Welcome to Meridian's 2021 annual result briefing. I'm Neal Barclay, Meridian's Chief Executive, and I have sitting here on my virtual left, Mike Roan, our CFO. At least I think he's there. I'll make a few opening remarks before we get into the guts of the presentation. Most obviously, we saw quite a shift in financial performance in FY 2021 compared to the previous two years. FY 2019 and FY 2020 saw successive record results powered by strong generation and growing retail sales volumes. This year, we maintained that customer growth momentum. We ran into tough drought conditions that reduced our generation capability and increased our hedge costs. That's just the nature of the business and the variable New Zealand weather. In January, we also completed negotiations with the owners of the Tiwai Point Aluminium Smelter to extend our electricity supply contract to the end of 2024. That extension was done at a significant discount to the existing contract. Both of these events impacted financial performance with EBITDAF and underlying NPAT down on prior years by 15% and 27% respectively. We do believe the underlying drivers of future business value are strong. In particular, since 2018, it's worth noting that we've grown the size of the combined New Zealand Meridian and Powershop customer bases by 20%, and the total volume of energy sold through our retail channels by 40%. Our sales momentum has not wavered this year. We believe there's still plenty of scope for further growth and enough liquidity in hedge markets to allow us to manage the risk. Our Harapaki wind farm construction is underway in Hawke's Bay and our development pipeline is rejuvenating. We're also buoyed by future opportunities that have started to take shape beyond the smelter's exit in 2024. Ultimately, the outlook for growth in the sector is huge as Aotearoa embarks on a path to a net zero emissions by 2050. There are some challenges our industry must manage on the decarbonization journey. Their own goal the electricity sector managed to score on the 9th of August by causing widespread customer outages was just a symptom of a broader contextual issue that the industry must address. The industry is emerging from a period of around 13 years where we've seen no discernible growth in demand. Accordingly, the system has not been put under any real pressure to accommodate new levels of peak demand as occurred on the 9th of August. It's also become crystal clear that over the last three years, that the flexibility and reliability of the gas supply chain from gas field through to generation has eroded considerably. Whilst there is investment going into the upstream gas assets, the situation may be exacerbated by the inevitable growth of renewables that are displacing baseload thermal generation at a rate of knots. Waikato, Turitea, Tauhara, and Harapaki combined equate to 8% of current demand despite muted demand growth. Now, I don't think anyone doubts the importance of reaching zero emissions economy, ideally sooner than 2050. The introduction of the 100% renewable electricity target by 2030 has rapidly upended the wider industry's long-standing plans to use gas, and in particular, fast-start gas peakers to provide renewable firming capacity and to efficiently transition away from coal. I doubt that there will be one silver bullet solution to enable a seamless transition, and some of the renewable firming initiatives being mooted presently are still well over a decade away. We do need government policy that is more sympathetic to and accepting of some gas generation. What happens to the load currently contracted by NZAS through to 2024 is a relevant consideration to any package of options to enable a seamless transition. As are efforts to enable large scale demand response from existing and new industrial users. I think the future is bright, but we do need to be smart in tackling the transition to a renewable grid to ensure the continued affordability and reliability of our electricity to New Zealand consumers. I'll talk more on this presentation about some of the actions Meridian is undertaking to invest in the decarbonization challenge. The New Zealand customer growth momentum was mirrored in our Australian Powershop business, and we're super proud of these results. Succeeding in retail is down to the proverbial battle of inches, and there's no single ingredient that I would point out to our secret sauce. It is really about getting every aspect of the customer offer and the service experience just right. To do that, you need great people and a culture that cares. The really good news is we know where we are now, and we know we've got plenty of potential to improve. While our cash earnings reflected the impacts of the drought and industry negotiations, the board was comfortable maintaining the ordinary dividend at FY 2020 level, albeit at a higher payout ratio. To help accelerate decarbonization, we kicked off our process heat electrification program in February, and it's super encouraging to see a growing commitment from businesses wanting to decarbonize their industrial processes. We already have 171 GWh of annual load under MoU or contracted, and we're close to having a further 100 GWh signed up. Now, Meridian can bring to the table sharp long-term pricing. The emerging barrier to getting more of these projects up, particularly as it relates to the financials, is the cost of transmission and distribution upgrades. Businesses are clearly trying hard to decarbonize, and this infrastructure is critical to support a timely transition to cleaner process heat for New Zealand. Accordingly, many conversion opportunities are dependent on the timing of funding awarded from the government's NZD 69 million decarbonization fund. Process heat electrification opportunities typically deliver a low cents per ton of carbon abated equation, and if appropriately supported, will deliver great outcomes for customers and our country. As an example, the coal boiler replacement at Woolworths in Timaru will reduce emissions by 11,000 tons a year. This is the equivalent of taking around 3,000 cars and their emissions off the road. Now, with very small operational emissions, the bulk of Meridian's footprint is in our supply chain, and it's really pleasing to see our partners making improvements in the quality of the measurements, reporting, and quality of their emissions. We continue to make positive progress in our gender equity measures, but as you can see from the chart, we clearly have more work to do. Last year's COVID lockdown coincided with our staff engagement survey, so we saw a natural lift at that time. I guess our people were thankful to have our support and the job security we promised. This year's survey results have returned to pre-COVID levels. Well, we did expect that, and they're still results that are set-believing. I'd like to call out the great work our people continue to do in this COVID-affected world. They have been positive and flexible, and as a business, we haven't missed a beat. I'd particularly like to acknowledge our team based in Victoria. They've