Good morning all. Welcome to Contact Energy's full year results for the 12 months ended 30th of June 2021.
I'm Matthew Forbes, GM, corporate finance, here at Contact. And today, we're joined by our CEO, Mike Fuge; and CFO, Dorian Devers, who will be explaining our results for the financial year.
We will have Q&A following the formal part of the presentation. We will go to the phones, first, then using [indiscernible] in office. We've also got the Q&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 flip to the next slide, the usual disclaimer and information people should note. And we go on to the content. I'll give an overview of the highlights and with the market setting. Dorian will be taking over with the detail of the financial results and give you a bit of an indication of the outlook. And then what's very important in this presentation is the progress we are making on the strategy we shared with the market in May of this year.
If we flip to the next slide and the next slide after that. So it has been a very strong year for Contact, with our EBITDAF performance up over $100 million from last year. That's [ all as a ] result of [ our prudent portfolio ] management [indiscernible] asset management as well [indiscernible]. I do want to stress that was done in incredibly challenging operating conditions, if you look at the fact we've announced Tauhara. Remember where we were sitting in the year. NZAS was undergoing a strategic review. New Zealand steel was undergoing a strategic review. Refining New Zealand was going -- undergoing a strategic review. And at the same time, in December -- November, December, we got told that we'll get significantly less gas volumes from the Pohokura 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 the Tauhara investment. So it's been a good year, but don't underestimate the tough and challenging market conditions in which we operated. [indiscernible].
Just to remind you of the strategy which we shared with you in May this year: growing demand, growing renewable development, decarbonizing our portfolio and creating outstanding customer experiences. Obviously you can see some of the first steps underway, which is very important to building credibility with the investor community, supporting the extension of NZAS; getting 10 megawatts of flexible electricity signed with a data center development; selling the Demand Flex project, 13 megawatts of Demand Flex; undertaking a hydrogen study; and agreeing a PPA with Genesis. And that is something that I do want to pause on because it is a indication of the future. It's the first page toward our electricity contract, a very significant 10 years. That's 10 years. It's directly linked to the retirement of the thermal plant. It is a model for future C&I longer-term deals. The market is tough at the moment [indiscernible] if you look at those longer-term deals. And for us, it does give us some protection from inflation. And it does give us longer-term funding flexibility options, including trimming our debt as we reduce our asset [indiscernible]. So that is, I think, a significant part of the achievements for the last year. Obviously, in renewable development, we announced the investment in Tauhara field. And we took on Roaring40s as a wind partner. They have over 500 megawatts of identified [ sites ], which we're delighted with. And we obviously had the very successful capital equity raised on $400 million, which was well oversubscribed.
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 have delivered there, but we are just starting the discussions about how we'll set up ThermalCo [ for using our name ]. We did investigate batteries significantly. We did encounter 1 or 2 regulatory hurdles, which we're working through with EA on. And we secured 17 megawatts of green flexibility. In terms of the customer experiences, we are New Zealand's fastest-growing broadband band -- brand, sorry. Connections were up 4%. We did stabilize our energy connections. We'll start to grow them again. And our end-to-end digital journeys continued, and you can see the continued reduction in our costs to serve as we have delivered on that strategy.
[ Going 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've talked about earlier. That is [ phenomenally ] important in terms of growing investor confidence for investment in renewables in the future. We can see obviously potential retirements, the retirement potential or conversion of [indiscernible], for example, but equally the 4 years of certainty that the Tiwai 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 well documented [ and entered in ] mainstream media. Hydro generation was down, and with that came increased deployment of both coal and gas into the market and in particular coal. That's not a situation that any of us want to see continue into the long term. And part of it is -- dealing with that is obviously things like ThermalCo and deployment of batteries, but here's hoping that they -- we're not going to see a year like the year we've seen in the last year in terms of [indiscernible]. Just as 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 at Pohokura field is well-documented problems. Carbon price has 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 marginal costs of new generation, which actually stifled investment. Several surprises have come up. You've seen that 3 terawatt hours of new generation announced. All the market needs is certainty, and it has respondent -- responded well.
Going to next slide, retail. Look, from our own performance, we're incredibly proud of what the retail team has delivered, 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 late ], 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% on our end ]. And so it's important that the market is working both in terms of ensuring surety of supplier but also protecting consumers from the turbulence of both our wholesale electricity market [ but ] broader energy costs across the globe.
So in terms of regulatory matters. The gas availability and the lower mean water, that has resulted in higher spot and -- 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 Tauhara field. It's one of the largest post-COVID private investments and we're incredibly proud of it. It's baseload. 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 investments 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 and officials on the market situation. Obviously the gas shortage has [ called ] everyone out, but there are encouraging signs around the performance of Maui 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 is obviously assessing options around how we cover dry year risk. We support those studies. We think that multiple options exist, whether it's green hydrogen, which we have actively led; whether it is potentially biomass, which Genesis [indiscernible]. There's a full range of options as well as potentially pumped hydro. If one 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 or 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. And obviously we are concerned that -- the industry continues to work with ERANZ in particular, that we work to address this issue because [ it won't do the country a favor if we as a ministry ] do not link arms and help solve the problem.
