Mercury NZ Limited (MCY) Earnings Call Transcript & Summary

Thank you for standing by, and welcome to Mercury Interim Results Analyst Briefing 2024 Conference Call. [Operator Instructions] Please be advised that today's call is being recorded. At this time, I'd like to introduce Vince Hawksworth, Chief Executive of Mercury Limited.

[Foreign Language] and welcome, everybody, to the Mercury 2024 Interim Results Presentation. I'm Vince Hawksworth, Chief Executive; and I'm joined by William Meek, Chief Financial Officer. So we'll go to Slide 3. Our business performance is a major event slide. First half, 4.5 terawatts of renewable generation and a big contribution there from Turitea full year and Kaiwera Downs stage 1. In fact, hydro representing 46% of our generation in the first half. So showing the importance of our portfolio expansion. Full year, we're forecasting 8.8 terawatt hours. Important event in the first half was the migration of mass market customers under the Mercury brand on to the Gentrack platform. We now have a single retail platform, and this will allow us to continue to grow our position as a leading multi-product utility retailer. As I mentioned, the reflection of Kaiwera Downs stage 1 coming in on time and under budget means that, that 43-megawatt, 147 gigawatt-hour project made an important contribution in the first half. We also committed to OEC 5, the new unit at Ngatamariki. That expansion will have annualized generation of 390 gigawatt hours and adds 46 megawatts, that commitment being important in growing some base load into our portfolio. We've had some challenges on geothermal drilling and that campaign has been delayed, and we're currently in the process of negotiating an alternative drilling contractor. When you add that all up, what that means for us from an FY '24 perspective is we're increasing guidance to $880 million from $835 million EBITDAF. And we are announcing a $0.093 per share interim dividend and maintaining guidance at $0.233 per share, which is the 16th year of dividend growth. So turning to the next slide. I suppose we understand that a safe workplace is a productive workplace and is an important thing that underpins everything we do. The graph shows the data which is obviously lagging data, but more important than that, I think, is the work we have initiated and continue to work through that addresses critical risks in the business, those risks that can seriously harm people, contractors, members of the public. We are currently 36% of our way through a deep-dive critical risk program. We have completed all of the outstanding improvement notices that we have had from WorkSafe. And we are very focused on increasing our Process Safety program. As you'll be aware, we had an event at Rotokawa steam hammer event in July '21. Recently, we plead not guilty to those charges. But I do want to emphasize that, that is in the context of continuing to engage with WorkSafe around an enforceable undertaking. Safety coming early in this presentation, I think, emphasizes the importance that we and the Board see with that. I'll pass to William to take us through the next few slides.

