Kia ora tātou, and welcome to Meridian's annual results presentation for the financial year ended 30 June 2023. I'm Neal Barclay, Meridian's Chief Executive, and I'm joined by Mike Roan, our CFO. I'll cover off the updates on the business and the sector, and then Mike will take you through the financial result. I'll then wrap up things, and then we'll get to your questions. You all note the topic missing from this highlight slide is NZAS. Six months ago, I said discussions with NZAS were continuing, and in the intervening six months, those discussions have continued to continue. There's really not much else we can add at this point, and we will inform the market of the outcome as soon as we know what it is. As for the financial result, at first blush, NZD 95 million NPAT looks like a bad year, but our net profit swings around hugely based on revaluation gains and losses on energy interest rate derivatives. Mike will help demystify that soon, but the number we really still focus on internally as a key metric of operating performance is EBITDAF, and pleasingly, at NZD 783 million, that was 10% up on the prior year. Strong retail performance continues to power our underlying earnings growth, supported by good management of the realized portion of our forward hedge position. That has allowed us to continue to nudge the dividend upward again this year. We remain very focused on supporting customers decarbonize their energy needs. We're now energy supplier to 472 GWh of committed process heat electrification projects, and the pipeline of potential projects continues to expand. A recent joint study completed by EECA and DETA found that boilers larger than 500 kW represent an electrification opportunity of more than 4,500 GWh in the South Island alone. We're delighted to announce a 27 MW demand flexibility agreement with Open Country Dairy. The demand flex they can offer will help Meridian manage both seasonal and peaking price volatility. This arrangement is a key part of their electrification project and represents a real win-win for the customer and the energy system. The potential for commercial demand response is massive and still largely untapped. We are the first mover on grid-scale battery technology in this country, with the construction of our 100 MW battery at Ruakākā in Northland. Our work to re-consent the Waitaki Power S cheme reached a significant milestone last month when we lodged a new consent application. We're seeking a further 35-year operating consent commencing in April 2025, on the same conditions as we have here today. We've been working with many interested people for many years to ensure our application has strong support across the board. Most notably, we've reached agreement with DOC to turbocharge Project River Recovery, and we're developing a strong partnership with the Waitaki Rūnaka of Ngāi Tahu that will deliver environmental and cultural benefits for generations to come. The Harapaki Wind Farm has worn the impacts of three ex-tropical cyclones and another of other large rainfall events during the first two years of construction. Cyclone Gabrielle, we all know, caused widespread damage over a large area, including within our construction site. The response from our team and staff at Transpower, Unison and Waka Kotahi, in and around the areas of destruction, is something I'm very humbled by and very thankful for. I'd also like to call out our team members who acted as first responders during the flood crisis. They were acknowledged by Red Cross for being there and being able to help when it mattered most. As we signaled to the market in July, all up, we've lost around three months to the schedule, but the project is now out of the ground and large turbine components are being transported to site. We should get the whole thing stood up and operating by next September. The Harapaki Wind Farm will produce enough power to supply around 70,000 homes, and just as importantly, will help improve grid resilience into the Hawke's Bay region. As we mentioned at our interim results, our development team have made strong progress increasing the size of our development pipeline. This pipeline now comprises options totaling 11 TWh, which is equivalent to 90% of our existing generation portfolio. This pipeline will undoubtedly change over time, but the key thing is we're creating a portfolio of development options with real depth that will support business growth for the next 30 years, not just this decade. Transformers have been something of a headache for us this year. Most significantly, two of our Manapōuri transformers have been showing elevated gassing levels and have been on extended outages. These are relatively new machines, and they shouldn't be misbehaving. Work continues to establish the cause of the issue, and while we hope not to have to write off either, the process is underway to procure at least 1 new Manapōuri transformer. Having a diversified, high-quality asset base really does make a difference, and we have enough flexibility across our generation fleet to manage several unit outages, outages like this. However, capacity is becoming more valuable, so the commercial case for carrying spares is making more sense now than it used to. On the plus side, our asset team have found a way to extract additional megawatts out of our Benmore and Manapōuri units. All up, they've added 43 MW of capacity across both stations and are chasing another 18 MW. That's equivalent of a decent-sized battery for close to zero real cost. We're working with credible and committed partners on Southern Green Hydrogen. Woodside and Mitsui are there, and we have secured the option for Ngāi Tahu to join the JV at the point of financial commitment. There is complexity in terms of the technical and commercial terms of the development phase, so progress has been careful, and we need to ensure that the JV foundations are right. What we have here is real. Hydrogen will play a significant part in the future low carbon energy system in New Zealand. So for me, Southern Green Hydrogen represents not only a strong commercial opportunity for our business, but even more importantly, potentially a significant step toward energy independence for our country. Now, every outcome that Mike and I talk to during this presentation is directly attributable to our people. So creating an inclusive culture that allows us to build a diverse and talented team is really priority number one for us. Over the last 12 months, we've focused on modernizing our staff benefits packages to include a broader definition of well-being leave, higher parental leave, KiwiSaver top-ups, better service recognition, and free medical insurance for all to accompany our life insurance already in place. These improvements have resonated really well with our staff. We've also refreshed our program, supporting our Belonging and Te Ao Māori strategies, and we've matured our hybrid working protocols. In April last year, we had to exit our Wellington HQ due to seismic issues. It's taken a while to sort out a long-term solution. It's very pleasing to note that last week we signed a lease on premises in the iconic Old Bank Arcade, and we expect to move in there early next year. Ultimately, we want an environment where our people can thrive and do their best work, but firstly, we need to avoid causing harm to anyone. While all the injuries incurred in our business over the last year relate to slips, trips, and strains, some of them have the potential to be much worse. Overall, our safety performance benchmarks well with industry, but our focus needs to be, and is unrelenting. The electricity market in Aotearoa continues to rate in the top 10 of the OECD countries in terms of the energy trilemma of affordability, security, and sustainability. It simply works very well. Just imagine for a moment that you are a South African resident suffering years of daily managed blackouts to avoid grid collapse, or an Australian customer having copped a +20% price increase this last year. After adjusting for inflation, residential and business prices have tended down in New Zealand for the last 10 years. Using a slightly different