Good morning all? Welcome to Contact Energy's full year results for the 12 months ended 30th of June 2021. I'm Matt Forbes, GM of Corporate Finance here at Contact, and today we're joined by our Chief Executive Officer, Mike Fuge, and Chief Financial Officer, 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 phone first, then also go to those in the 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. Thanks for joining everyone, and over to you, Mike. Yeah, thank you. If we flick to the next slide. The usual disclaimer, information that people should note, and if we go on to the contents, I'll give an overview of the highlights and where the market's sitting. Dorian will take you over the detail of the financial results and give you a bit of an indication of the outlook. 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 flick to the next slide, and the next slide after that. It has been a very strong year for Contact with our EBITDA performance up over $ 100 million from last year. That's as a result of volume management and asset management as well, good uptime achieved. 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 undergoing a strategic review. At the same time, November, December, we got told that we'd get significantly less gas volumes from the Pohokura field. 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 the Tauhara 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. It's been a good year, but don't underestimate the tough and challenging market conditions in which we operated. Next slide. 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. 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 NZAS, getting 10 MW of flexible electricity signed with the data center development. Selling the Demand Flex product, 13 MW of Demand Flex, undertaking the hydrogen study, and agreeing the PPA with Genesis. That is something I do want to pause on because it is an indication of the future. It's the first-phase electricity contract of very significant tenure, 15 years. It's directly linked to the retirement of thermal plant. It is a model for future C&I longer-term deals. The market is tough at the moment, 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 paying out debt, as we reduce our asset paper. That is, I think, a significant part of the achievements of the last year. Obviously, in renewable development, we announced the investment in Tauhara field. We took on Roaring40s as a wind partner. They have over 500 MW of identified sites, which we're delighted with. We've obviously had the very successful capital equity raise, $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. We are just starting the discussions about how we set up Thermal Co for using our link. We did investigate batteries significantly. We did encounter one or two regulatory hurdles, which we're working through with EA on. We secured 70 MW of green flexibility. In terms of the customer experiences, we at Spark New Zealand have grown broadband brand. Connections are up 4%. We did stabilize our energy connections and start to grow them again. Our end-to-end digital journeys continued. You can see the continued reduction in our cost to serve as we deliver 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 investor confidence for investment and renewables in the future. We can see obviously potential retirements, the retirement potential or conversion of Refining NZ, for example. Equally, the four years of certainty that the Tiwai deal has enabled over 3 TWh of renewable electricity generation projects to be announced. Go to the next slide. It was a tougher year in terms of hydrology. I think that's well documented in mainstream media. Hydro generation was down. 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 continue into the long term. Part of it is dealing with that is obviously things like thermal carbon deployment of batteries. 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 market uncertainty. 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 at the Pohokura field has well-documented problems. Carbon price has been up sharply. 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. Let's be clear, that was preceded by a decade where wholesale electricity prices were well below the long-run marginal cost of new generation, which actually stifled investment. Since the prices have come up, you're seeing that [3, 300 W 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've grown profitability for the first time in a number of years. 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 Energy and Electric Kiwi continue their incredibly strong growth trajectory. They've come off a bit of late. 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 only 1.4%, Dorian Devers. It's important that the market is working both in terms of ensuring surety of supply, but also protecting consumers from the turbulence of both our wholesale electricity market, but broader energy costs across the globe. In terms of regulatory matters, the gas availability in the lower main water, that has resulted in a higher spike in electricity prices. Obviously, the EA and the Minister are monitoring it closely. The answer to that is investment. We're leading the way with our investment in the Tauhara field. It's one of the largest 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. 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 caught 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. 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. The same goes for the battery project. The government's obviously assessing options around how we cover dry year risk. We support those studies. We think that multiple options exist, whether it be green hydrogen, which we have actively led, whether it is potentially biomass, which Genesis have touted for Huntly. 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, most likely, our belief is that what will happen, it's 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. Obviously, we are concerned that the industry continues to work with Air NZ 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 us solve the problem. Move to the next slide. Dorian, over to you. Next slide. 