Mercury NZ Limited (MCY) Earnings Call Transcript & Summary

Thank you for standing by, and welcome to Mercury's 2023 interim results analyst briefing. [Operator Instructions] I would now like to hand the call over to Chief Executive Officer, Vince Hawksworth. Please go ahead.

Morena 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. So going to our first major slide on Slide 3 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, wet, wet year. Our hydro generation has been up 45%. But not only that, in order to stay within operating constraints for our resource consents, we've seen 675 gigawatt hours of spill. That message around scale, lifting earning 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. And if you add that with the Trustpower retail acquisition and the additional generation through hydrology, that's moved EBITDA from $242 million in the comparable period prior year to $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. And looking at our pipeline, 3 of our 4 consented wind farms are proceeding through the process towards a final investment decision, those being Kaiwaikawe, Kaiwera Downs Stage 2 and Puketoi. So 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. And that, in parallel with our approach to vulnerable customers, has been incredibly important. And I will talk about that a bit later in this presentation because we're really sort of focused on how we do the right thing by all of our customers and particularly those that have been impacted by the weather. But 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 '23. Also noting that the numbers don't -- 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. And 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, $0.087 interim, 9% higher than previously. The DRP being continued and our ordinary dividend guidance for the full year, up 9% at $0.0218 per share. We've retained guidance unchanged at $795 million, largely driven by the fact that the hydro generation uplift is reducing the generating weighted average price. And we'll go into that in a bit more detail as required. Also, integration spend for the retail integration coming forward as we progress faster than expected stay-in-business CapEx down $30 million. That's the overview. I'm going to 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 4, and I'll just take us through some of the key financial highlights of the year. So as Vince said, our investments in scale has certainly made a difference to this year's results. So we've seen full year's of Turitea north wind farm production, the ex Tilt wind farms, they've also got a full period of generation. And obviously, the addition of the Trustpower retail business, again, a full 6 months contribution. So they're certainly lifting earnings relative to the prior comparable period. But also very wet conditions across the Waikato catchment. So to put that in perspective, we were up 45% on what we generated in the half year '22, so over 850 gigawatt hours more hydro generation. So 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-90s, actually, ECNZ actually generated a little bit more than we saw this year, sort of almost hitting 3,000 gigawatt hours, but they were running the entire grid at that point. So 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 3 fuel types in the fleet. So geo was up 19 gigawatt hours and wind up over 200 gigs in the year. So 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 the -- some of these bars actually look like almost full financial year results for a half year. So we're actually very close printing on EBITDA of $451 million to our FY '21 results, which was just $463 million. So again, a 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. So at half year did include a significant gain on sale related to the sale of our interest in Tilt renewables, so that explains the reduction in the NPAT by almost $200 million. Operating expenses do reflect the -- again, the increase in scale, due to the addition of Trustpower and more wind-related operating costs. We certainly are seeing inflation pressures emerging within the business. So that is feeding through, and we'll talk about -- a little bit more about that later. And on a sort of second half '23 basis, we expect OpEx to track at around $190 million versus the $160 million for first half. So backloading of costs largely due to retail integration driving that change. Stay-in-business CapEx is still relatively historically low. We're still sitting at $31 million, living up on where we were in the PCP. And again, that's largely driven by preparatory drilling costs. So really gearing up for that significant $120 million drilling program across our geothermal fields ticking off pretty much now. And growth CapEx, mostly due to CapEx at Kaiwera Downs, the now Broadband acquisition and a little bit at Turitea. There is an additional slide on Slide 23, just detailing some of the accounting treatment for our acquired swaps, which is slightly different. So we won't be -- we won't need to have a normalized EBITDA now. So the EBITDA will fix the fair value movements of those derivatives acquired with the Manawa hedge, Norske Skog and the Waipipi CfD with Genesis. As I said, the record wet, certainly in the investment has listed the earnings bridge, really explained by probably some key building blocks, $130 million added from more than 1,000 gigawatt hours of additional generation. Sales yields, we saw mass market yields lift only about 2.5% against PCP across all our brands. So that $26 million uplift is largely driven by C&I as contracts mature and reprice against an elevated forward curve. That $26 million also includes yields from derivatives with end users or industrial customers. Trustpower added $30 million EBITDA for the half year. Our noncustomer derivatives were up $22 million, ancillaries adverse at $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 nonrecurring. So that $64 million cash termination fee was paid and recognized in EBITDA last year, so depressed half year '22. And then we had $40 million derivative unwind also giving a net $50 million. Cost up 21%, largely due to scale increase, saw a change in other income relating to less income received on the total investment. So it was dividend, gives us a bridge to $451 million from last year's $242 million.