lens, over the same timeframe, electricity costs as a percentage of average household income have fallen from 2.4% to 1.8%, a reduction of 25%. Whilst industrial prices have risen over recent years, they are still competitive internationally. However, none of that is any comfort for many Kiwi households who are being squeezed by cost of living pressures. So we've launched an Energy Wellbeing Programme that will invest NZD 5 million over the next two years to provide targeted, direct support for 5,000 households. The program builds on the successes and lessons learned from the pilot we ran in 2022 that involved 134 households. Our team will work with customers who are struggling to make ends meet by understanding their needs, setting realistic goals, and offering support that will have the most impact on their circumstances. It does require a higher engagement model, specialist skills, and a strong network with the many agencies that support those most in need. We've found we can be effective and make a real difference to people's lives. Meridian has been and intends to always be fully compliant with the Electricity Authority's Consumer Care Guidelines. Our record on consumer care speaks for itself. We continue to have extremely low disconnection rates, and our credit team operate to a mantra that we do not disconnect any person who genuinely wants to pay their bill, even if sometimes they can't. We were also the first of the large retailers to cease clawing back from payment discounts a few years back now, and I think we're certainly showing leadership with our new energy well-being initiative. Forward prices have been through a crunch, and whilst now moderating, there is clearly still significant risk priced in. Peak load management, the role and availability of gas and gas storage, impending thermal plant closures, hydro firming options, NZAS's future operations in the country, and political and regulatory risk are all live issues for the sector. Ultimately, though, wholesale prices should trend towards the marginal cost of new generation. Hence, we still expect to see real prices moderate to within an NZD 80-NZD 90 per megawatt-hour long run average range. I think you see that kind of conviction from us and others in what is occurring in mass market retail prices, which have not reflected the lift in near-term wholesale forward prices. Most parties do take a long-term view, but as I've said before, it's likely to be a bumpy ride as we transition to a more renewable grid, and risk management capability is more important than ever. The good news is, the tools at our disposal to help manage risk, volatility, and physical risks are improving. I've mentioned demand response starting to emerge and offering significant value. Trading liquidity is as strong as it's ever been, and the offtake market is also evolving rapidly. There are enough parties with enough conviction to trade in the futures market at 2.5x t he system's physical generation. Environmental policy reform has progressed with the Natural and Built Environment and Spatial Planning Acts now passed into law. As written, these present concerns for the consent ability of renewable energy developments against more strongly articulated protections for environmental bottom lines. Government's process to improve the National Policy Statement for Renewable Electricity Generation, which will aid and better balance under the new legislation, requires a further round of consultation, and that will be a key area of focus for the entire sector. Importantly, as a sector, we remain highly aligned and engaged in the ongoing process of consultation to land a resource management framework that supports decarbonization. I think most people, including the policy and lawmakers, generally understand that delaying renewable energy growth is not an option for us here in Aotearoa. However, the environmental reform process has been complex, and the transition to the new statutory environment will require strong engagement between Central and local Government and the electricity sector. The Ministry for Business, Innovation and Employment completed a pre-election drop of a host of consultation papers on a variety of future energy topics, including the Gas Transition Plan and a Hydrogen Roadmap. Cabinet have also decided to further investigate the Lake Onslow hydro pump storage scheme and a more market-based portfolio approach as the two options under the NZ Battery Project. All of this activity is meant to inform the NZ Energy Strategy, which is intended to pull everything together into something coherent. As I mentioned earlier, we have a mature and competitive electricity market in New Zealand that is delivering good outcomes for consumers, and I'll be inclined to let it get on and continue just that. There is no shortage of capital looking for renewable projects, and investment is incurring at an ever-increasing rate, so I'm not convinced all of the central planning activity is necessary, but we will obviously stay fully engaged with the processes. I think where the government can and is adding value is by being clear and committed to an emissions reduction program, and there is good momentum being gained there. Two large-scale industrial decarbonization partnerships have been announced recently, and the GIDI Funding Program continues to allocate support for good decarb projects. Earlier this year, the government also tuned up the Clean Car Rebate. This is all needed when you look at the rate of abatement required to meet our country's Emissions Reduction Targets. It is critical that we have an ETS that the country can have enduring confidence in. The incentives need to be there to invest in reducing gross emissions. We can't just offset our way to a net zero carbon economy. So it is pleasing that the government's temporary departure from the Climate Change Commission's recommended direction of travel for ETS pricing looks to have been resolved. But that's true at Meridian, too. Our Half by 30 roadmap and our Climate Action Plan are focused on reducing our own gross emissions. And for those emissions we can't avoid 100%, our 100% emissions offset target has been expanded to now include one-off construction emissions. And the quality of our offsets matters, which is why we are building out our Forever Forests program, so that by 2030, our planting will remove the same level of emissions as Meridian produces. We're a long way down the road of identifying, quantifying, and managing climate-related risks, and you'll no doubt gather when you read our annual report cover to cover, as I'm sure many of you will, that there is a huge effort going into appropriately measuring and reporting all aspects of ESG. There's no task for the faint-hearted, and we are committed to leading in sustainable business practice and sustainability reporting. But the job ain't getting any easier, and our ability to prioritize on what will genuinely make a difference will be key from here, I think. A year ago, we shifted our retail approach from strengthening our market share to a focus on energy innovation and solutions that support our customers on their decarbonization journeys. This new approach is starting to show good results. We've quietly built up this country's second-largest EV charging network. We've also been working with 15 companies over the last three years to support them to reduce their emissions profiles from process heat. The companies listed at the bottom of this slide all have projects that are well advanced, and they're getting on with it. I think they deserve serious accolades for their stance on Climate Action, and there's plenty more businesses still refining their plans. Now, you'll, you'll hear me keep belting on about demand response because I do believe in it, and it is key to an efficient, clean energy transition that delivers megawatts without having to build them. We now have commitments of up to 90 MW for a seasonal demand response, including the Open Country Dairy arrangement I mentioned earlier, and the 50 MW deal we concluded with NZAS earlier this year. Being able to offer demand response is a very valuable aspect