Hi there, everybody, and welcome to the Mercury Interim Results call. I'm joined by William Meek, our Chief Financial Officer, and we'll proceed on through the presentation now. Going to our first major slide on slide three there, I guess the message here is that the investment in increased scale and our higher generation has driven the results. It's been an incredibly wet year. Our hydro generation has been up 45%. Not only that, in order to stay within operating constraints for our resource consents, we've seen 675 GWh of spill. That message around scale lifting earnings is really important. We're seeing the benefits of new wind generation coming from Turitea, from the north section and from the ex-Tilt wind farms. If you add that with the Trustpower retail acquisition, and the additional generation through hydrology, that's moved EBITDA from NZD 242 million in the comparable period prior year to NZD 451 million. New generation still coming on stream. Turitea South, we will start to see commissioning occurring in April. Kaiwera Downs Stage 1, we expect to see that completed and operational in October 2023. Looking at our pipeline, three of our four consented wind farms are proceeding through the process towards final investment decision, those being Kaiwera Downs Stage 2, and Puketoi. We have real options coming through in that pipeline. Turning to the customer business, we're all very aware of the situation that occurred through both Cyclone Hale and Cyclone Gabrielle. That in parallel with our approach to vulnerable customers, has been incredibly important. I will talk about that a bit later in this presentation, because we're really focused on how we do the right thing by all of our customers, and particularly those that have been impacted by the weather. ICP churn at 17% across the brands, we're reasonably happy with, and we're particularly happy that we have started gaining new connections over the first half of 2023. Also noting that those 14,000 don't include the Now business. Of course, we have the integration of Trustpower to work through, and we're pleased to say that we now expect to be able to do a mass market customer transition onto the Gentrack platform in the middle of this calendar year. That will start the process of us centralizing onto a single technology stack, which is an important step in the process. We continue to focus on our culture. We continue to focus on health and safety and how we build a stronger, safer organization. Our dividends, as previously signaled, NZD 0.087 interim, 9% higher than previously. The DRP being continued and our ordinary dividend guidance for the full year up 9% at NZD 0.218 per share. We've retained guidance unchanged at NZD 795 million, largely driven by the fact that the hydro generation uplift is reducing the generating weighted average price. We'll go into that in a bit more detail as required. Integration spend for the retail integration coming forward as we progress faster than expected, stay in business CapEx down NZD 30 million. That's the overview. I'm gonna pass to William to talk to the next couple of slides in terms of financial performance. Thank you, Vince, and a warm welcome to our investors on the call. We're on slide four, I'll just take us through some of the key financial highlights of the year. As Vince said, our investment in scale has certainly made a difference to this year's results. We've seen full years of Turitea North Wind F arm production. The ex-Tilt wind farms have also got a full period of generation. Obviously the addition of the Trustpower retail business, again, a full six months contribution. They are certainly lifting earnings relative to the prior comparable period. Also very wet conditions across the Waikato catchment. To put that in perspective, we were up 45% on what we generated in the half year 2022. Over 850 GWh more hydro generation. It's been the wettest half year in Mercury's history, and certainly since records began. I did have a look back, and if you go right back to the mid-nineties, actually, ECNZ actually generated a little bit more than we saw this year, almost hitting 3,000 GWh, but they were running the entire grid at that point. It's certainly been very wet and we'll explore that a little bit further. We're pleased to see actually increases in generation output across the three fuel types in the fleet. Geo was up 19 GWh and wind up over 200 GWh in the year. We saw an overall 29% increase in generation, which is certainly assisting the great result we present today. If you look at the bar chart here, some of these bars actually look like almost full financial year results for a half year. We're actually very close printing an EBITDA of NZD 451 million to our FY21 result, which was just NZD 463 million. Again, testament to that increased scale and the investment in that, and also the increased generation market share. NPAT is down 46% versus the half year. That half year did include a significant gain on sale related to the sale of our interest in Tilt Renewables. That explains the reduction in NPAT by almost NZD 200 million. Operating expenses do reflect the again, the increase in scale due to the additional Trustpower