Good morning, all. Welcome to Kontakt Energy's Full Year Results for the 12 months ended 30th June 2021. I'm Andy Forbes, GM and Corporate Finance here at Kontakt. And today, we're joined by our CEO, Mike Fudge and CFO, Doron Deves, who will be explaining our results for the financial year. We will have Q and A following the formal part of the presentation.
We will go to the phones first, then using so going to close in the office. We've also got the Q and A, which is available through the chat. So please use that if you would like to ask more questions and we'll announce those out when appropriate. So thanks for joining everyone and over to you, Mike.
Yes. Thank you. So if you click to the next slide, the user disclaimer, information people should note and we go on to the content. I'll give an overview of the highlights and where the market is sitting. Dorian will take you into the details of the financial results and give you a bit of an indication of the outlook.
And then what's very important for this presentation is the progress we're making on the strategy that we shared with the market in May of this year. If we click to the next slide and the next slide after that. So it has been a very strong year for Comtech with our EBITDA performance up over £100,000,000 last year. That's as a result of volume management and tracking asset as well, good uptime achieved. I do want to stress that this done in incredibly challenging operating conditions.
If you look at the fact we've announced Tahara, remember where we're sitting in the year, NZIS was undergoing a strategic review, New Zealand Steel was undergoing a strategic review, Refining New Zealand was undergoing a strategic review. And at the same time, in December November, December, we got told that we'd get significantly less gas volumes from the Pilbara field. So to have come through the year to have delivered a very solid financial result and to have had the privilege of being able to announce our investment and to achieve the equity raise is something I think collectively we are all as a company very proud of. We have supported our wholesale customers in uncertain times, and we have, as I said, announced our entire investment. So it's been a good year, but don't underestimate the tough and challenging market conditions in which we operate it.
Just to remind you of the strategy, which we shared as we were in May this year, growing demand, growing new development, decarbonizing our portfolio and creating outstanding customer experiences. Obviously, you can see some of the first steps on the way, which is very important to building credibility with the investor community. Supporting the extension of NZIS, getting 10 megawatts of flexible electricity signed with the data center development, selling the demand flex product, 13 megawatts of demand flex, undertaking the hydrogen study and agreeing the PPA with Genesis. And that is something I do want to pause on because it is an indication of the future. It's the 1st phase to light electricity contract, a very significant tenure for 10 years.
It's directly linked to retirement of thermal plant. It is a model for future C and I longer term deals. The market is tough at the moment, but we do encourage people to look at those longer term deals. For us, it does give us some protection from inflation. And it does give us longer term funding flexibility options, including firming our debt as we reduce our asset base.
So that is, I think, a significant part of the achievements of the last year. Obviously, in Renewable Development, we announced the investment in Sahara Field. We took on the Marine 40s as a wind partner. They have over 500 megawatts of identified slights, which we're delighted with. And we obviously had a very successful capital equity raise, dollars 400,000,000 which was below the subscribe.
We took first steps on the decarbonization of our portfolio. Our thermal assets did run phenomenally well this year and we're very proud of what the team delivered there. But we are just starting the discussions about how we set up thermal code for using our link. We did investigate batteries significantly. We did encounter 1 or 2 regulatory hurdles, which we're working through with EA on.
And we secured 70 megawatts of a green flexibility. In terms of the customer experiences, we have New Zealand's partners growing broadband brand, sorry, connections were up 4%. We did stabilize our energy connections and started growing again, and our eTwinning digital journeys continued. And you can see the continued reduction in our cost was due as we had to live on that strategy. Go to the next slide.
You can see, for the first time after a decade, some encouraging growth in electricity demand, up about 1% in the last year, despite the strategic reviews, which I talked about earlier. That is phenomenally important in terms of growing investment confidence for investment in renewables in the future. We can see, obviously, potential retirements, the retirement potential or conversion of refining and debt, for example. But equally, the 4 years of certainty that the TY deal has enabled over 3 terawatt hours of renewable electricity generation projects to be announced. Over to the next slide.
It was a tougher year in terms of hydrology. I think that's what our documents entered in mainstream media. Motor generation was down. And with that, came increased deployment of both coal and gas into the market, in particular, coal. That's not a situation that any of us want to see continuing to the long term.
And part of it is dealing with that is obviously things like thermal current deployment of batteries. But here's hoping that we're not going to see a year like the year we've seen in the last year in terms of maintenance. This is important. There have been short term factors causing a sharply higher price. You can see in the graph on the right.
Coal prices are increasing. Aluminum prices are up sharply. Methanol prices are up sharply. Gas availability of Pakeura Fuel has well documented problems. Carbon prices have been up sharply.
And obviously, COVID, which we did expect to suppress demand, New Zealand has done remarkably well. All of that has led to a spike in prices. But let's be clear, that was preceded by a decade where electricity wholesale electricity prices were well below the long run mark on cost of new generation, which actually stifle investment. Since the prices have come up, we've seen that 3 terawatt hours of new generation announced. All the market needs is certainty and it has responded and responded well.
Go to the next slide. Retail. Look, from our own performance, we're incredibly proud of what the retail team has delivered. They're growing profitability for the first time in a number of years. And we've increased our market share.
And obviously, broadband is something we're incredibly proud of going past that 50,000 connections. It is a tough market. Obviously, Nova and Electric Kiwi continue their incredibly strong growth trajectory. They've come off a bit of light. But to compete in this market, you have to be nimble, you have to be agile.
One of the things we are incredibly proud of is that despite the turbulence in the wholesale market, we have been able to protect our retail customers with price increases averaging nearly 1.4% lower. And so it's important that the market is working both in terms of ensuring surety supply, but but also protecting consumers in the turbulence of both our wholesale electricity market with broader energy costs across the globe. So in terms of regulatory matters, the gas availability in the lower mean water, that has resulted in a high spot in electricity prices. Obviously, the EA and the Minister are monitoring it closely. The answer to that is investment.
And we're leading the way with our investment in the Tahara field. It's one of the largest private post COVID private investments. We're incredibly proud of it. It's base load. It's very low carbon.
And when it comes on, it will displace significant thermal generation. We do work with our customers to smooth out pricing, those long term PPA deals, both give surety to the market and allow further renewable investment to be undertaken. And I think they are an important shift in the market that needs to be encouraged. We continue to work closely with the government officials on the market situation. Obviously, the gas shortage has caught everyone out, but there are encouraging signs around the performance of MAO next year.
In terms of the Climate Change Commission, look, we broadly support the Climate Change Commission's findings. We do believe that there are further options around further penetration of renewable electricity, growing the market rather than shrinking it. But we will continue to work with the commission on this. It's an incredibly important topic, not just for New Zealand, but for the world. And the same goes for the battery project.