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 this result, 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 CFD and merchant. We think that's going to flow through in terms of benefits in FY 2022, 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 2022. The other good thing, though, around this strategy is that we haven't sacrificed our retail business to deliver on it. We've maintained volume to our retail business. We've kept connections up. I think when you look at recent M&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. Maui's improved a bit. Our allocation of Maui's gone back up to 10 PJs from 7 PJs, which is good. We've managed to secure 13 PJs of gas for 2022. That's enough for a mean hydro year for us. If it's drier, we've obviously got those other mitigations that we normally talk about available to us. We've had a bit of M&A going on during the year, all been very strategically aligned. We went up to 100% ownership of Simply Energy. That's our vehicle for driving demand growth. 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 a sort of niche geothermal business, but it's got some fantastic capability that complements our already market-leading geothermal position. We've contributed another $7 million to capital towards Drylandcarbon. When that's fully ramped, we'll be getting about 70,000 units of that at a price below 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, That's making sure from an accounting perspective, our asset base is going towards where we think it's going to be going strategically. We'll 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. We think it actually helped form a price on Contact Energy at the time when the market was being driven by some non-fundamental topics, the rebalancing of that ESG S&P fund. 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 the cash flowing immediately. That's a small price to pay, in our view, for actually having certainty around refinancing and eliminating market risk from 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've stopped disclosing significant items, so we've restated FY 2020 accordingly. You can rest assured that if there is anything significant that we will tell you about it. Because of the focus we have at Contact on ESG, and actually the environment in particular, which really aligns quite well with our strategy around decarbonizing New Zealand. I'm going to start talking about Scope 1, Scope 2, and Scope 3 emissions in the operational and financial review. This section, giving that the same prominence that we actually give our financial performance, which is important. Next. In terms of our profits after tax, $187 million, up by $62 million. We've got the usual waterfalls here explaining what's going on. EBITDA's up by $107 million. If we start off with that first, we've seen lower renewable generation because of the dry conditions and because of those planned statutory outages. We've had a few thermal. Because we were more comfortable with our fuel position, we ran thermal generation harder. That cost us $21 million. 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 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, 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 companies passing through their lower cost of financing in line with the regulated price path to their customer. The good thing is, when you look at those two things together, that's $43 million 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. What that's enabled us to do is sell more volume to the wholesale market. By wholesale market, I mean other market participants. 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 to our EBITDA up by $119 million. I actually think when you get to the end of the reporting season, you add up the EBITDA of 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. There's certainly, from an industry perspective, no super profits in FY 2021. I think what you will see is the distribution of those profits has changed, and companies that have got better risk management options available to them, like Contact, will see their profits go up, and companies with weaker risk management options will see their profits go down. That's EBITDA. 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 2023 when we expect to switch out for Tauhara. Also linked to our GeoFuture project, which is how do we replace Wairākei. The current thinking is we'll build a bigger plant up at Te Mihi, where the quality of the steam, the enthalpy, the heat in the steam, if you like, is better. That means that the steam field around Wairākei, the Western Borefield, won't be needed as much post-2026 when Wairākei comes to end of life. Therefore, we accelerated depreciation of the assets to do with that. We have seen our interest lower, but that's around capitalization of interest associated with the Tauhara construction. Tax is obviously higher linked to higher profits. Our tax rate is 28%, in line with the statutory rate. We've got an 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, that's the key here, it's modest. If this becomes a big number, obviously you have to start 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. We're very comfortable where we are on that. In terms of our performance across our three operating segments, very strong. From an EBITDA perspective, our wholesale business up by $102 million. We had to take some tough decisions back in FY 2020. We decided to focus on risk management because that was the prudent thing to do. It meant that actually we reduced our sales book, that led to a lower financial performance for us in FY 2020. That was a difficult decision because others were contracting into those higher prices. They got the financial reward for that in FY 2021. What we have found is that a number of those parties that have contracted into those higher prices in FY 2020 have needed our support in FY 2021 to be able to deliver on those sales that they contracted earlier on. 