Thank you, Vince. So we're on Slide 5 now. I'll just talk to some of the key financials of the half year. We had a strong trading margin performance. So it was actually a lift of $14 million against the prior period. Trading margin essentially revenue from our generation and retail business less direct costs. Our hydro generation, we had a record hydro generation in the PCP. So hydro was actually 663 gigawatt hours lower coming in at 2,072 gigs for the 6 months. Geo was very similar, just up 11% on the PCP and -- but the -- our wind portfolio performed strongly with higher output from our new wind farm at Kaiwera Downs and full 6 months from the Turitea South wind farm. So overall, generation volumes were down 331-gigawatt hours, but nevertheless, the strength of the portfolio performance showing through a net trading margin uplift of 14%. Operating expenditure was up $31 million on the prior comparable period, 2/3 of that related to wages and maintenance, I'll come back to that shortly. EBITDAF At $434 million, so $17 million lower than last year's, which was a record performance for the company. Net profit before tax at $174 million, so down, again, largely due to higher depreciation, higher interest costs and we saw quite a significant net change in the fair value of our carbon units held for trading. Our operating cash flow was also down, pretty much all explained by higher cash interest and tax payments over the period. CapEx was up on the prior year, both stay-in-business and growth. So good to see strong progress in terms of the rehabs at Karapiro, the last station on the Waikato River, the start of our geothermal drilling campaign, which Vince will talk to shortly. Completion of migration of customers in our retail integration project and the turnaround at Kawerau, which saw a new turbine and generator installed and that's running fantastically. Growth investment up on the back of those completion of Kaiwera Downs stage 1 and OEC5, so the fifth unit at Ngatamariki under construction. Our dividends at $129 million are up $9 million and with our DRP operating with a 2% discount. Turning to Page 6. Just a really simple bridge from between the 2 half years, so really bridging that $17 million, fairly self-explanatory, generation volumes down 331-gigawatt hours, so 0.3 of a terawatt hour. So low hydro, high wind. We saw a strong performance in our retail position with higher pricing outcomes in both mass markets and commercial and industrial, so adding a positive $33 million. We saw electricity derivatives with adverse $11 million, really due to the impact of higher prices on the sales position. We've seen quite positive LWAP versus GWAP outcome. So LWAP matters in terms of what we buy energy from the market for, GWAP is what we're selling from our power stations to the market. So we saw a about a 2% movement there, 1.04 to 1.06. That's on quite a big numerator. So essentially, that applies to -- from an annualized basis, an 8,000-gigawatt hour base. So that's also driving our guidance upgrade, which we'll come to. We saw lower trading gains. We did get an increase in transmission charges from the new TPM, but those were offset by improvements in terms of settlements from the loss and constraint pool. And operating expenses down -- sorry, up $31 million explaining that $17 million bridge. Slide 7. A bit of a deep dive here on operating expenditure. So an increase in retail capability. So some of that head count driven, a call out there around the NOW broadband acquisition, so there's about $4 million of that $8 million due to a full 6 months of now. Retail integration is called out well in this deck. So again, celebrating a migration of customers to Gentrack. We saw an uplift in maintenance capability, $6 million of that due to new wind operations. So again, to Turitea South in KD1. And then we saw increases in our insurance costs and on several landowner agreements, bridging that $31 million. Movement of debt. So really just bridging our uses of EBITDAF. We can see tax, big investing uplift, both in state business and growth in those 2 new power stations, interest, dividends paid of $157 million post DRP, $19 million in other capital. So we saw a $76 million increase in net debt over the period. And back to Vince, Slide 8.

Thanks, William. So Slide 8 talks a little bit about where we're at with the generation development pipeline. The obvious project that we've been advancing for a while now is Kaiwera Downs stage 2 that we still expect to bring to final investment decision in this financial year. We have been working through a site optimization process, and that has dropped annualized generation, but we believe that will be the best economic investment that we can make. For some time now, we've been talking about the Kaiwaikawe wind farm. We continue to work that towards a final investment decision more likely to be early in the next financial year, largely because of delays to the procurement supply chain issues and also construction logistics, which are which are a factor, I think, for development generally in New Zealand as the world gears up to try and decarbonize. We are reviewing our Mahinerangi stage 2 wind farm project. We've had that resource consent for a long time. And we're looking at a sort of technology improvement that is likely to require some resource consent amendments. And we continue to look at Puketoi and Tararua repowering. We have a number of other prospects in the pipeline, which, at the moment, we remain commercially sensitive as we as we close our arrangements with various parties. But we think we've got plenty to do in the short to medium term. If you go to the next slide. I guess that just summarizes on Slide 9 there, the progress that has really sort of changed the portfolio of the our generation portfolio as Turitea South added to North with Kaiwera Downs plus the projects that we picked up through the Tilt transaction and then with Ngatamariki coming on board. So a much more balanced portfolio than we had 3 years ago. Going in a little bit more detail on Slide 10. So the Ngatamariki project, still on target for first generation late in calendar '25, that will take the Ngatamariki station from having 4 Ormat Energy Converter units with 86 megawatts total capacity. It will add a further 46 megawatts. That's $220 million project and adds 390-gigawatt hours. We're well advanced on this detailed design and the manufacturer is advancing. And you can see there the completed cold condensers, long lead items underway. We are currently expecting that to be delivered in the time frames that have been outlined, although we are keeping in close contact with the supplier regarding the situation in Gaza. Kaiwera Downs stage 1, fully operational now. Really pleased with the way this project turned out. The learnings from Turitea were really important in how we approach the project. And stage 1 is completed, it's up and running. I think you can see from the photograph there that it looks pretty smart, and we continue towards -- working towards stage 2 final investment decision. So moving to our retail business. As I mentioned in the sort of summary upfront, A real highlight for us was moving the customers, the Mercury customers on to the Gentrack billing system, and completing that towards the end of the last half year. That did mean that we reduced acquisition activity for a period through that transition. That made sense to us to make sure that existing customers were successfully migrated. We're now in a position where we can recommence acquisition activity. That single technology stack gives us the platform for enhancing choice for customers, effectively means that no matter what platform you were on before, you can now start to access the products that both the previous Trustpower brand and the previous Mercury brand had. Importantly, we continue to work diligently towards getting the synergies that we put in the original announcement. And we remain confident about that process completing in FY '25. And at present, we expect to spend about $44 million relative to the $50 million forecast, and you've got the numbers there for what we've done to date. I think what's really exciting for us is, this is completely driven internally by our people. And we've developed a lot of capability in doing these sorts of projects through this work. And it's quite unusual for a technology integration like this and a brand integration to really deliver very close to the timing we expect and to be on track to deliver the benefits that we described. I suppose, if I would go to the next slide, Slide 13, why is all of this important? Why does it matter? Well, this table here, chart shows the potential growth in renewable electricity required by 2050 under the BCG report, The Future is Electric. Of course, it may not play out like this, but it is critically important for the business to have developed strategies that play to this potential. If renewable electricity is to account for 58% of New Zealand's total energy demand, that's how you end up needing 30-terawatt hours. So that really is, when we say 58% of total energy, we're talking obviously about a lot of thermal fuel being converted to electric fuel. This does require a real collective action, it will require disciplined deployment of capital. In this environment, real long-dated options are important. And we see throughout the globe, real examples of governments and regulators accelerating this investment, whether that's the IRA and U.S.A., New Deal in South Korea or EU's Green Deal Industrial Plan. So that does put pressure on supply chains. I'm going to pass back to William now to go into a bit more detail on the market.