of the Southern Green Hydrogen proposition. While we understand the importance of gas to the electricity system, and we will continue to support gas generation for hydro firming, it is great to have alternate options as part of a more diversified and resilient hedge portfolio. That also adds value for our customers. We have a lot more to come in terms of distributed generation, storage, and virtual power plant customer propositions. I plan to be able to put more meat on those bones this time next year. I mentioned at our last results announcement that most of the NZAS exit mitigation opportunities are now squarely baked into our growth strategy. As you can see from this chart, most have progressed well or have been nailed. You'll also note some of our competitors have been busy supporting other demand growth opportunities and readying thermal fleet, the thermal fleet for retirement. If the smelter owners decide to wind down operations late next year, our business and the entire sector is now in a much stronger position to manage the potential impact. On the other hand, if the smelter commits to continue beyond 2024, there is a sizable pipeline of South Island generation options, including ours, waiting for investment and certainty. So I think from where we are today, if anything, the risk is balanced to the upside. Undoubtedly, it will be a better outcome for New Zealand and climate challenge if the smelter remains operating in New Zealand, and from our perspective, it certainly looks commercially viable. But certainty, one way or another, is what we all need most. I talked about Harapaki at the start. Suffice to say, it was very satisfying and a wee bit of a relief to see turbine, turbine componentry delivered to site last month. We expect to produce enough new juice to power all the homes in Napier by September next year, and we also expect to complete the project inside our existing NZD 448 million capital envelope, which is a pretty good outcome, we think. I talked earlier about the depth we are building in our pipeline of development options. That's great, but we're also mindful of the near-term imperative to make a decent hole in Aotearoa's emissions by 2030. So we're driving hard toward our toward our 7 and 7 objective, meaning getting 7 grid-scale renewable projects underway in the next seven years. Construction is well underway at the Ruakākā grid-scale battery site in Northland. A consent application has been lodged for the Mount Munro Wind Farm in the Wairarapa, and we are very close to lodging a consent application for Ruakākā Solar. We're also looking to consent our Swannanoa Solar option just north of Christchurch early next year. All up, our seven and seven plan will consume around NZD 3 billion in capital this decade, and our balance sheet can comfortably cope with that. I'll now hand over to Mike to unpack the financial result. Ngā mihi, Neal, and kia ora tātou, everyone. Ko Mike Roan tōku ingoa. Thanks for joining the call. As Neal's noted, if you only read the income statement, it might look like we had a poor result last year, but that couldn't be further from the truth. Meridian had another year of strong performance. It wasn't straightforward, they never are, but our teams found ways to incrementally lift operating cash flows while we patiently progressed a number of strategic initiatives. There's nothing flashy in the result, just lots of good old-fashioned hard work, and that shows character, in my view, lots of it. Over the next 15 minutes or so, I'm gonna focus on that result, and I'll start with dividends. The lift in final dividend shouldn't be a surprise. While we don't provide dividend guidance, what we did say last year, and again at interims, was that we would use some of the proceeds from the Meridian Energy Australia sale to support dividend flow through 2024, or at least up to the point when Rio Tinto makes it clear what it intends to do with the smelter. That's what you see on the slide, a 3% lift in the final ordinary dividend from NZD 0.1155-NZD 0.119 per share. It'll be imputed at 80% and paid to shareholders on the 22nd of September. This lifts the full year dividend from NZD 0.174 to NZD 0.179 per share, and while that's not back to the heady heights of 2019, it is NZD 0.015 per share higher than the ordinary dividend was back then. We're also applying the dividend reinvestment plan, but as with interims, those that opt in won't see the benefit of any discount to the market price of Meridian shares. Now, you can only lift ordinary dividend if operating results facilitate it, and as I noted earlier, and shown on the next slide, they do. Here you can see that both EBITDAF and operating cash flows continued to grow as our teams once again incrementally improved performance. While some may say a 10% lift in EBITDAF is more than an incremental improvement, the key point is that it's driven by continuous optimization by our operating teams. Said another way, we look for new ways to improve operational outcomes all the time. These improvements are often small and can look insignificant, but if you make enough of them, they add up, and every now and then, one or two work better than expected. The energy margin lift you see here was largely driven by changes made by our retail team as they refined the mix of and pricing to customers. As a result, we're able to offset rising costs that I'll talk to later. While some may report on the net profit after tax figure that comes later in the pack, as it's driven by large non-cash movements, it doesn't offer useful insight into cash operating performance. Anyways, the 10% lift in EBITDAF that you see on this slide is not easy to do, as our operating teams will attest to. But once again, they delivered superbly this year. And lest we forget, the wholesale team faced down another year of La Niña drought, but as it was the third in a row, I won't do my normal soliloquy here. Summer droughts are becoming BAU, I guess. So NZD 783 million of EBITDAF and NZD 509 million of operating cash flows it was. Not bad, team. Not bad at all. This slide provides a little more color on the NZD 110 million lift in energy margin that was summarized on the previous slide. Hopefully, you can see my point regarding retail customer mix and pricing optimization as retail revenue lifted by NZD 151 million. It didn't hurt that spot prices were lower than they were last financial year, as while generation revenue fell, the cost of supplying customers fell faster. Of course, if we hadn't hedged that wholesale exposure, we could have locked in the full NZD 244 million lift in physical energy margins shown here, but that's not how we roll. So our hedge contracts caught the flip side of lower spot prices and cost us this year. Before you think my comment might suggest that we're considering adjusting our hedging practice, we're not. It's the net result that matters, and prudent hedging is what you'd expect from a mature business like ours. We will learn from this experience, of course, and incrementally adjust if it makes sense. Talking to customers, the retail team has once again worked hard to secure and grow valuable relationships across the segments you see here. Total sales volumes continue to grow, but at slower rates than they did in the past three or so years, and pricing has lifted as well. I've said it before, and I'll say it again, we're fortunate to have the best retail team in the sector, and they improved their performance again while continuing to grow our business. I touched on generation volumes earlier, so I won't dwell on this slide other than to say that while inflows were strong on average last year, the past three years have consistently locked in droughts over the summer months. The South Island summer drought is unusual when you look at the long-term rainfall pattern, and three in a row is black swannish. Maybe not quite, but you get the point. It is unusual. The upside is that the La Niña weather pattern has been interrupted by a timely return to El Niño, and if anything, our wholesale team is now used to managing its way through whatever the prevailing weather pattern throws at them. The