We move to the next slide. Dorian, over to you.
Thanks, Mike.
So as usual, what I'll do is I'll start by highlighting some of the key themes 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&I or the option to keep our sales book smaller and manage fuel risk. You can see in these results we went for the latter 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 [indiscernible]. We think that's going to flow through in terms of benefits into FY '22 because, whilst we hope it returns to mean 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 '22. The other good thing, though, around this strategy is that [ we don't have to sacrifice 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&A activity and the prices 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. Maui has improved a bit. Our allocation at Maui has gone back up to 10 PJs from 7, which is good. We've managed to secure 13 PJs of gas for 2022. That's enough for a mean hydro year for us. And if it's drier, we've obviously got [indiscernible] mitigations, [ something we've talked ] about available to us.
We've had a bit of M&A going on during the year. We've been very strategically aligned. We went up to 100% ownership of Simply Energy. That's our vehicle for driving demand growth, that 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 million capital towards driving carbon. When that's fully ramped, we'll be getting about 70,000 units of that; and a price below the -- where we expect the market price for carbon [ feed ], 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 go and strategically. And 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 helped -- think it actually helped [ form a price on contact ] at the time when the market was being driven by some nonfundamental topics with the rebalancing [ of that ] ESG S&P funds. It has led to a little bit of short-term capital inefficiency that you can see in our numbers because we haven't needed all of the cash we got 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 send to all stakeholders. We'll start disclosing significant items, and we've restated FY '20 accordingly. And you can rest assured that [ it currently is insignificant, but ] we tell you about it. And because of the focus we have at Contact on ESG and actually the environment in particular which really aligns quite well [ with that ] strategy around decarbonizing New Zealand, I'm going to start talking about scope 1, 2 and 3 emissions in the operational and financial review.
So this section giving the same prominence that we actually give our financial performance, which is important.
Next, in terms of our profit after tax, $187 million, up by $62 million. You've got the usual waterfalls here explaining what's going on.
EBITDAF is up by $107 million. So if we start with that first. We've seen lower renewable generation because of the dry conditions and because of those planned statutory outages that we've had of geothermal. Because we were more comfortable with our fuel position, we ran thermal generation harder. That cost us $21 million. We've seen a quite significant cost inflation in that thermal fuel area around natural gas and carbon units. That's pushed up our costs by $34 million. We've actually been able to buffer our fixed-price variable-volume customers largely from what's happened in the wholesale market. Mike mentioned that. They've seen a $21 million price increase, which if you average that out across the $1.2 billion of revenue that we get through that channel 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 companies passing-through their lower costs 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 million of additional EBITDAF which more than offsets that cost inflation that we've been seeing on thermal.
The big news is, though, our risk management because it's -- 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 gentailers, 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 million. Actually, if everybody gets to the end of the reporting season and you add up the EBITDAF from all of the industry participants, you'll find that the overall performance of the industry is largely in line with FY '20. It might have -- actually have gone down, so there's certainly from an industry perspective no super profits in FY '21. I think what you will see is the distribution of those products has changed, and companies that have [ got, I guess ], best -- better risk management options available to them [ or at ] Contact 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 million higher. We've been accelerating the depreciation on TCC to ensure that it's fully depreciated by the end of FY '23, when we expect to switch it out for Tauhara. Also, linked to our geo futures project, which is how do we replace Wairakei, the current thinking is [indiscernible] a bigger plant up at [ Te Mihi ], where the quality of the steam, [indiscernible] [ the heat in the steam ], if you like, is better. That means that the steams build around Wairakei, the western borefield, won't be needed as much post 2026 when Wairakei comes to end of life. And therefore, we accelerated the depreciation of the assets to deal with that. We have seen our interest lower, but that's around [indiscernible] of interest associated with the Tauhara construction. Tax is obviously higher, linked to the higher profits. Our tax rate is 28%, in line with the statutory rate.
And we've got a accounting topic here, fair value of financial instruments, my favorite subject. This is around hedge effectiveness. It's a relatively modest number of $7 million, 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, it's very strong from an EBITDAF perspective. Our Wholesale business is up by $102 million. We had to take some tough decisions back in FY '20. We decided to focus on risk management because that's the prudent thing to do. It meant that actually we've reduced our sales book, and that led to a lower financial performance for us in FY '20. And that was a difficult decision because others were contracting into those line prices and they got the financial reward for that in FY '21, but what we have found is that a number of those parties that have contracted into those high prices in FY '20 have needed our support in FY '21 to be able to deliver on those sales that they contracted earlier on. And I think what that talked about within our Wholesale business is a deep understanding of the market and the quality of our trading too.