and more wind-related operating costs. We certainly are seeing inflation pressures emerging within the business, that is feeding through. We'll talk a little bit more about that later. On a second half 2023 basis, we expect OpEx to track at around NZD 190 million versus NZD 160 for first half. A backloading of costs, lastly due to retail integration, driving that change. Same business CapEx is still relatively historically low. We're still sitting at NZD 31 million level up on where we were in the PCP. Again, that's lastly driven by preparatory drilling costs. Really gearing up for that significant NZD 120 million drilling program across our geothermal fields, kicking off pretty much now. Growth CapEx mostly due to CapEx at Kaiwera Downs, the Now Broadband acquisition and a little bit at Turitea. There is an additional slide in, on slide 23, just detailing some of the accounting treatment for our acquired swaps, which is slightly different. We won't be, we won't need to have a normalized EBITDA now. The EBITDA will reflect the fair value movements of those derivatives acquired with the Manawa hedge, Norske Skog, and the Waipipi CFD with Genesis. As said, the record wet certainly in that investment has lifted the earnings. Our bridge really explained by probably some key building blocks. NZD 130 million added from more than 1,000 GWh of additional generation. Sales yields, we saw methanol market yields lift only about 2.5% against PCP across all our brands. That NZD 26 million uplift is largely driven by C&I as contracts mature and reprice against an elevated forward curve. That NZD 26 million also includes yields from derivatives with end users or industrial customers. Trustpower added NZD 30 million EBITDA for the half year. Our non-customer derivatives were up NZD 22 million. Ancillaries down, adverse, at NZD 6 million. The acquired swaps is really a prior period adjustment that relates to the Norske Skog CFD termination in the prior period, which is non-recurring. That NZD 54 million cash termination fee was paid and recognized in EBITDA last year, so depressed half year 2022. We had a NZD 14 million derivative unwind also, giving a net NZD 50 million. Costs up NZD 21 million, largely due to scale increase. Saw a change in other income relating to less income received on the Tilt investment, so it was dividend. Gives us a bridge to NZD 451 million from last year's NZD 242 million. Back to me with health and safety. Look, health and safety from our perspective is absolutely the key to better performance in the organization. We have put a lot of effort into and continue to put a lot of effort into improving our systems and building a more mature health and safety culture. That has been, I think, very much instrumental in making health and safety much more about the way we do business rather than a thing added to the business. We're still working through the WorkSafe health and safety charges as a result of the steam hammer event at Rotokawa. Those conversations are well advanced. In parallel to that, we're doing a lot of work on safety-critical elements, which are an important part of the safety case for our major hazard facilities. Overall, our performance is pleasing. As I always say in these presentations, there is always risk, and it's managing those risks, to avoid harm to our staff and the public that's critically important. Hand back to William to talk about market insights. We're on slide seven now. Really want to talk about spot prices. There's some familiar scatter plots here, which I'll talk to. The first on the left, Plots monthly spot price in Auckland against how storage is deviating from mean for that time of year. We really can see a step change in recent years, really probably on the back of the Pohokura outage back in late calendar 2018, where we saw effectively thermal fuels rise and probably exacerbated further with coal prices and carbon lifting since that time also. We're seeing absolutely higher prices when storage is below average and prices still higher than where they were trending earlier, middle of last decade, again, reflecting those higher prices. I think the second plot really plots monthly price against the spot gas price average for the month. We see quite a wide range. While we can certainly see a trend from rising from left to right, the correlation is certainly probably getting worse. I think the influence of gas is waning. We certainly have seen quite reasonable constraints in the gas market. Gas plants have become more like hydros, where they're looking to allocate this gas fuel across the year. We're becoming increasingly reliant on coal, which will take us to the next slide. This switches really to forward prices. The tidal electricity forward price reflects coal and carbon prices. Some probably... I'll probably start with the bottom right chart that details the three-year average forward futures price. This has been pushed by six months. That ignores the effects of hydrology. Hydrology, whether it's dry or wet, certainly influences the front end of the forward curve. The back end is certainly less influenced by short-term hydrology impact. We can see a very clear rising trend in