endured more than one year of COVID-related restrictions, and their commitment and resilience is absolutely amazing. I've talked before about my concerns around our annual rate of injuries. While none of the 18 LTIs resulted in serious harm this year, our people do operate in challenging work environments, and we have a lot more work to do to ensure they can continue to do that safely. Safety leadership and safety culture are the focus of a new program of work being led by Tania Palmer, our Chief People Officer. We showed investors our refreshed strategy at our May investor day. We also indicated the start of an ownership review of Meridian Energy Australia. Mike Roan will update you on that process a bit later on. We have evolved some of the targets since May. For example, Mercury's acquisition of Trustpower's mass market book gives us the opportunity to focus on a more appropriate medium-term target for our retail business around fixed price growth. As we deepen our development pipeline to accelerate decarbonization of this country, we're now aiming to have three options ready to build by the end of 2024. I've talked previously about the roadblocks the industry faces getting potential sites through consenting, this will be a real challenge and does require support through the government's RMA reform process. We'll touch on progress on most of these targets through the course of this presentation. Work with shareholders or stakeholders has helped us distill our sustainability focus down to the 10 material topics presented here. Those topics inform our activities, I'll call out a few successes over the last year. It is easy to forget Meridian is already net zero carbon, and we are now planting forests to create our own carbon offsets. By the end of 2021, we had doubled the number of trees currently in the ground, but we do need to seriously pick up the pace. Pleasingly, we've recently acquired two additional parcels of land to accelerate our planting program. Meridian's own EV charging network was launched earlier this year. We're deploying mostly AC chargers that integrate well onto existing electricity networks. They are ideally suited to shopping malls, retail and business parks, and community facilities. International experience shows AC charging offers an efficient complement to fast DC chargers. We published our first modern slavery statement. The statement sets out our actions to assess and address modern slavery risks in our operations and our supply chains. We've now just presented our third TCFD report. We at Meridian put a social focus as well established. We have long-term commitments to our generation communities, supporting local projects that are important to them. KidsCan, Kākāpō Recovery, and Project River Recovery are amazing causes. I'm personally honored to be part of them. We specifically acknowledge iwi rights under the Treaty of Waitangi. It is important for us, as a large user of natural resources, to partner with Iwi and find ways to deliver improved environmental, commercial, and cultural outcomes. This isn't just corporate speak. We are working actively with many Iwi groups to make a real difference. We've been talking about the green shoots of demand growth for a few years now. The impacts of COVID and Tiwai's fourth potline consumption skews things a bit from prior periods. If we normalize for those, we see demand uplift in the last two years, and that is despite near record temperatures taking the top off winter demand. Whilst the impact of a nationwide lockdown must have an economic impact, we've not seen anywhere near the same level of negative impact on demand that was evident last March, but it's early days. As I mentioned earlier, the customer growth we have achieved in retail and customer volumes and numbers has been a standout in the last few years, and we've achieved this without big movements in headline prices. The project to move Meridian's customers across to the Flux platform is in its final stages and focuses now on the remaining complex corporate and industrial customers. I'd like to acknowledge the Meridian Retail and Flux teams for doing an absolutely amazing job. They have reimagined and rebuilt our customer service operating model and migrated 95% of our customers to the new platform. The really, truly amazing bit is they've done all of that whilst losing no momentum in sales and creating close to zero disruption for our customers. There's no doubt electricity pricing is an emotive topic, full stop. Higher wholesale prices have been exercising many in the market and in the media over recent times. There is still plenty of evidence to show the sector overall is delivering great outcomes for New Zealand across the energy trilemma. The price graph here, which is MBIE published data, tells quite a story. Historically, there has been a significant rebalancing in our electricity prices across sectors. I think that's well understood. It also shows, though, that in real terms, overall market prices have not really increased since the 1980s. During the last 10 years, other than the industrial sector, most customers have experienced real price decreases. Lastly, the hedging strategies adopted by most retailers have meant that the vast majority of customers have been insulated from these high wholesale prices that we've seen of late. The price for electricity in New Zealand compares favorably with other OECD countries, in particular, and as of last year, large C&I customers paid the seventh lowest price in the OECD. That's of little comfort if you're a large business trying to recontract supply in this market, and the high wholesale prices we're seeing are certainly a cause for concern. Meridian has not stepped away from any customer, and we've provided pricing solutions, including terms of five and 10 years, to help moderate the impact of the current pricing on those customers. We've clearly seen prices moderate as hydro storage has recovered. They still remain relatively high, however, but that doesn't mean to say we're seeing inefficient price signals or a broken market. We'll touch on the drought shortly, it is worth noting that both Meridian's Waitaki storage and the national hydro storage only just got above average for the first time this year in the third week of July. Droughts cause higher prices, we have seen that many times before. Underlying the variable weather is the well-documented degradation in the gas deliverability that emerged in 2018. The outlook may be on the improve as investment programs of major producing gas fields are underway or are yet to define. Simply put, right now, the system has less fuel storage and capacity available for it to meet demand than we have enjoyed over most of the last decade. We're seeing the industry respond with several new renewable projects, that will deliver around 8% of electricity demand at a cost of about NZD 2 billion. These projects are in construction and they're in full commissioning right now, and more new developments are also being signaled. These stabilizing initiatives take time to turn up, and given hydro