Meridian Energy Limited (MEL) Earnings Call Transcript & Summary

Good morning, and welcome to Meridian's 2022 Annual Results Presentation. I'm Neal Barclay, Chief Executive. And as usual, I'm joined here with by Mike Roan, our CFO. I'll start by calling out a few of the highlights. EBITDAF lifted by 2.5% and underlying net profit after tax was flat year-on-year. Not exactly numbers to write home about, but as usual, the weather provides some context for the result. Hydro inflows for the year in total were about average, but we didn't and never do receive a nice constant flow water into our catchments. Heading within the average numbers were huge volatility, and that includes the lowest Q3 inflows into the Waihou catchment for 90 years. During that time, generation through the Manapouri Power Station was severely curtailed. In fact, for much of April, Manapouri, which has a capacity of around 847 megawatts was operating at around 80 megawatts. So given the vagaries of the weather, I think our team did a very good job delivering positive financial movement compared to last year. Noting that this year also included a full 12 months of the reprice to NZAS exit deal. The good news is all droughts eventually end, and we've had plenty of rain into the catchments over the last few months. And we're now -- and we're heading into FY '23 with better-than-average storage in the tank. The sale of our Australian business was probably the most significant achievement for the year. We realized a $214 million gain on sale and more importantly, the sale proceeds of 740 million have substantially boosted our balance sheet capacity to invest into New Zealand's renewable energy future. And our retail businesses continue to excel and take market share from our competitors. Over the last 3 years, we have added an equivalent of half the 2 waste smelters demand to our retail business. We set out to do that, and the team have absolutely smashed their targets. Our people, their safety and their well-being will always be front of mind for me. Our reported injury rates are declining. And fortunately, none of the injuries suffered by people working for us have had lasting impacts on their lives. But our near-miss reporting tells us that our risk exposure is still high, and we see this most obviously in relation to the Harapaki construction project. Harapaki is a challenging work site and has experienced difficult construction conditions. So I want to acknowledge the massive safety focus our project and contractor teams have established at that site. I'd also like to call out the work we are doing, supporting our people's well-being. We have developed a care team process that reps support around people in our business who are struggling. Our aim is to ensure they have the time and support necessary to heal and return to work. Our care team program was recognized that this year's Safeguard awards as New Zealand's best well-being initiative. Our overall level of staff engagement did slip during the year, but we understand where and why the decline occurred, and we're working to address staff concerns. To a certain extent, the downward trend is a sign of the times, and we remain in the top 25% of large New Zealand employers from a staff engagement perspective. All employers are facing significant challenges, retaining and attracting staff into their workforce. Mike will outline some of the things we've done this year with remuneration to ensure our people feel valued. Of course, remuneration is only one aspect of our overall value proposition. Take time out, belonging and flexibility are also important foundations for our workplace culture and continue to require focus and improvement. The exit out of Australia means we can point all of our strategic focus back to home. The prospects for growth in Aotearoa are huge and will help fast track this country's decarbonization. There are still lots of large moving parts, but the strategic options are becoming clearer for us. The Southern Green hydrogen opportunity has 2 highly committed incredible counterparty shortlisted now. Process heat electrification is becoming more viable with lifting ETS prices and a tenfold increase over the next 4 years in the government Getty fund. And Rio Tinto seemed clear around how their New Zealand presence can support their overall decarbonization objectives. In the meantime, we've made great progress building our book of wholesale hedge contracts to manage our portfolio risk. The swaption deal with contact that we announced last week means our hedge book is in good shape and the risk position for '23 and '24 is sorted. What happens beyond '24 would depend to some extent on what happens to the smelter and what happens to Southern green hydrogen. Our development team has done a huge amount of work strengthening our development pipeline. And that will bring technology and geographic diversification to our business well beyond just this decade. More on that shortly. This morning, we announced a $53 million or 13% increase in the Harapaki capital costs, which now totaled $448 million. Critically, this additional spend maintains the original first and full power milestones in mid '23 and '24, respectively. By many current projects, Harapaki has encountered significant inflationary pressures. But the bulk of the additional costs relate to weather conditions experienced during the first year of construction. And I can't believe my home province turned on such rubbish weather and the rainfall at site during most of the construction season set records for that time of year. As a result, we've lost all the contingency in our schedule, and we're left dealing with very sodden ground conditions. So we've taken the decision to invest in a substantial upgrade and strengthening to our roading design. Better quality roads have enabled us to continue construction through winter and keep the project on schedule. It should also reduce maintenance costs over the life of the project. So I'm comfortable we've made a sound trade-off decision. Also on the upside, longer-dated forward prices have firmed. So we expect the wind farm will realize better price capture at least in the first few years of its operation. As I mentioned earlier, our development team have been hard at advancing our portfolio of future generation options, but we need to move even faster and so we're increasing our investment support for that team. Ruakaka Energy Park will be our next development. We're currently tendering for the battery, and we expect to receive consent within the next couple of months. We plan to commence Building 23 and complete construction during 2024. I would love it to be sooner as the system has experienced regular pick stress events during winter months, but as I'm sure you're all aware, international supply chains are stretched, and we have work to do to manage the cost escalations and delivery time frames. We