Morning, and welcome to the Contact Energy annual results for FY22. Joining us today, we've got Mike Fuge, our CEO, and Dorian Devers, our CFO. Hand over to you, Mike.
Okay. Kia ora tatau. Welcome to the full year results presentation and a couple of announcements which we're very proud of as a company today. Without further ado, let's kick off. Go to the next slide. Sorry, that's me. The usual disclaimers and important information, which I presume everyone has read. If we acknowledge that and just move quickly to the way we're gonna play it today. I'll go through the FY 2022 highlights and market update. Dorian will then kick in with a detailed review of the financial results. Both Dorian and I will do the strategy update, and then there's a fair chunk of supporting materials there which we hope gives some color and detail to the results we're announcing today.
Look, another strong performance, despite the volatile market conditions, and we are ramping up our investment. It was a year of two halves, I think, which a number of analysts have pointed out, from very, very good hydrology in the first half the year to very dry and now back to very strong hydrology. All of which has led to another year of very solid results, which are close to the maximum that Contact has delivered, without any new generation. They are volatile conditions, as you can see now in the market, but we continue to generate well. Gas field declines and high coal prices have obviously played into how the market has evolved. We've responded.
Obviously we have increased renewable generation output, and we continue to develop our thermal strategy, and we're down by about NZD 16 million compared to FY 2022. Again, as I would emphasize, a very strong, robust result. We set this strategy out 18 months ago, and hopefully what you see today is us actually delivering on it in a very short space of time. Growing demand, growing renewable development, decarbonizing our portfolio, and creating those outstanding customer experiences, all of them underpinned by being true to our ESG commitments. The operational excellence which you see end-to-end across the business and the generation arm right through to retail. The transformative ways of working, attracting talented New Zealanders to come and work for us is absolutely key to the go forward in this plan.
18 months, this is a bit of a scorecard. You'll see the green there in grow demand, Southern Green Hydrogen. The team have completed some great work, and we expect that to be finalized over the coming 12 months. We've had some very positive engagements with several parties about electrification. Lake Parime data center is underway. User electrification probably gone a bit slower than we thought, but we see some. What's on the plus side, there's been some great creativity. As Rio Tinto signaled a couple of weeks ago, those negotiations are underway, and there is goodwill on both sides. Look, we have supported around 50 MW of new market, lower South Island electricity demand. It's not just about Lake Parime, but there are other projects in there. Renewable development.
Tauhara is underway. It's over 50% complete. Te Huka 3 we've announced today. You've got to remember that project didn't exist twelve months ago. Very proud of what the team created. We'll talk a bit about that later. It's got some very nice attributes. The solar partnership with Lightsource bp. The wind team with Roaring Forties, we've got a wind mast up. We're hoping for more. We have completed the assessment of the grid-scale battery. Obviously, lithium prices have put that on hold, but when it's right, we'll be able to build a battery. Decarbonizing our portfolio. We announced the closure of Te Rapa in 2023, which will release around 200,000 tons of carbon per annum and renewed our commitment to on TCC to 2024.
We're on target to meet our both our medium and long-term carbon reduction commitments. I would call out that you remember, this is a journey that we've been on for over a decade now, with the closure of New Plymouth, Ohaaki, Te Rapa, the reduction has been significant. Thermal review is ongoing. The swap option that we announced with Meridian in very, in many ways is a template for how the industry could organize itself for insurance products, as we go through the decarbonization transition. The outstanding customer experiences. Look, we grew by 50,000 connections in the last 12 months. Split roughly 50/50 between electricity and broadband with the difference made up by gas.
We launched that time of use offer with Good Nights, which we look to extend into an EV product offer. The wireless broadband we've piloted, it's ready to go live in the next few months. We're looking for a new brands and products. Obviously, we're very proud of what the team have achieved. They have won awards, they have grown market share, they have been innovative, and the broadband still remains an incredible part of our proud recent history. Tauhara. Look, it's not an easy environment out there, but the team aren't gonna die wondering. They have responded to both the supply chain, the COVID issues, and unbelievable construction industry inflationary pressures. They've been agile, they've been creative. It remains an absolute cracking project.
168 megawatts, remember that is equivalent to a wind farm 2.5-3 times that size in terms of output. Its plant capacity factor is second only to a nuclear power plant in many respects. And its carbon is remarkably low. That number there translates to 50 grams per kWh by manipulating around your exponential multipliers. And we've secured the subsurface production potential. In fact, the team have gone over and beyond, which forms the basis of the other announcement today for Te Huka, remembering that as part of the Tauhara field. Delighted about that. Demand. Obviously, as we come out of COVID and with economic uncertainty, the closure of Marsden Point Refinery, Norske Skog, demand dropped slightly in the year.
We see reasonable green shoots in the medium to longer term around that. We are seeing with the, it's a wet year, as everyone knows, particularly up north. We expect on average that demand growth to start growing in the future. Hydrology being on average for us improved hydro inflows compared to FY 2021, and the storage is reasonably healthy. We're also seeing positive signs on Maui and Pohokura in terms of gas and the go-forward, so a good result. Look, this graph we've been presenting for three years now about the various items which affect long-term electricity prices. There are some international effects. There are some local effects. Just wandering around the circle there, aluminum remains at very high.
It's come off its peak a bit. Methanol prices remain high. Gas prices and carbon prices remain high. Demand is in line with the expectation. Coal prices have gone through the roof with the Ukraine conflict, and hydrology is reasonably strong. All of which leads to the graph on the right, which shows an increase in sustained prices, which quite frankly, and I think a number of analysts have pointed to, the price of firmed, reliable electricity is probably a bit higher than what people anticipated 3 or 4 years ago, as opposed to intermittent wind and solar. Retail competition. Very proud of what the team has achieved here. It remains intense. We're delighted with the growth that the team are able to deliver. Obviously, it's not a market that's slow. There's a lot of dynamic in there.
It's an intensely competitive market. I think it's a market that we can all as Kiwis be proud of, particularly the turbulence you see going on overseas in Australia and the UK and Europe at the moment. The competition is delivering for customers. Climate change and regulation. Look, I do wanna talk a little bit about that because I think, particularly in the turbulence we see overseas, we do see bipartisan support for the regulatory framework for the market we have. You know, the commitment to addressing climate change is bipartisan, which is great for this country, allows investment confidence in the road ahead. You see the first emissions reduction plan. You see the very significant increases in the GIDI Fund.
In terms of renewable generation, the resourcing consenting reform, obviously, climate change will be a key part of that. The emissions trading scheme, which is under review, but there is a strong commitment as that being a key driver of decarbonization in this country. There is the wholesale market review, and the New Zealand Battery PPA project and transmission pricing methodology, which is now implemented. It's worth just spending a little bit of time on that about how we are responding. Look, wholesale market volatility, couple of things in there. Prices have spiked very high in the ASX; if you look forward, is showing a significant increase. We've responded.