So 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. And that has been, I think, very much instrumental in making health and safety a much more about the way we do business rather than the 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. And 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. However, 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.

So we're on Slide 7 now. I really want to talk about spot prices. So there's some familiar scatter plots here, which I'll talk to. So first, on the left plots, monthly spot price in Auckland against how storage is deviating from Main for that time of year. We really can't see a step change in recent years really probably on the back of the Powerco outage back in late calendar '18 where we saw effectively thermal fuels rise and probably exacerbated further with coal prices and carbon lifting since that time also. So we're seeing absolutely higher prices, wind storage is below average and price is still higher than where they were trending sort of the earlier sort of the 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. So while we can certainly see a trend from rising from left to right, the correlation is certainly probably getting worse. So I think the influence of gas is waning. We certainly have seen quite reasonable constraints in the gas market. And so our gas plants have become more like hydros, where they're looking to allocate this gas fuel across the year. And so we're becoming increasingly reliant on coal, which will take us to the next slide. This switch is really to forward prices. And so the -- electricity forward price reflects coal and carbon prices. So some probably -- I'll probably start with the bottom right chart that details the 3-year average forward futures price. This has been pushed by 6 months. So that look -- the effects of hydrology. Hydrology whether it's dry or wet certainly influences the front end of the forward curve, but the backend is certainly less influenced by short-term hydrology impact. So we can see a very clear rising trend in futures prices. So if we start at the start of that chart, we're sitting at about $100 a megawatt hour. That is for the 3-year period as the note sees from January 2021 to December '23. So back then, we were sitting at $100, a good proxy for what you might be buying or hedging energy for over in the medium term. And now we're sitting almost at $200. So 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 Taupo lake levels or the national lake levels have been relatively high and remain so well above average for the last 6 months. So just some comments there. So forward prices, they reflect the market view of marginal generation costs through time and volatility. So 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. And so forward prices are affected by retail energy intermittency. And so obviously, as we push towards more renewables, the trilemma around balancing affordability, renewability and reliability is front of mind. And so how often those more expensive generational sources at prices is probably more important than the levelized cost of energy, which we do -- we can't focus on in terms of what it cost to -- new solar system or a new wind farm. Moving to Slide 9, just focusing on the Taupo 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-plus years. You can certainly see from the other line, we've been setting some new upper limits. And we did press through just the maximum control limit under our consent at 357.25 meters above sea level back in late January, early Feb for about a week by a couple of centimeters. So it's certainly been very, very wet. You can see the generation delta against mean. So every single month, we have generated above what we'd expect on an average year. Inflows have been even higher. We spilled 675 gigawatt hours of water. Put that in perspective, we generated 3,735, so it's about a 1/4 of the water we generated was actually spilled down the river. Spot price is very subdued, really falling pretty much over that half year period and ending at a whopping $19 in December. So certainly, lots of generation going out, but at very low prices at that time. And over to Vince.