futures prices. If we start at the start of that chart, we're sitting at about NZD 100 a megawatt hour. That is for the three-year period, as the note says, from January 2021 to December 2023. Back then we were sitting at NZD 100, a good proxy for what you might be buying or hedging energy for over the medium term, and now we're sitting almost at NZD 200. It really drives to carbon prices rising, which is the bottom left chart, and then coal price also rising, though we have seen some reasonable declines in price in recent months. What you can see certainly is in the hydro chart, the range, and certainly, we'll come to this, quite wet periods where the Taupō lake levels or the national lake levels have been relatively high and remain so well above average for the last six months. Just some comments there. Forward prices do reflect the market view of marginal generation costs through time and the volatility. They are heavily influenced by the likelihood of coal generation setting prices, which is why we're seeing quite a gap between short-term spot prices and forward prices. Forward prices are affected by retail energy intermittency. Obviously as we push towards more renewables, the trilemma around balancing affordability, renewability, and reliability is front of mind. How often those more expensive generation sources set prices is probably more important than the levelized cost of energy, we can focus on in terms of what it costs to install a new solar system or a new wind farm. Moving to slide nine, just focusing on the Taupō catchment. If we look at the chart here, the blue shaded area shows the range of lake levels from high to low over the last 20+ years. You can certainly see from the yellow line, we've been setting some new upper limits. We did press through just the maximum control limit under our consent at 357.25 meters above sea level back in late January, early February for about a week by a couple of centimeters. It's certainly been very, very wet. You can see the generation delta against mean. Every single month, we've generated above what we'd expect on an average year. Inflows have been even higher. We spilled 675 GWh of water. Put that into perspective, we generated 2,735. It's about a quarter of what we generated was well, actually spilled down the river. Spot prices, very subdued, really falling pretty much over that half year period, and ending at a whopping NZD 19 in December. Certainly, lots of generation going out, but at very low prices at that time. Hand over to Vince. On slide 10, we look at some of the impacts of Trustpower retail acquisition and our sales in general. The top left chart shows mass market growth, which obviously includes the Trustpower retail coming in. That gives us connections up at 580,000. We've seen connection growth by more than 14,000 across all products and all brands. Our acquisition of Now Broadband in December has added a further 24,000 broadband connections. Certainly giving us significant scale, which is important as we think into the future as we consolidate our position in retail. There's still a lot of competition. Churn, national churn at 19%, Mercury churn at 17% on a rolling six-month basis. That churn is still real, and we would expect to see that continue. From a point of view of price rises, the 2.5% versus the PCP, below the general level of inflation, and we have been careful about where we think price rises should be as we look through into the future. We have had more product to sell, and that's really reflected in our C&I sales following Turitea North commissioning, and we've been able to sell that product into the forward prices that William described earlier. We're also seeing a continuation of the trend of interest in +5 year contracts. We see this as a positive thing. Sales yields have been higher in both mass market and MC&I. From a mass market point of view, that's been heavily influenced by bringing the Trustpower retail business into our overall portfolio. If we go to the next slide, I guess we'll talk a little bit about the customer care, and particularly in two blocks, really. One about the recent weather events, and then a more broader program that we are embarking on, thinking about the long-term customer care issues. We've both in the Mercury and in the Trustpower brands, we've been very proactive in supporting customers who've been impacted by the severe weather. That's included writing off bills for customers who can no longer live in their homes. That's any monies that they had owing with us, not yet billed, and any other monies they had owing. Also making credits for those customers so that they, when they rejoin, they start in a better position when they've found places to live. Also, we've been in that sense, we've been also supporting through social agencies, those customers who needed to dry out homes by making a credit to allow them to run dehumidifiers. As we go to press, we estimate that those total payments, keeping customers supported in what is an incredibly difficult time, are approaching NZD 100,000. We've also reviewed our pricing strategies that were coming up, and we will be putting on hold price increases for the most heavily