In terms of our Customer business, we're very happy with the performance, up $6 million from an EBITDAF perspective. They're really [ getting their straps now ], getting CPI-type price increases through every year. And when I say getting through, we're not just talking about them. We can actually see them hitting the financials; getting productivity coming through, which is driving the cost to serve a 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.
We'll talk about the Wholesale business in a little bit more detail. The generation costs were up by $77 million. $27 million of that is higher required generation. So we've had the swaption [ called ] 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, Genesis wouldn't run that part of the [ ranking ], and therefore the emissions wouldn't happen. I think the key thing here, though, is the -- with the scope 3 emission going up from 317,000 tonnes to 600,000 tonnes, it actually tells you that the emission intensity of the swaption had 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 ThermalCo is us working together in a way which we can actually do the same thing we're doing in a less-carbon-intensity way. We can see carbon costs are up by $17 million. That is the higher swaption that we talk about; the higher cost of thermal, running more thermal. And [ listed ] cost of carbon is up by 32% year-on-year for us.
Diesel and gas costs were up again due to the volume and the unit costs being higher. They're up -- that's up by $35 million. And transmission costs are down by $4 million, reflecting the -- Transpower's price path being lower. It means they're lower WACC.
So if you now just look our generation types. Geothermal is down by 219 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 dryer. The mean, we finished the year with a bit of a flourish with -- well, actually a bit of a deluge, just to say, towards the end of June, which got storage back up [indiscernible] we finished at 166 gigs, which is a lot higher than the 90 gigs that we brought 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 South Island upgrade which was happening for a large part of that period. So therefore, whilst our capacity is down, we couldn't dispatch onto the grid, anyway, for a large part even if we have 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 gentailers, their financial performance in a low-hydro year. And in particular, when constraints on natural gas are 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 can put it for a peak or set the max price where the market could go. Well, 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 have done a fabulous job. The availability of thermal is better than any year, going back to FY '17. And that enabled to dispatch an extra 234 gigs into a market that really needed it.
In terms of our contracted Wholesale revenue, it's up by $132 million. There's a bit of channel management going through here. You can see that we sold 682 gigs more in CFDs, though 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. On C&I, you can see that we were using C&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. And so we are re-contracting. Here we are today. We've got 1.6 terawatt hours of C&I contracted. And that 0.6 terawatt hours rolls off in FY '22, providing pricing opportunity for us.
In terms of our Customer business. The transfer price from our Customer business is up by $4.90. That's the same sense of a pricing 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 purchases. Indeed we do actually supply one prudent -- one retailer using the same methodology. I guess the other good test here is our retail business has seen its EBITDAF going up, which demonstrates it's been able to recover that from the market, that cost increase. And you'll have seen the right commercial behavior.
Last thing to mention here is we've introduced a new channel which is called our 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 at the marginal volume in here should be higher than the long-run marginal cost of building new renewables and a firmed one at that. And you should also see actually that this is derisking a 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 a sort of sophisticated WACC analysis, ultimately it should start to lead to a lower WACC [ for content ].
Next, for our wholesale trading. EBITDAF is up by $47 million. We have more volume going through this channel. And the price at this channel was up from $104 to $178 per megawatt hour. Location loss is obviously higher, reflecting the higher wholesale prices, but actually the percentage of location losses dropped from 6% to 5%; and that reflecting we had a bigger mix, a bigger percentage of North Island generation in FY '21 than we had in FY '20, [ probably the business ] swaption 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 to serve per connection going down? And is the EBITDAF going up? And the answer to all 3 of those is yes, so we are very happy with how the business performed. Electricity gross margin is up by $8 million, and that is in spite of the transfer pricing 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 down 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 million ]. If you go back to when the electricity [ pricing moving happened ] within our financials we had about $20 million of profit associated with that prompt payment discount not taken. That's now down to just $5 million. So that's a big headwind for us to absorb. It means that we've got the vast majority of our customers now under non-PPD products.
The other thing I'll just flag on this table. Contract assets is down by (sic) [ from ] $13 million to $9 million. 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, number of customer connections is going up. So we've obviously hit then the 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 million. That doesn't actually tell the picture of what was going on. There is 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 out and actually amortized it over the expected life of the customer, broadband gross margin would be up by [ $0.5 million ]. 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 EBITDAF for this business, so that includes the marginal cost to serve, is actually $1.5 million. 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've sorted out the back office now, getting the costs down, so very happy with how the -- broadband is going and which is why we're so keen to continue growing the number of connections.
In terms of OpEx for the Customer business, it's up by $2 million. That's to do with the business performed well. Bonuses 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 it's now down at $155.