We've announced another 0.43 TWh of investment today, which again, is the equivalent of 120-150 MW wind farm. We've announced our investment in wind and solar development, and we are very committed to responding to that call. The investment signals are there, and so responding to those is a key indication that the market is working. We've worked very hard with our customers, look, given this volatility in prices, particularly large C&I customers, is moving them to long-term PPA type contracts. I think that works for both parties. It works well. It enables us to commit to more renewable projects. It enables industry to have certainty around their input energy prices in the go forward, and to renew their commitment to help out on decarbonization in the country.
Obviously, we continue our engagement with the EA. Climate change, we absolutely support the target of 50% total energy consumption being renewable by 2035. We will continue to develop and assess the opportunities in our pipeline for that. We continue to get alongside the government in this space. We work with others in the industry, obviously, for thought leadership around how we deal with the challenges in front of the industry at the moment, whether it's dry year risk, whether it's interseasonal variability. How we as an industry, while maintaining an intensely competitive market which we have today, can actually find the right settings and investment and ensure the right outcomes for consumers. Our carbon commitment, we have definitely covered our position there, and investment in drylands carbon has been a key part of that.
The New Zealand battery project. Look, it's not so much the solution as asking the right question. That is the question to be at: how do we cover interseasonal and dry year risk? Onslow hogs a lot of the attention. I think there are other solutions out there that need equal consideration, and as I always have maintained, it's not gonna be A, B, or C, it's potentially D, all of the above. All we ask for is that each option is assessed fairly and the market is allowed to throw up the innovation and most economically efficient solutions. Given the creativity of Kiwis, I have no doubt that this will be very much a feature of the go-forward solution.
For the transition, look, whatever solution there is, it's gonna take a wee while to come into place. It's important that there is an orderly transition, security of supply, reliable electricity supply, having electricity supply when the wind isn't blowing or the sun isn't shining, is absolutely critical to ensure that we keep Kiwis engaged and enthusiastic about the transition. Energy hardship. We're playing our role here, obviously through ERANZ. That entity's done a lot of hard work. Typically, we don't see prepay as a product. We see it simply as a means of paying for the range of products and services we have. It may take us a little bit more effort and cost in terms of the way customers engage with us, but that is a key principle.
Obviously the work with ERANZ around energy poverty and making sure that we as an industry address that well going forward is critically important. Right. Dorian.
Thank you, Mike, and hello, everyone. As usual, I just wanted to start off by talking about some of the key topics that came up in FY 2022. The first is our mean hydro year EBITDA has continued to progress upwards. A few years ago, we talked about it being NZD 480 million. We guided to NZD 520 million for FY 2022. We continue to see a sort of positive thematic going forward. Market-linked channels from a price perspective, we think they're gonna remain high, linked to the high and escalating thermal fuel and carbon costs and the longer term channels which, like retail, which to date haven't really repriced. We're expecting more escalation in those going forward, you know, linked to the increases that we're seeing around CPI.
All of that sort of comes together in a guidance for FY23 EBITDA of NZD 550 million. Second point, which Mike sort of talked about a little bit was we've seen the firm long-run marginal cost of building renewables in New Zealand increase, and that's important because that sets the long-term electricity price. It's increased from historic levels of about NZD 85 per MWh to, we believe, somewhere now between 100-110 dollars per MWh, and that's a real number. The reason why this is important, because it demonstrates there is some inflation protection in industry income streams. As inflation goes up, WACC goes up, long run marginal costs go up, and electricity prices go up. Next topic.
We're a capital-intensive industry, but no one actually reports return on invested capital apart from the major energy user group, and they've got a relatively unique way of defining it. We're gonna start reporting this now going forward. We think it's now definitely the right time because with us deploying a lot of growth capital into the markets, it's important that investors can see the returns that we're making on that. We're gonna do it on a rolling four-yearly average because that irons out the annual volatility that you get in hydrology. Our starting position at the end of FY 2022 was 5.6%, which we do recognize is below our WACC. There's an opportunity for us there to improve.
I can assure you that all the growth capital that we're deploying at the moment is gonna deliver returns significantly higher than that. Mike talked a little bit about the demand environment. It's continuing to firm going forward. We've got that 50 megawatts of new market demand that we're seeing in the lower South Island based on opportunities signed up. We've got the aluminum smelter, which is very profitable, and we're expecting that to continue into the longer term, 'cause when you look at the supply and demand dynamics of aluminum, it favors the producers. In particular, if you've got a green smelter like the one we've got in New Zealand. You've got hydrogen export opportunities that we're looking at, but some really interesting hydrogen domestic opportunities as well.
You've got the data center opportunities coming through. The GIDI Fund, as Mike says, has been increased in size tenfold. It's now over NZD 600 million. Remember, that's the fund that's set up to support industries getting off fossil fuel onto renewable energy sources. Actually quite importantly for the dairy industry, it now covers the subsidy on grid connections, which we know has always been a bit of an issue for them around converting to electric boilers. We talked at the half year, we sold half the volume of Tauhara. We've sold it to counterparties with relatively strong balance sheets. That's important not just from a credit perspective, but it also these are players that could have contracted with independent power producers.
We think it's good in terms of carbon emissions that they didn't, because obviously that's generally solar, which has got a very low capacity factor, which means thermal generation has to stay around for longer. Far better you contract with a new geothermal plant which is at 95% capacity factor. The last point, which Mike actually mentioned is around the Turitea announcement and the closure from July 1, 2023. That takes 200,000 tons of carbon out of the atmosphere when it gets displaced by building more geothermals. That's important that we continue to demonstrate that visible leadership across the industry around decarbonizing not just our own portfolio but the industry's portfolio.
Remember, we're asking other industries to invest in their own decarbonization and consumers with things like EVs, so it's important that we are also decarbonizing our own backyard as well. Taranaki was actually a relatively efficient baseload thermal plant, so it does demonstrate what we've been saying for a while, is it's not economically viable to run baseload thermal generation anymore. In particular, if you take the market price of carbon, natural gas and coal and put it through any model, you'll end up with a short run marginal cost which is a lot higher than any of the net backs you can get through selling electricity. On to the financial performance. Profit NZD 182 million was down by NZD 5 million.
Within that EBITDAF is down by NZD 16 million, and I'll just sort of talk you through that. Our renewables were up by 111 gigs, and that allowed us to displace thermal generation and acquired generation and save NZD 41 million of costs, and you can see the benefits of that coming through in our Scope 1 emissions. However, even though we had more renewable generation, we actually saw our sales volumes drop by 301 gigs including and that includes merchant length. That reflects the fact that our thermal generation was down by 547 gigs, which was actually more than our renewables was up.