Thank you, Vince. We're on Slide 14 now. So there's a couple of charts here, one showing the 3-year forward price. So the futures curve in Auckland, the other of the NZU or the carbon unit price tracks from July through -- July '21 through January '24. So futures markets still elevated, really reflecting a whole lot of variables, but cutting to the chase, the tightness in gas deliverability feeding into thermal offers, which are ultimately driving pricing around $150 a megawatt hour mark. We are seeing peaks growing. Demand is up very marginally on the PCP. So that's positive. Certainly, the outlook is for a stronger demand growth as that increased electrification, decarbonization theme picks up speed. We can see carbon prices. So the carbon auctions last year were quite unsuccessful. So we didn't see any of those clear throughout the year. Certainly, this -- the new government is looking to the ETS to do heavy lifting in terms of incentivizing moves to a more renewable energy. So the March auction for NZU certainly will be very interesting. Recently there's some quite high carbon inventories out there at the moment across people that hold those, and obviously, the cost of carry for carbon is also higher with higher rates. So it will be interesting to see how carbon prices trend. But what these prices ultimately tell us is that sort of more renewables are required and ourselves and the sector are certainly moving mountains to bring new capacity to be -- so totally displace higher thermal costs and see those energy prices come back. A slide around hydrology for the year, so this is familiar to most. So certainly a very different year in the Waikato Catchment and at Lake Taupo for the half year. You can see last year, we were balancing frequently along the top, in that dark blue line, getting very close to the maximum controllable level, that's the consented levels that you saw in January last year, as thickly reaching the top. This year, it's been quite different. We can see every single month has been drier than normal reflected in that lower hydro production. We tracked the main storage level for Lake Taupo throughout Q2. We had a wet spell there during the Christmas New Year's break. So we saw quite a sharp increase in the lake level really setting us up for the dry months, sort of late summer and autumn which is good. So we've seen weather conditions in January and February to date. There's a lot of volatility in and futures prices versus spot. So we saw the start of the year, futures market was predicting, prices in the, let's say, $200 range. And given what's happening hydrologically in the South Island, we saw prices fall back to $120 in July and almost $150 in August. We saw futures and spot prices track sort of within [indiscernible] sort of the back part of that year. And then we saw, again, we saw spot prices escalate sharply and diverge away from the futures price 3 months prior. So some interesting volatility there around futures prices being both higher and lower than actual spot price outcomes, which in the short term are hugely affected by plant availability and particularly national hydrology.