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 million from an EBITDA perspective. They're really hitting their straps here now, getting CPI-type price increases through every year. When I say getting it through, we're not just talking about them. You can actually see them hitting those financials. You're getting productivity coming through, which is driving the cost connection lower. Our broadband product is really starting to do quite well financially now, which is great. Corporate costs are flat year- on- year with a bit of productivity offsetting cost inflation. Talk about the wholesale business in a little bit more detail. The generation costs are up by $77 million, $ 27 million, that is higher acquired generation. 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 Rankine, and therefore, the emissions wouldn't happen. I think the key thing here, though, is with the Scope 3 emissions going up from 317,000 tons to 600,000 tons, it actually tells you that the emission intensity of the swaption had gone up, so they are burning more coal. We're not part of that decision process. What it does tell us is that the benefit of our strategic review of thermal and Thermal Co is us working together in a way which we can actually do the same thing we're doing in a less carbon-intensive way. We can see carbon costs are up by $ 17 million. That is the higher swaption that I am talking about. The higher cost of thermal, running more thermal, and just the cost of carbon is up by 32% year-over-year for us. Diesel and gas costs are up again due to volume and the unit cost being higher. That is up by $35 billion. Transmission costs are down by $ 4 million, reflecting Transpower's price path being lower leads to a lower WACC. If you now just look at our generation types, geothermal's down by 219 GW, which is in line with our expectations. Remember that is 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 than mean. 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. Hāwea, we finished at 166 GW, which is a lot higher than the 90 GW that we brought into the year. 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 three units at the moment. The timing's pretty optimal, actually, because you've got the Lower South Island upgrade, which is happening for large parts of that period. Therefore, whilst our capacity is down, we couldn't dispatch onto the grid anyway for large parts, even if we had full capacity. The key is we need to have all four 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 generators, the 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 could put it through a peak or a max, set the max price for where the market could go. I think those days have gone. 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. Our generation team have done a fabulous job. The availability of thermal is better than any year going back to FY 2017, and that enabled us to dispatch an extra 234 GW 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 GW more in CFDs. 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 largely supplies other market participants, so it has minimal impact on consumers where their prices are set based on more longer-term trends. Our C&I, you can see that we were using C&I to manage fuel risk, and that's why it's contracted in volume during the year. 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 TWh of C&I contracted, and about 0.6 TWh rolls off in FY 2022, providing pricing opportunity for us. In terms of our customer business. The transfer price on 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 that an independent retailer will be paying for their electricity if they are prudently hedging their electricity purchases. Indeed, we do actually supply one retailer using the same methodology. I guess the other good test here is our retail business' EBITDA 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. 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. The volume going into this will be covered by us building new renewables. 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 a firmed one at that. You should also see actually that this is de-risking 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. If you're doing a sort of sophisticated WACC analysis, ultimately it should start to lead to a lower WACC for Contact. In terms of our wholesale trading, EBITDA is up by $47 million. We have more volume going through this channel, and the price of this channel was up from $104 to $178 per MWh. Location loss is obviously higher, reflecting the higher wholesale prices. Actually, the percentage location loss dropped from 6% to 5%, and that reflected we had a bigger percentage of North Island generation in FY 2021 than we had in FY 2020, probably because of the swaption and the dry conditions. That's the wholesale business. On to the customer business. There's three things we look at from a financial performance of this business. Are connections going up? Is the cost to serve per connection going down? Is the EBITDA going up? The answer to all three of those is yes. We're very happy with how the business performed. Electricity gross margin is up by $8 million, that is in spite of the transfer price being up by 8%, that's because those network cost reductions have largely offset that. We have seen a cash tariff increase of $4 per MWh, 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 the wholesale market. It means we're providing certainty to them. There'll be some years of under-recovery, some years of over-recovery, 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 Price Review 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. 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 million to $9 million. 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. 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. As you can see from the numbers, our number of customer connections is going up. We 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's 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 a $1 million. 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 out, and actually amortize it over the expected life of a customer, broadband gross margin would be up by $1.5 million. 