting merchants.

Great. You mentioned with the Stratford units sort of changing perhaps their operating model, and putting more work into them [indiscernible] how should we think now about the annual operating costs and annual OpEx of those units?

It's more about changing the modus operandi, where we slightly restrict their output and we don't ramp them up. We've been ramping them up perhaps faster than we needed to. It's changing the operating, so the operating cost, we're not expecting an impact on the operating cost per se.

It might be and there might be an impact on, say, this is CapEx we need to work that through, but not in OpEx. And as Mike says, it's more around actually the GWAPs that you get from dispatching. Peakers might drop a little bit, because you're not operating quite as flexibly. You might lose some auxiliary income because you're not in the frequency keeping market, or that sort of stuff. So they're the sort of topics.

And what kind of ramp rate changes are we talking about, sort of the…

It's just when you come into a half hour period, we may have gone without going into too much detail. We may come up just a bit quick. We can ramp it up a bit slower than what we'd like.

Okay. Yes. Great. We're coming into a winter that, those that prognosticate about the market are very worried about. How should -- what's your view on how winter 2024 is going to look? What should we -- what should investors be looking for through this period?

I think it obviously -- you're subject to the vagaries of the asset base of the market, but we are very comfortable, for instance, with how TCC has performed. We consider we have gas, we have the extension in hours. GT22 is coming back. And so we're as ready as we can be. We're taking advantage of the HVDC outage to get some critical work done down south. And our geothermal plant is in good shape. So we're confident that we've done everything we can.

There tends to be an industry worry about every winter, which means everything goes fine.

That's good. Last one for me then is looking beyond next year or beyond this year. TCC gone, you've got 2 Peakers. Start to think about how to cover dry winters. You've also had your competitor talking about biomass units. Would you participate in a tender if they can somehow make that sort of scheme available? Would you think about buying something?

We always give a consideration. We're an active market participant. Previous tenders that have happened, we have actively considered, if not dissipated, so yes.

We'll go to the online questions. We have a few here from Stephen Hudson. One is just, is the current channel pricing of 140 to 150 megawatt hour been adjusted for shape and location, pretty much at your long-term wholesale price view, or is there more to come?

Remarkably it is, Stephen, so obviously as inflation goes up, it's a real-term price guidance that we've given, and so it allows for future increases in budget not much.

This is on Tauhara. What are the milestones or the timeframe for the last 22 megawatts at Tauhara?

The last 22 megawatts, once we've started it up and done the process testing and got an assessment of where the capacity is actually sitting, is going back in and doing some final piping modifications to debottleneck the identified bottlenecks. So the ultimate is that we have to shut down after 1 year from a statutory point of view. That's when you'd have any necessary modifications in place, 2025.

Next one. You don't have a comment in the slide pack around your full-year trailing operating cash flow payout policy. Is this dividend basis under review after [ ANZUS ], or will you just think about where in the existing 80% to 100% range you will move to?

I was going to -- no, we don't, at the half yearly, we don't generally comment on that. It's a full year thing. But no, the dividend policy is staying, as it is at the moment. And as we said earlier, we will adjust that accordingly as market risk changes, such as the TY deal, and also as more volume comes online, such as Tauhara and Te Huka 3. So Stephen, no change in that regard.

Last one from Stephen. Do you think that falling PV prices recently have had anything to do with the largest buyer in the world, the U.S., banning purchases from the largest seller, China, due to the 2022-23 forced labor-based import bans?

Stephen, like you, I'm in the world of speculation. Probably yes.

This one is now from Vignesh Nair at UBS. A 2-year build timeframe for GeoFuture from FID seems ambitious, given Tauhara has taken 3.5 years. Can you give some color on how much easier the design site work required and build process is for GeoFuture versus Tauhara?

I think the answer to that is it's not easier. It's not going to be easier. We've done a whole lot more work upfront. And so remember, pre-FID expenditure, we've estimated in excess of $100 million. We've already spent $30 million. We're actively drilling ahead of FID. We're doing a lot more front-end design. So that gives us much more confidence in that 24 to 30 month delivery.

Okay. And the second question from Vignesh is, you talked about incremental increases in EBITDAF lifting the operating free cash flow meaningfully, higher than 60% conversion. Can we assume that the increase in guidance for FY '24 should make its way to the DPS for FY '24 or is a revised dividend policy likely to impact FY '25 and beyond?

I think we answered that with Stephen's question, is that dividend policy at this stage remains as it is. And the guidance remains as it is.

That's all. Thank you. Looks like we have finished with our online questions. No more questions today. So with that, we'll draw this to a close. Thank you.

Thank you. Thank you, everyone.

Thank you.