The reason for that is we acquired less gas year-on-year, about 4.5 PJs less gas, and we're only comfortable taking our gas storage down to 4.7 PJs, 'cause we always wanna retain some residual gas there for future fuel risk. The other topic is with the wholesale pricing dropping year-on-year 'cause of better hydrology naturally in FY 2022 relative to FY 2021. Fewer opportunities to get merchant length by acquiring generation like the spot like the swap option, so that also impacted our sales volumes. That was a NZD 6 million impact. With Contact being sort of 80% renewable, you'd expect us always to be in a situation where the cost inflation on our thermal assets and acquired generation is higher than our price.
is lower than our price increases. Unfortunately, this wasn't the case in FY 2022. We had an unusual situation that in FY 2021 we had good hydro inflows in autumn going into winter. At times when other people's catchments were relatively dry, so we got some very good lengths at some very good pricing, which hasn't obviously repeated, and there's about a NZD 24 million headwind associated with that. We've also got the full year impact of the transitional TY contract flowing through, and we'll talk about it in a bit, but we had relatively modest increases in terms of prices with our retail business, and that reflects, you know, the focus on the consumer and also, you know, regulatory risks associated with that channel.
Overall, that left us in a position where our pricing was actually down by NZD 10 million, even though we saw NZD 26 million of cost inflation on acquired generation and thermal fuel. Location losses were up by NZD 9 million. That's a function of more South Island generation up with the hydro, but also less North Island generation with less thermal and acquired generation, and then other income and expenses and fixed costs were up by NZD 6 million. That's the EBITDAF. In terms of the back to net profit, depreciation was higher by NZD 13 million. As we're going through our S/4HANA project, we're identifying components with the legacy SAP system that won't be needed in the new one and accelerating the depreciation on that. Going the other way, we had interest costs were NZD 14 million lower.
Our underlying interest is lower year on year because we've got the full year benefit of that equity raise that we did in February 2021 flowing through, so that's worth NZD 3 million. You've got NZD 11 million more capitalized interest associated with Tauhara as that project gets close to completion. We had capital work in progress on average for FY 2022 with about NZD 200 million higher than FY 2021 for that particular project. Tax expense is lower by NZD 3 million linked to the lower profits, and then we've had a favorable movement of NZD 7 million on our fair value of financial instruments.
For the technical people out there, that's because we've had a big increase in interest rates that everyone will be familiar with and the impact that has on our interest rate swaps. In terms of the performance across our three segments, the wholesale business up by NZD 21 million from an EBITDAF perspective, but retail was down by NZD 39 million, and that reflects, you know, we have an arm's length market-driven transfer price into the retail business. As I said earlier, it hasn't been able to recover that from customers. That's not a Contact topic. I mean, that's the same across the industry, I'd expect. Then corporate costs are down by a couple of million NZD year-on-year. We now get into the wholesale business.
Generation costs are down by NZD 42 million year on year. That's a function of the higher renewables, but also, like I mentioned, the having access to less natural gas. That meant our thermal generation was down by 33% and our acquired generation was down by 30%. We are getting a lot of cost inflation coming through here, though, and we expect that to continue into the future with higher thermal fuel and carbon costs. Fourteen percent increase in the marginal cost of running our thermal generation, which is up at NZD 109 per MWh now. Then a 22% increase in our acquired generation costs, which is up at NZD 142 per MWh now, with that sort of indexing to what's going on for international coal prices, which Mike mentioned earlier.
The other topic to call out is our gas and electricity transmission costs dropped by NZD 6 million year-over-year. There was more constraints on the grid in FY 2023 than there was in FY 2021. Our transmission rental rebate was NZD 3 million higher. If you also remember, we contributed NZD 2 million to Transpower in FY 2021 to get them to hurry up and start the Lower South Island transmission upgrade. That's obviously non-recurring.
Just to add to that, I mean, that was a fantastic investment for us because we're already seeing the benefits of that with all the downpours of water that we've seen in the last month or so, with prices in the Lower South Island connected to prices in the rest of the South Island and the ability to export more water. Obviously, it's good from a Tiwai mitigation perspective, because now our exposure to a Tiwai exit isn't just our South Island Lower South Island generation market share, it's the South Island market share, which is a lot lower. In terms of generation, geothermal, very good performance, 3.3 terawatt-hours. All the assets performing very well. Hydro, a mean year. It makes it sound quite simple, 3.9.
As Mike said, very volatile. We had a huge swing between halves, 850 GJs less water in the second half than in the first half. Because the replacement fuel costs keep escalating each year, that volatility costs more and more money. That's worth about NZD 100 million, if you price that on a fuel replacement basis. Also linked to the lower hydrology in the second half of the year. Unfortunately, we had some challenges with our thermal assets, so we were actually without both peaking from March through to May. We've got a crack on the radial of TCC, which is limiting the operating hours that we can use that for.
In order to conserve hours for the winter, we actually took TCC out of action in April as well. That actually meant April we had no thermal assets available apart from Whirinaki, which, as you'd expect, coincided with a very low EBITDA that month, although we were 100% renewable. Just on the assets, TCC, we're expecting to have available for the winter, and then we'll take it down, repair the radial. We're expecting the second peak to be back in September. I would say about TCC is, you know, once the radial is fixed, the condition of the asset is very good.
We've got the contracted gas, and the market conditions going forward around the ASX are conducive to us keeping TCC up and running till September 2024. We don't expect any CapEx to enable that. That's obviously good from an industry perspective 'cause it continues to displace coal. In terms of wholesale contracted revenue, just wanted to talk a little bit about the market. When you look at what analysts are predicting in terms of industry EBITDA growth, like for like, I think it's up about NZD 150 million. You can get to that number. There was some big one-timers, adverse one-timers in the prior result. I'm thinking about Genesis dispute on carbon with Beach.
Mercury had the issue with Kawerau and writing off that out of the money position with Norske Skog. That's worth about NZD 60 million, I reckon. In terms of fuel, lower fuel costs in FY 2022, you've got 1.4 terawatt-hours more hydro, and you've also got Turitea coming to market as well. You've got about NZD 140 million in lower fuel costs. It's about a NZD 200 million increase in EBITDA for that. Going the other way, you've got the full year impact of the transitional TY deal, which takes you down to NZD 150 million. You notice I didn't mention anything about channel pricing in that. It basically means that any price increases that the industry has got have just offset cost inflation.
With most of the cost inflation being linked to thermal assets, which only make up 20% of the generation, you're probably scratching your heads going, "How can that be?" That does highlight the issue is that there's about 60% of volume isn't repricing. It's either TY or it's mass market. I'll get to that point in a bit. If you look at the context of the channels that are repricing, C&I is up at 115, and our CFDs now are up at 139. Our strategic fixed price channel, which is TY, and it also includes all our long-term contracts that we've signed that have got inflation protection. That saw a price reduction, but that's linked to the transitional TY deal.
If you look at the transfer price into the retail business, remember that the forward market driven up by NZD 13 a megawatt-hour, but you'll see on the retail side, issue is that's not being recovered from the market. I made that point right at the start not to sort of downplay the sector, but it does highlight the opportunity around repricing of TY. It also highlights that, you know, our mass market channel for us is the lowest net back of all of our channels, with the exception of TY. In terms of our wholesale trading and merchant revenue, a big drop here of NZD 87 million. This reflects what I talked about earlier.