[ Moving on ] to the OpEx for the [ whole of context ]. So OpEx has gone from $201 million in FY '20 through to $211 million in FY '21. So just explaining how that worked: In FY '20, we had a onetime cost that's provisioned by holiday pay. That's obviously -- the Holiday Act. That's obviously nonrecurring, so costs go down in FY '21 as a result. We've acquired some businesses, Simply and Western Energy. So some portfolio changes, we get OpEx coming in with that. That will lead to high OpEx in FY '22 as well, [ all things being we're picking up ] the full year impact of that.
Incentive costs are higher. We actually capped our bonuses in FY '20 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, and we've seen some quite significant inflation actually in the area of insurance. I suspect, if you talk to any of my peers, they will also say the same thing about insurance costs, being 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 flowing through to 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 extra costs to serve associated with that because the productivity benefits that we've got through that 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 1,200 connections, which is an outstanding performance.
So I said I'd mention and talk about greenhouse gas reporting, scope 1, 2 and 3 emissions, so here we go. You can see the emissions have gone up in FY '21. That reflects the fact that scope 1 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 industry. So we have been tolling gas for Nova. Actually that's better in terms of carbon emissions because the emission intensity of TCC is lower that the plants would have been used. So if you actually combine the 2 businesses in that regard, you've seen lower emissions. And I think that's a sort of glimpse as to some of the benefits that we can get when we work together on ThermalCo. You can see scope 3 emissions have gone up due to the swaption. I think the key thing here is that, our FY '26 target, which has been signed off by science-based initiative, we're still comfortable we're going to get to. With Tauhara 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 -- 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 at natural gas, which will reduce scope 3 emissions. We also expect to see something coming out of ThermalCo which will reduce the carbon intensity, or 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, $371 million of operating free cash flow, which is $0.50 per share. It's up by $81 million year-on-year. You've got the benefit of the EBITDAF flowing here through here.
We've got higher CapEx, and that's the $10 million that we spent on those planned statutory outages in terms of geothermal. So that's a must have. We've seen the inventory levels go up for natural gas. That's obviously good in terms of managing our fuel risk going forward but a bit of the headwinds in terms of FY '21 operating free cash flow. And -- but the good news is, even with those 2 topics going the other way, we've still been able to deliver a cash conversion of 67%. So that's [ converting our ] EBITDAF into operating free cash flow, which is very strong.
On to the balance sheet. I guess the big story is around our equity raise. It's led to our net debt reducing by $369 million. So our net debt level is now down at $645 million. On a snapshot basis, our S&P net debt-to-EBITDAF is at 1.2x. We don't have any hybrids, which is why we're comfortable that we can fund our $1.4 billion of growth capital plans for Tauhara and geo futures and a [ group-scale ] battery. We do -- we will need hybrids so, as I said before, in order to do that.
And we are expecting our net debt levels to rise. We've got well over $300 million of CapEx associated with Tauhara in FY '22, which will take this debt up closer to $1 billion. We have some refinancing to do, a retail bond in November, $150 million. [ Latest thing is we will ] refinance that with a $200 million 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 hybrid seems to be pretty good at the moment, as well the 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 2/3. That's $0.14. Our dividend is in line with our dividend policy. So remember we pay out 80% 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, '18, '19 and '20. And when you do that, the dividend of $272 million is at a 88%, so well within the range. If we do pay a dividend, say, of $0.35 going forward as well in FY '22, we are still going to be within the range, but this -- that will be based on the average operating free cash flow of FY '18 through to FY '21, which obviously we now know. And the reason why we've dropped in range is because, as I've just gone through, the operating free cash flow performance in FY '21 was very strong. So I can say, at the moment, there is no intention to change our dividend.
The dividend will be paid on the 15th of September, and the record date is the 27th of August.
Just talking 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, so we're sending e-mails out to shareholders to remind them that they have to opt in. They have till the 30th of 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 of trading post when the share goes [ ex-divvy ].
Now to outlook. So this is slightly different. We had our famous $480 million that we used to talk about, which was the expected EBITDAF that we will deliver through a cycle, a mean hydro 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 fewer risks. We've got less gas available. Therefore, generation is lower. The cost of that thermal generation is higher, and so what we decided to do was actually to show you what are -- how we expect our business to be structured in FY '22 instead.
So we've got 4 donut 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, any sales which aren't contracted, that they will be priced based off the ASX futures, with the margin overlay depending on which margin -- which channel we're selling through. You can see that, relative to our sort of original $480 million business structure, the amount of volume we've got going through fixed-price variable-volume channels is less, reflecting fuel risk [indiscernible] 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 costs of carbon, the costs of natural gas. And because we've got less gas available to us, we're exclusively putting through peakers, which has got a higher heat rate than TCC. When I look at this, it sort of shows me that there's relatively low levels of price risk within this because most of our sales volume has already been contracted. And fuel risk is being managed by having a lower sales book. There's the option to produce or -- is to get access to extra gas at one TCC for -- and also get [ used, thawed gas ] and maybe forward swaption.