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 to serve, is actually $1.5 million. Because we've grown connections so much, we started to hit some of those key volume triggers in our white label service provider, which is getting our cost of goods down. Actually, we've sorted out the back office now, getting the cost to serve down. Very happy with how the broadband's going, and which is why we're so keen to continue growing the number of connections. In terms of OpEx for the customer business, up by $2 million. That's to do with the business performed well. Bonus costs are higher as a result. It does mean even with that, our cost to serve per connection has still dropped and is now down at $155. Moving on to the OpEx for the whole of Contact. Our OpEx has gone from $201 million in FY 2020 through to $211 million in FY 2021. Just explaining how that works. In FY 2020, we had a one-time cost that's a provision for holiday pay associated with the Holiday Act. That's obviously non-recurring, so costs go down in FY 2021 as a result. We've acquired some businesses, specifically 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, all 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. 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. To be 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 flowing through into our number. The really important point is the last point, where we've doubled the number of broadband connections that are up by 25,000. We've seen no marginal extra cost of service associated with that because the productivity benefits that we've got through that new white label provider offset the volume. We've gone from having one CSR looking after roughly 600 connections to one CSR looking after just under 1,200 connections, which is an outstanding performance. I said I'd mention and talk about greenhouse gas reporting, Scope 1, Scope 2, and Scope 3 emissions. Here we go. You can see the emissions have gone up in FY 2021. That reflects the fact that Scope 1 emissions are higher 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. 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. If you actually combine the two businesses in that regard, you see lower emissions. I think that's the sort of glimpse as to some of the benefits that we can get if we work together on Thermal Co. You can see Scope 3 emissions have gone up due to the swaption. I think the key thing here is our FY 2026 target, which has been signed off by the Science Based Targets 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 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. 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 Thermal Co, 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. 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 EBITDA flowing through here. We've got higher CapEx, and that's the $10 million that we spent on those planned. That's the outlays in terms of geothermal. 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 a headwind in terms of FY 2021 operating free cash flow. 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 convert our EBITA into operating free cash flow, which is very strong. Onto the balance sheet. I guess the big story is around our equity raise, which led to our net debt reducing by $ 369 million. Our net debt level is now down at $ 645 million. On a snapshot basis, our S&P net debt to EBITDA 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. Tauhara, GeoFuture, and grid-scale battery. We will need hybrids, though, as I said before, in order to do that. We are expecting our net debt levels to rise. We've got well over $ 300 million of CapEx associated with Tauhara in FY 2022, which will take us back up closer to $1 billion. We have some refinancing to do. Our retail bonds in November, $ 150 million. The latest thinking is we'll refinance that with a $ 200 million bond, probably a hybrid. Like I say, we do need hybrids to do our capital plan. We don't have a hybrid yet. We need to work through the product disclosure statements on that. Pricing on hybrids seems to be pretty good at the moment. There's a lot of demand for them. 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, t hat's $ 0.14. Our dividend is in line with our dividend policy. Remember, we pay out 80%-100% of the average operating free cash flow for the preceding four years. For this year, that's the average operating free cash flow that we've seen in FY 2017, 2018, 2019, and 2020. When you do that, the dividend of $ 272 million is at 88%. Well within the range. If we do pay a dividend, say, at $ 0.35 going forward as well in FY 2022, we are still going to be within the range because that will be based on the average operating free cash flow of FY 2018 through to FY 2021, 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 2021 was very strong. I can say at the moment, there is no intention to change our dividend. The dividend will be paid on the September 15, and the record date is the August 27. Just to talk a little bit about our dividend reinvestment plan. 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 emails out to shareholders to remind them that they have to opt in, and they have till the August 30 to do that. The price of the share for the dividend reinvestment plan will be set based on the VWAP for the five days of trading post when the share goes ex-dividend. To outlook. This is slightly different. We had our famous $480 million that we used to talk about, which was the expected EBITDA that we would deliver through a cycle in 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 fuel risk. We've got less gas available therefore thermal generation is lower. The cost of that thermal generation is higher. What we decided to do was actually to show you how we expect our business to be structured in FY 2022 instead. We've got four 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 a margin overlay, depending on which margin, which channel we're selling through. You can see that relative to our original $480 million 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 natural gas, and because we've got less gas available to us, we're exclusively putting it through peakers, which has got a higher heat rate than TCC. When I look at this, it shows me that there's relatively low levels of price risk within this because most of our sales volume has already been contracted. Fuel risk is being managed by having a lower sales book. There's the option to get access to extra gas and run TCC, or to get used stored gas and maybe call the swaption. Overall, this gives the EBITDA of $ 520 million for FY 2022. This isn't guidance that we're planning on updating. Our view is we provide a very wholesome set of operating stats every month, and that that should be enough to update and stay on top of what our financial performance is going to be for FY 2022. 