affected regions whilst we understand more fully how the situation will play out. Looking at it in a more, from a more holistic sense, we recognize that customers can be vulnerable at any time in their life cycle, and that can turn up for almost any of us, depending on what happens from a employment perspective or a home perspective. So we've got a list of things that we are working through, both with our industry colleagues and also ourselves. And I'd probably particularly call out our Home Sweet Home pilot and our Kāinga Ora Bill Cap pilot as really important ways that we can support some communities. To do that, we've also spent a lot of effort with our own people, developing our Here to Help team, which are specialists in working with those people that are really struggling in that point of time when the need is at the highest. Going to retail integration, which is the next slide. Look, we've made significant progress, and we're pretty pleased with where we've got to. We now have a single retail team operating across all brands. From a leadership perspective, of course, we have people answering the phones for Trustpower and Mercury on separate systems. We are moving very effectively through combining those technology systems, both people, process, and the systems. We're using a adaptive agile working framework to do that, and we expect that to see us moving customers onto the Gentrack platform in the middle of the year. That's really important because that'll start to move us to one technology stack. As we go to the one team, one brand, one technology stack, we'll see that roll out in the second half of the calendar year. The benefits will come to both brands, the customers of both brands. Mercury brand customers will be able to access some of the cross-sell opportunities that have been present in the Trustpower brand. Customers coming from Trustpower onto the new platform will be able to avail themselves of some of the technology that's been available to Mercury customers, like loyalty and consumption insights. As I say, we're expecting to do a customer migration in mid-2023. Costs are being incurred faster than the original business plan, but actually that's because we are moving faster to integrate. We are still forecasting to gain the synergies that we have said previously. Just noting that we got a NZD 43 million EBITDAF contribution from the Trustpower business. Moving from retail to generation development. You know, the progress at Turitea has continued to occur such that we expect generation in April and completion in this financial year. We have now seen turbines being erected and the substation significantly well advanced. We now forecast pro-total project cost at NZD 450 million, and we have reached conclusion around claims with our EPC contractor. Kaiwera Downs, which whilst a smaller project, is obviously a really important project to continue our contribution to decarbonization in New Zealand. The project's on time and on budget, and we expect it to be fully operational by October 2023. I think, you can see the different terrain in the photographs, and particularly the terrain has very different characteristics with us having to use explosives to create the foundation, the foundations for the wind turbines. Quite different from the materials we experience in the Tararuas. What comes next? We still, we strongly believe that we have one of the best progressed and most executable pipelines in the sector. We have four consented projects. As I said earlier, three of those are currently progressing through to final investment decision. That's really important because whilst there is reform of the RMA occurring, it's still unclear how the NBEA, the Natural and Built Environment Act, will actually speed up the process of getting consents for these really important projects. Having consented projects is a great strength. We also have a project in consent, which is a fifth binary unit at Ngātamariki, and a number of projects, as yet not named, which would give us a further 1,200 megawatts of potential build across a number of fuels: geothermal, wind, battery, and solar. I think the other really important thing to note in this area of the business is that the economics, and the access to resources, being contractors and equipment, are still tight, and inflationary pressures are very real. We do think that they will flow through, and it seems unlikely to us in consideration of the global demand for new plant and the inevitable demand on engineering experience, given the disastrous consequences of cyclones, that that's going to ease significantly. A turn to market and regulatory situation. We're really pleased with the quality of the Boston Consulting Group report, The Future is Electric, that set out, I think quite clearly, the big opportunities and challenges for the sector as we go through the next period to 2050, but in particular, the next 15 years. If we look at this page, the develop new renewable generation of pace, there is a significant pipeline across the sector, of which I've just described Mercury's. We think that can achieve the outcome required. However, it will be an issue of getting consents, resource