water values reflect scarcity, we believe supply risk is still being priced into the spot and electricity futures markets. In my view, the long-term trend in prices is likely to be down as renewables become cheaper to build. We're also likely to continue to see considerable short and medium-term price volatility, both up and down, as the percentage of renewable energy increases. The risk management strategies adopted by businesses will need to account for that volatility. I mentioned earlier that there is sufficient liquidity in wholesale hedge markets to enable us to manage the portfolio risk to further retail growth. This chart shows just how successful the reforms of the electricity hedge market in 2009 have been. The volume of exchange-traded ASX futures has trended up to be similar in size to the physical market. In FY 2021, volumes far exceeded the physical energy traded. As you can see, Meridian has put significant capital at risk and continues to do the heavy lifting in terms of supporting ASX growth. ASX is only part of the story. There's also a strong over-the-counter market in New Zealand and a growing market for long-term power purchasing agreements as new developments are being kicked off. I think there's plenty of liquidity and opportunity for parties to manage risk and their exposure to wholesale prices should they choose to do so. Of course, there's no point in waiting until your house catches fires before attempting to buy insurance. The Electricity Authority has an extensive market improvement program in play. Of late, we've seen the implementation of many of the Electricity Price Review recommendations. We've had an overhaul of the trading conduct provisions. That was needed. The final decision on corrective actions for the December 2019 UTS have been published. As expected, the cost to Meridian was within the NZD 5 million before tax amount that we provided for in last year's accounts. More recently, the events on the evening of 9th of August created a very poor outcome for affected customers. I can assure you that the industry's collective failure is felt most acutely by those of us who have a responsibility towards our customers. I'm certain all parties will want to ensure learnings are taken on board. We avoid a similar outcome occurring again. As I mentioned at the start, the industry is moving quickly into a decarbonization phase, and we'll have bumps along the way. There is a broader contextual conversation that also needs to take place. 2021 saw the landmark final advice from the Climate Change Commission to government on its first three carbon budgets. The government now has until the end of the year to set these budgets and release the country's first emissions reduction plan. Already there is movement on government policy. The Clean Car Discount has been launched, and government have implemented further reforms of the Emissions Trading Scheme. From my point of view, this sets New Zealand on the path to its low carbon future, and the electricity sector is the biggest enabler of this future. Notably, the Climate Change Commission have recommended consideration of a 95%-98% renewable electricity target, which could allow for a longer runway for gas to support system flexibility. This month, Transpower published its new transmission pricing methodology. This offers an updated estimate of what Meridian could pay in transmission costs once reforms are implemented. We understand the Electricity Authority has asked Transpower to rethink some aspects of the proposed methodology, and further consultation will take place later this year. The TPM saga continues. Back in January, we reached agreement with Rio to extend our contract with the smelter to the end of 2024. It's fair to say that since then, we've enjoyed plenty of constructive feedback about the extent to which we were taken to the cleaners. Looking at where LME prices have gone since, it certainly would appear Rio got the best of that deal, at the same time, they've lost any option of a guaranteed electricity supply agreement beyond 2024. I think most people understand the revised NZ agreement is a cents in the dollar type arrangement designed to buy time. Time for the Southland region, the electricity sector, and Meridian Energy to transition away from a significant employer and user of energy, to do that in an orderly fashion. I guess it will be a far more interesting results briefing for all concerned if we were contemplating the smelter turning off all their pots next week, as could have been the case. The key thing is, we are making the most of that time to mitigate the impacts of the smelter closure. You'll be familiar with the plan as described on this page, and I'll just quickly go through the latest on some of the options. The swaps and replacement discussion continues with various parties. We think a portfolio of options is emerging, and as part of that, the Smelter Demand Response within the existing agreement with NZAS will likely take on a greater degree of importance. The Clutha Upper Waitaki Lines Project continues to track well, and Transpower do not envision any significant time delays. We aim to secure a North Island battery site by the end of September. Now, while the battery concept grew out of a desire to create greater effective capacity on the HVDC, an asset like this would have also made a big difference during an event like the ninth of August. We've upped the priority on this project and are looking at ways to bring it forward for deployment to late 2022 or early 2023. Earlier this month, Hawaiki Submarine Cable Limited, owned by the founders of Datagrid, was sold to a large Singaporean private company, BW Group Limited. We view this as a positive development, both for getting the sub-sea cables required for the Datagrid installed into the Southland, and more broadly for Datagrid itself. We expect to see significant focus on the Datagrid opportunity in the coming months. The hydrogen registration of interest jointly prepared by Contact and Meridian was issued to the market on the 22nd of July, which coincided with the public release of the McKinsey report and the launch of the Southern Green Hydrogen website. Counterparties have until the 10th of September to submit their responses. We'll evaluate those responses by early October and then enter into more detailed commercial and technical discussions with shortlisted counterparties. In parallel, we are progressing engineering pre-feasibility work that will support future counterparty discussions. I think we're making really, really good progress across a range of options there. Now, I'll finish with just some comments on the severity of this year's drought. Our analysis shows it was the third worst drought that we have seen in the Waitaki catchment. The amount of water that didn't turn up in FY 2021 compared to FY 2020 was the equivalent of the entire Lake Pukaki operating range twice over. Our catchments are generally fed by a small number of significant rainfall events each year, and there was clearly a lack of those between November and June. That's part