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 other elements are too aggressive. I dare say 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 pack like we do normally. Last slide, we normally provide some specific guidance for the coming financial year on some key topics. 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 $ 250 million-$ 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. We also want to maintain the momentum that we're seeing within our retail business. 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 Energy'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 adjacency for our retail business. We're continuing to invest into digital, which will have some longer term benefits for us. You've also got costs associated with resource development, things like Roaring Forties ensuring that we get new renewable projects as advanced as possible so we're ready to push the button as new PPAs or new demand is signed. 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 five years cumulative expecting CapEx to be about $100 million higher than we've been seeing it historically. About $40 million of that $100 million is coming in FY 2022. That links to investments that we're making in terms of hydro into [S/4HANA], 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 S/4HANA. 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 2021. Interest continues to fall. There's a bit obviously reflecting lower market rates flowing through here. The biggest component is as your capital work in progress on the balance sheet for Tauhara keeps getting bigger, your capitalized interest also gets bigger. That's one of the reasons why interest is dropping. Geothermal generation returns back to normal after those planned statutory outages in FY 2021. As I said, our current thinking is we're targeting a $ 0.35 dividend for FY 2022. On that, I will hand back to Mike. Thanks, Dorian. Just to remind you of the strategy, growing demand, growing renewable development, decarbonizing portfolio, and creating outstanding customer experiences. Underpinned, one, we started on the ESG journey. The integrated report that you've seen before you today is a key part of that journey. Operational excellence, which we've seen the benefits already in our crack and shutdown program and performance of the thermal asset in 2021, and continuing to transform the way we work together to deliver value to shareholders. If we go to the next slide, just in terms of setting out some key milestones so you can measure our delivery. It's growing demand, it's building the in-house capability, to support industry electrification. We've got to get alongside our customers to help them decarbonize their portfolio. With that will come 100 MW of new C&I demand we expect by 2025, which we'll come to about how that underpins renewable development. We want to identify over 300 MW of market-backed demand opportunities. For instance, the hydrogen work that's been undertaken, which further stimulates electricity 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 GeoFuture, further geothermal development on the Tauhara field, potentially wind and solar, by 2024. You'll see a decision on New Zealand North Island Battery, in 2023, hopefully delivered in 2024, depending on battery delivery times. That demand response, which is now 13 MW, we want to see that up to the size of a decent-sized peaker, by the end of 2025. 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. 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 SAP and upgraded 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 over 75% of our customer interactions are actually digital and continuing that journey. 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 MW 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. Also going forward, the electrification of boilers with Open Country Dairy. Those are the sorts of deals that we want to focus on repeating again and again. If you look to our growing renewable development, that's 342 MW of development opportunity. Remember, to compare that to wind, you have to multiply that by three. To compare that to solar, you've got to multiply that by five. That is a cracking development pipeline, which we're going to get on and develop, subject to us growing the demand growth. Scoping 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. On the right-hand side, you can see the wind and solar development. Wind, we've obviously got 500 MW of wind generation potential already through our Roaring Forties partnership. Getting the wind mast up, assessing the sites, and getting underway with consenting are obviously the key next steps. The Demand Flex, you've seen how that's grown, 6 MW last year, 13 MW 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's already talked about the greenhouse gas emissions intensity. The last year has been tough. Turning that around over the next five years is important. Also the same with Scope 3. Finally, creating outstanding customer experiences. You've seen the growth in energy connections. We've turned a corner there. You've seen the rapid growth in telco connections, which we're obviously delighted with. The connections per CSR, which Dorian spent some time on at an aggregated level, we're now up above 2,300 and want to continue to grow that. That has led to that reduction in cost to serve despite the growing customer base. The percentage of revenue from non-energy products we want to see continue to grow. Go to the next slide. This is what you can expect in the next 18 months to 2 years. The hydrogen registration of interest is underway. We've been very impressed with the interest internationally and locally that's been displayed. We