We were able to get long in FY 2021 into some very good pricing because we had favorable hydrology when others didn't. You can see the impact of that in terms of a falling wholesale price that we're getting there on our long. Also just with wholesale prices dropping on long, less opportunity to, you know, run thermal kit and acquire generation. Therefore, our merchant long went down from a volume perspective too. In terms of location losses, already talked about those. Those were up by NZD 9 million year-on-year. In terms of our retail business, I said at the half year, you know, there have been some quite big changes with the external environment.
I'm thinking Tiwai staying beyond 2024, which we have always been pretty positive about, and Tiwai are now positive about as well, based on their announcements. We've seen some significant increases in inflation. We were going to look at the settings regarding retailing of electricity. Before we get into the performance, just want to give you three sort of conclusions on that. With retail net backs now so heavily discounted from other channels, we don't see value in increasing our retail load from where it is at the moment. However, we do see value in continuing to bundle and non-energy products with our existing customer base, and leveraging fixed costs and building on the success that we've had around broadband.
With price changes for this channel more linked to CPI, because it is a consumer-facing channel and a longer-term channel in our view, we do see more price escalation going forward linked to the higher levels of CPI, which we think will start balancing this channel back to others and closing the gap. In terms of the overall performance, you can see that disconnect between the market and consumer prices coming through in the retail electricity gross margin, which is down by NZD 43 million, with tariffs only up by NZD 5 or 2%. We saw earlier that the transfer price into this business was up by NZD 13 per megawatt hour.
We have been very successful around connection growth, and we've got consumers telling us they really want to decarbonize, but they don't have the tools. The Good Night product that Mike mentioned is exactly the type of tool they're after. It incentivizes them to shift their load off-peak from peak times to off-peak, which decarbonizes the overall electricity portfolio. That's fantastic. Connections were up 25,000 as a result of that. If you look at gas margins are down by NZD 5 million. While we put tariffs up a lot, there's three levels of inflation coming through now. ComCom has signed off an accelerated capital recovery for the gas infrastructure owners.
We're seeing 13% increases in gas transmission on a like-for-like volume basis this year, and then it's going to continue to go up 10% every year thereafter. That has to be recovered. You've also got higher carbon costs coming through, and you've got the higher fuel costs coming through. Unfortunately, remember, this is a traded product for us. We'll need to continue to look at our tariffs to recover those three lots of escalations that are coming through. Broadband's performing really well, NZD 7 million of EBITDAF. Even when you overlay the OpEx associated with that's still NZD 5 million of. Sorry, EBITDAF, NZD 7 million of gross margin.
In terms of cost to serve for this business, continues to outperform very well, down by NZD 1 million year-on-year, even though we have 51,000 more connections. That talks to all the work that's happening around digitalization. We've actually got to the point now where our call center staff can actually handle twice the number of connections that they could in the previous year, which obviously all flows through as productivity, which is fantastic. In terms of greenhouse gas reporting, as I said earlier, as you'd expect, that's down. Scope 1 emissions are down by 258,000 tons linked to the increased renewables. Scope 3 emissions are down due to the lower use of a swaption. We do report the swaption as a Scope 3 emission, even though it is a financial product.
As I said this last time, if we didn't call it, Genesis wouldn't run the ranking, and the emissions wouldn't go into the atmosphere. That's just us being genuine. Within Scope 3, though, within that, you see a little tick up, and that relates to the construction associated with Tauhara. Sustainable construction is something we take very seriously, and in particular, with the increased renewable development we're doing, we're looking at opportunities around that. In terms of our OpEx, I think we said previously that we'd taken NZD 13 million of metering costs out of OpEx and disposed of that as gross margin. That's to align us better with what others within the industry are doing. We've restated the prior year to be aligned to that.
OpEx is up by NZD 12 million, 6%, and the slide sort of explains the key movement. We've got a bit of full year impact of our acquisitions that we've done flowing through there. There were some one-timers, a number of one-timers in the prior year and this year, which sort of nets to NZD 1 million increase. We're seeing bonus costs for staff lower because we had a very strong performance in FY 2021. Then you get to the underlying performance where the OpEx is up by NZD 5 million, which is 2.5%. I'm actually quite happy with that because you've got some quite high underlying inflation within that. Insurance is 7%. Sort of underlying general inflation is about 6%, and we've invested NZD 3 million more in our brand.
We've been able to keep a cap on OpEx because of the productivity, not just the digitalization, but the good work the procurement team are doing around where we're rolling over contracts with suppliers, making sure the escalation in those is well below the level of underlying inflation. We've got more OpEx being invested in growth. This is the money that's going towards the Southern Green Hydrogen project, building our wind portfolio and the additional connections we have within our retail business. Just coming back to that brand, we don't take investing a further NZD 3 million in our brand and advertising lightly. We're actually quite proud that we've underinvested in it relative to others within the marketplace historically, because it allows us to offer more competitive pricing.
With the value of the brand sort of transcending both the upstream part of the business and the downstream part of the business, and our strategy around leading the decarbonization of New Zealand and building a lot more renewables, we do think now is the right time to have a strong brand within the marketplace. Our cash flow. Remember at Contact, we talk a lot about cash conversion, which is what percentage of our EBITDAF actually converts into operating free cash flow. Remember, it was quite low at the half year of 41%, but we did predict that it would improve and get to 60% by the end of the year. Which is exactly where it's ended. It's still slightly lower than the 67% we achieved in the prior year.
Just some of the reasons for that, we've seen a NZD 17 million investment in trade working capital, which is obviously negative from a cash flow perspective. There's a few topics driving that, but one in particular, the staff bonus accrual was lower in at the end of FY 2022 than it was at the end of FY 2021. Obviously the bonus costs are low for the reasons I've already mentioned, but we've also shifted our remuneration structure. Anyone below senior manager has now had all of their at-risk short-term pay bought out and gets paid out in their monthly salary, which is obviously negative from a cash flow perspective. We're seeing CapEx higher at NZD 75 million, but this has been guided.
This is the sort of NZD 100 million of additional stay in business CapEx that we talked about spending cumulatively over the next four years to support S/4HANA and some projects which increase the resilience of our renewable assets and get a few extra gigawatt hours out in terms of the Roxburgh Runners. That's important to do that at a time when prices are relatively high. All of that gives an operating free cash flow of NZD 0.418 per share. Dividend NZD 0.35 per share. There's some retention there which go towards building high quality renewable development. Then you can see in the top right our new KPI, return on invested capital. In the appendices, there's a lot of workings to actually explain exactly how that's created.
You can see it's on an upwards trajectory, up to 5.6%. One of the reasons why it is a little bit depressed at the moment is aligned to our Contact26 strategy. We are accelerating the depreciation on a number of assets based on where we see the asset portfolio being in a number of years' time. In terms of balance sheet and interest, the half year our interest expense was relatively high at 5.7%. It's dropped back down to 5.3%, and that reflects us better adjusting for the money from the equity raise. We've got the percentage of variable interest back up to 29% now. Really the variable tends to be cheaper for us than fixed.