downside is that the wholesale team was once hampered in its efforts in 2023 again. That said, this has upside as well. If we do get a series of summer storms this year, the wholesale team should be able to add a little more upside to energy margin delivery. Time will tell whether that plays out. Last thing on this slide worth talking to is the advent of the doldrums. FY 2023 represented the lowest annual yield from our wind farms since 2016. However, lightning doesn't strike twice, they say, so the doldrums should be over, and La Niña has completed its three-peat. So it's onwards and upwards from here. As shown on this slide, operating costs were slightly above the operating cost forecast range presented this time last year. This is obviously a little disappointing, as we pride ourselves on cost discipline and hitting outcomes, but there were a couple of late-breaking contractual wash-ups in June that hadn't been well signaled. That said, cost increases were focused in the areas I talked to last August and again in February. Salaries, Flux, and the development team, largely growth and people. Insurance was challenging, but I know we're not alone there. Global insurers are not lining up to supply New Zealand right now, and that's reflected in lifting insurance premiums for our business and every other Kiwi business or person that owns property or assets. We're looking for new ways to mitigate this cost, but it's difficult without asking shareholders to self-insure, and we're not near that point yet. Finally, the Masterton call center costs landed as expected. As a reminder, Meridian gets paid NZD 6 million for providing a service to Shell, so the Australian call center costs are only new in the sense that previously, both costs and revenues for Masterton were eliminated as Meridian Energy Australia was consolidated. Capital costs landed materially lower than forecast last August. We provided updated capital forecasts in May and June, so this shouldn't be news to anyone. However, this slide makes it clear that stay-in business CapEx remains steady, and while growth CapEx ramped up to support Harapaki and the Ruakākā battery construction programs, we didn't use the funds put aside to support potential land acquisition, and Harapaki was obviously disrupted. As Neal noted, we're confident in the reforecast dates for Harapaki, and with the banishment of La Niña, let's hope the Hawke's Bay and other parts of the North Island get a summer this year. As presented on this slide, I expect operating costs to land between NZD 268 million and NZD 274 million this financial year. This suggests a year-on-year lift of between NZD 19 million and NZD 25 million. The waterfall chart shows we intend on investing that cash. Staff costs will continue to lift, but at about half the rate of last year. This is driven by the same factor impacting everyone, inflation. But unlike last year, where we continued to build our development team, this year that team is at the level we feel we need to compete, so the lift here is largely to ensure people are properly compensated. We'll also continue to lift our investment in the Flux platform. That business is slowly but successfully growing its offering in Australia, with two new customers secured and a pipeline that's building. Now, I'm not sure if I've mentioned our finance transformation program before. The title was probably a little grandiose, in that we're replacing our finance procurement commercial systems that are at the end of their respective lives. But it's an important initiative, as when complete in FY 2025 it will provide the first layer of enterprise-wide platforming that Meridian will have undertaken. And as it's a cloud-based platform, replacements should no longer be necessary. But as it is cloud-based, investments are treated as operating costs as opposed to capital. Hence, you see its impact here. I don't want to talk to insurance again, but we may also need to lift our resourcing in the sustainability space this year if we're to keep making the progress that we feel is required. And it's important to pick up on the theme that Neil mentioned in relation to energy hardship. We've committed to providing a multi-year, meaningful, and dedicated service for customers that are in hardship. It could be that we invest further in this space and time, but for now, we're making sure that current efforts are resourced and supported properly. All other operating costs will be held flat to last year. A couple of other things to note from this slide. I'm forecasting total capital expenditure of between NZD 420 million and NZD 445 million this financial year. As you can see from the slide, that largely reflects cash being invested in Harapaki and Ruakākā, but it's also driven by a lift in stay-in-business CapEx, given there's a generation control system replacement project that's getting underway. We should have moved the Wellington team, including this fellow and I, into new premises by the time the financial year is complete, and there are a couple of asset projects underway that will lift stay-in-business CapEx. One of them noted here is the replacement of all electrical and automation technology at Manapōuri. It's a multi-year initiative that will be complete in 2028, all going well. Last, the generation team did spend more money in the second half of last year, as I suggested they might at interims, and the FY 2024 total cash forecast for that team is for between NZD 90 million and NZD 95 million, subject to decisions on what plays out with the Manapōuri transformers. I'll update you if anything changes. Now, the graphs on these, on this slide shows the difference between net profit after tax and underlying net profit after tax. The reconciliation between the two is shown on Slide 45 of this pack, but as we're sticking with this slide for now, the difference is largely unrealized fair value movements and derivatives, as those relate to future years and are non-cash items. This year, those non-cash fair value movements were NZD 309 million. So if you add them back to net profit after tax, you can see why underlying net profit after tax rose, while net profit after tax fell. This also makes sense, as underlying net profit after tax should reasonably follow the EBITDAF and operating cash flow trend. If you go all the way back to slide 16 of this pack, you'll see it does. I tend to suggest that investors look beyond net profit after tax when it comes to operating results, but take your pick. What I can assure you is business performance last year lifted last year, even as net profit after tax fell materially. Last but not least, there was a NZD 1.1 billion lift in the value of generation assets over the year, driven primarily by a NZD 10 lift in the long-run price path. Now, this is a new slide this year. It's here to provide a little more insight into why net profit after tax moves around materially year-on-year. Demystified a bit, as Neal said. As mentioned a minute or so ago, the reason is pretty straightforward. We use derivatives to manage risk, and for the most part, incrementally improve the results I talked to earlier. As shown on this graph, the impact on net profit after tax from using those derivatives was negative NZD 351 million last year, whereas it was positive NZD 402 million in 2022. Substantial but divergent outcomes driven by the same factor, rising and then falling forward market prices. But not all derivatives are treated equally, as some have cash impacts, while others have non-cash impacts. I'm going to attempt to describe this by focusing on energy derivatives. Energy derivatives that are settled in the operating year have a cash impact on business performance. We call these realized energy hedges in the financial statements, and for context, the cash impact of settling them in FY 2023 was negative NZD 42 million. However, as those derivative hedge retail sales, we collected the margin between those retail sales and the cost of the hedge. That is, the derivative allowed us to lock in energy margin. The impact of all of this was summarized on Slide 17: Energy Margin. But we also hold energy derivatives to hedge