and parcel of what we deal with, and I think we managed our portfolio well through the prolonged dry period. Mike will add a bit more color on that shortly. The good news is inflows in the last two months have now alleviated our fuel squeeze, and we've started the new financial year in reasonably good shape. I'll now hand over to Mike, who's leading our MEA ownership review, and he'll also drill into the numbers in a bit more detail. Over to you, Mike. Hey, thanks, Neal Barclay, and thanks everyone for joining the call this morning. I'm gonna talk very quickly to the review of our Meridian Energy Australia business before cracking into those financials. As always, I'll try and provide a little more insight than you might see on the slides directly, so showing up is worth your time. Right. We announced that we were considering an ownership review of the Aussie business during our Investor Day back in May. We followed this up with an NZX announcement early June. Following our board endorsement, we released a flyer during July, and last week followed this up with an information memorandum to parties who had entered into a non-disclosure agreement with us. This created a bit of media and speculation on both bidders and proceeds. All I’d say is don’t count your chickens yet, as it won’t be until later this year, all going well, that we decide whether ongoing ownership offers the most value to shareholders or alternatively, a partial or full sale. To get ahead of any questions, the reason we’re looking closely at our business in Australia is twofold. First, we noted that investors seem particularly interested in entities like Meridian Energy Australia. Second, the increasingly fragmented and interventionist electricity policy at state and federal levels in Australia concerns us. That said, we do like Australia’s long run prospects, as it must also transition to renewables, and the challenge there is larger than it is in New Zealand. Time will tell, but retaining an organic proposition in Australia remains an option for us. Back to FY 2021 financial results. It was an interesting and challenging year for us. In terms of the year itself, I think my comments at interims are a good place to start. If you recall, we had a decent first half with EBITDAF of NZD 422 million, which was down by about NZD 43 million on FY 2020, but still represented the best first half performance ever for Meridian. Or second best first half performance ever for Meridian. However, my key point from February was that we'd run into a dry patch by November and started using hydro storage to deliver revenue while we waited for summer inflows to arrive. I didn't know it at the time, but those inflows wouldn't arrive until mid-May, and the lack of rain would put a material dent in both storage and our opportunities. By late April, Lake Pukaki was approximately 700 gigawatt hours or 53% below average for that time of year. The drought, alongside the renegotiated Tiwai agreement that kicked in on the 14th of January, meant the second half EBITDAF was well down on the prior year, NZD 81 million to be precise. Full- year EBITDAF fell by 15%, from NZD 853 million last year to NZD 729 million this year. Underlying net profit after tax fell by 27%, from NZD 316 million last year to NZD 232 million in FY 2021. Both EBITDAF and underlying net profit after tax are non-GAAP measures, and if you look at our net profit after tax, you could be fooled into thinking we had a bumper year. The reality is that the majority of the difference between underlying net profit after tax and net profit after tax itself was driven by unrealized gains on electricity and treasury instruments, which do not translate into cash. Don't be fooled. The best way to measure how the year went, at least from my perspective, is by tracking operating cash flows. They fell by 29% from NZD 604 million last year to NZD 431 million in FY 2021. Don't get me wrong, our performance remained sound during the challenges we faced. We just didn't do as well as we did last financial year. Let's move on to dividend before diving into a bit of detail. As Neal's already mentioned, there are no surprises in the dividend space either. We're rolling the FY 2020 ordinary dividend through to FY 2021. That means a final ordinary dividend of NZD 0.112 per share will be paid on 15th of October. In turn, the full-year ordinary dividend will remain at NZD 0.169 per share, imputed to 86%. One thing I do want to pick up on here is that the board has approved implementation of a dividend reinvestment plan. We've signaled this a couple of times this year, and as a result, shareholders will have the option to participate in that plan. Those that do will be able to buy shares in Meridian with their final ordinary dividend proceeds at a 2% discount to the market value of those shares. Documentation that describes how the dividend reinvestment plan works is being sent out as we speak. Simply put, performance in New Zealand was sound in some areas and outstanding in others, there are a few things to reference in this slide. First, energy margin was NZD 128 million lower in FY 2021 than it was last year. As mentioned above, there's good reason for this, as while wholesale prices soared, we faced pretty sizable drought in the second half. While some uninformed commentators think we do well in these circumstances, the more nuanced know that it tends to create challenges for us, and those challenges are pretty simple. Without an adequate supply of fuel, we could end up short to those wholesale prices. Now, we're fortunate that our wholesale team puts a lot of thought and effort into managing our portfolio in these circumstances, and as a result, we didn't end up with spot price exposure. The hedges we bought and the lack of fuel weighed on energy margin delivery. For a drought as substantial as it was, the wholesale team did a superb job. As I've said before, we also have a pretty decent retail team. In my view, they are the best that are out there. They did a stellar job lifting contracted revenue by NZD 149 million, as shown on the waterfall. I know that some of you will be thinking that if we hadn't been focused on developing customer relationships, that we would have had stronger energy margin. That's possibly true, but it's short-term thinking, and what really matters is long-term success. If you pick up any business textbook, it'll tell you that's the only possible if you've got strong relationships with those who use your product. Whether you're an electricity business, a lust-filled teenager, or Amazon, relationships take time to develop. You might be wondering how teenagers fit into that category. They don't. My current lockdown experience cooped up with a couple of them suggests that they're too focused on short-term goals to think about longer term relationships. Anyways, I'm off message and getting into dangerous territory, particularly as one of them might burn down the stairs if they're listening to this. What I'm trying to say is that we've been really clear over the past few years that our focus has been centered