So turning to some of the operational highlights and issues that we're dealing with. And as I mentioned earlier, the geothermal drilling program, we have had delays and we are in the process of rephasing that. We are also in the process of negotiating with an alternative drilling rig contractor. And we still intend to complete the 8-well geothermal drilling campaign, and that's important to sustain both capacity and also ensure that we are ready for OEC5 at Ngatamariki. To date, expenditure has been $46 million. And based on the revised schedule and the costs, we expect the campaign cost to be a further $114 million through to FY '26. So totaling $160 million, that is a step up. However, what is going to be important is that the holes are completed and give us the ongoing fuel that we need for our geothermal stations. Turning to the next slide, which is Slide 17. I mean, a key thing about our existing assets is ensuring that we continue to invest to enhance and optimize particularly increasing efficiency and flexibility. We have been investing in control systems at Ngatamariki and Kawerau. This supports our pathway towards centralizing our control room operations. And we've been in the first phase of that by centralizing Ngatamariki and Nga Awa Purua. As we then work through with our operations teams and working through training and planning, we will bring all of those sites together. Importantly, we have a long program of rehab work on the Waikato River. The important thing there is that as we do that rehab work, we turn our mines to increased efficiency and increased opportunities with the water that flows. The picture there is a runner from the Karapiro station refurb. If you were to set that runner against the one that came out, the one that came out would look very agricultural. This is -- has the benefits of computer-aided design and modern technology. When these projects, the 3 machines are completed, and we're halfway through the second machine, we'll have an increase of capacity at Karapiro of 17 megawatts, really important in the context of peaking and average generation will go up by 32-gigawatt hours. As William mentioned earlier, on the completed unit, that's been operating really well and meeting or exceeding expectations. So we're pretty pleased with how that project is rolled out. Of course, we've talked a little bit about retail integration. So on Slide 18 now. We just show that the total connections across all products have increased by 17,000. However, we're now in a position with the integration to really focus on some of the benefits as well as achieving the cost synergies that program is working on. We can now look at the benefits of providing products to all of that customer base, which gives us opportunities, particularly in the telco space. So we're pretty pleased to be in this position, and that has helped us. Looking forward, the high forward curve has seen -- as prices have reset in C&I, we've seen the increase in yields, and that's flowed through. And also our sales yields in mass market. As William mentioned earlier, the challenge in pricing is that transmission and distribution prices will continue to elevate as interest rates and resets flow through for those businesses. So we take a long-term view on how those flow through to customers as -- and try to think about that as a longer-term process rather than too much price and bill shock. So I'll pass on to William to take us through some of the balance sheet stuff.

So we're now on to Slide 19. Mercury's capital structure. We're operating at the good end of the 2x to 3x credit band for -- from S&P for a BBB+ entity. Net debt at just below 2 yards, so $1.983 billion, so up $76 million. Certainly, having a balance sheet to fund major renewable generation development is important. So certainly, our balance sheet puts us in good [ steed ] for the funding of our renewable program. Just to call out there around the DRP being active for the interim period. Debt diversity. So quite a very diverse profile of debt, with maturities right out to 2052 or 2050 for our capital bonds. If held to the 30-year maturity. We are planning for a $300 million capital bond refinanced in July this year. So that's in train. So more to come on that. But again, very happy with those different funding sources, both domestic and offshore to provide that balance sheet strength. Just a bridge on guidance on Slide 21. So we've -- we issued guidance and have confirmed that throughout the year at $835 million. Guidance with these results is up to $880 million. Various components to that, we're expecting to see our geothermal output down slightly. We've talked to these price outcomes certainly in terms of time of use, price outcomes in the market, both for energy purchase and generation supplied, contributing over $40 million of that uplift, stronger outcomes in terms of our pricing to the commercial and industrial customers. Settlement residuals related to loss and constraints. The market has been very interesting. I think the FTR option premium, settlements for the gross market have been $21 million out of the money. So that's $21 million that effectively feeds back into the LCR pool for distribution back to parties facing wholesale prices. So that's been pretty interesting with the lower prices, particularly in July and August versus futures. And then we see an uptick there in operating expenses against what we guided initially at $835 million. But very pleasing to see EBITDA guidance at $880 million for the full year.