Overall this gives EBITDAF of $520 million for FY '22.
This isn't guidance that we're planning on updating. Our view is we provide a very positive set of operating stats every month, and that, that should be enough to update and to stay on top of what our financial performance is going to be for FY '22. So as you know, we like to make your lives easy, and I -- hopefully, this will be very easy to translate into models. I suspect some people will think some elements to this are too conservative and elements are too aggressive, and I daresay you'll let us know over [ the next few days ]. I should just finish off saying, because we've moved so far away from that $480 million assumption, we haven't included that reconciliation in this packet 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 million to $225 million. 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 up is you've got the full year impact obviously of Western Energy and Simply's OpEx flowing through here. You've got costs associated with us growing our connection numbers for broadband, and there is OpEx associated with that. We've got costs in here built on the success of broadband looking at a new adjacency for our retail business. We've -- continuing 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 Roaring40s, ensuring that we get new renewable projects as advanced as possible so we're ready to push the button as new PPAs on new demand is signed. So that explains the OpEx.
CapEx is up as well. We've got a range there of $95 million to $105 million. I signaled this actually at the Investor Day, that we were over the next 5 years cumulatively expecting CapEx to be about $100 million higher than we've been seeing it historically. About $40 million of that $100 million is coming into FY '22. And that links to investments that we're making in terms of hydro, into Roxburgh runners, which will ultimately lead to increase generation down there; the investments that we're putting in terms of replacing our transformers at Clyde. We're upgrading our SAP system to S/4HANA. And again, those new subsidiaries that we've acquired have some CapEx associated with it.
Depreciation is up, reflecting the run rate of those changes that we made in FY '21. 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 at Tauhara keeps 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 planned statutory outages in FY '21.
And as I said, our current thinking is we are targeting a $0.35 dividend for FY '22.
So on that, I will hand back to Michael.
Thanks, Dorian.
And just to remind you of the strategy: growing demand, growing renewable development and decarbonizing the portfolio and creating those outstanding customer experiences, and underpinned. One, we're starting on the ESG journey and the integrated report that you see before you today and to be part of that journey. And operational excellence, which we've seen the benefits already in [ that fracking ] shutdown program and the performance of the 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 setting out some key milestones that you can measure our delivery. So there's growing demand that's building the in-house capability and to support industry electrification. We've got to get alongside customers to help them decarbonize their portfolio; and with that, a kind of 100 megawatts of new commercial and industrial demand we expect by 2025, which [ we'll come to ] about how that underpins renewable development. And we want to identify over 300 megawatts of market-backed demand opportunities, for instance, out of the hydrology work that's been undertaken which further stimulates just the demand growth.
In growing renewable development. Obviously Tauhara is a big one, but we want to take our final investment decision, subject to demand growth, around geo futures and further geothermal development on the Tauhara field and potentially wind or solar by 2024. You'll see a decision on the North Island battery end '23; hopefully, delivered in '24, depending on battery delivery times. And that demand response which was -- is now 13 megawatts, we want to see that up to the size of a decent-size peaker by the end '25.
Decarbonizing our portfolio. Obviously completing the thermal review, getting the industry players together and decommissioning TCC and getting a coherent structure going forward 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 and set and upgraded to S/4HANA; growing to 650,000 customer 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 this graph here. One, in terms of growing demand, I've already talked at length about the Genesis PPA, 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 tolling deals that we struck with Nova Energy to make sure we ran their gas through our more efficient combined-cycle plant; but also going forward, the electrification of boilers with Open Country Dairy; and most of 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 is under development already and some of it is already consented, but it's a very strong development pipeline and 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 Roaring40s partnership, getting the wind mass up, assessing the sites and getting underway with consenting [ all the statements in each state ].
The Demand Flex. You've seen how that's grown: 6 megawatts last year, 13 megawatts that was deployed last week as reserves, last Monday today night. The renewable generation, the ratio was 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 intensity. Obviously the last year has been tough, but turning that around over the next 5 years is important, and also the same in scope 3.
And finally, creating outstanding customer experiences. You've seen the growth in energy connections. We've turned the corner there. You have seen the rapid growth in telco connections, which we're obviously delighted with; the connections per CSR, which Dorian spent some time on. At a aggregated level, we're now up above 2,300 and want to continue to grow that. And that has led to that reduction in costs to serve despite the growing customer base. And the percentage of revenue from non-energy products, we want to see continue to grow.
We go to the next slide. These are what -- this is what you can expect in the next 18 months to 2 years. Obviously the hydrogen registration of interest is underway. We've been very impressed with the -- interests from internationally and locally has been displayed. We do want to continue these data center partnerships, and we do want to engage on industrial electrification with key customers across New Zealand. We see that as key going forward. Beyond that, you will see that development of the hydrogen option. The data centers will actually come online. And you'll actually see the implementation of those boiler replacements. Growing renewable development, I've already talked. Obviously, getting Tauhara built and delivered is a key KPI for all of us going forward. Getting those geo field consents in; looking at opportunities to further accelerate geothermal; and firming up solar, wind partnerships over the next 18 months are key. Getting those wind sites consented are a key indication that we are on track to continue to grow into new -- renewable generation.