do want to continue these data center partnerships, we do want to engage in 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 options, the data centers will actually come online, you'll actually see the implementation of those boiler replacements. Growing renewable development. I've already talked, obviously, getting the Tauhara built and delivered is a key KPI for all of us going forward. Getting those geothermal consents thin, looking at opportunities to further accelerate geothermal, firming up solar and wind partnerships over the next 18 months are key. Getting those wind sites consented are a key indication that we're on track to continue to grow into new renewable generation. Decarbonizing our portfolio. The development of the thermal concept, but over time, also looking at how we decommission TCC is going to be the two critical components of that. As we form up our proposals for how we could 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 S/4HANA upgrade, getting that platform absolutely key. We see that as key to that product flexibility, being able to, in a very agile way, introduce new products and offerings into market. Beyond that, you'll 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. With that, take questions. Great. Thanks, Mike. We might go to the phones first. If you're on the phones, remember, if I call your name, press star six and unmute yourself. The first question online comes from Grant Swanepoel from Jarden. Grant, go ahead. Good morning, team. Can you hear me? Yes, we can. Yes. First question is just around dividends. That was a great year. I know you have a lagged system on, give us $ 0.35. When would you consider taking the current momentum and next year into consideration, particularly when you're down at just 83% for next year's dividend? Dorian? Yeah, I think, Grant, 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. As soon as we can see some more PPAs and stuff being signed in the data centers that we've talked about, things like that, I guess that's going to give us the comfort. I mean, or, and the board the comfort. Thanks. That actually answers my next question, which was around, you didn't mention Tiwai exit. It'll stay in your thinking. 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 2025 or calendar 2025-year risk period? Well, we can't comment on what our competitors are doing. Obviously, at the moment, we had to plan on what is contracted, which is the end of 2024 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. Just on that again, Grant, obviously, the more PPAs that Genesis sign 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, first of January 2025. That's if they go. Obviously, there is an ongoing conversation about whether they will go. That's probably a question better to be had with Meridian. You probably know the answer to this, that aluminum's looking super profitable at the moment with, aluminum prices and all commodities all around the world are seeing higher prices. I suspect they're doing pretty well out of the smelter down there at the moment. Can I take it that your fairly bullishness on further generation developments, and a decision in about calendar 2023 has all that South Island demand stimulation in mind and a Tiwai stay or go in mind? Follow on to that one is, what sort of next geothermal size would you be considering after the 152 as the first tranche? That's a number of questions all contained. I'm not too comfortable with the word bullish. What you'll see is prudent investment as we see the demand growth emerging. You'll see prudent investment going forward. What you'll see in the investment program, the options we're looking at is the GeoFuture, which is a reconsenting of Wairākei, which Dorian alluded to. That's got about 0.4 TWh-0.45 TWh additional generation associated with it just through more efficient use of the steam. The other options we're looking at are indeed whether is right-sizing the next development onto Tauhara field, whether that is another 0.4 TWh, 0.5 TWH, for instance. Yeah. We're in the background, Grant, 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. Our plan, as we said, aligned to our strategy is you sign a PPA and you build to supply that demand. You're also seeing players out there who are actually saying, well, we want to be able to link our PPA to your renewable demands, generation that you're building so that we can say our PPA is linked to that geothermal plant, and therefore they get their green profile with that as well. That's our strategy is to get demand and build simultaneously. Thanks. 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? Is this going to potentially be a solution to how the lights went out and this is something that the government could potentially afford themselves in terms of a capacity price market? Again, you stacked a number of questions in there, Grant. 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. We're awaiting the investigation. From our point of view, we had every piece of thermal kit we had available deployed. TCC takes 72 hours, so that wasn't an option. We'd obviously taken a decision in July to shut it down because we didn't want to spill. Let's be clear about that. Thermal Co, 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 with a thermal kit in New Zealand and are able to prudently respond to some of these drop-offs of wind or cloudy weather, I cannot see that being anything but a good thing. I think the thing about what we see with Thermal Co is also, this is something Dorian's very passionate about, is more efficient deployment of thermal capacity in terms of carbon emissions. Why are we burning coal in Rankine when it's clear that notwithstanding the difficulties in the Pohokura field, we have an abundance of onshore gas in New Zealand. That 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 in government, look, it's a conversation that we, as New Zealand and as an industry, need to have. We're not doing it because we think commercial advantage. It's the right thing for this country to be considering. We have enough gas reserves and gas initially 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 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. That's great. Thanks, Grant. See you later. We'll go to the line, Nevill from Jarden, p lease star six to unmute yourself, Nevill. I think you just muted yourself. You were on mute actually, yeah. Are we back? Yes, you're back, Nevill. Thank you. Right. You've got two Jarden Analysts in a row. Apologies for that. 