around customers first. While that might cost us a little in the short run, we're confident that in the long run, it'll serve our investors well. I know there are folk out there that will also think that we're simply looking to extract more coin from them, but that's a cynical view. The reality is that if someone values what you do, they'll gladly pay you for your services and possibly stick with you through the tough times. That is what we're trying to build. So far, the data shows we're doing a reasonable job on it. Since I managed cynicism, this also feels like the right place to focus a little commentary on the wholesale market, particularly commentary that suggests it's broken. My only request to you is that you ask yourself why folk might be saying that, and yesterday provides a useful example. As yesterday, a group of large New Zealand business attacked another, us, for making too much money with the sole motivation of lifting their own profitability. Go figure. This was both surprising and disappointing, but given the underlying motivation, you have to be skeptical of the claim, particularly as the government looked into excess profit as part of its Electricity Price Review in 2018 and found nothing. Our own independent analysis completed by PwC aligns with the government findings. We've released those PwC conclusions, but I want to come back to my key point. Consider the motivation for claims before deciding whether they're credible as opposed to buying into the rhetoric directly. We see business attacking business, there will be an economic motivation. We know that some MEUG members were exposed to the higher wholesale prices in 2021, and that they want those prices to fall. We get that. I'd point out that in this case, the electricity industry has responded ahead of them by committing to approximately NZD 2 billion worth of new generation development in response to those prices. Those investing are not just incumbents. We're seeing new entrants step into the electricity market and invest as well. This is the exact response you'd expect from an effective market. This is a complex industry and silver bullet fixes do not exist. While kicking off in the media can make you feel better, it tends to distract from managing the challenges we face. The good news is that over the past 20 years that the market's been in effect, there's been substantial progress in terms of market design and levels of competition, even if over the same period, we've had a few moments that we wish we could have back. We're always striving to get it right, but perfect does not exist, unfortunately. The progress has been substantial enough for residential customers to see pricing, security of supply, sustainability, and product choice benefits. That might seem like a strange thing to say following the events of 9 August, but I've said this is a complex industry and when things are complex, they don't go right all the time. The industry actually has a pretty decent track record, at least compared to the period before the market existed, and we need to give folk time to work through how such situations might be avoided in future. In the meantime, the data that I see and Neal referenced suggests that residential customer costs per unit are lower today in real terms than they were in 2013. I should point out that industrial customer per unit costs are rising, but they're still approximately half the cost that residential customers pay. That's pretty decent empirical evidence as it means that for residential customers, electricity is a smaller part of people's cost base than it was back in 2013, at least in inflationary terms. To top it off, the International Energy Agency last ranked New Zealand's electricity market as the 10th best in the OECD, and New Zealand is the only non-European country in that top team. We also get the International Energy Agency's highest rating of AAA and a pretty solid soundbite in that New Zealand is a world-leading example of a well-functioning electricity market, which continues to work effectively. We know that the International Energy Agency will update its rankings in October, we'll get to see if that view changes. That is where my security of supply comment came from. Anyways, the facts suggest that residential customers are benefiting from what has played out within the electricity sector, and our team will continue to work out how we attract more of those customers to Meridian. Right, let's talk about Australia. The key feature on this slide is the fall in generation spot revenue. As I've noted in the second and third bullets, generation volumes sound, wholesale prices fell materially, and this drove the NZD 39 million reduction in energy margin. In turn, this flowed through to EBITDAF, which fell from NZD 66 million in FY 2020 to NZD 38 million in FY 2021. The good news is that wholesale prices lifted towards the end of the financial year, if you've seen our operating stats for July, financial performance has improved materially. Since lockdown, the growth in customer numbers has slowed, even though customer revenue has grown on the back of a 20% lift in household consumption due to lockdowns in the lucky country. Growth in customer numbers slowed, but the team in Australia remain committed, and they once again lifted the Roy Morgan Electricity Provider of the Year and Canstar's Most Trusted Energy Provider award. I always like to say something about Large-scale Generation Certificates or LGCs. Largely, as we do not have or need such certificates in New Zealand. The team in Australia both create and then sell LGCs from our renewable generation assets. Unlike previous years, where hedging of LGCs added value to the business, this year, mark to market losses from them were NZD 3.3 million, huge derivative sales and purchases are well off FY 2020 levels. I'll finish with my other favorite when talking about Australia hydro storage or good news. Storage at both Burrinjuck and Keepit hydro power stations is full, at Hume, storage is higher than at any time Meridian has owned that asset. I suggest you look at the Hume graph on the Goulburn-Murray website, you can see what I mean. It looks like we're gonna get decent generation volumes from those facilities this year. This is a new slide, we added it as we think it provides some useful insight. First, it sets out that we, like all retailers, pay the spot price for electricity consumed by our customers. Doesn't matter whether a company is vertically integrated or not, the New Zealand electricity market ensures a level playing field for retailers. This slide also builds on the New Zealand energy margin slide that showed that the cost to supply customers has grown massively. Here we show that at NZD 184 a megawatt hour, the price paid to support our customer base in FY 2021 was about NZD 89 a megawatt hour higher than in FY 2020. Finally, it highlights the internal transfer price that our retail team buys electricity from our wholesale team at. As stated on the slide, it was NZD 81 a megawatt hour in FY 2020, and it lifted to NZD 88 a megawatt hour in FY 2021. What