constraints, and contention and inflation, as I've described. The projects are real, and they're available. That leads to the next problem or challenge or opportunity, and that's reliability during peak demand. There is no doubt, as BCG said, that that can be managed through both battery, more battery storage and the use of fast start peakers. The big challenge will be the transition through the next couple of years as we work through that. Whilst we have seen a lot of water, it is always the most difficult peak demand is always the one to manage when the hydro's already full and operating at full capacity. That is something that as an industry, we're keen to resolve. I think it was pleasing to see that the sector through Sapere Group, made a submission to the EA on this subject, and we look forward to the EA's decision, hopefully very soon, to allow us to see some changes that support peak demand risks. Dry years, I think the preferred pathway described by BCG of more renewables, enough gas peakers and large scale demand response makes a lot of sense. We're pleased that the government's New Zealand Battery Project is not only focusing on Onslow. That leads us to the fourth block of transmission and distribution. Look, I think we've just seen through Cyclone Gabrielle that resilience is incredibly important. When we talk to a trilemma of renewability cost and reliability, when it really comes down to it, reliability wins the day because we're just seeing, and we have got people living through today, the outcomes that occur when you can't get access to electricity. There is no doubt that that is a question that is going to flow through the debate over the coming months and years as we see the need for investment in distribution and transmission. That inevitably flows through ultimately to costs, irrespective of the generation technology. I'll just hand back to William to finish off with guidance. Thanks, Vince. Lucky last slide before we open for Q&A. EBITDAs guidance is held at NZD 795 million on 4,900 gigs of hydro generation. We can certainly see subject to the usual caveats. The bridge there between our initial guidance at the start of the year and subsequent upgrades hold. Certainly, we're seeing a tug of war between additional hydro volumes versus GWAP pricing. The high lake levels is forcing release of water, so we're certainly losing discretion essentially across the Waikato when you're at full gate at Taupō. That results in like something like 600 megawatts of generation overnight and about 850 during the day. It's like a two-step release. We're seeing a lot of GWAP across the hydro portfolio versus our low weighted average prices in terms of buying power for customers, held at just under NZD 800 million. Ordinary dividend guidance is maintained at NZD 0.218 per share, as Vince says, up 9%. That's a decade and a half of ordinary dividend growth enjoyed by our shareholders. In CapEx, same business capital expenditure, down NZD 30 million to NZD 130 million, largely due to the first start of geothermal drilling. With that, we'll open the lines up for questions. As a reminder, to ask a question, you will need to press star one one on your telephone. Again, that's star one one on your telephone to ask a question. Please stand by while we compile the Q&A roster. Our first question comes from the line of Grant Swanepoel of Jarden. Your line is open, Grant. Good morning, team. Just a quick one. You guys, stayed away from the TY conversation. Anything to update us on that front? No, not really, Grant. Yeah, we remain willing and engaged as necessary, but nothing, no new news. Thanks. Next one on the Trustpower throwaway line of NZD 43 million for this year, previously you guided to NZD 50 million, is that because of the flood damage and the extra costs you're pushing into or the support you're giving there? No. There was two things really, Grant. The first, if you recall, the timing of the completion of the deal, ended up being May 1st of the previous year. That, as a consequence of that, the seller did not put through the pricing rise that we expected prior to that. They chose to kick for touch. That meant that the pricing through that part of the customer base was delayed. The second part of that is some inflationary impacts on the Manawa hedge. Thank you. Can you give some idea, you indicated that some of the synergies are starting to be realized. Of that NZD 35 million, is there much in that NZD 43 million number you're talking about? No, that's a standalone count. It ignores the integration costs and synergy realization. Most of the synergies are appearing in rationalization of licenses. We do have some double up, so they will be permanent. At the moment, obviously we're scaling up Gentrack licenses versus install with FAP licenses. That's been covered through the integration costs in terms of that hump. You know, we were running 80 sprints. We've got a whole lot of people that are being brought on. Again, they're all accounted for through that integration cost budget. Thanks, Will. In terms of some of the good news, I think, Turitea North, your total costs reduced by $30 million on previous guidance. It's a bit of a change