Decarbonizing our portfolio; obviously the development of the ThermalCo concept but, over time, also looking at how we decommission TCC. It's 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 will keep you updated. And we look forward to that conversation with the rest of industry continuing.
Creating our outstanding customer experience. Tonight, you will 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 S/4HANA upgrade, getting that platform as key. We see that as key to that [ product ] flexibility; and being able to, in a very agile way, introduce new products and offerings into the 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...
Questions.
Take questions.
Great. Thanks, Mike. We might go to the phones first. [Operator Instructions]
And the first question on the line comes from Grant Swanepoel from Jarden.
Can you hear me?
Yes, we can.
Yes.
My first question is just around dividends. It was a great year. I know you have a lagged system on [ getting this to ] $0.35. When will 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, Grant, is when we -- 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, the data centers that we've talked about, things like that, I guess that's going to give us the comfort. I mean [indiscernible] the comfort.
So that actually answers my next question, which was around you didn't mention Tiwai exit or 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 in 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 incoming [ 4 exit ]. And 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 there -- yes, just on that again Grant. There are more -- obviously, the more PPAs that Genesis sign off the back of their decarbonizing their own portfolio, the more need that, that puts on us and the rest of the market to make sure that we're growing demand elsewhere and to cover that volume when it comes to market in 1st January 2025. That is they've got to -- obviously there is a ongoing conversation about whether they will go. That's probably the question better to be had with Meridian. I mean we can comment, and you probably know the answer to this. 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 are doing pretty well out of the smelter down there at the moment.
So can I take it that your fairly bullishness on further generation developments and decision in about calendar '23 has all that South Island demand stimulation in mind and a Tiwai stay or go in mind? And then a 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 all contained, 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 geo futures, which is the re-consenting of Wairakei which Dorian alluded to has got about [ 0.4 or 0.5 ] additional generation associated with it through -- just through more efficient use [ that's sustained ]. And the other options we are looking at are indeed whether we -- if rightsizing, the next development on Tauhara field, whether that is another 0.4 or 0.5 terawatt hours, for instance.
Yes. And I mean we are in the background, Grant. We [ don't ] talk about it because of the stage of negotiations and stuff like that, but we are working through PPAs and things around bringing new demand into New Zealand. And our plan, as we said at the launch of our strategy, is you sign a PPA and you build to supply that demand, yes. And you're also seeing players out there. We were actually saying, well, "We want to be able to link our PPA to more renewable demand generation that you're building," so that we can say our PPA and -- is linked to that geothermal plant. And therefore, they get the green profile with that as well. So that's our strategy. It's to get demand and build simultaneously.
And Mike, no disrespect intended by bullishness. It's a sense of joy actually. ThermalCo: 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 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'll await the 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 it spilt ]. So let's be clear about that. ThermalCo: A number of options around it. Number one 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 a thermal kit in New Zealand and are able to prudently respond to suddenly dropoffs of wind or cloudy weather, I cannot see that [ their engineers ] [indiscernible]. I think the thing about what we see in ThermalCo is also -- this is something Dorian is very passionate about, is a more efficient deployment of thermal capacity in terms of carbon emissions. Why are we burning coal [ and rankings ] when it's clear that, notwithstanding the difficulties in the Pohokura field, [ the big ] field, we have an abundance of onshore gas in New Zealand. And there is an opportunity to see that more efficiently deployed so that 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 and government. Look. There'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. It's the right plan for this country to be considering. We have enough gas reserves and gas initially in place in this country to get us through 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.
We'll go to the line of Nevill from Jarden. [Operator Instructions] I hope you just muted yourself. You were unmuted actually, Nev.
Are we back?
Yes.
Yes, you're back, Nevill. Thank you.
Yes. All right, you've got 2 Jarden analysts in a row. Apologies for that. And my question is a little bit of a follow-on, but perhaps just to be specific, to begin with, can you tell us just what is the yet-to-pay CapEx outlays for the SAP system upgrade and for Tauhara? [indiscernible] into FY '21. [ What's sort of the ] remaining CapEx...
What are the CapEx outlays for SAP?
Yes.
That will be -- let me think. A little bit about $17 million. We expect to spend most of that in FY '22.
[indiscernible].
All right -- sorry. $17 million rather than $70 million...
Yes...
That's -- we will get worried when we hear SAP. No, that's good.
Yes, yes, yes. Sorry. It's not -- it's an upgrade, not full new SAP implementation. I should have -- because the equipment -- when we talk about SAP [indiscernible] $200 million [indiscernible].