isn't as clear from this slide is how we calculate that price, but it isn't that complex either, so I'll summarize it here. We simply assume that a retail business would hedge its risks progressively over a three-year period, and the FY 2020 and FY 2021 internal transfer prices reflect that. The average of the previous three years' ASX prices for the relevant financial year, shaped on a volume-weighted basis based on our consumption profile. Of course, there are more important issues than internal transfer price. We thought it was useful to capture this information. On to operating costs. There's always a bit more on this one than I think is necessary. Long story short, we showed discipline again in FY 2021 in relation to costs. At this time last year, I stated that we expected to spend between NZD 261 million and NZD 266 million, and we spent NZD 265 million. While that's a lift of NZD 6 million on last year, by the time you strip out the accounting adjustments for software as a service and the Holidays Act provision, underlying operating costs lifted by NZD 3 million during FY 2021. That increase was directed towards our development activities where we continue to ramp up effort to ensure we have sites available to meet expected decarbonization growth. For those not versed in the software as a service adjustment referenced here, in April, IFRIC, the International Financial Reporting Interpretations Committee, revised its policy in relation to costs incurred implementing software as a service arrangements. Long story short, following that policy revision, all costs related to software as a service should flow through the P&L as operating costs, as opposed to recognizing those costs as intangible assets on the balance sheet and amortizing them over time. Given this decision, we've presented a small restatement for FY 2020 and in FY 2021, software as a service costs amounted to NZD 2 million, as you'll see on this graph. For those that would like more detail, you can see page 122 of our annual report. Second to last comment. While it doesn't capture the cost item here, we've retained an elevated provision for doubtful debts in FY 2021. At NZD 9 million, it's lower than the NZD 15.7 million provision held in FY 2020, but it's approximately NZD 4 million higher than the levels held before COVID showed up. How it moves in time will depend on how the economy navigates the virus. With that in mind, during the first week of lockdown, electricity consumption looks like it is down by about 7%, which is not substantial compared to lockdowns in 2020, where consumption fell by between 16% and 19%. That could change, of course, so we will see how things progress. Finally, we estimate that operating costs will fall in the NZD 275 million-NZD 280 million range this financial year, largely driven by NZD 6 million of software as a service costs flowing through the P&L, with the remainder driven by ongoing focus on development and lifts in insurance and employee costs. I talked about net profit after tax and underlying net profit after tax at the start, so I will not dive into it in too much detail here. As the two graphs show, our preferred measure of performance, underlying net profit after tax, fell by 27% from FY 2020. I'm sure that makes sense to most of you, given explanations provided earlier in this presentation. It shows that year-on-year, our cash performance was impacted by the drought. While net profit after tax lifted by 145%, the key difference between the two measures is fair value movements in both electricity and interest rate derivatives. These are non-cash items that can move materially year-on-year. For example, in FY 2020, electricity derivatives reduced NPAT by NZD 113 million, this year lifted it by NZD 169 million. They can move around considerably. My simple message is that FY 2021 was not the record year that FY 2020 was. Other than for that, in Australia, we saw a gain from changes to the Australian generation asset remediation costs. While it isn't shown here, the value of Mount Millar and Mount Mercer wind farms was stable, and the Green State hydro asset valuation lifted by NZD 55 million. I don't have too much to add to the statements captured on this slide. Stay in business CapEx remains stable at NZD 50 million, the decision to move forward with Harapaki and the ongoing work to cut over our customer platform to Flux meant that investment CapEx was NZD 72 million, which is well up on prior years. Harapaki consumed about NZD 41 million of the cash, and the cut over to Flux, much of the remainder. While I'm on the customer platform cut over, the customer team delivered the impressive results I mentioned earlier while this was in progress, and there hasn't been any material issue for our customers or our business in completing this three-year project. We're pretty sure that customers are going to love what they see in the coming months as we finish the migration of C&I customers onto the Flux platform and then start optimizing it. I'll leave you with our forecast CapEx range for FY 2022, which is NZD 205 million-NZD 215 million. I expect stay in business CapEx to be similar to FY 2021, with the residual largely attributed to Harapaki and Australian development activities. We'll revisit this when we've determined the outcome of the ownership review. Our balance sheet remains a pretty straightforward read. Net debt lifted by 9% over the year to NZD 1,648 million. While net debt to EBITDAF lifted from 1.8x-2.3 x, S&P removed the negative outlook from our BBB+ credit rating following completion of the NZAS transaction. I'll finish where I started. It's been an interesting and a challenging year for investors in Meridian. Our team is focused on working through the transition away from aluminum as directly as it is focused on the economy-wide transition away from fossil fuels. We need to put our best feet forward if we are to make that transition a successful one for both our shareholders and for New Zealand. Neal, back to you. Just get off mute. Thanks, Mike. I think you summed things up quite nicely there. I'll just make a couple of concluding comments myself. I think what you see in Meridian is a high-performing business and a culture that is values-based, and our customers do understand that about us. You can expect us to be very focused on mitigating the loss of the aluminum smelter, but in doing so, we will not lose sight of the big picture, and we will continue to focus on our customers and supporting New Zealand's decarbonization goals. What you see in the electricity sector is an industry that, whilst not perfect, does deliver world-leading outcomes for New Zealanders across the trilemma of reliability, sustainability and cost. Most importantly, that market is delivering clear investment signals and the industry is responding. I think we'll wrap it up there, and move to questions. Obviously, there's none on the floor today, so we'll be going online. Thank you very much, sir. Ladies and gentlemen, we will now begin the question- and- answer session. As a reminder, if you wish to queue for a