in trend from the other guys. What caused your costs to trace like that? All we're gonna say, Grant, is our original project cost, this is not just for the north, this is for the full project, both north and south. We had given indication of NZD 480 million, which was up, I think, from the original project cost estimate of NZD 464 million. Now we're estimating NZD 450 million. Good job. Final question, just on your guidance not having changed after adding 400 GWh of water. I understand that you guys have to run a bit overnight, which causes the [audio distortion] expected to hurt a little bit. With the forward prices still looking so sturdy, your slide nine supporting that view, what price are you looking for in the second half to see your earnings not changing at all in terms of your guidance? Yeah, we're quite. Our view is that certainly for the March through late Feb, March, April period, we'll run close to budget expectations. It's really just the back end. We essentially you might end up with an uplift. Again, given the challenge we've had with the GWAP is the high levels of generation across the river has seriously depressed GWAP across all hydro generation, because it's not just on the difference across all of it. It just creates a wedge between what you're buying power for versus what you're how you're generating it in terms of those volume weighted. It's a curious phenomenon, particularly when you run a firming system, run essentially almost base load. Thanks, Rob. Thanks, Ben. That's from me. Thanks, Grant. Thank you. Our next question comes from the line of Vignesh Nair of UBS. Your line is open, Vignesh. Good morning, gentlemen. Can you hear me? We've only just, you, quite frankly. Okay. That's thanks for the presentation and well done on the results. Just a few questions from me. Can you perhaps give a bit more color on the new supply projects coming to market, specifically the larger ones, like Puketoi and Kaiwera Downs 2? When are those consents expire? Broadly, when are you looking to bring that to market? You know, given the fact that FID is in the next six-18 months. Looking besides the projects, bring them on via PPAs plus merchant. How does that split kind of work? Thanks. Vignesh, that was very difficult to hear, I think the question was, how are we thinking about the progress of those Kaiwera Downs 2 and Puketoi, from a perspective of bringing them to market PPAs versus in the portfolio, and some of those decision issues, if we caught the question right. Yeah, correct. Okay. I think, as I said, we've got these well-consented projects. I think part of your question was about consent timeframes. Whilst we don't talk much about Mahinerangi Stage Two at this stage, that consent was given effect to through the build of the first stage. That consent sits there, and we're able to use. Similarly, Kaiwera Downs Stage 2 is a consent that we're giving effect to through the build of stage one. We have strong optionality around that. We see that as the better of those two South Island projects, partly because the grid access is easier, and partly because we have a relatively recent project, bearing in mind, Mahinerangi's first stage was 2011. Similarly, Puketoi, we have, we're bringing through so that we fully understand. Puketoi is a big project. We want to make sure we fully understand the risks and the opportunity, given the learnings that we've had out of Turitea in that part of the world. Kaiwera, we've recently got the consent. As everyone's aware, we're trying to bring that to FID. We have a PPA and offtake agreement with Genesis. We're very keen to bring this project forward. We have had some challenges as we've tried to deal with transmission access, transport pathways. The project itself, we're advancing by getting all of our ducks in a row, our pricing done, and our, with the intention of being able to do that around about the middle of the year. You could probably look at these in batting order as trying to get there with Kaiwera, then Kaiwera Downs and Puketoi, subject to all of the detailed investigation. In terms of the, f itting them in the portfolio or not? Well, as I say, Kaiwera, we've been working closely with Genesis on. Kaiwera Downs Stage 2, we'll bring that to FID, and we think there'll be a few choices about how we do that. Puketoi, at this stage, we haven't really needed to turn our minds to how that fits. The portfolio still has space for more wind generation in any event. Okay. That makes sense. Just one more thing on Puketoi. Is that limited by Central North Island transmission constraints north of Dannevirke, or does the existing infrastructure cater to that capacity as well? There was always a bay in the Turitea in the Turitea substation preserved for Puketoi to come into the Turitea line and then through to Linton. I guess ultimately, I have no doubt there'll be further transmission conversations about enabling more renewables. We have set up to be able to bring Puketoi into Turitea. Notwithstanding that, it's still a pretty long piece of transmission to be developed between Turitea and Puketoi as well, which we will have to factor into all of our pricing calculations. Okay, that's very