The government's obviously assessing options around how we cover dry air risk. We support those studies. We think that multiple options exist, whether it's green hydrogen, which we have actively been, whether it is potentially biomass, which Genesis have touted for Huntley. There's a full range of options as well as potentially pumped hydro. The important thing that all those options are studied in detail, they are studied with a neutral eye.
And most likely, our belief is that the what will happen is not A, B or C, it's going to be D, all of the above. It will certainly a mixture of all the options available to New Zealand. Energy hardship. Look, this is incredibly important for us as a nation. It's important for us as a market.
Obviously, we are concerned that the industry continues to work with ERAMs in particular that we work to address this issue because it will become a derailer if we as an industry do not lend arms and help to solve the problem. Next to the next slide. Dorian, thank you. Thanks, Mike. So
as usual, what I'll do is I'll start by exploring some of the key things that are going to come out as we go through my section of the presentation. First and foremost, at the half year, we said we had an option. We had the option to sell more C and I or the option to keep our sales book smaller and manage fuel risk. You can see in this result, we worked for that there. That's proved to be a good financial decision as well because the highest returning channels for us have been short term CFDs and merchant NIMs.
We think that's going to flow through in terms of benefits in FY 'twenty two because whilst we hope we could turn to mean high hydrology, we are expecting that the natural gas constraints will continue and the market will be relying on more expensive forms of fuel in FY 'twenty two. The other good thing though around this strategy is that we haven't sacrificed our retail business to deliver on it. So we've maintained volume to our retail business. We've kept connections up. And I think when you look at recent M and A activity and the price people are prepared to pay to acquire customers, I think that validates that strategy that we have had.
In terms of gas, Mike mentioned that a few times. We expect gas to remain tight. Now it's improved a bit. Our allocation of now it's gone back up to 10 PJs from 7, which is good. We've managed to secure 13 pj's of gas for 2022.
That's enough for a mean hydro yield for us. And if it's drier, we've obviously got those other mitigations that we want to talk about available to us. We've had a bit of M and A going on during the year. We've been very strategically aligned. We went up to 100 percent ownership of Symphony Energy.
That's our vehicle for driving demand growth. So they look at decarbonizing customers and potential customers, getting much more carbon intensive forms of energy onto electricity. We've acquired Western Energy, which we're really happy about. It's that sort of niche geothermal business, but it's got some fantastic capability that complements our already market leading geothermal position. And we've contributed another $7,000,000 capital towards driving carbon.
When that's fully ramped, we're getting about 70,000 units of that price below the where we expect the market price for carbon to be, which we expect to continue to go up. We're not just doing that for financial reasons, though. We actually think it's important to be able to demonstrate physical carbon abatement to offset physical emissions rather than financial abatement, if you like, just by buying units from the Crown. We've accelerated depreciation, and that's making sure from an accounting perspective, our asset base is going towards where we think it's going to be going strategically. You can talk more about that on the next slide.
As Mike said, we did the equity raise. That's really positioned us well for growth. We think it's been well received by the capital markets. Also, we think it actually helped form a price on contract at the time when the market was being driven by some non fundamental topics with the rebalancing of that ESG, S and P funds. It has led to a little bit of short term capital inefficiency.
You can see in our numbers, because we haven't needed all the cash to go in immediately, but that's a small price to pay in our view for actually having certainty around refinancing and eliminating market risk on that aspect of our financing and just having a flexible balance sheet, which will enable us to build New Zealand's best renewable development projects. That's a key message to potential stakeholders. We stopped disclosing significant items that we've restated FY 2020 accordingly.
And you
can rest assured that if there's anything significant that we will tell you about it. And because of the focus we have in contact on ESG and actually the environment in particular, which really aligns quite well our strategy around decarbonizing New Zealand, I'm going to start talking about Scope 1, 2 or 3 admissions in the operational and financial reviews at this section, giving that the same prominence that we actually give our financial performance, which is important. Next. In terms of our profits, our tax, dollars 187,000,000 up by $62,000,000 We've got the usual waterfalls here explaining what's going on. EBITDAS up by $107,000,000 if we start off with that first.
We've seen lower renewable generation because of the dry conditions and because of those planned statutory additives that we had at geothermal. Because we were more comfortable with our fuel position, we ran thermal generation harder. That cost us $21,000,000 We've seen quite significant cost inflation in that thermal fuel area around natural gas and carbon units. That's pushed up our cost by $34,000,000 We've actually been able to buffer our fixed price variable with volume customers largely from what's happened in the wholesale market. Mike mentioned that they've seen a $21,000,000 price increase, which if you average that out across the $1,200,000,000 of revenue that we get through that channel, it is under 2%, which is modest when you consider what CPI is, for example.
We've also got the benefit of those lower network costs flowing through here with the lines of companies passing through their lower cost of financing in line with the regulatory price path to their customer. And the good thing is when you look at those 2 things together, that's $43,000,000 of additional EBITDA, which more than offsets that cost inflation that we've been seeing on thermal. The big news is, though, our risk management, because what that's enabled us to do is sell more volume to the wholesale market. And by wholesale market, I mean other market participants. So these are other generators, if you like, who have needed extra fuel, which they bought from us in order to supplement their own positions and ensure that they can continue to supply their customers.
That's led our EBITDAF up by $119,000,000 Actually, I think when you get to the end of the reporting season, you add up the EBITDAF with all of the industry participants, you'll find that the overall performance of the industry is largely in line with FY 2020. It might have actually gone down. So there's certainly, from an industry perspective, no super profits in FY 'twenty one. I think what you will see is the distribution of those profits has changed and companies that have got, I guess, better risk management options available to them like ConTek will see their profits go up and companies with weaker risk management options will see their profits go down. So that's EBITDAF.
Depreciation is $29,000,000 higher. We've been accelerating the depreciation on TCC to ensure that it's fully depreciated by the end of FY 'twenty three when we expect to switch out for Watohara. Also linked to our Geo Futures project, which is how do we replace Wairaki. So the current thinking is we'll build a bigger plant up at Tumidi where the quality of the steam, the enthalpy, the heat in the steam, if you like, is better. That means that the steam build around Wairaki, the Western Moorfield won't be needed as much post-twenty 26 when Wairaki comes to end of life.
And therefore, we accelerated the depreciation of the assets
to do
that. We have seen our interest lower, but that's around capitalization of interest associated with the Tohara construction. Our tax is obviously higher linked to higher profits. Our tax rate is 28% in line with the statutory rate. And we've got an accounting topic here, it's fair value of financial instruments, my favorite subject.
This is around hedge effectiveness. It's a relatively modest number of $7,000,000 and that's the key here, it's modest. If this becomes a big number, then obviously that starts to ask questions because it's telling you that your hedges aren't effective and aren't doing what they're meant to be doing. But we're very comfortable where we are on that. In terms of our performance across our 3 operating segments, very strong.