question, please press zero followed by one on your telephone keypad and wait for your name to be announced. That is zero followed by one on your telephone keypad. Thank you. Your first question is from the line of Andrew Harvey-Green from Forsyth Barr. Please go ahead. Thank you. Morning. Morning, guys. A couple of questions from me. First of all, just around sort of understanding some of the OpEx and the increased there. I guess from my perspective, I'd expect there's a little bit of a decrease potentially coming through from the Flux, and some sort of benefit coming through from that. Is that still the case? Or has there been some change there? Mike- Yeah. talking about the benefits from Project Momentum. Do you want to cover that? Hey, Andrew. I can't remember whether it was in that slide or not, but what you've seen is customer servicing costs have held flat. In fact, decreased slightly over time. We'd expect that to continue in the coming years. Where we're really focused on making sure we've got the right cost base is in that development space, which is why I pointed it out, as part of the FY 2022 forecast. In essence, the underlying cost base growing a bit faster than probably what the [audio distortion] are delivering on the other side [audio distortion]. Sorry, Andrew, I missed that. Hey, I think I got the gist of it, but missed some of it. I said it last year at our announcement results as well as the delivery of that program, is delivering real cost benefit. What you see is the growth in customers, there's a growth associated with growing customers, just growing that customer base. Every time you pick up a customer, their metering and field service costs alongside internal costs. The Flux platform, what it's allowed the customer team to do is manage and gain efficiencies in our internal cost base, even while we've added material volume of customers to our business. We'd expect that to continue over time. It's well and truly delivered business case benefits and the efficiency outcomes that we expected from it. We're actually pretty proud of the fact that we're holding those customer costs flat to falling slightly while we're growing our customer base as material as we have. Okay. Second question is just on the CapEx and clarifying a couple of things. On the slide, it was like NZD 45 [audio distortion] funds. Not sort of mentioned NZD 50. Just looking at that past five years, does that look like [audio distortion]? Sorry, on previous. Is that the kind of level we should be doing long term going forward? Andrew. You're really breaking up. I think you're talking about stay in business CapEx. Mike, just give a bit of flavor of how that looks going forward, I think. Yeah. Andrew, I think if I picked it up, I said that I'd expect stay in business CapEx to stay reasonably at FY 2021 levels. As you say, I'd mentioned approximately NZD 50 million, the slide it's got NZD 45, you can see the trajectory over the past few years. I think that's a reasonable frame for stay in business CapEx, moving forward. Where I was really trying to get people to pay attention is the growth CapEx that plays out as it relates to Harapaki, then possibly development in Australia, if we continue to be owners of that business. Does that give you enough? Yeah. No, that's okay, thanks. The last question, given it's pretty hard for you to hear me. Just around the swap contract and what you thinking there. You talked about the smelter perhaps getting involved in placing that. Am I right in saying that was the first time that they've really been talking about the details and giving you a sort of more color about how much Mike is looking at providing? I'm sorry, Andrew, I didn't get the gist of that at all. It was something about the smelter. Mike, did you? Look, I think it was, Andrew, I'll try and paraphrase it. It was you were talking about swap and replacement and Neal's comment in relation to the SDR, the Smelter Demand Response- Yeah. That's better. whether we had had any sort of conversation with Rio in relation to demand response following the conversations last year. The answer to that is no. No, we haven't had any engagement with Rio Tinto on their activities since conversations we had with them last year. What Neal was really referencing is we're looking more wholly at a package of both supply and demand side options to manage that underlying hydro volatility or hydro inflow risk. What we can see is that that Smelter Demand Response component of the Rio agreement in fiscal year 2023 and 2024 could form part of that package. It's an existing arrangement that we have with them rather than anything new. Yeah. I'll just add to that. It's an existing arrangement. We can envision better arrangements that would actually work for both parties, and whilst we haven't had any conversations with them about those since the extended exit deal was put in place, we've made it very clear to Rio leadership that, if they ever wanted to entertain any thought of remaining in this country beyond 2024, they'd have to bring something to the table that made them operate in a far more sympathetic way with the overall industry, as opposed to just being a taker of energy. Okay, thanks so much for taking the questions offline. Thanks. Thank you, sir. Your next question is from the line of Steven [audio distortion] Securities. Go ahead. Good morning, guys. Can you hear me okay? Yes. Yep, we're good. I just have four questions if I could. You've had a PP&E fair value change. I just wondered if you could give us some idea of the assumptions around the NZAS volume and pricing post-2024 in that fair value change in PP&E. Secondly, maybe one for Neal. Is a gas fuel swap option acceptable to you post 2022? Then maybe back to Mike, could you give us an idea of the book value of the Australian assets under review? Then just lastly, Harapaki. Could you confirm that you're fully at risk on your civils? And if so, what are you seeing in these early days on the civil works? Hey, thanks, Steven. I'll cover off two and four. Mike, you cover off one and three. Hey, Steven, you picked up the PP&E fair value movement. PP&E lifted by NZD 200 million. The assumption that we're using for NZAS is that it is not connected to the system as part of that valuation. That's the simple assumption is there is no consumption from Rio Tinto, therefore no price, no contract. Hey, I'll pick up number three while we're on it, which was, I think, book value of the Australian assets, which doesn't come out through our accounts. I'll be wrong on it because I've got last year's value in mind. The book value is about NZD 470 million net assets. Steven, on your second question, would we entertain a gas fuel swap option? Absolutely. We are in conversations with parties around such a sort of transaction. I would say, though, that the economics of a gas peaker have got a lot tougher of late, and they need some sort of confidence they can get a return on that investment within a relatively short space of time. That's sort of the issue that I'm alluding to. We're certainly looking to work with parties in