sales that have been made over the next two and three years. These derivatives are valued at the end of each financial period, and the change in fair value is also captured in the financial statements. It was NZD -333 million in FY 2023 and reflected the fall in ASX futures prices, Neal mentioned earlier. However, this is a non-cash cost, as those derivatives have not been settled. The amount may flow into operating revenues or costs in future, in future years, but it will depend on what energy prices do between now and then. The total and separate impact of realized and unrealized energy derivatives is captured on the income statement and in the notes to our financial statements to ensure investors know that we have these obligations. If I bring the commentary back to the graph, if the total impact of energy derivatives was -NZD 375 million in FY 2023, the fair value movement and of interest rate derivatives must have been +NZD 24 million. As forward energy and treasury prices move materially over time, the change in fair value of these derivatives of any year can be substantial. Of course, if forward markets were stable, the impact would be negligible, but we're talking about electricity here, so it's unlikely. Anyway, I hope that diversion helped a little. One further complication this year is we've changed how we present energy hedge balances because of an interpretation of how the derivatives that I've just talked to should be framed under IFRS 9. This doesn't change our non-GAAP, EBITDAF, or underlying net profit after tax calculations. However, it does change the way the GAAP income statement now looks. A reconciliation of those changes is on slide 30 and in the notes to the financial statements, and the notes to the financial statements explain this clearly and in detail. Now, this slide shows that our balance sheet remains particularly flexible. Net debt has lifted in FY 2022, but the key rating metric, net debt to EBITDAF, remains well below the bottom of the BBB+ threshold of 2x. We did issue a new green bond during the year as an existing green bond expired. As we have another green bond expiring this year, it's likely that we'll replace that as well. But all going well, that shouldn't create too much drama. As I don't have too much more to add, I'll finish as I started. We've delivered another sound result for investors in our business and have rewarded them by lifting dividend again. At the same time, we remain well-placed to navigate future challenges with a strong balance sheet and a growing development pipeline. There's plenty of action yet to play out in FY 2024, but I'll hand back to Neal so he can make a few closing comments. Thanks, Mike. Not a bad effort for an engineer to explain all of that accounting gobbledygook, I would say. Anyway, and look, to sum up, it's been a solid year, and we've produced a good underlying earnings result. Retail growth continues to be the main driver of our incremental financial improvement, but that trend will run out of steam. Building out a stronger customer product set while delivering renewable generation infrastructure to support Aotearoa, Aotearoa's transition is our mission. To that end, we have a clear strategy for long-term growth and are tracking to plan. We have lots more work to do to ramp up the build of our development pipeline, but the growth and the depth of that pipeline of opportunities has been very pleasing. The green shoots of a transition to a low-carbon economy are starting to show, and importantly, customers will have a strong part to play in how their electricity system evolves. I think when we look back in 10, maybe even 5 years, we'll be stunned by how critical demand responses become in terms of system security and efficiency. Obviously, NZAS and Southern Green Hydrogen remain the big-ticket options for our business. Our objective is to support both to coexist, as we believe the New Zealand Inc. benefits are strong for both. For New Zealand, the opportunity is to fully leverage our renewable energy advantage and grow our economy to zero carbon. While that phrase, that phrase rolls off the tongue easily, it'll certainly be harder to deliver. But if we don't, we will have continued to fail future generations of Kiwis. On that cheery note, we can move to questions. I think we'll start with questions in the room first, before heading to the phone lines. Morning, Neal and Mike. Thanks for that. A few questions from me. First of all, probably no big surprise, there's a couple of questions around OpEx and CapEx. Looks like a reasonable step change we're seeing in the OpEx side. And I know you called out some of that being a move to sort of cloud computing. Is there sort of any one-offs in there, just thinking about what's FY 2025 and beyond? Or as you move to more cloud computing, are we actually gonna see another sort of step-up in FY 2025? It's a good question, Andrew. They're one-offs. So the finance transformation initiative will span 2024 and 2025. But to it is the second part of your question, which is, you know, more and more platforms are becoming cloud-based platforms, and so it is possible that we move from, you know, operating cost base to OpEx as we redeploy systems, you know, that are cloud-based. So but the cost that I did note there is a one-off, but it will span 2025 as well. Okay, thank you for that. Then on the CapEx side, again, there's a reasonable step up there, and I think you sort of typically spend sort of NZD 45-ish for a very long period of time. Do we look like we should be going back to that kind of level FY 2025 and beyond? And again, just moving, talking about the move away or move towards cloud computing, does that reduce IT CapEx? Yeah, it should. I mean, it should. So, so I'll answer that piece first is, should see a reduction in IT CapEx over time, 'cause it's moving to, to OpEx, standard business CapEx once we get through some of the program. As I mentioned, the SCADA replacement, they happen, you know, once every 10-12 years. The move to Old Bank is a one-off, and I, I did mention the asset program, which is Manapōuri, and that'll run through 2028. So that'll contribute to standard business CapEx, but it will come off as we get through 2024, standard business CapEx. Thank you. Next question, just around I guess the commentary in the medium to long-term price, NZD 80-NZD 90 real. So obviously, it's a really reasonably common topic of conversation, and there are a few higher estimates out there. I guess the question for me, really, is your confidence in terms of seeing that drop going back down there, particularly given, thinking about civil costs having gone up quite materially if we think about the cost of new, new build. Yeah, I think we—I mean, we've all seen costs increase over the last few years, but you've got to believe that technology will continue to drive the long-term trend, which is, you know, cost down. You've got to believe that manufacturing around the globe will gear up, scale up, and meet future demands. So yeah, the civil costs are a bit of a challenge at the moment, but again, as supply comes online, efficiency, scale operations, those sorts of things, yeah, there's no reason to suggest it wouldn't revert back to something more like the long-term trend. And I guess- Sorry, I'll just make one other point, Andrew. We are... Look, we are talking about a long-term price forecast, not the next few years, not even necessarily the next 5. We're talking the next 30 years, in that context. Okay. And I guess the flow on consequence from that, like I think we pointed to it, but it does sort of imply wanting to forward sell as much as you can into the current high, a relatively high price wholesale curves. I assume that's what you've been doing? Well, we've grown our retail book significantly over the last four or five years. That wasn't all just taking advantage of a market opportunity. We wanted to grow the scale of that business. We thought we had a compelling proposition for customers, and we've been very successful at it. We still expect to continue to grow our retail business, but it'll be more in terms of value-add products that support