From an EBITDA perspective, our wholesale business up by $102,000,000 We had to take some tough decisions back in FY 2020. We decided to focus on risk management because that was a prudent thing to do. Invent that actually we reduced our sales book and that led to a lower financial performance drop in FY 2020. And that was a difficult decision because others were contracting into those line prices and they got the financial reward for that in FY 2021. But what we have found is that a number of those parties that contracted into those line prices in FY 2020 have needed our support in FY 2021 to be able to deliver on those sales that they contracted earlier on.
And I think what that talks about within our wholesale business is that deep understanding of the market and the quality of our trading team. In terms of our customer business, we're very happy with the performance up $6,000,000 from a lever debt perspective. They're really hitting their straps now, getting CPI type price increases through every year. And when I say getting through, we're not just talking about them because you see them hitting those financials. You're getting productivity coming through, which is driving the cost of connection lower and our broadband product is really starting to do quite well financially now, which is great.
And then corporate costs are flat year on year with a bit of productivity offsetting cost inflation. I'll talk about the wholesale business in a little bit more detail. The generation costs were up by $77,000,000,000 $27,000,000 that is higher required generation. So we've had the swaption pulled almost continuously in the second half of the year because of the dry conditions. That impacts our Scope 3 emissions.
We do classify swaption as a Scope 3 emission because our experience is if we didn't call it, Genasys wouldn't run that part of the ranking, and therefore, the emissions wouldn't happen. I think the key thing here, though, see, with the scope for emissions going up from 317,000 tonnes to 600,000 tonnes, it actually tells you that the emission intensity of the swaption have gone up, so they are burning more coal. We don't we're not part of that decision process. But I think what it does tell us is that the benefit of our strategic review of thermal and thermal coal is us working together in a way which we can actually do the same thing, but do it in a less carbon intensive way. We can see carbon costs are up by $17,000,000 That is the highest option that's talked about, the higher cost of thermal running more thermal and just the cost of carbon is up by 32% year on year for us.
Diesel and gas costs are up again due to volume and unit costs being higher. That's up by €35,000,000 And transmission costs are down by €4,000,000 reflecting the Transpowers price path being lower linked to lower WACC. So if you now just look at our generation types, geothermal is down by 2 19 gigs, which is in line with our expectations. Remember that's the planned statutory outage program we had in the year, which was run very successfully. In terms of our hydro performance, we saw a relatively wet start to the year in Q1, some early spring rains, but every subsequent quarter was drier.
The main we finished the year with a bit of a flourish with actually a bit of a deluge, I should say, towards the end of June, which got storage back up. So hardware, we finished at 166 gigs, which is a lot higher than the 90 gigs that we bought into the year. And that's actually one of the reasons why we decided to turn TCC off in July because we didn't want to run the risk of spilling water early this financial year. The key story though around hydro is that we're replacing our transformers down there. We're down to 3 units at the moment.
The timing is pretty optimal actually because you've got the lower southbound upgrade, which is happening for large parts of that period. So therefore, whilst our capacity is down, we couldn't dispatch onto the grid any way for large parts even if we had full capacity. The key is we need to have all 4 units back up and running by May 2022 when the upgrade is meant to be complete down there. From a thermal perspective, it's interesting when you look at the relative performance of the Gentainers, the financial performance in a low hydro a year. And in particular, when constraints on natural gas is becoming the new norm, it does show the value of having multiple risk mitigations available to you.
I think relying purely on the market as a risk mitigant was fine when you had $6 gas and it was plentiful and you could put it through a peak and that set the max price for where the market could go. But I think those days have gone. So you will get people looking, I think, at their risk management strategies after this year. It's not a problem we've got because we do have thermal generation within our portfolio. Our key point though is that, that thermal generation is available to run.
And our generation team has done a fabulous job. The availability of thermal is better than any year going back to FY 2017 and now enables us to dispatch an extra 234 gigs into a market that really needed it. In terms of our contractions wholesale revenue, it's up by $132,000,000 There's a bit of channel management going through here. You can see that we sold 6.82 gigs more in CFDs. So that channel correlates more closely with the wholesale market from a pricing perspective, which is why the aggregate price of that channel is up by $49 a megawatt hour.
Remember what I said earlier, that this channel will largely supply other market participants. So it has minimal impact on consumers where their prices are set based on more longer term trends. Our C and I, you can see that we were using C and I to manage fuel risk and that's why it's contracted in volumes during the year, but we have got to the position now where we're comfortable with our fuel position. So we are recontracting. Here we are today, we've got 1.6 terawatt of C and I contracted and that 0.6 terawatt rolls off in FY 2022 providing pricing opportunity for us.
In terms of our customer business, the transfer price in our customer business is up by $4.90 That's the same transfer price methodology we've been using for many years applying it consistently. It's the same price independent retailer will be paying for their electricity if they are prudently hedging their electricity purposes. Indeed, we do actually supply 1 through 1 retailer using the same methodology. I guess the other good test here is our retail business has seen to see the DAP going up, which demonstrates it's been able to recover that from the market, that cost increase, and you're seeing the right commercial behavior. Last thing to mention here is we've introduced a new channel, which is called strategic fixed price sales.
So this is a channel where you're going to see volume increasing as we decarbonize New Zealand, growing electricity demand through decarbonization backed by PPAs. So the volume going into this will be covered by us building new renewables. So you'll always find that the price of the marginal volume in here should be higher than the long run marginal cost of building new renewables and affirmed one of that. You should also see actually that this is derisking the business, especially if we're contracting with policy counterparties because it's taking price risk out in this channel and giving you certainty in terms of cash flows. So if you're doing sort of sophisticated WACC analysis, ultimately, it should start to lead to a large WACC forecast.
As far as wholesale trading, EBITDA is up by $47,000,000 We had more volume going through this channel and the price of this channel was up from $104 to $178 per megawatt hour. Location losses were obviously higher, reflecting the higher to location loss dropped from 6% to 5%, and that reflected we had a bigger mix, a bigger percentage of North Island generation in FY 2021 than we had in FY 2020, probably the business option and the dry conditions. That's the wholesale business. On to the customer business, there's 3 things we look at from a sort of financial performance of this business. Are connections going up?
Is the cost of service per connection going down? And is the EBITDAS going up? And the answer to all three of those is yes. So we are very happy with how the business performed. Electricity gross margin is up by $8,000,000 and that is in spite of the transfer price being up by 8%, and that's because those network costs reductions have largely offset that.
We have seen a cash tariff increase of $4 per megawatt hour, which is about 2%, which is great. That's what I've been saying now for a few years. We want to get CPI type increases through this, a long term channel for us. That will mean we're buffering consumers from the ups and downs of wholesale market. It means we're providing certainty to them.