Yes. It's not -- it's an upgrade.
Yes.
Very good. And of course, the big one, Tauhara...
Yes.
Yes, yes. That, we're expecting that is going to be about $320 million, something in that region, excluding capitalized interests, for FY '22, Nevill.
And sorry. I guess, the total yet to spend to complete the project...
We spent about -- well, at the end of the financial -- FY '21, we had spent about $70 million of the $580 million, so we've got about $500 million to go.
$500 million.
Perfect. So my questions are 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 [ you've given sort of about ] strategic contracts. How should we think about that in terms of thermal displacement, which I imagine you would count as additional to market? More importantly, how do we think about that in terms of data centers or possibly hydrogen in terms of Tiwai? 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. One is, one, the most important thing is that we see that -- the potential for 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 [ processes ] replacement. The Tiwai question is actually an interesting one. Obviously the immediate problem that we have to solve for is potential at Tiwai's. And additional demand to take up the potential [ supplies of ] Tiwai is obviously key, but Southland 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 hydrogen [indiscernible] or green chemicals. It's underway. It's not just about replacing Tiwai. It's growing beyond Tiwai into a space where you create industries that are going to be there for generations on end, supporting New Zealand and for export.
So just to add to that, Nevill. So 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 in to support because that's new demand. So when we talk about data centers; and also thermal substitution, be it us or Genesis, for example, it's new build. There's a few tensions in there that obviously you need to work through, but that's roughly how we see it.
Okay. So just to be specific then: The next sort of increment of Tauhara, for example, if you signed sort of an open country, like, conversion and for another [ geo ] factory in Southland, would -- and signed a contract off at Tauhara, that would count as meeting that [indiscernible] demand.
No, no, no. That would go towards displacing a Tiwai project...
No -- Tiwai. And it's on the South Island. Initially, strategy is that's Tiwai volume.
Yes.
So on a North Island, [ you'd see it's strong enough ].
If Tiwai happened to stay, that's when having wind farms and concerted wind stuff farms down there, ready to go becomes quite important, Nevill.
Perfect. And just the 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 at the moment? What are you saying to them?
So the letter we wrote to the minister by 12:00 the next day made very clear that we have 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, we'll start up TCC. Because we've taken a decision to close down TCC to [indiscernible]. And Dorian talked about the increased hydro volumes we have at Lake Hawea. So the first representation to the minister is we did everything we did. Our traders acted with the utmost integrity at all times. And in fact, one of our [indiscernible] demand -- available generation got -- was actually, at the end of the day, dispatched, but we await the investigation, the broader conclusion. We don't want to speculate. And 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. It's obviously the look back, the operational issues which arose and sort of how the market was warning 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, deployment of batteries, a more coherent response around the way thermal generation is deployed into market are key issues going forward. And look, those are the conversations we'll be taking up with the minister.
That's great. And maybe just on ThermalCo then: You don't anticipate regulatory change needed for that.
At this stage, no.
We'll go on to the Q&A. We've got a question from Ken Phillip of Craigs Investment Partners. "Do you have long-run OpEx, SIB CapEx assumptions to go beyond FY '22? Some of FY '22 guidance appeared to be [ one-off ]."
That's actually a very good observation. And a lot of that expenditure is one-off. So if you think of the S/4HANA upgrade, if you think the Roxburgh runners, those are one-offs, which I mean the point about the Roxburgh runners is that it's actually an economic project in some right and the additional efficiency that it gives you. And we also -- at the investment presentations in May, when we outlined the Contact26 strategy, we were very clear about what -- the 5-year expectation stay-in-business CapEx, which in turn is underpinned by very robust and detailed asset management plans. So after that, the big one is probably, to me, the [ rotor ] replacement. And in terms of the 5 year, I think we guided to about $100 million...
Yes, yes. So basically we have [indiscernible] on that. We fit our [indiscernible] 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 million cumulatively over the next 5 years. So we've talked about $40 million of that happening in FY '22, which means that the balance of $60 million has been spread over the next 4 years and then sort of reverses back to normal. OpEx is a bit higher. Some of that is sustainable, linked to the fact that we've just got -- acquired a couple of businesses who've got higher OpEx. 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 driving demand, therefore you want more generation to be consented and available and more [ wind ] and stuff like that. Actually you're probably in a pretty good state if that then continues into the future, but -- it means everything is going according to plan and the market is developing how we want. Some of that, if it does [ stay ], will be a good thing, but clearly we will cut back if and when we need to.
Next question, from Jeremy Kincaid from UBS. "Some market participants have proposed changing the structure of the market. What is Contact's view on this? In particular, what is your view on establishing a capacity market and breaking up the generation retailer business model?"