Thanks, William. So to sort of wrap it up before we move to questions. Summarizing the first half, important announcement with Ngatamariki for our future generation, completion of Kaiwera Downs, strong trading margin that is reflective of the portfolio and comparing with PCP with much higher hydro, lower hydro, but still a strong trading margin. Challenges in geothermal drilling, however, we'll get that back on track, $0.093 interim dividend declared. Yes, higher operating expenditure inflation, and full period of NOW, new wind generation coming into the portfolio maintenance and insurance costs. So some headwinds that I think many are experiencing. Retail integration, done and dusted. So as we look forward, looking forward to being able to move Kaiwera Downs 2 forward to investment decision using our single retail platform to now grow our position as a leading multi-product utility player, getting an alternative drilling rig contractor in place. We continue to work hard, advocating for a whole of system view of the transition. That's -- and we will continue to do so. New Zealand can't be successful in this space without the full supply -- the full value chain working together to get both distribution, transmission, generation and customers all lined up. And that is critically important in our view. Dividend guidance unchanged. EBITDAF guidance updated to $880 million, subject to hydrology, as Williams just explained, CapEx at $135 million. So good half year, with a lot of work to do, wood to chop in the next half, but we're feeling very positive about that outlook. We'll close and open up for questions. Thanks, operator.

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

Can you hear me?

Yes.

Yes.

Fantastic. Great uplift to your EBITDA. But can you just help us on what is one-off in that and what is more organic? So the LWAP, GWAP, does that normalize out as we move into the following years? Also the lost rental rebate. So that change in the ruling where the alliance companies used to connect their not yourself, that came through April last year. Did you factor any of that into your guidance initially? And does that -- the number, do we get, put $4 million, $5 million into our forecast in the future for that change in the rulings?

Yes, I'll have a crack at that question. So yes, LWAP, GWAP, it's quite volatile. So it's -- if you look across the last 5 years, yes, it does move around quite a lot. This year has been certainly favorable. I wouldn't bank on it recurring every year. But we have -- we certainly have seen some benefits in terms of the leveraging the hydro system during peaks. It's done -- the Waikato has done a pretty good job in that, and we certainly have seen on the demand side with customers, their profiles generally don't respond to pricing, but just driven by temperatures and underlying activity. And so that's -- it's just -- you just don't get a correlation between price like you do with our generation portfolio. So that's been positive. The loss and constraint stuff, yes, it is a change in terms of the way those are distributed back to parties. There were -- we had accounted for some of it, but it's increased. So they call out around the FTRs that has increased. Sort of loss and constraint residuals because those premiums, particularly the people that have bid for FTR contracts have overpaid relative to settlements to the tune of over $21 million in the half year, that's quite a big number. And again, those -- most of those rentals are driven by losses on the grid. They are marginal. So when you do get higher prices, then essentially those rentals do expand and contract. So again, they even got higher volatility than LWAP, GWAP. So very, very difficult to forecast. But certainly, in the short term, we can't see drivers for those -- either the price yields, all those loss and constrained rentals to change materially, certainly for the next 4 months. So we've extrapolated those through into our latest guidance.

Perfect. And then the $160 million CapEx for the 8 drill holes, do we now think of your drill program over the longer term at $20 million per hole and you do about [ 1.3 ] over time. So does your maintenance CapEx over the longer term go up? Or is there just some sunk costs due to changing supplier or driller?

I think it's a combination of both. It's certainly -- it's not ideal having to change horses midway, but it was a decision that was necessary. We're still in the process of negotiating with an alternative supplier. So that's the -- still in trying. We're certainly seeing price escalation, certainly, casing costs, those sorts of things. They do fluctuate. We'll see whether global supply chains sort themselves out, when we get some price reductions into the future. But yes, at the moment, based on the current cost of drilling, that will lift CapEx attributable to our geothermal plants. It's not just drilling. I mean that includes -- $160 million includes sensually connection, so the piping networks to a site. So again, that can be -- that can vary depending on where on the field, you're actually drilling holes, how distant from the plant or whether you can utilize an existing pipe system.

Pulling back the KD2 output, about a few gigawatt hours. Can you talk to how wind costs are changing at the moment and whether it's still feasible to put wind up in this country at the moment?