There'll be some years of under recovery, some years of over recovery, But through a cycle, I expect when we get to the end of it, we will be recovering our costs, which is important. The other thing to note here is that number is net of our prompt payment discount not taken, reducing by another $5,000,000,000 If you go back to when the electricity pricing review happens, within our financials, we had about $20,000,000 of profit associated with that prompt payment discount not taken. That's now down to just $5,000,000 That's a big headwind for us to absorb. It means that we've got the vast majority of our customers now onto non PPD products. The other thing I'd just flag on this table, contract assets is down by $13,000,000 to $9,000,000 So it's a relatively modest number for us.
This is how much money we have spent historically on acquiring customers. I affectionately call it the sins of the past, which you then amortize over the life of the customer. And I think the important thing here is to say we must be doing something right because this tells us we're actually spending less money on acquiring customers. But as you can see from the numbers, our number of customer connections is going up. So we've obviously hit a bit of a sweet spot here.
Gas margins are flat even though volumes are down by 7%, which tells us we're not making money on retailing gas at the moment. The reason why the volumes have dropped is because we have put prices up aligning to what we're seeing in terms of the wholesale gas market. I guess every cloud has got a silver lining. We have freed up 0.3 PJs of gas, which we can then use to support the electricity market. Broadband gross margin is down by $1,000,000 That doesn't actually tell the picture of what's going on.
There's an accounting topic here because we have to expense every modem when we sign up a new customer. If you back that out, that cost down and actually amortize it over the expected price of the customer, broadband gross margin would be up by $1,500,000,000 And you can't see it here in the numbers, but I'll tell you anyway. The more important thing is when I look at the performance in the second half of the year, the EBITDA for this business, so that includes the marginal cost of service, actually $1,500,000,000 because we've grown connections so much, we've started to hit some of those key volume triggers in our white label service provider, which is getting our cost of goods down. And actually, we sorted out the back office now, getting the cost of goods down. So very happy with how broadband is going, and which is why we're so keen to continue growing the number of connections.
In terms of offerings for the customer business, up by $2,000,000 That's to do with the business performed well. Bonus costs are higher as a result. And it but it does mean even with that, our cost to serve per connection has still dropped and is now down at $155 Overall, on to the OpEx for the whole of the contract. So our OpEx has gone from $201,000,000 in FY 2020 through to 211,000,000 in FY 'twenty one. So just explaining how that works.
In FY 'twenty, we had a one time cost that's provisioned by holiday pay associated with the Holiday Act. That's obviously non recurring, so costs go down in FY 'twenty one as a result. We've acquired some businesses, simply in Western Energy, so some portfolio changes. We get OpEx coming in with that. That will lead to higher OpEx in FY 2022 as well as things being equal because you have the full year impact of that.
Incentive costs are higher. We actually capped bonuses in FY 2020 because of the effects of COVID. We thought it was the right thing to do. That cap has now been removed and you've seen a strong financial performance. So bonus costs or incentive costs are higher.
We have seen underlying cost increase. We've seen inflation. We've seen some quite significant inflation actually in the area of insurance. I suspect that you talked to any of my peers, they will also stay the same to get out of that insurance costs, being very open and honest with you. They've gone through the roof and we're looking at ways to mitigate that.
We have got productivity still happening. Our cash collection has been phenomenal. It means our bad debt costs have come down and we're still seeing benefits of digitalization growth flow through our number. But the really important point is the last point where we've doubled the number of broadband connections that are up by 25,000, but we've seen no marginal exit cost of service associated with that. But the productivity benefits that we've got through that new white label provider offset the volume.
So we've gone from having 1 CSR looking after roughly 600 connections to 1 CSR looking after just under 1200 connections, which is an outstanding performance. So I said that I'd mention and talk about greenhouse gas reporting, Scope 1, 23 emissions. So here we go. You can see the emissions have gone up in it by 2021. That reflects the fact that stable emissions are high because of the dry conditions and we've been running thermal assets more.
What you can't see here actually is the benefits of the tolling for the wider registry. So we've been tolling gas for Nova. Actually, that's better in terms of carbon emissions because the emission intensity of TCC is lower than the plants that would have been used. So if you actually combine the two business in that regard, you see lower emissions. And I think that's the sort of glimpse as to some of the benefits that we can get.
We work together on thermal coating. You can see Scope 3 emissions have gone up due to swaption. I think the key thing here is our FY 'twenty six target, which has been signed off by the science based initiative, we're still comfortable we're going to get to with Terraria coming online. We expect that's going to get us up to about 95% renewable in terms of our generation. In terms of the Scope 3 emissions, as we're carbon is rapidly hitting that $70 per unit price, which is when it becomes economically viable for consumers to switch home heating to heat pumps.
So we'll start to see less retailing of natural gas, which will reduce Scope 3 emissions. We also expect to see something coming out of ThermoCo, which will reduce the carbon intensity of things like the swaption or whatever insurance product the industry lands on going into the future. And that will also reduce scope 3 emissions. So we're still comfortable that we're going down the right track here. In terms of cash flow, dollars 371,000,000 of operating free cash flow, which is $0.50 per share, it's up by $81,000,000 year on year.
You've got the benefit of the EBITDAS flowing here through here. We've got higher CapEx and that's the $10,000,000 that we spent on those planned natural gas fees in terms of geofi terminals. That's a must have. We see the inventory levels go up for natural gas. That's obviously good in terms of inventory of fuel risk going forward, but a bit of a headwind in terms of FY 2021 operating free cash flow.
But the good news is even with those two topics going the other way, we've still been able to deliver a cash conversion of 67% that's converted our EBITDA into operating free cash flow, which is very strong. Onto the balance sheet, I guess the big story is around our FQAs. It's led to our net debt reducing by $369,000,000 So our net debt level is now down at $645,000,000 On a snapshot basis, our S and P net debt to EBITDA is at 1.2 times. We don't have any high risk, which is why we're comfortable that we can fund our $1,400,000,000 of growth capital plan, the Tohar, GE of Futures and a Briskale battery. We do we will need hybrid so, as I said before, in order to do that.
We are expecting our net debt levels to rise. We've got well over $300,000,000 of CapEx associated with Tohara in FY 2022, which will take us back up closer to $1,000,000 We have some refinancing to do, our retail bonds in November, dollars 150,000,000 Latest thinking is we'll refinance that with a $200,000,000 bond, probably a hybrid. Like I said, we do need hybrids to do our capital plan. We don't have a hybrid yet, so we need to work through the product disclosure statements on that. Pricing on hybrids seems to be pretty good at the moment, so there's a lot of demand for them.
So now seems like a good time to look at that. In terms of our dividend, we are declaring a final dividend of €0.21 As we've seen in the recent past, we're imputing it 2 thirds, that's €0.14 Our dividend is in line with our dividend policy. So remember, we pay out 18% to 100% of the average operating free cash flow for the preceding 4 years. So for this year, that's the average operating free cash flow that we've seen in FY '17, 'eighteen, 'nineteen and 'twenty. And when you do that, the dividend of $272,000,000 is at a 88% or what was in the range.