However, year-over-year interest stayed roughly the same. It's up from 5.2% to 5.3%. Whilst we've now got a bigger percentage of variable interest, we've seen obviously variable rates go up quite considerably. On average in FY 2021, they were 30 basis points. On average for us in FY 2022, they were 152 basis points. By the time you got to the end of the financial year, they were up at 300 basis points. I think everyone here is familiar with the rapid rise in interest rates. In terms of balance sheet capacity, our net debt to EBITDA is at 1.5.
Relative to our sort of BBB ceiling that we've got linked to our S&P credit rating, we've got NZD 825 million of capacity there. That will support us with our Te Huka 3 project, plus other projects that we're looking to do. We've got about NZD 390 million of go forward spend on Tauhara as at the end of FY 2022 as well. If we do need more capital for whatever reason, we've got about NZD 400 million of capital bonds that we could do and get the NZD 200 million equity credit on it.
We're gonna continue with our undiscounted dividend, DRP, but we could shift that to a discounted one and get a higher uptake, which, you know, others in the industry have already done. In terms of the dividend, we guided that the dividend for FY 2022 was gonna be NZD 0.35 per share, which is exactly where it's gonna be. We're announcing a 21-cent per share final dividend, 90% imputed. That takes the overall dividend paid and declared for FY 2022 to 84% of the operating free cash flow, the average of the previous four years. Within our guided range of 80%-100%.
We are continuing with our undiscounted DRP for shareholders as well, and we're guiding to a dividend for FY 2023 of NZD 0.35 as well, keeping it the same level as FY 2022. That does reflect we're still in a build phase. It also reflects obviously that there hasn't been an agreed new long-term contract put in place with Tiwai yet. This is just a bit more workings around our mean hydro year EBITDA of NZD 550 million. Just to highlight a couple of things. Pricing's going up linked to repricing of C&I, but also mass market going up linked to higher CPI levels.
We've got some quite big increases around transmission and storage linked to inflation and a number of regulatory changes feeding into there, like TPM, like the accelerated recovery of gas transmission for the capital recovery for the owners. ACOT's no longer available, all those types of things. OpEx is higher as well year-on-year, reflecting inflation. We've got 5% wage and salary inflation feeding through here. We've got some more money on growth and ESG type topics. We have got some one-timers. Unfortunately, we had a big favorable one-timer in terms of the Holidays Act provision release, and then we've got some one-time costs in FY 2023 as well. There's quite a big swing associated with that.
This provides all the detail which you can use for your models. In terms of the risks for that, obviously hydrology is a risk. We have been relatively modest about the amount of gas that we're assuming that we will consume with our thermal assets. If we get more gas available and the market pricing is conducive, we can obviously run our thermal assets harder and make a bit more money through those. In terms of market price risk, you can see from the donut charts, we're relatively well contracted. There's about 40% of CFDs and 30% of C&I volume that isn't contracted yet.
Right. I'll just return you to the strategy, and we'll talk a little bit about the Te Huka investment. Just mindful that, this project, as I said, didn't exist a year ago. We thought we were gonna do Tauhara, and then get on with, GeoFuture, which is next down the track in terms of the Wairākei replacement. The team, the subsurface, and the drilling campaign that we did for Tauhara has been remarkably successful. You see right on the bottom right there, we've already secured the resource in terms of, wells drilled, which is a great outcome. There was grid capacity, and there was consent available.
What that added up to was an opportunity to put in what's effectively the equivalent of a 120-150 megawatt wind farm, slotted into the development pipeline. It fits very neatly between the Tauhara project and the GeoFuture, or effectively Wairākei replacement in terms of resource utilization. The construction cost. Look, it's fair to say that the whole industry is experiencing construction cost inflation. Our market intelligence out of Australia is that they're seeing pressure on wind farm developments and solar developments in the order of 30% from what the numbers that people were experiencing 2, 3, 4 years ago. The cost is in line when you take into account the inflators from roughly in line with what we put into market around 2017, 2018.
We are confident in the number. It does allow us to take advantage of both the retirement of Te Rapa, but also the fact that at the moment, you see firmed prices for reliable firmed electricity in the go forward ASX. The simple answer is get on with it, and I do wanna pay credit to the team who pulled it together in such a short space of time. We have been conservative on the estimate. We have a good EPC contract in place underpinning it and the balance of plant. We have got market bids in for those, so we're confident of that cost, much more confident in that cost estimate in the go forward. It reflects the market conditions we see today.
The added bonus there is we have the resources currently working on Tauhara, they'll swing across. We very much expect them to swing across and work on this project. Go to the next slide. This is, we've obviously got Tauhara there, and with the capacity upgrade that we announced in February, you've got the Te Huka, which we're taking it FID on today. With the GeoFuture project, just through increased efficiency of new plant, we expect another 0.4 terawatt hours there. Behind that, there is still around 0.78 of consented offtake for Tauhara, which would eventually lead to another plant, appropriately placed and sized on the field. Which leads to, for the geothermal business alone, an almost doubling in output over the next five, six years.
For our overall renewable pipeline, if you remember, mean hydrology year, we put out about 3.9 terawatt-hours of hydro. Takes us very close to that 9-10 terawatt-hours of renewable generation output from the company. You can see on the right there, the timeline as we see it playing out. You see the announcement today, the commitment on Te Huka, which goes with the commitment and the capacity increases were previously announced on Tauhara, and we look forward over the coming years to the maturation of the GeoFuture project, announcements around that second half calendar 2023. Go to the next slide. Dorian, you can talk to this slide.
This is obviously the money slide. With Tauhara and Te Huka, we are spending a significant amount of capital, so NZD 1.1 billion that we're deploying to increasing renewable development. That is gonna increase our Contact's renewable generation by 25%. That's a pretty significant number. It brings 1.825 TWh of energy per year to the market. What we want to do is sort of give a little bit of guidance as to where that's gonna take our EBITDA. We've already talked about our mean year hydro EBITDA for FY 2023 being NZD 550 million.
Of that new energy that's coming to market, 875 gigs of it will just be a fuel replacement, so it will displace Te Rapa and TCC. That just naturally happens. 700 gigs of it will just service the PPAs, the long-term PPAs we signed up with Mayuk and Genesis, which will just happen. Remember, they've got inflation built into them as well. Then you've got a smaller amount, 250 gigs, which is a merchant strip, and we've shown it there linked to the pricing in calendar year 2025 when it comes to market.
You look at those things and you go, well, assuming we execute, which we're passionate that we will do, then the only real risk there is around the NZD 250 million that's got a merchant strip price linked to it. You then got a bit of extra fixed cost, and that reflects that the fixed cost for Tauhara and Te Huka 3 are slightly higher than the TCC costs and the throughput costs that are coming out. And that's some of that because we've got the carbon costs for geothermal in there as well. Overall, that leaves us with for calendar year 2025 NZD 720 million. Remember, the other thing we haven't done there is we haven't shown any repricing of our channels.