Well, I think it's still feasible on the better sites. So it is quite site-specific. So yields matter much more in a high CapEx environment than in a lower CapEx environment. So I think it does become very project-specific, Grant. The -- this year with KD2 is simply a layout issue where we can optimize the yield against the amount of CapEx put in. So the incremental benefits of the additional turbines don't make sense against their operating yield is kind of where we've got to. Certainly, on lower-yield sites the current sort of trajectory for wind turbines is pricing is makes them more challenging than they might have been 4 or 5 years ago.

And a final question just on the elephant in the room. How is it going with Tiwai, are you still prepared to supply a South Island wind farm to them, and is there any time line on that outcome?

No, no real information I've got on time line. I think we've been pretty consistent to say that we're happy to keep talking with Tiwai. I think one of our competitors was much more effusive yesterday, and I'll probably leave it at that.

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

Just a couple from me. I just wondered if you can give us a feel on the geo drilling campaign. There's a 25% increase in the cost there that you've noted today, just how much of that is scope versus inflation. I've got a couple of other follow-up questions, but if you can give us a feel for that, that will be useful.

I think Stephen, as we said, we are in -- we are currently just negotiating with an alternative contractor. I think when that gets a bit more advanced, we'd probably be able to give you a better feel for how those things will play out. And the -- yes, scope versus inflation wise, it's probably more the latter than the former. But because of the different approach that comes in having an alternative contractor that will have an impact as well. But we'll probably have more to say on that at the full year.

Okay. Just sort of continuing that theme, I guess, we saw investors largely pull out of the global EPC market. I think beginning of last year or late the year prior to that. Are they still out of the EPC market here in New Zealand essentially?

I probably couldn't really give you a categoric answer on that. Obviously, Kaiwera Downs was not an EPC contract. We're pretty comfortable with the approach that we're taking which is not EPC, whether they or any other supplier would choose to do EPC in New Zealand. We haven't engaged them on that basis.

So you say your expectation is that KD2 would be -- would not be full turnkey or would not be full EPC?

Correct?

Yes. Just on the FID decision for KD2, perhaps I try and ask the question in a slightly different way. Is it contingent on an offtake arrangement being put in place?

It'd be contingent on demand in the South Island not falling through the floor.

Sorry, my question is it contingent on an offtake arrangement being put in place?

Yes, I heard the question. I just said, I mean the point I'm making is, clearly, it won't go ahead if there isn't enough demand and -- but probably not in a position to talk about the other part of the question that I think is implied.

Yes. Okay. No, no, got you. And just on guidance, can you give us an update on what you're expecting for Trustpower retail. That's my last question.

Sounds like a William question, [ he just throwing in below pass out the scrum ].

Sorry, what aspect of Trustpower retail?

Just what the contribution in your EBITDA guidance is -- what you baked in for Trustpower retail?

Well, it sort of doesn't work like that anymore. So it's all just become Mercury, with the loan...

Okay. No split out?

No, no. So once they all went into the same part, just other than those that are in the tech area, you haven't got -- they're just -- they're all Mercury customers now. So we're still -- in terms of the synergies, that's a huge focus from here on in terms of just working through those we're confident we can deliver the synergies of the business case supporting the original acquisition. And then the integration costs, we've signaled at $50 million. Again, we're on track. I think $43 million, I think it will, in the deck spent today. So a few more things to do, so we can reduce licensing costs, those sorts of things. But yes, it's well advanced. We're very pleased to have migrated all those customers and seen no discernible change in churn. So the slight reduction in electricity accounts largely driven by reduced acquisition activity. It's just difficult to be onboarding customers when you're trying to migrate customers onto a new stack. So it's just -- but we don't have that impediment now. So we're back in.

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

A few questions from me, more around the guidance. First question around the guidance or you -- but to give us an idea how much was baked in, what has effectively occurred in the first half versus second half? Or I guess another way to think about it? What were you -- what was the first half, you were assuming in your original guidance?

I don't actually know. I'll have to come back to you on that.

Okay. That's so good. Second question is just around OpEx. This sort of, I guess, been another step-up here. Is the much of that OpEx increase we could describe as one-off? And I guess sort of flowing on to what we can think about for FY '25 and slightly heading towards about $390 million for this year.