helpful. One more thing, final one on Trustpower retail. Just following on from Grant's question before, is the correct way to think about it as in normalized year, you had NZD 50 million worth of EBITDA plus NZD 35 worth of synergies, so NZD 85, you said post 2024? Correct. Yeah. Okay. Very clear. Thank you, guys. Not from Trustpower. It's obviously from the combined retail businesses. The two you need to get there. Yeah, correct. Synergies. Yeah, I'm with you. Yeah. Thanks, Will. That's all from me. Thanks. Thank you. Our next question comes from the line of Andrew Harvey-Green of Forsyth Barr. Your line is open, Andrew. Morning, Vincent and William. A couple of questions from me, just following on actually, firstly on that question, I guess, around the synergy side of things. I notice in the notes you talk about better OpEx and CapEx synergy. It sounds like the majority of that is going to be OpEx as opposed to a reduction in stay and business CapEx. Is that correct? Weighted towards operating costs, yes. Yeah. Next question, I guess is kind of related as well, but just thinking about underlying OpEx going forward. We had NZD 160 million this period with I guess some integration costs. You're, I think, talking about NZD 190 million for the second half. Now, how much of that should we think about in terms of, I guess, underlying OpEx, which we can expect going forward versus those one-off costs? The integration costs obviously will end, so that's definitely creating a bump. We're just working through what the implications of inflation are when it's running at 7%. That's a general rate. How that affects our decisions around, essentially quantity, what work we do, what's necessary and what the price is. Some cases we're seeing 100% price increases on certain contract supply. Others, you're not seeing material price changes at all. It's just all over the show, and really driven by the work we need to undertake. Then, that's before you start dealing with foreign supply and what, and what foreign vendors are actually charging for equipment and service. We're just working through what the implications of that are. Again, it's still unclear about how long we'll be in this inflation bubble. I mean, it's probably being a little bit more persistent than people may have imagined. The Reserve Bank is obviously frantically trying to calm it down. It's still weird. It's a work in progress in terms of what that might mean across the border fleet. We do have some medium-term contracts that have got inflation-based escalators in them, so whatever the inflation prints, that's what turns up in costs. Yeah. We do have choices around the scope of works we undertake. Obviously that's balanced against what the risk, how does that affect reliability. You don't wanna save a penny to spend a pound. Yeah. Yeah. Next question was just around the Turitea costs and I guess, my interpretation, although you're very careful in how you worded it, but, am I right in saying we're not going to see any liquidated damages going through the P&L? That's all just netted off within that CapEx number going forward? It's all. If there are any settlements, then they turn up and they're recognized as a reduction in project cost. In the CapEx? Yeah. Okay, thanks. Last question was just around just confirming something as much as anything else. When I look at actually your results from the prior period, there was a NZD 20 million uplift, non-cash uplift, which related to the predominantly Norske Skog contract. I'm correct in saying you haven't restated the historics? Although I do note that the segmental accounting has changed a wee bit. Does that mean in terms of what we should be comparing on an apples-for-apples basis? Last year was an EBITDA more of the, I think NZD 222 EBITDA, going up to NZD 451. Yeah. That, certainly those, the Norske Skog transaction. One leg of that for us terminate the particularly long-term contract with Norsk for $64 million. That, that hit last year's EBITDA. That's, that's in that's in that bridge which is the 50, which includes the unwind of 14. Yeah, there are some... Then obviously that means we've got a longer book, and so that quantity is available for either, it's sold to spot or more likely sold into customer segments, mostly C&I. You can see C&I v olumes grow. You get a, you trade out of a out of the money contract into higher price contracts. Yeah. All right. That's great. That's all from me. Thanks. Thanks, Andrew. Thank you. Our next question comes from the line of Stephen Hudson of Macquarie. Your question please, Stephen. Hi, Vince and Will. Just a couple from me. Just on CapEx, I think you've talked about a steady state, same business CapEx, ex Trustpower retail, but post-FRAC of NZD 90. Can you remind us when you're expecting to revert to that level? That's my first question. Second question, obviously some reasonably big numbers there in your pipeline, 1.2 terawatts under investigation. Can you just talk in broad terms whether or not the mixed own ership model that you exist under constrains your ability to deploy capital and build out your aspirations there? Just coming back to the swap unwind impact, I think you talked about