the industry to support those sorts of investments because we're going to need them. There's no doubt about it. Harapaki, yes, we are at risk at the civils. We manage the project ourselves, and the project has gone into abeyance with the lockdown. There will be some cost of that. At this stage, because we're in the early stages of gearing up into the actual project, those costs are not that significant. Obviously, if we go through further COVID delays through the construction period, then those costs will build. We have built in a reasonable amount of contingency for that eventuality into the economic projections before we signed up to the deal. That's really useful. Thanks, guys. Thanks, Steven. Hey, Neal, I just had a text from Andrew who said our call quality isn't the greatest either. He wondered if, while the questions are on, whether we both go on mute so that we can hear him a bit better. Andrew Harvey-Green, I would agree. It's a good suggestion. You go on mute and I'll throw it to you. Yeah. Okay. Thank you, sir. Your next question is from the line of Grant Swanepoel from Jarden. Please go ahead. Thank you. Morning. Hopefully my voice isn't doubling up. It is. Just on from Andrew Harvey-Green. The maintenance CapEx. Mike said NZD 50 million, but the presentation said NZD 55 million-NZD 60 million. Which is it, Mike? Brian, I think if you use NZD 50 million, you'll be fine. The forecast that we've got for FY 2022 is captured in the presentation, says standard business CapEx of about NZD 55 million-NZD 60 million. What we've tended to find is our forecasts have exceeded our actual capacity to deliver standard business CapEx. The numbers that you're seeing, the actual numbers in the preso, I think would be a reasonable forecast for you. Thanks. Next, data opportunities, exclusivity. Has he bought land yet? When does that exclusivity fall away if he doesn't buy soon? Sorry, Grant, which opportunity are you referring to? The data center. Oh, the Datagrid. Datagrid. No, look, I understand this. They've got conditional offers in on a range of properties, but they haven't gone unconditional yet. Does his exclusivity expire if he doesn't? Yes. Our exclusivity expired on the original terms about one month ago. We pushed it out based on the progress that we saw Datagrid making. We gave them another two months to land something, Grant. Thanks. Final question. The 171 GWh heat contracts with just a 250 target, does that seem a bit lax opportunistic intent? You're talking about the process heat electrification target? Yeah, look. Yes MOUs of companies that are actively moving to electrify their fossil fuel use. Whether it's equating Like I say, I think got a couple of MOUs that I hope to have sort of floating around on my desk within the next day or two. We'll be pushing 250-300 as we sit here today. We've actually increased that target internally. We think there's the opportunity to go for about 600. If we can get support from government, particularly around this transmission and distribution cost, which is the main hurdle for getting the economics over the line, then I think that sort of level of growth is achievable. Obviously it'll be a great outcome for the country in terms of reduction in emissions. That's great news. Thanks. Thank you very much, sir. Your next question is from the line of Jeremy Kincaid from UBS. Please go ahead. Thank you. Hi, team. Hopefully this is clear. First question, just around the three buildable options by 2024. Can you give some color on what they are and the potential size? We're still fine-tuning the portfolio, but there'll certainly be one wind farm in there, and we'll be pushing through to consent on one of our wind farm opportunities, in the not too distant future. We've got a couple of really promising grid-scale solar sites coming up that we think we should be able to get to a consented state in the not too distant future. We've also got the battery in play and we've got a conditional offering on a parcel of land on that at the moment. We think with the progress we've made on the design, we can probably get that deployed, like I say, sometime late next year or early the following year. I'd say it'll be a portfolio of probably battery, solar opportunity and at least one wind farm, possibly two. The potential size of the solar and the wind farms? The next best option for us is our Mount Munro option, which is in the Wairarapa. I think it's circa 50 MW. Is that right, Mike? Yeah. Yep. We're trying to do Thank you. We will look at big options as well, but we think medium-sized chunks are one, they're easier to deploy, we can do them more rapidly, more flexibly, and the economics are looking pretty compelling for them. Sure. Second question. Just on the process heat MOUs, you've made good progress there. I suppose your guidings are greater than 250 gigawatt hours over the next three years. That just seems a bit conservative. Can you talk to that relative to the success you've had? Yeah. As I was just saying to Grant, we've internally lifted our sights to at least 600 gigawatt hours. The opportunity is greater than that, some of these parties we're competing with biomass as well. One of the really exciting things with this opportunity, too, is we're starting to work through options to enable these customers to provide demand response back into the system, so they can keep some element of their existing infrastructure in place and can either run it on biofuel or even, if need be, coal. You're making a step by moving the bulk of their usage off those fuel types onto electric in the first place. We think we can do it in a way that provides quite a lot of flexibility back into the system. You're right, 250 is soft and we're revising our internal view as to what's possible. Jeremy, I might just add a touch to that is that there is a massive opportunity out there for fuel conversion. As you know, if you've seen any of the reports that are floating around, the biggest constraint we've got is actually network transmission pricing. We're going to need some form of breakthrough if we're to see numbers bigger than what Neal has mentioned as the way that transmission distribution charges are allocated to new customers cutting across is an area that will challenge not only what we're trying to do, but it'll form part of the plank that the government's got to decarbonize the economy. That's what will limit the opportunity. The economics are lining up probably better than we expected, but that one there is a bit of a challenge. Great. Thank you. That's all for me. Thank you, sir. There are no further questions at this point. I would like to hand the floor back to the speakers for any closing. Please go ahead. Thank you. Okay. Well, there's no further questions, we'll call an end to it there. Thank you all for attending. Sorry, the call quality was obviously a bit average there when we were doing questions, there'll be plenty of opportunity in the coming days to talk to most of you and fill any other questions you have. Anyway, have a good rest of your lockdown. Enjoy the rest of the day. Thank you.