If we do pay dividends, say, of 35% going forward as well in FY 'twenty two, we are still going to be within the range because that will be based on the average operating free cash flow of FY 'eighteen through to FY '21, which obviously we now know. The reason why we've dropped in range is because, as I've just gone through, the operating free cash flow performance in FY 'twenty one was very strong. So I can say at the moment, there is no intention to change our dividend. The dividend will be paid on 15th September and the record date is the 27th August. Just to talk a little bit about our dividend reinvestment plan,
so this is the first time that you've had the opportunity to participate in that. We launched
it back in February, which was a while ago. It's participate in that. We launched it back in February, which was a while ago. So we're sending e mails out to shareholders to remind them that they have to opt in. They have until the 30th August to do that.
The price of the share for the dividend reinvestment plan will be set based on the VWAP for the 5 days trading post when the share goes ex Tilly. Now to outlook. So this is slightly different. We had our famous $480,000,000 that we used to talk about, which was the expected EBITDA that we would deliver through a cycle in the mean hydro a year based on our business structure. There's been a lot of change, and therefore, that structure isn't relevant for us anymore.
We've adapted our portfolio. Our mix of sales is now different by channel, reflecting fuel risk. We've got less gas available. Therefore, thermal generation is lower. The cost of that thermal generation is higher.
So what we decided to do was actually to show you what our how we expect our business to be structured in FY 'twenty two instead. So we've got a 4 doughnut charts on the left there. That actually shows you the volume that we're expecting to sell through our sales channels, how much of it is contracted, that's the blue bit, and what price it is contracted at. Our working assumption is that any sales which are contracted, that they will be priced based off the ASX Futures with a margin overlay depending on which margin which channel we're selling through. You can see that relative to our sort of original $480,000,000 business structure, the amount of volume we've got going through fixed price variable volume channels is less, reflecting fuel risk.
You can see that the amount of thermal generation is a lot less, reflecting the constraints within the natural gas market and the gas that's available to us. You can see that the cost of thermal generation has gone up due to the cost of carbon, the cost of gas and because we've got less gas available to us, we're exclusively putting through peakers, which has got a higher EBIT than TCC. When I look at this, it sort of shows me that there's relatively lower levels of price risk within this because most bus sales volume has already been contracted. And fuel risk is being managed by having a lower sales book. There's the option to produce is to get access to extra gas and run TTC and also get used stored gas and maybe for the swaption.
Overall, this gives EBITDA of $520,000,000 for FY 'twenty two. This isn't guidance that we're planning on updating. Our view is we provide a very wholesome set of operating staffs every month and that, that should be enough to update to stay on top of what our financial performance is going to be for FY 'twenty two. So as you know, we like to make your lives easy. And hopefully, this will be very easy to translate into models.
I suspect some people will think some elements of this are too conservative and others are too aggressive. And I dare say you'll let us know over the next few days. I should just finish off today because we've moved so far away from that $480,000,000 assumption, we haven't included that reconciliation in this path like we do normally. Last slide, we normally provide some specific guidance for the coming financial year on some key topics. So just taking you through that.
This all aligns very much to our new strategy that we took investors through at our Investor Day. We are seeing OpEx going up. We're targeting a range of €215,000,000 to €225,000,000 That does reflect the demand growth and us working in the background to make sure that we've got consented renewable generation to build into that demand growth when it gets delivered. And we also want to maintain the momentum that we're seeing within our retail business. So some of the things that you can actually see driving that OpEx apart is you've got a full year impact obviously of Western Energy and Synchrony's OpEx flowing through here.
You've got costs associated with us growing our connection numbers for broadband and there's OpEx associated with that. We've got costs in here built on success of broadband looking at a new adjacencies for our retail business. We've continued to invest into digital, which will have some longer term benefits for us. But you've also got costs associated with resource development, things like rolling 40s ensuring that we get new renewable projects as advanced as possible. So we're ready to push the button as new PPAs are new demand is signed.
That explains the OpEx. CapEx is up as well. We've got a range there of $95,000,000 to $105,000,000 I signaled this actually at the Investor Day that we were over the next 5 years, cumulative expecting CapEx to be about $100,000,000 higher than we've been seeing it historically. About $40,000,000 of that $100,000,000 is coming into FY 'twenty two, and that links to investments that we're making in terms of hydro into rostrawanas, which will ultimately lead to increased generation down there. The investments that we're putting in terms of replacing our transformers at Clyde, We're upgrading our SAP system to Esrohanna.
And again, those new subsidiaries that we've acquired, that's some CapEx associated with it. Depreciation is up, reflecting the run rate of those changes that we made in FY 2021. Interest continues to fall. There's a bit obviously reflecting lower market rates flowing through here, but the biggest component is as the capital work in progress on the balance sheet for tow hierarchy is getting bigger, the capitalized interest also gets bigger. So that's one of the reasons why interest is dropping.
Geothermal generation returns back to normal after those plans actually actually is in FY 2021. And as I said, our current thinking is we're targeting a €0.35 dividend for FY 2022. So on that, I will hand back to Mike.
Thanks, Brian. And just to remind you of the strategy, growing demand, growing renewable development, decarbonizing portfolio and accelerating those outstanding customer experiences. And underpinned, mine was started on the ESG journey. The integrated report that you've seen before yesterday is a key part of that journey. Operational excellence, which we've seen the benefits already in the Kraken shutdown program almost as a thermal asset in 2021 and continuing to transform the way we work together to deliver value to shareholders.
So if we go to the next slide, just in terms of setting out some key milestones so you can measure our delivery. So it's growing demand. It's building the in house capability to support industry electrification that's going to get alongside our customers to help them decarbonize their portfolio. And with that will come 100 megawatts of new commercial and industrial demand we expect by 2025, which we'll come to about how that number is in Renewable Development. And we want to identify over 300 megawatts of market back demand opportunities.
For instance, the heightened work has been undertaken, which further stimulates electricity demand growth. In Ground Renewable Development, obviously, Tahara is a big one, but we want to take our final investment decision subject to demand growth around geofuture's further geothermal development on the Tahara field, potentially wind and solar by 2024. You'll see a decision on the New York North Island battery in 'twenty three, hopefully delivered in 'twenty four depending on battery delivery times. And that demand response, which is now 13 megawatts, we must see that up to the size of a decent sized pico by the end 'twenty five. Decarbonizing our portfolio, obviously, completing the thermal review, getting the industry players together and decommissioning TCC and getting the A coherence structure going for the quarter is really important.
And we talked earlier about creating those outstanding customer experiences, moving from a trusted energy retailer to a trusted retailer full stop using that fantastic platform we have in SAT and upgraded to West Ohana, growing to 650,000 government connections by the end of 2025, continuing that relentless downward trend on cost to serve, that is an absolute game changer and making sure to support that, that over 75% of our customer interactions are actually digital and continuing that journey. So if you look here on the graph here, 1, in terms of growing demand, I've already talked at length about the Genesis BPA, how that helps the retirement of the thermal plant. The fact that we have a data center 10 megawatts under contract and continuing that journey will be a key focus. You can also see on the right hand side the avoided carbon emissions, whether it is the time deals that we start with over energy to make sure we ran their gas for our more efficient combined cycle plant, but also going forward, the electrification of volumes with open country Country Terry and those are the source of deals that we want to focus on repeating again and again.