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 yet to pay CapEx outlays for the SAP system upgrade and for Tauhara? What are the cap- As of end of 2021. What are the CapEx? What's the remaining CapEx? For SAP? Yeah. That will be, it'll be about $ 17 million. We expect to spend most of that in FY 2022. Right. Sorry, $17 million rather than [$17 million]. Yeah. We'll get a bit worried when we hear SAP. That's good. Yeah. It's an upgrade, not a full new SAP implementation. I should have [inaudible] $200 million or something. No, it's. It's an upgrade. Yeah. Very good. Thank you. Of course, the big one, Tauhara. Yeah. Yeah. We're expecting that's going to be about [$ 200 million-$ 320 million], something in that region, excluding capitalized interest, for FY 2022. Nevill? Oh, sorry, I guess the total yet to spend to complete the project. We spent about, by the end of the financial, that's FY 2021, we'd spent about $70 million of the $ 580 million. We've got about $ 500 million to go. Perfect. Thank you. My questions are a little bit follow 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 can so far with the 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 sort of the Southland demand enhancements as not additional to market? How do you think about it? Look, initially, I think two things. One, the most important thing is that we see 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. We certainly see the North Island obviously potential for data centers and process heat replacement. The Tiwai question is actually an interesting one. Obviously, the immediate problem that we have to solve for is, the potential Tiwai exit, and additional demand to take up the potential supply to Tiwai is obviously key. Southland has a cracking wind resource. It's a great Class 2, very steady wind. The potential there is if we can get industrial growth, whether it's based on hydrogen and green urea or green chemicals underway, it's not just about replacing Tiwai, it's growing beyond Tiwai into a space where you create industries that are gonna be there for generations on end, supporting New Zealand and for export. Just to add to that, Nevill. I think the stuff in the lower South Island, we think is 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. When we talk about data centers and also thermal substitution, be it us or Genesis, for example, is new build. There's a few tensions in there that obviously you need to work through. That's roughly how we see it. Okay. 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 dairy factory in Southland and signed a contract off at Tauhara that would count as meeting that. No. Additional demand? No. That would go towards, displacing, Tiwai volume. Tiwai. If it's in the South Island, initially the strategy is that's Tiwai volume. Yeah. Some of the North Island you see as strong demand. If Tiwai happened to stay, that's when having wind farms in the consented wind farms down there ready to go becomes quite important, Nevill. Perfect. Thank you. Just the last question from me. What are you telling the Minister in respect 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 most? What are you saying to them? The letter we wrote to the minister by 2:00 PM the next day made very clear that we had every piece of available thermal and hydro and geothermal generation available. As I said in the presentation, we also deployed the 13 MW of demand response into the reserves market. The only thing we couldn't do, because it required three days, was start up TCC because we've taken the decision to close down TCC to prevent spill. Dorian talked about the increased hydro volumes we have in Lake Hāwea. The first representation of the Minister is we did everything we did. Our traders acted with the utmost integrity at all times. In fact, not all our Whirinaki demand that available generation got was actually in the end of the day dispatched. We await the investigation, the broader conclusion. We don't want to speculate. There's been a lot of media commentary, but we're very confident of our position of what we did physically with the 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. Obviously deployment of batteries, a more coherent response around the way thermal generation is deployed into the market are key issues going forward. Those are the conversations we'll be taking out with the minister. That's great. Thank you. Maybe just on Thermal Co then, you don't anticipate regulatory change needed for that? At this stage, no. Great. Thank you. Thanks, Nevill. We'll go on to the Q&A. We've got a question from Cam Parker from Craigs Investment Partners. Do you have long run OpEx, SIB, CapEx assumptions to go beyond FY 2022? Some of the FY 2022 guidance appears to be one-offs. That's actually a very good observation, a lot of that expenditure is one-off. If you think of the S/4HANA upgrade, if you think of the [Roxparaness], those are one-offs. The one about the [Roxparaness] is that it's actually an economic project in its own right and the additional efficiency that it gives you. We also at the investor presentations in May, when we outlined Contact26 strategy, we're very clear about what the five-year expectation of sustainable business CapEx, which in turn is underpinned by very robust and detailed asset management plans. After that, the big one is probably the Te Mihi rotor replacement. In terms of the five-year, I think the guidance was about $100 million increase. Yeah. Basically, we have, Cam, on that, we set our level 1 CapEx, standards of CapEx will be the same level as we have been seeing over the last few years. We're saying that there's going to be an uplift of $ 100 million cumulatively over the next five years. We've talked about $ 40 million of that happening in FY 2022, which means that the balance of $ 60 million is then spread over the next four years, and then sort of reverse back to normal. Yeah, OpEx is a bit higher. Some of that is sustainable, linked to the fact that we've just acquired a couple of businesses that got a higher OpEx. Some of it is obviously linked to growing demand and things like that. 