We're just keeping that at the FY 2023 level. We'd expect channels to obviously reprice between 2023 and 2025, in particular retail. Then the other positive thing about this, you look at the Scope 1 and 2 carbon emissions, they drop from 787,000 tons down to just 350 thousand tons, which gets us well on the way to our targets that we've set ourselves. I think Mike said right at the beginning, this is also great for regulatory risk for the industry. You know, prices have been high now for a while, so that is telling us we need to build more generation, more renewable generation.
This is the first, I guess, a serious announcement that this happened since Harapaki back in February 2021. Remember, this project will happen. It will be online in the next couple of years. We don't have to worry about EPCs or financing. This will get built.
Look, the theme of today is very much about execution and delivery as well as commitment and promises. I did wanna finish saying, you've seen what we've done in the last 12 months, and I think you'll agree it's been pretty busy. Those key pillars of the strategy, we've actually executed on very substantial decisions in that, which is very much capped off by what you see today. What do you expect in the coming months and year ahead? Well, you'll see a decision on hydrogen, both export and domestic. You will see the commitment on data centers in the industry, and you'll see some pretty chunky announcements around bolder electrification. Somehow we've got Western Energy up and demand growth that's probably belongs with renewable, but we're delighted with the acquisition of Western.
What you're gonna see over the coming 12 months, the board have already committed to investment in a new core tubing unit drilling, which allows us to re-life some of the 300 penetrations we already have in the Wairākei, Ahuroa, and Tauhara fields. We see that as a real opportunity for taking down the cost of reservoir management and the drilling campaigns. In terms of the renewable, continued progress on Tauhara, you'll see Tauhara well underway. You'll see the consents for the Wairākei replacement project. You'll see us get underway on solar and wind consenting, some announcements on that. You'll see progress on the Roxburgh Runner replacement, and you'll see us re-lifeing the transformers of our critical Roxburgh and Clyde hydro schemes.
In terms of decarbonization, you'll see progress, continued progress on the thermal review that we're undertaking. We continue to develop the thinking around that. We'll be preparing for the end of the current allowance we have around TCC life, and you will see the actual closure of Te Rapa and handing the boiler over to Fonterra. In terms of the outstanding customer experiences, we've talked to that, to the success we've had to date in the last year. I do pay tribute to the team, because they've done a remarkable job in turning around a decade of otherwise decline in that business.
You will see the launch of an EV product, you'll see the launch of additional products, and you'll see, hopefully not continued growth and just straight out connections, but continued growth in the high value that we can bring to ordinary Kiwi homes in terms of multi-products, enabling ordinary Kiwi homes to decarbonize their business. We started with that decarbonized journey, decarbonization journey at the very beginning of this presentation at a macro level, and we're finishing that journey today in this presentation in every Kiwi's home. With that, we're happy to take questions.
Thank you, Mike. On the line. We'll go to the line first for questions. The first question comes from Grant Swanepoel from Jarden. Grant, unmute yourself, star six, please.
Good morning, team. First of all, thanks so much for the calendar 2025, 720 expectation.
Mm-hmm.
Help us. Just thinking about gentailers being a defense against inflation. With your dividend remaining at NZD 0.35, can you put some color around 2025 and beyond on where you think the dividend can get to? Your free cash flow per share could potentially rise from 42 cents to 58-60 cents. With an 80%-90% payout, that's somewhere between 46 and 52 cents dividend. Does that make sense? Should we be helping investors to think about that?
Absolutely. Dorian.
Yeah. I mean, we can't obviously go into specific numbers, Grant. We don't normally guide out that far. The intention is, as we've said all along, as we have increased EBITDA and operating free cash flows due to projects coming online, we increase the dividend accordingly. Obviously, we've got Tauhara coming online first, towards the end of 2023. That should be positive from a dividend perspective. The other topic is we are pretty low in the range, which we've said reflects the fact that there's not a long-term NZAS contract in place. That's the other determinant of what happens with the dividend.
I think it's fair to say, you know, the board will be more comfortable holding a dividend level that's more within the middle of the range, once a long-term deal on the NZAS contract has been done as well. I hope that helps, but I can't give any sort of specifics around the numbers that you sort of talked to, because obviously we don't do that type of guidance.
Fantastic. Thanks. Can I go on to my next question?
Yeah, sure.
It's around Te Huka. This 20% cost increase relative to Tauhara, are geothermal getting the same sort of cost pressures from the Ukrainian war that wind is getting? I wouldn't have thought so. Can you link that into your long run marginal cost expectations? In that 100-110, does that mean that you expect wind post this Ukrainian crisis to start jumping in terms of where those long run marginal costs were landing? On the Te Huka side, you had indicated that you probably weren't gonna pull Te Huka till you had a PPA against it. How are you developing on those C&I PPAs that you were talking about in the past?
Yeah. Let's just unpack that a little bit. Yes, the cost, we've been very conservative on the cost estimate for Te Huka. It reflects, in part, we don't get the scale that we've certainly got on the Tauhara plant. Remember, Tauhara is over three times the size of Te Huka. It had an EPC. It's got an EPC contract in there that was effectively done in completely different economic conditions. We are seeing, and we were somewhat surprised by the market intelligence coming out of Australia, that wind projects there are already seeing those cost pressures, particularly on coming out of steel at around 30%. That was recently. You're right, we're not as exposed to that because the subsurface is effectively for Te Huka is locked in. It's drilled.
The seam is behind the wellhead and ready to go. There is some exposure there. For those who visited the site last year, we hope to get you back next year. There's a lot of steel and concrete, both of which have experienced those cost escalations. I think you're right, we're not as exposed as wind and solar.
Just on, I think we were very mindful of the increase in CapEx on a dollar per megawatt basis. We could have waited with this project and done it, you know, six months later. That would've led to a lower dollar per megawatt. However, we do have to work through how this fits with our GeoFuture project, around you know replacing Wairākei. If we delayed it would start to impact the schedule around that. The timing was useful around integrating with that project. The other point is the market that these electrons are coming into, with the pricing being, you know, relatively high at the moment. It's gonna. You can do the math.
I mean, it's gonna throw off about NZD 60 million of EBITDA in the first year. Every month you delay it sort of dwarfs the higher capital cost that you're gonna have through announcing it at the current moment in time. As Mike said, I mean, we've been impacted by global commodity prices. One of the bigger impacts though is, you know, New Zealand prices in terms of construction costs and sourcing finished goods in New Zealand. Although commodity prices have come back down again, you know, they're still quite a bit higher than they were. Finished goods that you purchase in New Zealand haven't actually started to really come back down again yet. They sort of lag commodity prices.