customers and their decarbonization efforts. It's been interesting. I mean, I'll add one little piece as really interesting interaction with consumers who are impacted by higher prices, that they've tended to wanna contract over longer periods of time... particularly in that C&I space, to manage some of the short-run costs that they face. And so the duration of sales in our C&I book has lifted quite materially over the last couple of years from, you know, between 2 and 3 years to just over 4. So, which is, again, it's, it's kind of a natural consequence of people being exposed to high prices and us being able to contract with them over longer periods of time. Mm-hmm. And, just last question from me. Net debt is a reasonable step up this year, certainly a bit more than expected, and it looks like a big part of that reason is a big increase in restricted cash, which has gone from sort of circa NZD 50 on average to almost NZD 200. You able to just sort of talk to that a wee bit and what we can expect going forward on that? So it’s driven by position that we’ve got on ASX, as I think we’ve been really open, which is we bought a position to facilitate the sales that the retail team had made. And as ASX prices have come off, the collateral requirements to maintain that position on ASX have grown. So that’s what’s driving it. How temporary is it? I mean, I think anyone could have a guess as to what prices are doing, but, you know, we do intend to use ASX to manage the position, but collateral requirements will change. As you know, the wholesale team enters into new contracts that are at market, they don’t have as big an impact on the collateral requirements that Macquarie, who’s our clearing participant, might need from us. So I would say over the long run, they'll moderate, but it does depend on what wholesale prices do. Morning, team. Three from me. First one is, really all focused on the medium-term perspective you can bring. So, you've talked about the EECA study, talking about 4.5 TWh of potential new industrial demand growth. How much of that do you think will actually go to electrification? How much will we see in market by 2030? What number should we have in our minds about that? Oh, look, it is hard to say, because biomass is part of the equation. But electrification looks like the stronger option, particularly in the South Island. I'd expect it to sort of play out over the next 10, 15 years. By 2030, I mean, some of these projects need to get up and running. So I wouldn't want to put a number on it, Neal, but it'd have to be in place, it would have to, we'd have to have made strong progress towards achieving that sort of conversion by 2035 if we're going to get anywhere near our country's emissions reduction targets. So more tail end to that, sort of 2030, 2035- Yeah, just because of the amount of work it takes and the involvement in the business case, and, you know, the conversion activity itself. It just, it'll just naturally take a wee bit of time. It has been, it's been interesting, Neal, because the numbers have moved around a bit, right? And I think, you know, literally, when you initially looked at them, a lot of the conversion was slated to biomass. You know, it's not so clear now whether biomass or electric are the way to convert. In fact, you know, Neal talked, many of the customers are actually converting to electricity, and you've just seen a RFP from Fonterra that's out there in relation to its activities. So they are obviously thinking, you know, quite carefully about biomass or electricity. And if you saw, you know, material conversion from Fonterra, then that would accelerate that change. So- Mm-hmm. I think as Neal said, it's a bit uncertain at the moment, but the key is the number. You know, New Zealand needs to deliver those sorts of outcomes to decarbonize. Great, thanks for that color. The next one, I mean, you've been pretty clear about demand response, possibly the potential for demand response from, also from Southern Green Hydrogen. I'm just wondering what your view is about the need in the market elsewhere, for gas peakers and gas storage. Obviously, the Gas Transition P lan brings this up. Do you have a house view as to what needs to happen, if anything, over the next sort of up to 2030? Well, I think sort of over, well, over the next 10, 15 years, Neal, we need to have continued and reasonably significant investment in the gas industry, both in storage and peaking capacity. From what I understand, it degrades reasonably quickly. So from about 2028 onwards, we can start to expect to see the current deliverability of gas being further constrained. So, you know, that sector needs support to continue to drive good business cases, invest in the underlying infrastructure, and deliver a reliable service, 'cause it's gonna underpin, you know, an efficient transition to electric. You've obviously resolved how you want to replace the swap option. Would you still contemplate offtake or cover, cap cover of some sort from such facilities? Yeah. Yeah, I mean, we've got transactions with Nova and Contact in place today. We'd continue to support gas-based swap option type arrangements alongside a suite of demand response type opportunities. And, you know, and we've talked about it, but we think Southern Green Hydrogen is quite a game changer in that regard, 'cause it's a big slab of demand that can respond to a sort of a hydro scarcities situation. Last one for me. Just looking at the sort of supply, potential new supply that could come to market, people are talking about to come into market, getting you know fast track consents for. Looks like there's quite a lot of it between now and sort of 2025, 2026. Do you think the futures curve sort of is aware of that? Do you think it prices it in? Do you think we see some kind of change in what the outlook for that over the medium term, as the supply comes in and is actually bankable and obviously actually producing? Do you have a view? Well, I think all the participants in the market can read and hear all of the options coming to potentially to market over that sort of time frame. They're also, as I say, looking at some of the risks associated, particularly with the gas market, I think. You would expect as we deliver more and more renewable generation, that they would put downward pressure on that futures, you know, futures price curve. But a lot of that's still got to be committed and delivered. And I know from our perspective, we'll look at every business case, ensure it meets its commercial investment hurdles before the time of commitment. But certainly, we're not gonna build anything if we haven't already created an option and have a consent and ready to go. So, it'll be interesting to see, you know, how these things do get deployed in reality. But, certainly everybody's in a hell of a rush to make sure they're at the front of the queue, for, you know, to invest into the right sort of conditions. Thanks for that. Yeah. I'd say, Nev, don't bet against the futures market unless you're willing to lose your shirt. Anyone else from the room? Okay, I think we can go to the phones. For the phone parties, to register a question, please press star one on your telephone and wait, announced. The first phone question from Craigs Investment Partners. Please go ahead. Hi, guys. Can you hear me? Yep. Yep. Yes, Cam. Oh, great result. Just regards to your customer growth expectations over the next two to three years, medium-term. I was just wondering if you could talk to unit price sort of growth expectations as well as customer mix and what you're seeing in the market. Cam, we're comfortable with our market share. We'll continue to compete actively, because it's very difficult. You can't just... It's very difficult to maintain a flat customer position. You're either typically going backwards or forwards. So we'll maintain a pretty competitive stance in the market, as we always have. But like I say, our focus is really on developing a product set that supports customers to decarbonize and grow volume that way, and grow demand and at the same time. In terms of price expectations, I mean, we review prices every