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 wind and stuff like that, actually you're probably in a pretty good state if that then continues into the future, but means everything's going according to plan and the market's developing how we want. some of that, if it does sustain, would be a good thing. clearly we'll 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 generator retailer business model? Look, we are not supportive of both those options. 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 surety. The critical thing is that the market as it's 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. That's the transfer price that we work out and give them. We ask them to compete on a fair and level playing field. 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 long run marginal cost of firm renewable generation. For that requires investor certainty and confidence. That's our very strong position on both those issues. You mentioned your swaption contract C&I, to what level can you expect this over the next years? We're expecting it to sort of remain roughly 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've got Tauhara coming on. We'll see it start to sort of creep up as we prepare for FY 2023 when we see Tauhara coming online towards the end of it. Final question online from Stephen Hudson, from Macquarie Securities. He says, thanks. Thank you, Stephen, for joining in. A few questions on guidance. There's a couple one-offs around Holidays Act and expense provisions in FY 2022 and, on a GM level average of around 3,250 GWh. How much development OpEx is in the $ 220 million guidance, and can you just explain how operating cost guidance is derived? How much development OpEx is in- Yeah. I mean, we haven't gone into specific details around this. There's clearly a few million associated with it. The largest, biggest component of that would be rolling forward the use of the contract. We've got the net. What were the other? Provision for holiday in FY 2022. Yeah. There was a one-time provision of $5 million in FY 2020 to cover the historic costs of applying in a Holiday Pay going back six years. That's a statutory requirement. We're waiting for the outcome, as is everyone, of the MetroGlass case appeal. The appeal happened I think a few weeks ago. I think we're scheduled to find out the outcome relatively soon. Until we find that, we provide increased provision each year linked to the bonuses that we pay. Obviously, the cost on an annual basis is relatively small. The big one was in FY 2020, people were providing for six years. Cool. Thank you. Thanks, Stephen. Any questions in the room? Mark Robertson, Forsyth Barr. First question, I think Grant spoke around, talking about dividend guidance, including current year numbers. Mine's more around, we now know that sort of rolling prior four-year guidance, then that taking into account your 80%-100% range. Just wondering why it's being kept flat at $ 0.35, even though the rolling four-year average has increased $ 0.023. At this stage, I think the most important thing is we're trying to give investors absolute certainty. We made a commitment around that four years, and that is what we stuck to. When we announced it, we announced the $ 0.35. Sticking to 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, is absolutely key. Thank you. Second question, you spoke a bit around cost increases. I just wonder if you'd provide a little bit more color on the inflationary pressures on the business. You mentioned about the insurance costs. Just around expectations beyond FY 2022. The biggest cost inflations that we see is around fuel. We've got fuel costs with OMV, or Pohokura, and now it's sort of largely locked in, so we're good with that. Obviously, the market price for natural gas is about $ 15 a GJ, which is considerably higher than our OMV contracts. That's where you buy small parcels. We do want to buy more gas. Obviously, when you do that pushes up your cost inflation. We would buy total generation if we had to, but we're more reliant on market price for gas. That will flow through. Carbon cost is flowing through. Yeah, insurance it's not a huge cost, but the increases we're seeing, and it's across the industry, have been eye-watering. There's not really many claims in New Zealand. You've got [Cowra] claim around business interruption. In the big claims, there were a lot of big claims globally within the industry. There was CS Energy, had a major issue in Australia. There's been some large sort of explosions within the U.S. Unfortunately, we all get charged by the market, even though we've got good performing assets in New Zealand. 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 through a couple of percent is what we are seeing. Obviously, we're mindful that CPI is going up quite a bit at the moment. It's 3.3%. That potentially could flow through a bit. We always assume this will roll up 2%, which is in line with what the Reserve Bank targets, right. Last question from me, just around that $ 520 million FY 2022 guidance. Any sort of opinion or sort of color around it seems a little bit light given how good the hydro situation was going to be 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 similar things. Yeah. Some are light, some are heavy. Look, you know with hydro in New Zealand, it can turn on a dime. I think that's prudent advice. Given the turbulence of the last year where we were short hydro, we lost 4 PJ of gas all of a sudden in November. The uncertainty, I think that that's very prudent guidance. It can still turn on a dime. The good thing is we're giving you all the tools. To do it. To do what you want with it. Okay. Gentlemen, we do have another appointment at 11:15 A.M., which we're one minute over, so I do apologize that we have to rush away. Thank you for your attention and your time. It's been appreciated. Thank you. Thank you very much. Thank you.