Again, we are being impacted by the timing of the project, but we'd expect that to drop for future projects. As Mike says, this is a relatively small project for us. All the pre-fit work that you do around, you know, design, consenting, development is relatively a similar amount of money regardless of the size of the project. This is only a 51.4 MW project as opposed to, you know, 170 MW projects like some of the other ones that we are doing and are talking about doing. That's all flowing through. We do expect future projects to be lower.
You know, I think we're sort of talking about 5.2%-5.5%, reflecting, you know, a continued drop in commodity prices and starting to see some of the finished goods costs in New Zealand flowing through. We do think it's gonna I mean, the cost structure of geothermal and building is a bit different from wind and solar. We analyze that quite a bit, but we do see all forms of generation being sort of relatively, you know, impacted in the same way by what's going on internationally. I think it flows through in different areas, but we see it leading to roughly the same answers.
Last part of this question, Grant, you asked about PPAs, and I think the approach to this is that this project is incredibly economic with its merchant exposure. Where we're going with PPAs is we take them at a portfolio level, and obviously, you know, with Tiwai and the ongoing discussions with Rio, once we get that landed, then that sort of will set the tone for how much of the portfolio that going forward we contract, and remembering that portfolio is gonna grow significantly over the next 4-5 years.
On the long run marginal cost expectation?
Well, that's what our firm long run marginal cost expectation is NZD 100-NZD 110 per MWh, Grant, and that's real.
Oh, thanks.
Okay.
My last more technical question, just on your strategic fixed prices jumping by 450 GWh based on the start of last year. Is this taking into account half of the CFD with Meridian and the swaption? And can you give us a bit more color on the CFD and the swaption pricing?
I don't know.
Oh, no. Meridian
The strategic fixed price sales, I guess that's probably a new classification, Grant. I don't think it's jumping that much. It'll just be a full year of our sort of NZAS load.
I think the pricing should be dropping year on year, and it's the full year impact of the transitional NZAS deal, Grant.
Okay.
Yeah.
Thanks, guys.
Those forward CF, CFDs aren't in there, Grant.
Yeah. They aren't in there, yeah.
Thank you.
Okay.
Thank you, Grant. We'll go to the room now for any questions. Andrew.
Andrew.
Questions.
Thanks, follow on actually first of all, just around Te Rapa and OpEx, as NZD 20 versus the NZD 15 for Tauhara. Can you sort of talk me through that? Is that all economies of scale or is there something else?
Oh, no, it's a different type of plant. Obviously, you know, it's a different type of plant. The large scale is a bit more complex, and there is the economy of scale.
Mm.
That's probably where your expectation is.
I just have a few questions just around volatility and again, your sense of sort of have a normalized hydro number of 5, which is great. I guess the question I've got is, even going back to when you had the 480, do you think the earnings volatility has increased so the potential upside, potential downside range is greater than it was? Can you sort of talk to that a little bit?
The volatility increased, but I don't think the earnings range has. I think what you've seen is a shift. Dorian, you might want to elaborate.
Yeah. I mean, it's how it's sort of what's the normalized curve look like, 'cause we have reduced our fixed price load as well, which reduces downside risk, but provides more outside opportunities as well. I think the point around the volatility, and this point I made when I was talking about it, is because the fuel replacement costs are escalating so much at the moment, that means volatility costs you a lot more money.
Yeah.
That's the same across the industry. I think, you know, we've benefited from the fact that we have reduced our fixed price variable volume load regarding that.
Yeah.
Obviously, we've got, you know, access to a range of mitigations which support us as well.
Yeah, Andrew, that we're endeavoring to aim within the same earnings at risk.
Yeah
amount on an absolute basis, 'cause we believe we've set that at the right risk return trade-off. We've got some of our mitigations falling off, including, swap option at the end of the year, so we have continued to reduce our fixed price sales position. Yes, earnings will be more volatile, but not to the downside.
The other thing is our cash operating free cash flow is relatively stable as well because in times when there is a lot of water, we tend to inject more gas, and when there isn't, you know, we're using the gas, sort of evens out the volatility from a cash flow perspective as well.
Yeah.
Yeah.
Sure. Just in terms of swap option, a couple of quick queries from me, I guess, on that one. In terms of the swap option piece, if you could tell us what the megawatt capacity you've got there? To me, I think you've got one.
Yeah. 50, 50 MW for the swap options.
In terms of the CFD, is that just through the winter months as well?
I think it's 8 months actually, the CFD. March to October.
Yeah. Last question I just had was just around the batteries. You've done all the work on that side at the moment. I guess interested to understand how far away you are at the moment. I guess the other piece is just given the shortage of
Yeah.
Just the revenue piece on the battery economics has been improving.
That clearly offset.
I mean, the increase in lithium prices has been eye-watering.
Yeah.
That even with the increase. You're right, the intraday spread is what drives the economics of a battery, and the increased volatility is only good news for battery economics. The increase we've seen in lithium prices just have completely outweighed that. We've done a bit of work in the background. You know, we're still progressing resource consent and looking at sites. The intent is that when the time is right, we are indeed ready to go. You're right, those two, both the supply side and demand side are two very important components of it.
The other thing is to remember also when the battery was sort of ideated, it was also talked about as being a mitigation to a certain extent to a NZAS exit, because it allows you to run, you know, an extra 100 megawatts over the HVDC, and obviously that, the value of that mitigation is diminishing quite rapidly at the moment based on NZAS's keenness to stay.
Yeah. Be able to give us a sense of how much battery costs?
Well, when we started the assessment, and when we ended the assessment or stopped counting the assessment, capital costs are about 50%.
Yeah.
Yeah.
And we can't see for...
I don't know if you can get an EPC on building the battery, either anymore.
Well, the major suppliers aren't even offering hedged lithium prices. You have to take monthly price exposure.
Yeah.
Never mind high price exposure. They won't even take that.
You won't know what your costs are.
That's all.
Cool. Well, thanks again.
Just a few from me. Thanks, guys. I'll start off with perhaps just a little bit more on that long-term sort of price for you. Obviously, that's gone up a lot. A couple of questions just to flesh it out a bit. The 100 to 110 you describe as firmed. Does that mean we should expect sort of average spot prices, the simple average, to look NZD 100-NZD 110? That's what
Yeah. Yes.
The second part of that question is that sort of price range then you would expect to be selling long-term contracts to, you know, large users so that
Yep.
Yep. Yep. Location adjusted.
Location adjusted.
Yeah.
That's exactly where we expect it to.
Right. Adjusting for location, the deals you might be signing up, say, next year will be focused on that kind of-
Yeah.
Okay, that's great. In terms of the uplift, you know, there's always gonna be different technologies at the margin, but are you thinking mainly this is about wind cost? Is that sort of the main driver? Obviously.
Well-
Geothermal appears to sneak under the.
Yeah. No, geothermal sneaks under. It's wind cost, but it's the cost of firming that wind, which you think of the escalation in thermal costs with coal going to NZD 200, NZD 300, NZD 400 a ton. Gas prices going from what we thought was normal at NZD 6-NZD 8, sort of NZD 10, NZD 12, NZD 14 a GJ. It's not just the cost of the actual wind projects, it's the cost of firming and with the increased carbon price that's just come through. Yeah.