If you look to our growing renewable development, that's 342 megawatts of development opportunity. Remember, to compare that to wind, you have to multiply that by 3. To compare that to solar, you've got to multiply that by 5. So that is a cracking development pipeline, which we're going to get on and develop subject to us growing the demand growth. The consenting is underway.
Some of it's under development already, and some of it is already consented. But it is a very strong development pipeline. In reservoirs, we understand very, very well. And on the right hand side, you can see the wind and solar development. Wind, we've obviously got 500 megawatts of wind generation potential already through our growing 40s partnership, getting the wind mass up, assessing the sites and getting underway and sensing, obviously, the key mix speeds.
The demand is flexed. You've seen how that's grown, 6 megawatts last year, 13 megawatts that was deployed last week as reserves last Monday night. The renewable generation, the ratio is down a bit due to basically a difficult hydrology year. Obviously, we want to turn that performance around. Dorian has already talked about the greenhouse gas emissions and intensity.
Obviously, the last year has been tough, but turning that around over the next 5 years is important and also the same with Scope 3. Finally, creating outstanding customer experiences. You've seen the growth in energy connections. We've turned the corner there. You've seen the rapid growth in telco connections, which we're obviously delighted with.
The connections per CSR, which Brian spent some time on At an aggregated level, we're now up above 2,300 and want to continue to grow that. And that has led to that reduction in cost per serve despite the growing customer base. And the percentage of revenue from non energy products, we want to see continue to grow. Go to the next slide. These are what you this is what you can expect in the next 18 months to 2 years.
Obviously, the hydrogen registration of Ingrid has gone away. We've been very impressed with the interest internationally and locally that's been slight. We do want to continue these data center partnerships, and we do want to engage in industrial electrification with key customers across New Zealand. We see that as key going forward. Beyond that, we will see that development of the hydrogen options.
The day centers will actually come online, and you'll actually see the implementation of those boiler replacements. Growing new renewable development, what we talked, obviously, getting the Harrah built and delivered is a key KPI for all of us going forward. Getting those geothermal concerns then, looking at opportunities to further accelerate geothermal and firming up solar and wind partnerships over the next 18 months are key. Getting those wind sized consented are a key indication that we're on track to continue to grow into new renewable generation. Decarbonizing our portfolio, obviously, the development of the thermal coat concept, but over time, we're also looking at how we decommission TCC is going to be the 2 critical components of that.
So as we form up our proposals for how we can structure it going forward, we'll keep you updated, and we look forward to that conversation with the rest of the industry continuing. Creating outstanding customer experience. Tonight, you'll see the launch of a new product around time of use to enable people ordinary Kiwis to shift their load to later in the evening to charge their cars as needed. We look forward to that. We do have to continue with the S4HANA upgrade, getting that platform as key.
We see that as key to that product, so flexibility being able to go in a very agile way, introduce new products and offerings into market. And beyond that, you will see the launch of wireless broadband, new data driven energy products in the home, Helping ordinary Kiwis in their home decarbonize the way they use energy is going to be key going forward. And with that, take questions.
Great. Thanks, Mike. We might go to the phones first. So if you're on the phones, remember if I call your name to press star 6, unmute yourself. The first question online comes from Grant Sonboom from Janard.
Grant, go ahead.
Good morning, team. Can you hear me?
Yes, we can. Yes.
First question is just around dividends. It was a great year. I know you have a lagged system on kind of €0.35 When would you consider taking the current momentum in next year into consideration, particularly when you're down at just 83% for next year's dividend?
Dorian?
Yes. I think, Dorian, it's when we're getting more traction with the demand growth and seeing some certainty. Obviously, what we're working on down in the Lower South Island to make sure we get continuity down there is quite important. So as soon as we can see some more PPAs and stuff being signed in the data centers that we talked about, things like that. I guess that's going to give us the comfort and the Board the comfort.
Well, thanks. So that actually answered my next question, which was around you didn't mention TYX, it will stay in your thinking. So it appears that your dividend is at least taking that into account. Is the rest of the market taking that into account considering what Genesis is doing, is signing PPAs that run right the way through that FY or calendar 25 year risk period?
Well, we can't comment on what our competitors are doing. Obviously, at the moment, we have to plan on what is contracted, which is the end of 24x. So that's what we plan on. If that position changes, obviously, we will be looking to maintain the agility and capability to respond to that change.
Yes. I mean, the more just on that again, Grant, the more obviously, the more PPAs and Genesys are off the back of their decarbonizing their own portfolio, the more need that puts on us and the rest of the market to make sure that we're growing demand elsewhere to cover that volume when it comes to market in 1st January 2025. That gives a go. Obviously, there is a ongoing conversation about whether they will go. That's probably a question better to be had with MRIdian.
I mean, we can comment and you probably know the answer is that aluminum is looking super profitable at the moment with aluminum prices. More commodities all around the world are seeing higher prices. So I suspect they're doing pretty well out of the smelter down there at the moment.
So can I take it that you're fairly bullishness on further generation developments and incisioning about calendar 'twenty three has all that South Island demand stimulation in mind and a TUI stay or go in mind? And then follow on to that one is what sort of next year thermal size would you be considering after the 152 as the first tranche?
So that's a number of questions will contain. So I'm not too comfortable with the word bullish. What you'll see is prudent investment as it as we see the demand growth emerging, then you'll see prudent investment going forward. What you will see in the investment program, the options we're looking at is the TIER futures, which is a re presenting of YAPI, which as Dorian alluded to, that's got about 0.4 to 0.45 additional generation associated with it through just through more efficient use
of the
steam. And the other options we're looking at are indeed whether we is rightsizing the next development on Tehada field, whether that is another 0.4 terawatt hours, for instance.
Yes. And I mean, we're in the background, we don't talk about it because the stage of negotiations and stuff like that. But we are working through PPA things around bringing new demands into New Zealand. And our plan, as we stand the line to our strategy, is you sign a PPA and you build to supply that demand. You're also seeing players out there, we're actually saying, well, we want to be able to link our PPA to your renewable demand generation that you're building so that we can say our PPA is linked to that geothermal plant and therefore they get the green profile of that as well.
So that's our strategy is to get demand and build simultaneously. Thanks.
And Mike, no disrespect intended by bullishness. It's a sense of joy actually. Thermal Co, you say you're talking to other parties. Genesis seems to always be pushing back on any conversation on that front. Are you talking to the big parties yet?