an NZD 175 million impact for the full year, NZD 50 in the first half. Do we just assume that NZD 125 is still current guidance for the second half? Okay. There's three questions. I've forgotten what the first question is. Sorry, can you repeat that? Sorry, Will. I've got on my notes that you've talked about a steady state, same business CapEx at NZD 90. Yeah, that's right. That one's easily dealt with. I think at the FY 2022 results, I think we actually guided 110. We've got a drilling hump for the next two years, and we've guided 110. That's all in. That includes expanded retail business. You come back to 90 after those two years? No. We're elevated above there. I think we've guided NZD 160 million, which was now being reduced to NZD 130 million in this year because of delays to start of that drilling program. We've guided steady state CapEx of NZD 110 million. Not NZD 90 million. That was on the FY 2022- Ninety. Yeah. Cool? Yeah. The second one. Thanks. In terms of capital. In terms of constraints on our balance sheet and inability to execute, I think there's some capital structure slides at the back of the deck. We're forecasting to be down to 2.2x debt to EBITDA. Again, we'll be back in the good part of our range. I think there's quite a lot of flexibility around if you really wanted to push out a generation development program and be really aggressive, there are ways for Mercury to fund that. We've got some headroom around our sub-debt, and we could probably raise another NZD 400 million there. Half of that would be treated as equity for rating purposes. The DRP can be more aggressive. While we're actually paying out on currently through treasury stock through our two buybacks historically, the participation agreement with the government would effectively, they'll participate pro rata. You'll quickly, if you put a bigger discount on DRP, you can raise equity with the government supporting that. That's another quite significant lever. We do partner with people, so partnership's a valid model, which again, means you can deliver projects but reduce the funding cost because you'll bring in new capital from third parties. I think there's a lot of levers. At the moment, we see our biggest issue is actually getting projects through feasibility, design, constructability, procurement, and then to FID is our key challenge. I think, certainly the large generators and many others are very active in terms of actually delivering capacity into the market, given where the forward curve sits. At the moment, I think the race is on, and at some point the wind will turn, and we'll go from what is currently, we're in a boom market at the moment. It'll turn, and you'll have a bit of a bust cycle, and that'll see people's appetite to deploy capital wane. I think that'll be a quality problem. If, if it's we're not doing projects because we don't have the balance sheet, I'll be extremely surprised. The third question? Sorry, just on the swap unwind cost, I think you tied it to NZD 175. Okay. We've got a, there's a slide right at the back of the deck just detailing the Manawa. The accounting treatment for that now is essentially we will fair value those contracts at start and end of the period. That fair value movement will be recognized below the line, rather than quickly having an unwind schedule to quickly bring Our purchase price allocation of those three swaps to nil over their maturity. We don't need to normalize any more, and those fair values will effectively just throw through. Just they'll influence impact as they would, whether they're above or below the line. We won't have this issue where our EBITDA is being reduced as a consequence of those unwound schedules. From a cash flow perspective, you won't need to worry. I mean, this year is really interesting. We've had really low spot prices, we've actually been take the Manawa hedge. It's a in the money hedge over its life based on the forward curve. We were actually paying away, we were out of the money for the last six months, we're effectively paying Manawa. At the same time, the fair value of that hedge, despite six months of that maturing, has actually gone up because the forward curve rose. For the remaining nine years of that contract, it's actually worth more than what we started at the beginning of the period. That's reflected through fair value. The good thing is that from an analyst or cash flow perspective, somewhat you can ignore the impacts of those fair value movements. Okay. Thanks, Will. Thanks, Steve. Thank you. At this time, I'd like to turn the call back over for closing remarks. Well, thanks everybody for attending. Hopefully you've got what you needed out of that. Particularly thanks, Grant, Vignesh, Andrew and Stephen for the questions. Look, it's, I think in summary, been a big transformational half year for Mercury, and we are seeing now the benefits of the investment in scale and the higher generation that that brings. We're pretty excited about the next half year as we get through the integration of the Trustpower business. Thanks everybody for attending. I'm sure we'll speak soon. Thank you. This concludes today's conference call. Thank you for participating.