No, no, that makes sense. What you're saying is the cost has gone up a percentage, whatever that is, 10, 20, maybe.
Yep.
Yep.
You're also saying the firming gap. In other words
Yeah.
The revenue you get out of wind farm is less compared to the 100-110 that it was before.
Yep.
Can you give me a rough ratio of what that would be? Some of us, we talked about 85% GW to TW.
That's still what we're hearing in the market. Yeah.
Okay. You've still got that.
But what we've done, so there's sort of three levels on that. There's the capital cost, which are up, you know, 10%-20%. Then there's your funding costs, your WACC effectively, which are up materially on higher interest rates. We've done a wide range of views as to how we're gonna get those firming products in the future. You know, transitioning from gas and carbon out to biomass and the like. You know, there's numbers out in the market on what that means. Once you get to a certain point, every megawatt hour of intermittency you add, you have to add a megawatt hour of firming, green firming.
Yeah.
That's sort of what leads us to.
From the firming part, I think the numbers out in the market, if it's Alex or Huntly, whatever, it's NZD 250-300/MWh. That firming is-
Yeah.
Very expensive.
Yep.
Yeah.
Okay. No, that's really helpful. Thanks. Really the second thrust of questions is just around regulatory risk. I mean, you talked about bipartisan support.
Yeah.
The sort of, you know, potential left field demons somewhere in the tail curve. The ones we could see are maybe around the Climate Change Commission recommendations, the new ETS settings. They happen to have a section about potential windfall clawback on higher carbon price. There's also the Section 36 changes to the Commerce Act coming through in April next year. I'm just wondering if you have any changes in mind around how you know, separate the two parts of the retail versus wholesale. And the third one is the wholesale market review from the EA, and whether you have any kind of flavor for where that's gonna come, because we expect something this month.
Yeah. Let's unpack that a little more and just start maybe at a high level. We should be incredibly grateful in New Zealand that our electricity market is working as well as it is compared to, say, Australia, U.K., Europe, where you've seen both external circumstances such as Ukraine war combined with unfortunate political intervention. You know, the average consumer in the U.K. is gonna see their energy bill go from GBP 1,200 a year to GBP 4,400 a year. You're not talking 5, 10%, you're talking about a tripling. You're seeing the struggles in the Australian market where a cap introduced on prices, wholesale prices, had some very unintended consequences and potential brownouts, and you've seen energy bills also escalate there significantly.
Which puts the New Zealand market and its settings and its workings in context. I think, if anyone makes a decision to fiddle and play, there are some fables, you know, some real life lessons about how not to do it. Again, look, the reason we're making that investment today is because we have confidence around a diminished sovereign risk from unfortunate political intervention. You go underneath that. Obviously, the wholesale market review, we expect that to be relatively benign, but I think it will send some clear messages around major industrial players in the market here not expecting a free or easy ride. That, you know, is. I think everyone has to pay their fair share in the going forward.
I think from a retail price, you've seen the market behave remarkably well and actually protect the consumer from some very volatile swings in the wholesale market, compared to what they have actually experienced and compared to what their counterparts in the Western world have experienced over the last 12 months.
Yeah, I think we showed the graph level where you can see what, you know, retail pricing across the industry is going up. It's like 1% per year. I suspect relative to other industries and the level of price increases that you're seeing around those, the level of increases that you've seen in electricity have been significantly lower. That obviously helps, as well. Yeah.
Super clear. Thanks. Just the last kind of follow on that. So we shouldn't expect, when the new legislation, Section 36, comes into force April next year, any change in the way you're currently reporting or currently the way you operate too?
At this stage, we're not anticipating it, but we're keeping a close eye on it.
Perfect.
Remember, we do have an arm's length arrangement between both businesses in terms of transfer price. It's aligned to what we, you know, we've got an example of how we're selling to tier twos at that price as well. We're about as arm's length as you can get.
That's great. Thank you.
Okay.
Thank you. Any further questions in the room?
Maybe just one. Just, Mike, you made a comment earlier around the, you know, the green shoots starting to emerge on the, on the demand side.
I guess we can think about data centers, things like that. Are there any other sort of color you can give in terms of-
Oh.
What we want to see?
Three years ago, Open Country Dairy did the boiler conversion. We've seen other primary processors get very interested in electricity conversion. Obviously, the Climate Change Commission signaling around the price has given them a strong motivation to come off coal sooner rather than later. There's been some good progress in that space in the process heat conversion and high temperature boilers. We've, in this room, talked about the different data center opportunities prior to starting this, and it was amazing how everyone went around the room. They could talk about a data center. Those data centers, whether it's Lake Parime, whether it's what Spark have invested or, you've seen other announcements around the table.
The domestic hydrogen is looking really interesting. There are a number of industries where very hard to abate carbon emissions, where hydrogen is pretty much the only solution. Working with those, you know, still at a relatively immature state, but these could be quite material topics. They actually need to develop ultimately for New Zealand to hit its climate change targets as well. Some of those are quite exciting.
Great. We've got a question online from Stephen Hudson.
He's got three questions. I'll start with one. Stephen Hudson, Macquarie. What non-geothermal development OpEx, if any, in FY 2023 guidance? The second one is, what have you assumed on AGS availability for, FY 2023 or LDs? What, if any, past due payment stress are you seeing in your retail book? Three questions. Geothermal, non-geothermal OpEx, AGS availability, and any credit concerns.
Okay, the non-geothermal OpEx, Dorian alluded to that. Obviously, core costs like insurance, we've seen go up. Obviously, there is wage inflation pressure, which is starting to play through. There is the pre-investment we're making in wind solar pipelines, which turns up as OpEx. We're stepping up the investment pipeline, so that means pre-FID expenditure is going up. We see those three pressures coming through. Second question was AGS. AGS, we expect AGS continues to function well for us in terms of the amount we can inject and take out each day. We signaled pressure problems at the beginning of the year. There's a technical review group working on that, a joint technical review group with First Gas.
We fully expect the findings of that to come out later in the year and the solution.
We'd expect the availability to be much the same as we've seen.
Yeah.
for FY 2022.
Yeah.
We're not expecting any change. As Mike says, there is a technical working group that's gonna come back with potential solutions to resolve some of the problems that we've seen. The last one was, I'll take the last one about any issues around receivable collections linked to the environment. Yeah, we have seen a little bit of a tick up, actually. I mean, nothing particularly significant, but, and when I'm talking to people within other industries and sectors, you know, they're saying that they're seeing a similar story.
What I would say, though, is the team at Contact that deals with that is very, very good, and were able to manage that very, very well during the COVID process, which is obviously the last sort of time that we had the sort of stress on that part of our operations. Very confident in them.
Great. There's no further questions, online, with all that turned in, thank you very much. Thanks for joining us.
Thanks a lot.
Thank you. Thank you.
Thank you.