So on Slide 10, we look at some of the impacts of Trustpower retail acquisition and our sales in general. The chart -- 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. And our acquisition of now Broadband in December has added a further 24,000 broadband connections. So certainly giving us some significant scale, which is important as we think into the future, and 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 6-month basis. So 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. And we're also seeing a continuation of the trend of interest in plus 5-year contracts. And we see this as a positive thing. Sales yields have been higher in both mass market and C&I. And from a mass market point of view, that's been heavily influenced by bringing the Trustpower retail business into our overall portfolio. So if I go to the next slide, the -- I guess we'll talk a little bit about the customer care and particularly in 2 blocks really, 1 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 have been impacted by the severe weather. That's included writing off bills for customers who have -- who can no longer live in their homes. So that's any monies that they had owing with us not yet billed and any other monies they had owing, and also making credits to those customers so that they -- when they rejoin, they start in a better position when they found places to live. And 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 sort of go to press, we estimate that those total payments keeping customers supported in what is an incredibly difficult time are approaching $100,000. We've also reviewed our pricing strategies that we're 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 more from a more holistic sense, we recognize that customers can be vulnerable at any time in their lifecycle, and that can turn up for almost any of us depending on what happens from an 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 Kainga Ora bill cap pilot as really important ways that we can support some communities. And 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. So from a leadership perspective, of course, we have people answering the phones for Trustpower and Mercury on separate systems. But we are moving very effectively through combining those technology systems, both people, process and the systems. So we're using an 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 will start to move us to one technology stack. So 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. So Mercury brand customers will be able to access some of the cross-sell opportunities that have been present in the Trustpower brand and 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-'23. Costs are being incurred faster than the original business plan, but actually, that's because we are moving faster to integrate. And we are still forecasting to gain the synergies that we have said previously. Just noting that we got a $43 million EBITDAF contribution from the Trustpower business. So moving from retail to generation development. 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 total project cost at $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 is on time and on budget, and we expect it to be fully operational by October 2023. And 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 foundations for the wind turbines. So quite different from the materials we experienced in the Tararuas. But what comes next? We still strongly believe that we have one of the best progressed and most executable pipelines in the sector. We have 4 consented projects. And as I said earlier, 3 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 NBA, the Natural Built Environment Act will actually speed up the process of getting consent to these really important projects. So having consented projects is a great strength. But we also have a project in consent, which is fifth binary unit at Ngatamariki and a number of projects has 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. So we do think that they will flow through. And it seems unlikely to us in the -- 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. Let's turn to market and regulatory situation. But we are really pleased with the quality of the Boston Consulting Group report, The Future is Electric, that's set out, I think, quite clearly the big opportunities and challenges for the sector as we go through the next -- well, the next period to 2050, but in particular, the next 15 years. And if we look at this page, the developed new renewable generation of pace, there is a significant pipeline across the sector, 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, but the projects are real and they're available. That then 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 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. And 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 is already full and operating at full capacity. So that is something that, as an industry, we're keen to resolve. And I think it was pleasing to see that the sector through [indiscernible] 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. And 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. And when we talk to the 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. So 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. So I'll just hand back to William to finish off with guidance.

Thanks, Vince. Lucky last slide before we open for Q&A. So EBITDAF guidance is held at $795 million on 4,900 gigs of hydro generation. We can certainly see subject to the usual caveats, but the bridge there between our initial guidance at the start of the year and subsequent upgrades hold. Certainly, we're seeing it's like a war between additional hydro volumes versus wet pricing. So the high lake levels is forcing release of water. So we're certainly losing discretion, essentially, across the Waikato you're at full gate at Taupo, that results in something like 600 megawatts of generation overnight and about 850 megawatts during the day. So sort of like a 2-step release. So we're seeing lower GWAP across the hydro portfolio versus our low weighted average prices in terms of buying power for customers to held at just under $800 million. Ordinary dividend guidance was maintained at $0.0218 per share as when -- up 9%. So that's 1.5 decades of ordinary dividend growth enjoyed by our shareholders. And in CapEx, business capital expenditure down $30 million to $130 million, largely due to the first start of GWAP drilling. So with that, we'll open the lines up for questions.

[Operator Instructions] Our first question comes from the line of Grant Swanepoel of Jarden.

Just a quick one. You guys stayed away from the TR conversation. Anything to update us on that front?

No, not really, Grant. We remain willing and engaged as necessary, but nothing -- no new news.

Next one on the Trustpower line of $43 million for this year. Previously, you guided to $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 were some 2 things really, Grant. The first, if you recall the timing of the completion of the deal ended up being May 1 of the previous year. And 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.

And the second part of that is some inflationary impacts on the Manawa hedge. And so can you give some -- you indicated that some of the synergies are starting to be realized. Of that $35 million, is there much in that $43 million number you're talking about?

No, that's a standalone count, the integration costs and synergy realization. Most of the synergies are appearing in rationalization of licenses, but we do have some double ups. So they will be permanent, but at the moment, obviously, we'll be scaling up Gentrack licenses versus and still with SAP licenses. That's been covered through the integration costs in terms of that hump. 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.

And then in terms of some of the good news, I think Turitea north, your total costs reduced by $30 million on previous guidance, it was a bit of a change in trend from the other guys. What caused your cost to trade like that?

All we're going to say, Grant, is, yes, our original project cost. This is not just for the north but for the full project, both north and south. We had given indication of $480 million, which was up, I think, from the original project cost estimated $464 million, and now we're estimating $450 million.

Good job. And then final question, just on your guidance, not having changed after adding 400 gigawatt hours of water. I understand that you guys have to run a bit overnight, which causes the [indiscernible] but just to help us a little bit. But with the forward price is still looking so sturdy, your Slide 9 supporting this view, what sort of price are you looking for in the second half just your earnings not changing at all in terms of your guidance?