year, and I wouldn't want to provide any sort of guidance around that. But we will respond to the market, and you can be sure that we'll be competitive across both the brands. All right, thank you. Just with regard to, you know, rising costs and so forth, within the, you know, the business units that everyone seems to be struggling with at the moment, and, will we see Meridian's cost to serve and Flux platform sort of come through and, and the benefits, or I know it's hard to get visibility on that, but are you expecting to see any benefits, you know, flow through IT platforms? You want to take that? Yeah. Cam, I mean, we do obviously track our cost to serve very carefully over time. And, you know, I would best estimate I'd have is it remain relatively flat. You know, there's new technology that we can deploy. The teams are looking for opportunity all the time to reduce that cost to serve, and certainly, the systems that they use, you know, have helped them manage the, you know, the inflationary pressures. But I think, you know, best estimate would be to hold them flat, possibly a gradual rise in the shorter term. Long term, it's so difficult to tell, though. But, I'd say best estimate is probably hold them flat. Yeah, just to add to that, I mean, our, our cost to serve on a per customer and per megawatt of volume sold have trended down quite significantly over the last few years as we've grown the size of the business. So we have picked up, you know, some already some reasonably significant efficiencies from technology deployment and doing things more effectively across the retail business. We will have to deploy some capital into developing energy solutions and new innovative ways to support customers, but I think Mike's probably right. We can do that within our existing operating cost envelope, hopefully. Great. Great, thank you. Just the last one for me. You know, you've worn to the ground in terms of battery construction, you've got two solar projects you're keen to push go on. What are you seeing in terms of CapEx costs out there in terms of solar development? I'm not too sure if you can give us a range on that. And just with regards to the battery, you know, batteries are expected to decline in cost. You know, over the medium term. Are you worried that potentially you've gone too bit beyond this, or you've come forward, being first to market and so forth? If you give us some color around that, that would be great. Yeah, well, we haven't actually gone to market yet for one of those solar. You know, we, we've had RFIs and so forth, but we, we're about to move through that process, probably with Ruakākā Solar first. So that'll be, sort of back end of this year, early next year. So we'll discover a bit more about where solar prices have got to. Our, our market intel suggests that prices are now coming back to sort of pre-COVID levels, for panels. So that, that's, that's optimistic. Certainly, battery technology, you'd expect that to continue to decline from a unit cost perspective. It's fair to say that the Ruakākā battery, we signed up to at a reasonably high point in the market, but the business case was strong, so strong for us, and the imperative to get on and do it was also so strong that that made sense, we think. So I guess we'll see, Cam. But like I say, we're starting to see signs that unit costs are getting back to where they were before COVID, and hopefully, they start to diminish from there. The key thing from a solar deployment for the economics, actually, it comes down to as much around the location, so and scale. So being large and being close to or having really strong transmission options make a real difference to the economics. Great. Thanks, guys. Useful. Thank you. The next phone question comes from Stephen Hudson from Macquarie Securities. Please go ahead. Hi, guys. Just a few from me. Just firstly, the futures closeout gains for FY 2023, Mike, a good sort of, I think, a Pandora's box. I think it's NZD 46 million. Can you give us some sort of steer on how we should about how that normalizes over 2024? Maybe a couple, Neal, just on Te Āpiti. I know you've in-housed the maintenance there. Can you give us a feel for sort of how the net cost is washed out as you've in-housed that, and whether or not you're sort of carving out a competitive edge through doing that? And just on NZAS, the P&L accounts were out, I think, a couple of months ago. It's reasonably opaque, but I think you can sort of back calculate a kind of NZD 150 million operating profit for the smelter at current spot prices. Is that sort of ballpark what you're thinking? And then the final one is just on the reval. You mentioned the NZD 10 lift across the long-run price path. Can you share some numbers there and the years that you're talking about? Good question, Steve. I'll start with the futures closeouts. I'd probably treat them as a one-off. Now, in saying that, probably everyone in the room is aware that there are a few more closeouts in July. But the reason I say, you know, treat them as a one-off, as opposed to ongoing revenue stream, is the reason for those closeouts. We were able to make those closeouts because we had bought a wholesale position to support the growth in the retail business, and the retail team grew to a level where we got comfortable, and, you know, we decided to halt that growth, and we'd actually bought a bigger wholesale position than we needed. And so, you know, we hedged out that... We thought we were hedging a larger exposure than we created, and then we liquidated that position because we don't, you know, it's not something we carry. I think I said at interims, we don't make money by trading derivatives. You know, that's the kinda key point. But, you know, as the optimization goes on, that I mentioned between the wholesale and retail team, you do see some further capacity for closeout in 2024. 2025, too early to tell. There's too many things moving around for 25. But if I come right back to where I started, I reckon probably the best way to frame it is, is treat it as a one-off. We don't try to make a heap of money by trading derivatives. Do you wanna do through... Well, I'll answer the Te Āpiti question. Yes, so Stephen, we in-housed Te Āpiti actually, after we'd in-housed West Wind, and then we subsequently in-housed the maintenance and service teams at White Hill. The driver of that strategy is we couldn't, at that time, get extended availability warranties that would include main components on any of those wind farms from either of the OEMs that were involved in it. And certainly, the cost from a purely service perspective, it was far cheaper, more effective, and a better outcome for us to do that ourselves. What we've seen is the market's evolved quite a lot. OEMs are now offering long-term availability warranties, which include all the main components, and that's what really drives the cost in these wind farms, particularly in the second half of their lives, as things start to wear out. So at Harapaki, we've signed a 30-year availability agreement, and that's outsourced for the duration. We've also extended the availability warranty at Mill Creek, which was the last of our, you know, wind farms produced in the mid last decade. From, I think it was originally 5 years out to 30 years as well. So that's the model at the moment, but these things go in cycles. So I think we're actually quite well positioned because we can effectively, we've got a hedge against the OEM model because we've got a really well-functioning, capable, in-house, service and maintenance operation that can, you know, do the job and do it well. If I pick up Genesis, Steve, and, you know, guide me on my answer here, 'cause I might go a few places, I think they had a great year in 2021, a good year in 2022. 