There's always things that are infrequently recurring. There's not very many examples of things that are just one-offs. So this is the area, you can see the key drivers of change are sitting in 2 areas: employee compensation and maintenance. So those are 2 areas that we've got a laser focus on in terms of how we manage those costs and how we get maximum value per dollar spent. So yes, we're working through how that OpEx stream locks for the future. That being said, the retail business is well advanced in terms of -- that's planning, in terms of delivering the efficiencies from bringing two retail businesses together from 1.5 years after we acquired them.

Okay. And last question around guidance. I think at the full year, you talked about insurance proceeds of around about $18 million you're expected to come in. It looks like that hasn't come in the first half. I assume that's still expected in the second half? And are we still looking at around about $18 million for that?

Yes, it's in that order, $18 million, $20 million, yes. So that's built into the $880 million.

Yes. Yes. And my last question, I guess, is related to -- I was going to ask just on KD2, but I think that's kind of been covered. But similarly, I guess, with the Kaiwaikawe, I think at the full year result, you were talking about offtake agreements being necessary prerequisites for both of those from funds. That language has gone here. Does -- do we take it that effectively you have an offtake agreement for Kaiwaikawe at this stage. And now it's just working through, I guess, the more fundamentals about getting a wind farm out?

So Kaiwaikawe is -- it's obviously taking us a lot longer than we hoped. If you recall, it has an arrangement with Genesis, neither party has terminated that arrangement. However, we do need to work through the -- what effectively the consequences of all of the delays that have occurred since we've been underway, whether they were the resource consent delays, the transport route delays working through the connection arrangements and also reoptimizing from a point of view of the technology. So it is a more challenging project for a number of reasons. But we would still happily sell that on a PPA basis to Genesis. There are some issues we would have to work through and issues that they would have to be happy with, but that's a conversation for when we have resolved some of the issues that we've got.

Okay. Great. And last question, just around Mahinerangi 2, and it's like you're [ reconsenting ] that, I assume that's mainly because the turbines are much bigger than they -- than the original. Is it reasonable to assume that you're looking at a reasonable step up in the size of that project, it seems to be the usual trend when you reconceives a bigger turbine?

Look, it's early days yet, Andrew, on that. But you're right. I mean, the issue is higher tip heights giving better yield, potentially fewer machines but better yields. So we need to -- we're just working through all of the technology alternatives, the connection alternatives and how that might turn up across the across the land use perspective. But we think it's important to dust all of that off because under certain circumstances, where the smelter stays, where potentially a fiber cable lands in Southland, that draws more load like data centers, one could see quite a demand for renewable electricity from offtakers as a consequence of that over the next decade or so.

Our next question comes from the line of Jamie Gray of NZ Herald.

I just wondered if you could give us some more detail around the price increases flagged for April 1, like the extent of it and what are the cost increases behind that decision?

Yes. Thanks, Jamie. Well, I suppose starting with what are the underlying increases, we are seeing a lift in all of the input costs. So if we take transmission and distribution prices, they are obviously set through the Congress Commission and regulated, but that whole process brings in the inflationary effects. We are seeing those. Our approach to those is to is to pass those through as they occur. So that's part of it. We have seen a reasonably sustained wholesale prices, and you can see those in the charts in our presentation. But we are very mindful of bill shock and impact on customers. So the extent of those it's -- they will be very regional. They will own a certain amount of our customers are contracted, but they are quite region-specific. And depending on the region, they will be between 5% and 8% at the highest. Overall, that's everything all in. And I think it's just reflective of the situation that the industry finds with input costs, inflationary costs and so forth. At the same time, as our presentation shows, we're deploying a lot of capital into new assets to make sure that we electrified to achieve decarbonization. And as that occurs, there is energy for all customers, I also note that this sector has reinvested billions of dollars over the last decade or so. And unfortunately, we're not the water sector or the roading sector.

Our next question comes from the line of Nevill Gluyas of Jarden.

Three questions from me. The first one, it was impressive to get the retail integration done so quickly. I guess my question is sort of a follow-on. Can we expect new products, and I guess I got VPPs, particularly in mind, sort of to start rolling out? Are they supported by a new system?