Yes. We're quite -- our views are certainly for the March through sort of late Fed March, April period will run close to budget expectations. So it's really just the back end. We essentially you might end up with a slight -- with an uplift. But again, given the challenges 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. So it's cracked a wedge between what you're buying power for versus what you're -- how you're generating it in terms of those volume weighted. So yes, it's a curious phenomenon as particularly when you run a firming system runs essentially almost baseload.

Our next question comes from the line of Vignesh Nair of UBS.

Vince and William can you hear me?

Only just you quite correctly.

Okay. [indiscernible] just a few questions for me. Can you perhaps new supply projects coming to market, specifically the larger ones like Puketoi and Kaiwera Downs too. So what are your concerns [indiscernible] when are you looking to bring that to market problems with [indiscernible] in the next 6 to 18 months? And looking the projects, sort of bringing them on via PPAs plus merchant so how does that split kind of work?

Vignesh that was very difficult to hear, but I think the question was how are we thinking about the progress of those Kaiwaikawe, Kaiwera Downs, Puketoi from a perspective of bringing them to market PPAs versus in the portfolio and some of those sort of decision issues, if we got the question right.

Yes, correct.

Okay. So I think, as I said, we've got these more consented projects. I think part of your question was about consent time frame. So whilst we don't talk much about Mahinerangi Stage 2 at this stage, that consent was given effect to through the build of the first stage. So that consent sits there and we're able to use. Similarly, Kaiwera Downs Stage 2 is a consent that we are giving effect to through the build of Stage 1. So we have strong optionality around that. We see that as the better of those 2 South Island projects, partly because it's -- the grid access is easier and partly because we have a relatively recent project, bearing in mind, Mahinerangi 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 so. And Kaiwaikawe, we've recently got the consent. And as everyone is aware, we're trying to bring that to FID, we have a PPA and offtake agreement with Genesis. And 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 down and our -- and with the intention of being able to do that around about the middle of the year. So you can probably look at these in batting order is trying to get there with Kaiwaikawe and Kaiwera Downs and Puketoi subject to all of the detailed investigation. In terms of the fitting them in the portfolio or not, well, as I say, Kaiwaikawe, we've been working closely with Genesis. Kaiwera Downs to Stage 2 look, we'll bring that to FID, and we think there'll be a few choices about how we do that. And Puketoi, at this stage, we haven't really needed to turn our minds to how that fits, but the portfolio still has space for more wind generation in any event.

Okay. That makes sense. And just 1 more thing on Puketoi. Is that limited by Central North Island transmission constraints north of [indiscernible] or the existing infrastructure sort of cater to that capacity as well?

There was always a bay 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 will be further transmission conversations about enabling more renewables, but we have set up to be able to bring Puketoi into Turitea but notwithstanding there, 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. And one more thing, final one on Trustpower retail. Just following on from Grant's question before. Is the correct way to think about as in normalized year, you have $50 million worth of EBITDA plus $35 million worth of synergies? So $85 million say post '24?

Correct.

Yes. From Trustpower it's obviously from the combined retail businesses…

Yes, correct so it's the synergies, yes, I'm with you.

Our next question comes from the line of Andrew Harvey-Green Forsyth Barr.

Vincent, William, a couple of questions for me. Just following on actually firstly on that question, I guess, around the synergy side of things. I noticed in the notes you talked about debt OpEx and CapEx synergy. It sounds like the majority of that is going to be OpEx as opposed to a reduction in stay-in-business CapEx. Is that correct?

Weighted towards operating costs, yes.

Yes. Next question, I guess, is kind of related as well, but just thinking about underlying OpEx going forward, so we had $160 million this period. I think there's some integration costs, and you're I think talking about $190 million for the second half. How much of that should we think about in terms of, I guess, underlying OpEx, which we can expect going forward versus those sort of one-off costs?

Well, 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 and how that affects our decisions around essentially quantity, what work we do, what's necessary and what the price is. So in some cases, we're seeing 100% price increases on certain contract supply and others, you're not seeing material price changes at all. So it's just all over the show and really driven by the work we need to undertake. And then -- and that's before you start dealing with foreign supply and what foreign vendors are actually charging for equipment and service. So 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 trendily trying to come it down. But yes, it's still -- it's a work in progress in terms of what that might mean across the broader 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. We do have choices around the scope of works we undertake and obviously, that's balanced against what the risk, how does that affect reliability. So you don't want to save a penny to spend a pound.

Yes. Yes. And next question was just around the Turitea costs and I guess my interpretation for your [indiscernible] on how you weighted it. But am I right in saying we're not going to see sort of any liquidated damages going through the P&L, that's all just netted off within that CapEx number going forward? Yes.