Look. We are not supportive of both those options. I'm -- from my own personal experience, [ we are of ] capacity markets, for instance, operating in Chile and Singapore. My experience is they don't bring necessarily additional surety. The critical thing is that the market is set up now, 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. There's the transfer price that we work out and give them. We ask them to compete on a fair and an even playing field, and so the question of whether you separate or not is not going to provide any immediate reliefs 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 long-run marginal costs of thermal renewable generation and, for that, requires investor certainty and confidence. So that's how I'd respond on position on both of those issues.
[indiscernible] asks, "You mentioned you started to re-contract the C&I. To what level can you expect this over the next years?"
We're expecting to sort of remain roughly at the same level. We will start to increase it a bit because recognizing C&I load is relatively flat. And our generation portfolio is going to flatten a bit when we have Tauhara coming on. So we will see it start to sort of creep up, as we prepare for FY '23, when we see Tauhara coming online towards the end of it.
Final question online is from Stephen Hudson from Macquarie Securities. "A few questions on guidance. There's a couple one-offs around Holidays Act and [ set ] provisions in FY '22 and kind of geothermal average from around 3,250 gigawatt hours. How much development OpEx is in the $320 million guidance? And can you just explain how operating cost guidance is derived?"
The -- how much development OpEx -- is Stephen...
Yes.
I mean we haven't gone into the specific details around this, but there's clearly [ those few million ] associated with it. The large -- biggest component of that will be Roaring40s in the contract we've got with them. What were the other?
Provision for all [indiscernible].
Yes...
Yes. That was a -- there was a onetime provision of $5 million in FY '20 to cover the historic costs of applying Holiday pay [ that go about ] 6 years by the statutory requirement. We're waiting for the outcome, as is everyone, of the [ Metro Gas ] case appeal, which happened -- the appeal happened, I think, a few weeks ago. And I think we're scheduled to find out the outcome relatively soon, but until we find that, we provide -- increase that provision each year for -- linked to the bonuses that we pay. But obviously the cost on an annual basis is relatively small. The big one was in FY '20 [indiscernible] providing for 6 years.
Thank you. Thanks, Stephen. Any questions in the room?
Mark Robertson, Forsyth Barr. So first question: I think Grant spoke around talking about dividend guidance, including current year numbers. Mine is more around -- so we now know that sort of rolling prior 4 year guidance and then that taking into account your 80% to 100% range. I'm just wondering why it's been kept flat at $0.35 even though the rolling 4-year average has increased $0.023.
So at this stage, I think the most important thing is we are trying to give investors [ absolute ] certainty, so we made a commitment around that 4 years and that is what we stuck to. We also -- when we announced it, we announced the $0.35. So sticking to that range is important in terms of surety. It's also obviously an uncertain market going forward, so we're making sure that our balance sheet is as strong as possible as there is potential uncertainty. And also to take those capital opportunities which we talked about through the presentation is absolutely key.
Second question. You spoke [ about around ] cost increases. I'm just wondering 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 '22.
Well, I mean, the biggest costs inflations that we see is around fuel. And we've got fuel costs with OMV for Pohokura and Maui sort of largely locked in, so we're good with that, but obviously the market price for natural gas is about $15 a gigajoule, which is considered to be higher than our OMV contracts. That's really buying small parcels, and we do want to buy more gas. And obviously when you do that, that pushes up your cost inflation in that [ we were buying ] [indiscernible] would normalize market price for gas. So that will flow through. Carbon cost is flowing through.
Yes, insurance. Actually it's not a huge cost [indiscernible] increases we've seen. And it's across the industry...
[indiscernible].
Or have been [indiscernible]. That was done -- there's not really many claims in New Zealand. You've got [indiscernible] claim around business interruption, but in the big claims, there were a lot of big claims globally within the industry. That's [ CS Energy ] had a major issue in Australia. There's been some large sort of explosions within the U.S. And unfortunately, we will get caught 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 some mitigations on that.
General sort of cost inflation. You're seeing things -- a couple of percent is what we assume. Obviously we're mindful that CPI is going up quite a bit at the moment, [ 3.3% up ]. So that potentially could flow through a bit, but we always assume [ this will roll up ] 2%, which is in line with what -- the reserve bank targets, right?
I mean last question from me, just around that $520 million full year '22 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've just released your July stats today and we calculated them as being a decent amount up on July last year.
So...
I've told you there would be people saying...
Yes. [ It sound like him ], but look. You know, with hydro in New Zealand, it can turn on a whim. And so I think that's prudent advise. And given the turbulence of the last year, where we were short of hydro, gas [ suddenly lost 4 PJ ] and gas all of sudden -- November; and the uncertainty, I think that is very prudent guidance. It can still turn [indiscernible].
And the good thing is we've given you all of the tools [indiscernible] what you want with them.
[indiscernible], okay? And gentlemen, we do have another appointment [ within 15 ], which we're 1 minute over for, so we do apologize that we have to rush away. So thank you for your attention and time. Thanks very much. We appreciate it. Thank you.
Thank you very much.
Thank you.