2023, good start. You know, they're in a commodity cycle as well, and you know, aluminum as a commodity has come off. The big question is, are they gonna be here post 2024? I mean, that's the, the big question. We don't know. We, we honestly don't. What we do know is, what they tell everybody is they are committed to decarbonizing their aluminum portfolio, and that sits in the Pacific, you know, in Australia and New Zealand. So would they like to be able to retain Tiwai and enter into a, you know, new arrangements for Bluff? For sure. Could they, would they like to decarbonize the remainder of their aluminum smelters? Absolutely. Can they do it economically? That's, they only they know the answer. As Neal said, we have provided them with agreement and terms that we think support that in the long run, and we think it's in their interest, our interests, and New Zealand's interests, the way we structured the proposal. But we don't know, and there's a good line that you, Neal, used, which is: That conversation has continued to continue. I think that's what you said. Yeah. So, you know, the-- there's obviously some challenges in making that play out, and, but the conversation's a constructive one. We'll see. I think we'll find out in, you know, the reasonable near term, whatever that means, what they intend to do. Hope I got some of that question, Steve. I think the other aspect is, and as you know, we're not the only counterparty that they're talking to around an energy contract. So they're trying to pull together a portfolio solution that will meet their needs, and that's, you know, obviously more complex than what they've had to deal with in the past, which is probably driving the timeframe. Steve, I'll grab that last question, which was the reval, and I'd mentioned that that was driven by a NZD 10 lift in long run price path. You know, we've talked to NZD 80-NZD 90 bucks real. What that tells you is, you know, the movement in our price path is probably closer to the NZD 90 buck level than the NZD 80 level over the last year, driven by some of the stuff that we were just talking about before. You know, civil construction costs, manufacturing base, and just how long that takes to normalize. That's really helpful. Thanks, guys. Thank you. The question from Grant Swanepoel from Jarden. Please go ahead. Good afternoon, Andy. First question, just on demand growth. So 1% for the country for the FY 2023, pretty, pretty dire. You guys have 40 committed pre-demand that's coming up. Well, when do we start to, or should we start to detail plus growth as well? So, was that when should we start to see that demand growth materialize? Yes. Oh, look, Grant, it's, it's very difficult. All I can say is we're starting to see those conversions in terms of process heat. I think we all know what's going on with electric vehicle penetration, and that's starting to increase. So we would start to... We, well, we expect to see demand starting to emerge over the next few years, and by the back end of this year, about by the back end of the decade, our models sort of predict that you'll start to see a couple percentage points per annum type lift. We're nowhere near that today. In fact, it's been, as I think you just mentioned, it's been quite sluggish this last winter. But, as these conversion opportunities take place, and, and there'll be some big slugs of it, too, you know? We still don't know what Fonterra are gonna do, but if they do transact something in the electricity market, there's quite a lot of volume there. And like I say, we're making good progress on the other process heat opportunities, and EVs seem to be taking off. But, you know, it's not gonna be quite a hockey stick, I hope, but certainly, we'll have to wait a few more years to sort of see that really strong demand starting to emerge. Okay, thanks. Then, you indicate that you've got 40 MW of demand flexibility with the 50 MW of demand response from Tiwai, and who knows what's going to happen beyond 2024. Is there a number that you guys are working towards a demand response that maybe mitigates the old 150-MW swap you used to have with Genesis? I know you've got that bit of replaces the Contact and Todd, as you mentioned earlier, a nd Nova. Can you talk about where you want to get to with demand response for your portfolio? Yeah, it's, it's of that order, Grant. Within, you know, if you put aside Southern Green Hydrogen, which we, we, you know, it's potentially 600 MW of demand response right there, but, and about 40% of New Zealand's hydro firming, risk management could be delivered through that project, which is why we think it's got legs, even in a, you know, in an interstate scenario, well, as well as. But, across the rest of the board, yeah, I mean, the way we're talking about it internally is the retail team, in particular, would like to be able to present to the business an eighth grid-scale project within 8 years, and that would, and that would turn up in the form of demand response. So we think, you know, somewhere between 100 and 150 MW is not unreasonable to go after and could well be achievable. And apart from corporate customers, there's also the virtual power plant opportunity that's starting to emerge in more mass market parts of the market. The technology's evolving as solar batteries and EVs start turning up in households. If you can collect that demand and trade it back into the wholesale market, we think that could be significant as well. So yeah, we see our retail business as being certainly complementary to our generation growth business. And we think that'll emerge within the next five years. So it's gonna be this decade that we'll start to see those sorts of developments. Thanks, Neal. My final question, just on costs, obviously. It looks like the whole sector's got this 9% plus cost through on the OpEx side of things. Can you talk to what is controllable and what is not controllable? So things that you are doing that's innovating, moving to cloud-based, et cetera, so we get some sort of idea of what is inflationary and what is actually probably just a lot of cash sitting around and taking advantage of building out opportunities that you've always wanted to do. And then just to follow on that, you were talking a few years ago when Flux was gonna convert your IT to the Powershop-type system, that this was going to reduce costs by NZD 10-15 million. That disappeared. Has this Powershop convert proved disappointment, or is it just where costs have moved to nowadays? Thank you. I think I'd take the Flux one first, Grant. Is the, you know, I think you might have answered the question there, which is, you know, costs of IT business has just lifted like everything else. So some of those savings, don't know whether we'd said 10-15, but, I'd have to look through the record to see what, what they said. Owen's nodding at me, saying that we did. So, the- Yeah, just to actually clarify, 'cause I signed off on that business case and have signed off on the recent PIR. A lot of those benefits have been delivered. They were avoided costs in terms of future CapEx costs, future operating costs. And as I pointed out, if you look at our retail business, it's increased in scale by about 58% in the last 5 years, but costs have remained flat. So that's part of the Flux story. The issue with the particular Flux deployment was that it was a couple or three years late, and so the NPV value of those benefits dissipated because of the delay whilst we were spending money on the conversion. But overall, the business case was still strongly NPV positive. I think on the cost, Grant, more generally, you kind of said controllable, uncontrollable. The way I'd frame that is, you know, everybody's been impacted by inflationary costs, which has flowed into salary uplift. It's also flowed into the cost of goods and services that we buy to run the business. But it's moderating, so those impacts are moderating. And the second bit for us that's driven cost increase has been the growth of our development effort. And as I suggested today, you know, we've got a team that we feel is the right size to prosecute that space now, and you've seen it in the way that they've delivered on our pipeline. So again, I would expect moderation in cost increases moving forward. Great. Thanks for those answers. Thanks, Grant. Thank you. At this time, we're showing no further questions from the phones. Okay, well, thank you all for your attention. Look forward to doing it all again in another six months. Thank you all. Bye.