It's all -- if there are any settlements then they turn off and recognize as a reduction in project costs.

And the CapEx, yes. Okay. And last question is just around just confirming something as much as anything else. So when I look at actually your results from the prior period, there was a $20 million uplift noncash uplift, which related to the predominantly the 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, so does that mean in terms of what we should be comparing on an apples-to-apples basis last year and was an EBITDA more of the, I think, $222 million EBITDA going up to $451 million?

Yes so that certainly those -- the Norske Skog transaction, so one leg of that for us terminate the particularly long-term contract with Norske for $64 million. So that hit last year's EBITDA. So that's a net bridge which is the $50 million, which includes the unwind of $14 million. So yes, there are some -- and then obviously, that means we've got a longer book. And so that quantity is available to either sell to spot or more likely sold in to customer segments, mostly C&I including C&I, so you sort of get -- you trade out of the money contract into higher-priced contracts.

Our next question comes from the line of Stephen Hudson of Macquarie.

And just a couple from me. Just on CapEx, I think you've talked about a steady state and business CapEx sort of ex Trustpower retail but post [indiscernible] of 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 next ownership model that you just under constraints your ability to deploy capital and build out your aspirations there? And then just coming back to the swap unwind impact, I think you talked about $175 million impact for the full year, $50 million in the first half. Do we just assume the balance that $125 million is still current guidance for the second half?

3 question, I've forgotten what the first question is, sorry, can you repeat that?

Sorry. Well, I think I got my notes that you've talked about a steady-state stay-in-business CapEx at 90%.

That's right. That one is easily dealt with. So I think the FY '22 results, I think we actually guided $110 million. So we've got a drilling hump for the next 2 years, and we've guided $110 million. That's all in. That includes the expanded retail business.

And so you come back to 90% after those 2 years?

No, no, no, we're elevated above that. I think we've guided like $160 million, which was now being reduced by $130 in this year because of delays the start of the drilling program. And then we've guided a steady state CapEx of $110 million, not $90 million, that was in FY '22. The second one in terms of capital -- in terms of constraints on our balance sheet and ability to execute, I think there's some capital structure slides at the back of the deck. We're forecasting to be down to sort of 2.2x debt to EBITDA. So 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 $400 million [indiscernible], which will give us -- half of that would be treated as equity for rating purposes. The DRP can be more aggressive. So while we're actually paying out on currently through treasury stock through our 2 buybacks historically, the participation agreement with the government would effectively -- they participate pro rata. So you'll effectively if you put a bigger discount on DRP, you can raise equity with the government supporting that. So that's another quite significant lever. We do partner with people. So partnership is 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. So I think there's a lot of levers. So at the moment, we see -- our biggest issue was actually getting projects through feasibility design, constructability, procurement and the [indiscernible] as our key challenge. And I think all certainly the last generators and many others are very active in terms of actually delivering capacity into the market given where the forward curve sits. So at the moment, I think it races 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 will turn and you'll have a bit of a bus cycle, that will see people's appetite to deploy capital wane. So I think that will be a quality problem as far as it's -- we're not doing projects because we don't have the balance sheet, I'll be extremely surprised. And the third question?

And just -- sorry, just on the swap underlying costs, I think you've guided to $175 million…

Okay. So we've got a -- there's a slide right at the back of the deck just detailing the Manawa. So 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 we recognized below the line rather than fickly having an unwind schedule to effectively bring the purchase price allocation of those 3 swaps to nil over their maturity. So we don't need to normalize any more. And those feed values will effectively just flow through, just -- will influence impact as they would, whether they're above or below the line, but we won't have this issue where our EBITDA has been reduced as a consequence of those unwind schedules. So from a cash flow perspective, you won't need to -- you won't need to worry. I mean this year is really interesting. We've had really low spot prices. So we've actually been -- take the Manawa hedge. It's in the money hedge over its life. Based on the forward curve, we were actually paying away. So we were out of the money for the last 6 months, and we're particularly paying Manawa. At the same time, the fair value of that hits despite 6 months of that maturing has actually gone up as the forward period rose. So for the remaining 9 years of that contract, it's actually with more than what we started at the beginning of the period. And so you've got -- and that's reflected through fair value. So the good thing is from an analyst or a cash flow perspective, somewhat you can ignore the impacts of those fair value movements.

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 sort of transformational half year for Mercury, and we are seeing now the benefits of the investments 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. So thanks, everybody, for attending. I'm sure we'll speak soon. Thank you.

This concludes today's conference call. Thank you for participating. You may now disconnect.