Well, thanks. We were pretty pleased to get it done as quickly as well. Look, we don't really want to start citing about new products. We certainly realize that there is a lot of scope when you're the largest retail player to bring products for customers to market. We don't subscribe to the argument that it's only the small nimble players that can do that. We think scale helps. So we would probably say, at this stage, watch this space, but we do have to make sure that we also deliver on the promise we made in the transaction, which was to get the synergies. And those are pretty important as well is if we're going to maintain the best pricing we can to customers. But certainly around things, looking at more time of use pricing, at EV pricing, at other things that help that's important. But what's also important is more innovation for those who are at least able to pay. So I think all too often innovative product, and people talk about this stuff. It's for the people who can afford the battery, the EV and everything else. We think it's pretty important to think about those that are most impacted by price, and we're doing a fair bit of work in that space.

So I guess as a follow on to that, we should expect to see sort of developments in GLOBUG sort of product mix?

Yes, you can expect -- we have some work to do with GLOBUG in the sense that, that has some integration work to complete, wasn't in the original program, but it is in a program now. But yes, one could see -- expect to see a GLOBUG map 2 roll out over time.

Nevill, the big opportunity, obviously, is just to cross-sell telco products, broadband and mobile to the legacy Mercury base, which we didn't have that capability. We had a very small-scale broadband offer, but there's a lot of customers there that we can -- we know a lot about them. I can contact them quite easily. So I think that's a big opportunity for us.

Yes. Great. It makes sense. Second question then, obviously, a feature of recent times for all the obvious reasons, supply chains, sort of local resource constraints, delays to projects, and I guess I just wanted to focus on that a little bit with the new term projects. So KD2, if you did reach FID, when is a sensible time to expect full power and what kind of time range of uncertainty, should we think about on that given the risks?

It depends on the start date, doesn't it? Which kind of depends on the conversation we had earlier about demand being there. But I think your question about delays, it rather depends when in the -- seasonally, it starts because of the because of the challenges of certain types of work through winter. And we'll certainly -- we would certainly expect with what we learn from Turitea have applied at KD1 to have some degree of confidence that with our contracting strategy that we would deliver to the time we set at FID. I'm not deliberately being evasive there, but it does rather depend on which side of winter you start.

Okay. No, that's useful. And my last question was just to get your views. You mentioned you're sort of advocating for a whole system view. In your view, what are the big gaps right now?

Well, I think the situation -- so look, we've had a change in government. That government is now in the process of obviously doing its first 100 days, and it's repealed the NBA and it's put the RMA back in and so on and so forth. It's talking about fast track consenting. I think we all know that there's been a significant number of potential new projects announced. There is a queuing process within the transmission system to get in line for those. So I think, really, if the landscape has been made more -- yes, better from a point of view of protagonists to go on and get on with the work. I think the question then is how does the sector work together? And I don't mean that in a commerce act situation. I mean that in a way that generators, large like us or small players or the new solar people that have started up operate with distribution companies and the transmission system. And we've got to demonstrate to society at large. And I think this government, which is trying to get out of the way and focus on the things it needs to influence that we can deliver and we've got to deliver on the basis that the lights stay on that the costs are reasonable and we make the progress towards electrification and sustainability. So it's going to be about people with the right mindset, I think.

Right. Okay. And just I suppose it's been one of the efforts of MDAG or one of the highlights of their work is suggesting there's maybe a hole in the contract space around firming. I mean do you guys have sort of products and development or even working with them now that sort of provide, if you like, firming both ways, sell or buy for independent generators?

So we have -- well, in fact, we made...

The sleeving deal...

We made the sleeving deal is a perfect example of that. And we'll -- look, we had taken a view that we'll price anything that anybody comes to talk to us about. And look, the MDAG report has a whole bunch of stuff in it, which no doubt will get worked through over time. I come back to the sort of basic situation that New Zealand has a wholesale market that has, by and large, kept the lights on now for 2 decades or more, and has done it with our dollar of government money going in, which are with other subsidies, it is becoming increasingly renewable. So I think we just have to be really careful as we work through those things and we just don't throw the baby out with the bath water. But it's important that the -- it's important that these new players who -- if they're ready to take capital risk that they can operate in the marketplace. So the EA plays an important role in ensuring that market accessibility works.

I'm showing no further questions at this time. I'd like to turn it back for closing.

Thank you, operator. Look, thanks, everybody, for coming on the call or on the Internet. We will close at that. And again, thank you for your attention.