And is this going to potentially be a solution to how the lights went out and this is something that the government could potentially forward themselves in terms of the capacity price market?
So again, you've stacked a number of questions in there, Grant. So in terms of last week's outage, I think you've seen in the media a number of insights emerge over the week as to the potential causes of the outage. And we're the late investigation, but from our point of view, we had every piece of thermal kit we had available deployed. TCC takes 72 hours, so that was an option. We'd obviously taken a decision in July to shut it down because we didn't want to spill.
So let's be clear about that. Thermal Co, a number of options around it. Number 1 is, yes, it is a potential solution to the challenges of increasing penetration of unreliable wind and solar going forward. So that if you have one operator of the thermal kit in New Zealand and are able to prudently respond to so many drop offs of wind or cloudy weather, I cannot see that, that'd be anything but a good thing. I think the thing about what we see in thermal coast also, this is something Doreen is very passionate about, is more efficient deployment of thermal capacity in terms of carbon emissions.
Why are we burning Colin Rankins when it's clear that notwithstanding the difficulties in the power crew field, we have an abundance of onshore gas in New Zealand. And that is an opportunity to see that more efficiently deployed so the carbon emissions are abated not sometime in the future, but in the here and now. I hope that answers your question. In terms of engagement with the major players in government, look, it's a conversation that we as New Zealand and as an industry need to have. And we're not doing it out of because we think commercial advantage is the right thing for this country to be considering.
We have enough gas reserves and gas emission in place in this country to get us through the transition. We have enough assets already in place to get us through the transition. The thing the only thing standing in our way is us as people, as Kiwis who own and operate those assets doing the right thing.
Thanks, team. Onwards and upwards. I'm moving on. Thank you.
Thanks, Scott. That's it on.
See you later. We'll go to the line, Neville from China. Please start, so let me just stop, Neville.
Are we back?
Yes, we're back, Naimo. Thank you.
All right. You've got 2 general analysts in a row. Apologies for that. And my questions are a little bit follow on, but perhaps just to be specific to begin with, can you tell us just what is the year to pay CapEx outlays for the SAP system upgrade and for Tahira? What are the CapEx?
What
are the CapEx outlays?
What are the CapEx outlays? What are
the CapEx
outlays? For
SAP? Yes.
That will be up. It will be about $17,000,000 soon, and we'd expect to expect most of that in FY 2022.
Right. Sorry, dollars 17,000,000 rather than $17,000,000 That's right. We'll get worried when we hear SAP. No, that's good.
Yes. Is it after I not have full new SAP implementations? I should have, because when we talk about SAP, it's $200,000,000 of public knowledge today. It's not right.
Yes. Very good. Thank you. And of course, the big one, Tahira?
Yes. We're expecting that to be about $320,000,000 something in that region, excluding capitalized interest for FY 'twenty two, Neville.
And sorry, I guess, the total year to spend to complete the project?
We spent about well, at the end of the financial, Equation 1, we spent about $70,000,000 of the $580,000,000 So we've got about $500,000,000 to go.
Perfect. Thank you. So my question now, a little bit follow on. Just on you said at the Investment Day that you wouldn't be signing or putting FID on new projects unless you sort of had a contract with a counterparty with additional to market demand, which appears to be playing out in the presentation, so far, strategic contracts. How should we think about that in terms of thermal displacement, which I imagine you would count as additional to market?
And more importantly, how do we think about that in terms of data centers or possibly hydrogen in terms of TY? Should we consider the South sort of the Southland demand enhancements as not additional to market? How do you think about it?
Look, initially, I think 2 things. 1 is, one, the most important thing is that we see that the potential demand growth and those long term deals are part of, but not the only part of getting certainty around that demand growth. So we certainly see in the North Island, obviously, potential for data centers and processing replacement. The T Way question is actually an interesting one. Obviously, the immediate problem that we have to solve for is the potential TY exit.
And additional demand to take up the potential supply to TY is obviously key. But Southern has a cracking wind resource. It's a great Type 2, very steady wind. And the potential there is that we can get industrial growth, whether it's based on hyphen, green embryo or green chemicals underway. It's not just about replacing TY, it's growing beyond TY into a space where you create industries that are going to be there for generations on edge, supporting New Zealand and for export.
So just to add to that, nevertheless, I think the stuff in the Lower South Island, we think is being enabling us to maintain demand down at the Lower South Island. The other stuff that we're looking at is stuff that you need to build into to support because that's new demand. So when we talk about data set is that also thermal substitution, be it HUSL or Genesis, for example, is in new build. There is a few tensions in there that obviously you need to work through. But that's roughly how we see it.
Okay. Okay. So just to be specific then, the next sort of increment of Tahara, for example, if you signed sort of an open country like conversion and for another dairy factory in Southland and signed a contract off of Tahara, that would count as meeting that? Is that the amount?
No. That would go towards displacing TY volume.
If it's in the South Island, initially, strategy is STY volume. So in the North Island, you see it's stronger than that.
If T Y happens to stay, that's when having wind farms in your considered wind farms down there ready to go becomes quite important network.
Perfect. Thank you. And just last question for me. What are you telling the minister in respect of sort of both, obviously, last Monday debacle, but also in terms of the EA review, the competition review that's sort of coming to some sort of conclusion, what are you saying to them?
So the letter we wrote to the minister by 2 o'clock in the next day made very clear that we had every piece of available thermal and hydro and geothermal generation available. And as I said in the presentation, we also deployed the 13 megawatts of demand response into the reserves market. The only thing we couldn't do because it required 3 days was start up TCC because we've taken the system to close down TCC to prevent spill. And Byron talked about the increased hydro volumes we have in Lake Hawea. So the first representation of the Minister is we did everything we did.
Our traders acted with the utmost integrity at all times. And in fact, not all of our Piranaki demand that our available generation got was actually in the end of day dispatch. But we await the investigation, the broader conclusion. We don't want to speculate that there's been a lot of media commentary, but we're very confident with our position of what we did physically with our assets and the way we traded those assets. Longer term, I think there's a number of interesting conundrums.
There's obviously the look back, the operational issues which arose and sort of how the market was warned about an impending situation and how it responded. I think the broader question is, as wind and solar become an increasing feature in the market, there's a question we need to answer of how we can mitigate that. And obviously, the full deployment of batteries, a more coherent response around the way thermal generation is deployed into market are key issues going forward. And those are the conversations we'll be taking out with the minister.
That's great. And maybe just on thermal code then, you don't anticipate regulatory change needed for that?
At this stage, no.
Great. Thank you.
Thanks, Neville. We'll go on to the Q and A. We've got a question from Cam Piper from Craig Berson Partners. Do you have long run OpEx, SIB CapEx assumptions to go beyond FY 'twenty two? Some of your FY 'twenty two guidance appear to be one.
That's actually very good observation and a lot of that expenditure is one offs. So if you think of the S4HANA upgrade, if you think the Roxburgh Runners, those are one offs, which I mean the point about what Roxburgh Runners is that it's actually an economic project in its own right and the additional efficiency that it gives you. And we also at the investor presentations in May when we outlined the Contact 26 strategy, we're very clear about what the 5 year expectation is to stay on business CapEx, which in turn is underpinned by very robust and detailed asset management plans. So after that, the big one is probably the Tumigy write up replacement. And in terms of the 5 year, I think the guidance was about $100,000,000
increase. Yes. So what basically we have, Cam, on that, we set our dollar CapEx standards of CapEx will be the same level as we have been seeing over the last few years. But we're saying that there's going to be an uplift of 100,000,000 in Q2 as we open the next 5 years. So we've talked about CHF 40,000,000 of that happening in FY 'twenty two, which means that the balance of CHF 60,000,000 is then spread over the next 4 years and then sort of reverse back to normal.
Yes, OpEx is a bit higher. Some of that is sustainable, it leads to the fact that we've just got quite a couple of visitors. We've got a higher office. Some of it is obviously linked to growing demand and things like that. So actually, you probably want it to sustain if you're successful at growing demand and therefore, you want more generation to be consented and available and more wins and stuff like that, actually you're probably in a pretty good stake if that then continues into the future.
But this means everything's going according to plan and the market's developing how we want. So some of that, if it does sustain, it will be a good thing. But clearly, we will cut back if we need to. Next question from Jeremy Kincaid from UBS. Some market participants have
proposed change in structure of
the market. What is Contec's view on this? In particular, what is your view on establishing a capacity market and breaking up the generated retailer
business model? Look, we are not supportive of both those options. I'm from my own personal experience, aware of capacity markets, for instance, operating in Chile. And Singapore, my experience is they don't bring necessarily additional maturity. The critical thing is that the market is set up now.
It is operated effectively and efficiently. On separation, look, we treat our retail arm as they have to compete on the same basis as independent Tier 2 retailers. That's the transfer process we work out and give them. We ask them to compete on a fair and level playing field. And so the question of whether you separate or not is not going to provide any immediate relief to ordinary Kiwis.
What will provide relief to Kiwis is the building of new long term sustainable renewable generation, which leads to prices returning to the longer margin cost of firm renewable generation. And for that, it requires investor certainty and confidence. So that's Alvaro's strong position on both those issues.
And Michael asks, you mentioned you're starting to be contract fee at C and I. To what level can you expect this over the next years? Are we expecting to sort of remain roughly at the same level? We will start to increase it a bit because recognizing C and I load is relatively flat and our generation portfolio is going to flatten a bit when we have SoMara coming on. So we'll see it start to sort of creep up as we prepare for FY 'twenty three when we see SoMara coming online towards the end of it.
Our question online is from Stephen Hudson from Macquarie Securities. This is thanks. Thank you, Stephen, for joining in. A few questions on guidance. There's a couple of one offs around Holidays Act and tax provisions in FY 'twenty two and on a GAAP level average of around 3,250 gigawatt hours.
How much development OpEx is in the $220,000,000 guidance? And can you just explain how operating cost guidance is derived? How much development of it is in? I mean, we haven't gone into specific details around this, but there's clearly a few million associated with it. The large fixed component of that would be more than 40 piece of the contract.
We've got the net. What were the other? Yes. That was a onetime provision of $5,000,000 in FY 'twenty to cover the historic costs of applying in a holiday pay over about 6 years as statutory requirement. We're waiting for the outcome, as is everyone, of the Metro Glass case appeal, which happened the appeal happened I think a few weeks ago.
I think we should be able to find out the outcome relatively soon. But until we find that, we provide increase our provision each year for the to the bonuses that we pay. But obviously, the cost on an annual basis is relatively small. The big one was in FY 'twenty, so if you were to provide it for 6 years. Thank you.
Thanks, Steven. Any questions in the room?
Mark Robertson, 4thirty five. So first question, I think Grant spoke around talking about dividend guidance, including current year numbers. Mine's more around so we now know that sort of rolling prior full year guidance, then that taking into account your 80% to 100% range. Just wondering why it's being kept flat at $0.35 even though the rolling full year average has increased $0.02
So at this stage, I think the most important thing is we're trying to invest with absolute certainty. So we made a commitment around that 4 years and that is what we start to. We also when we announced it, we announced the 0.35¢ So stepping into that range is important in terms of surety. It's also obviously an uncertain market going forward. So making sure that our balance sheet is as strong as possible as there's potential uncertainty, but also to take those capital opportunities, which we talked about through the presentation.
That's been key.
Thank
you. Second question, you spoke about around cost increases. I just wonder if you could provide a little bit more color on the inflationary pressures on the business. You mentioned about the insurance costs, but just around expectations beyond FY 2022?
Well, I mean, the biggest cost inflations that we see is around field. And we've got field costs with O and B or Pohuagua and now it's sort of largely locked in. So we'll go through that. But obviously, the market price for natural gas is about $15 a gain of goodwill, which is considerably higher than our O and B contracts. That's where you buy small parcels.
And we do want to buy more gas. And obviously, we can do that. That pushes out cost inflation. We were buying the target rates, which we have to go over. We're more reliant on a market price for gas.
So that would flow through. Carbon cost is flowing through. Yes, insurance is not a huge cost, but the percent increases we're seeing. And it's across the industry, I've been eye watering. That was done.
There's not really many claims in New Zealand. You've got Caraou claim around business interruption. But I mean, the big claims, there were a lot of big claims globally within the industry that ES Energy had a major issue in Australia. There's been some large sort of explosions within the U. S.
And unfortunately, we will get tired by the market even though we've got good performing assets in New Zealand. So that may well continue to go up. We are working to try and come up with mitigations on that. General sort of cost inflation, you're seeing things to a couple of percent. Obviously, we're mindful that our CPI is going up quite a bit at the moment, we have hit 3.3%.
So that potentially could grow through a bit. But we always see this as we roll up 2%, which is in line with what the Reserve Bank targets, right?
And then last question from me. Just around that $520,000,000 full year 'twenty two guidance. Any sort of opinion or sort of color around it? It seems a little bit light given how good the hydro situation it was going into the year compared to last year and given obviously you just released your July stats today and we calculated them as being a decent amount up on July last year?
So I told you there would be people saying Yes, it's not a lot
of time ahead. Look, you know with hydro in New Zealand, it can turn on and so I think that's prudent in size. And given the turbulence of the last year where we were short hydro gas, we lost 4 PJ Gas all of a sudden in November and the uncertainty, I think that is very prudent guidance. It can still turn off on. And the
good thing is we're getting you all the tools
in terms
of doing what you want to do.
Okay. And gentlemen, we do have another appointment, 11:15, which we're on and over for. So I do apologize that we'd have to rush away. So thank you for your attention and your time and certainly appreciate it. Thank you, everyone.
Thank you.