will, however, get it done. And we have also secured a second battery option site at Bunnythorpe. The Ruakaka Energy Park solar farm consent is expected to be lodged in early '23, with construction complete in early '25. We're in the process of acquiring an additional parcel of land adjacent to Ruakaka to lift the capacity of the solar farm to 100 megawatts. We're also preparing to lodge the consent application for the Mt. Munro wind farm later this year. We expect that project to focus -- sorry, to follow closely on the heels of Ruakaka developments. Beyond that, we have a more sizable pipeline of secured options and advanced prospects for multiple solar and wind sites, mostly in the North Island. And we need more. Our aspiration, our obligation and our plan is to ensure we create enough capacity to build our market share of New Zealand's future renewable electricity requirements. As an objective, building our market share doesn't sound all that aspirational. But when you consider that building our market share means building the equivalent of between 15 and 20 Harapaki sized power stations over the next 28 years, well, it looks bloody tough. But tough or not, it is necessary, and we need to get a rig on. The growth in our retail business has come from hard on market share gains and having the best customer retention rates in the industry has helped maintain the momentum. But there's no shortage of competition and we are driven to continue to innovate and to lead. During the year, we established a new energy solutions team. Their mission is to advance options for distributed generation and commercial demand response solutions for customers. We believe there is massive scope to add value to customers and the system as a whole by providing innovative technology solutions beyond traditional energy retailing. The team will also lead in the deployment of our current EV charges. We currently have 61 charging stations in 30 locations, making us the second largest provider of public charging in New Zealand, and we have a further 82 charging stations committed and awaiting construction. We've made good progress selling our certified renewable energy product. Our commitment to the customers who purchase these certificates is that we will reinvest the sale proceeds into decarbonization projects for others, and that's what we're doing. A good example is a project to support kids care to start electrifying their vehicle fleet. And to tidy up our underlying customer technology stack, we expect to complete the migration of the Meridian customer base to the Flux platform by the end of this calendar year. I seem to recall possibly saying that this time last year, but we are truly downtime picking the last set of complex C&I customers. And interestingly, the hardest segment to sort out are the customers with unmetered services. Now we are all acutely aware that of the pressure challenging wholesale conditions are putting on large customers as wholesale prices tend to feed through to their pricing quickly. The mass market prices continued to trend below CPI and in real terms, they have been declining for more than a decade now. All the evidence tells a strong competition that is working for customers in the New Zealand electricity market. That said, we know many Kiwi households still struggle to pay for their power. So this year, as our customer team launched the new energy well-being program. This is a pilot program aimed at reducing the impact of the 4 key drivers of energy hardship on our most vulnerable customers: financial, housing quality, energy supply, and energy efficiency. We're building the knowledge of in-house energy well-being specialists and partners to look at the whole picture for individual customers and to support them to progress up the energy well-being spectrum. We're finding we can make a real difference beyond the boundaries of energy supply, and our ambition is to scale the program up for a much greater impact. Now as you would expect, we've been very busy focused on moving forward with our NZAS exit mitigation plans, and we have no intention of buttoning off our efforts. NZAS had begun exploring options for the smelters future beyond 2024. That process is a way to go. And I'd point out there is a massive gap between the terms of the exit deal. We negotiated with NZAS in January last year and what we consider to be a sustainable contract for electricity in New Zealand. Only time will tell whether that gap can be bridged or not. On the mitigation front, as I mentioned earlier, we have built out a new drought hedge package that improves the diversity and carbon efficiency of our hedge position. And in April, Transpower exceeded expectations by completing the heat of schedule, the project to materially enhance the transmission export capacity out of Southern. I remember in 2020, when we started to talk to NZAS about an extended exit deal, the cloth of the Upper Waitaki Line project was scheduled for completion in late '23. So the National Grid operator has done a great job bringing delivery forward. And whilst I've never done it myself, I do imagine installing 142 kilometers of transmission line duplexing through some very challenging terrain and conditions, there's no mean feat. So hats off to them, they have got it done. I've talked to the expected battery milestones earlier. While we see this as primarily supporting the flow north of electricity, it will also play a very important role in terms of grid and regional supply system stability. The electricity system needs this type of investment, and we're moving as quickly as we can. We have customer commitments that get us halfway to our 600 gigawatt hour process heat electrification target. We're also talking to a number of those customers about demand response opportunities. The concept is that the customer can introduce electrode boilers to replace their thermal boilers but keep their thermal boilers available to be in biomass when electricity supply is challenged. Then we are willing to buy that demand response capability from them for good value. It creates a real win-win outcome in our view. H2 is all go. We're working with 2 shortlisted parties, to skew future industries and Woodside. We expect to choose one party in agreed terms for the development stage of the project by the end of this year. From there, some real money will start to be spent, building into a final investment decision in 2024 and likely commissioning in 2027. There are skepticism around green hydrogen, but there are aspects of the southern green hydrogen opportunity that are unique and make a lot of sense to us. We already have existing hydro backed high-capacity renewable energy available. In that context, there is a significant value in the demand response that the hydrogen facility can offer to the electricity market. We believe this will materially enhance the overall project economics. Green hydrogen is tomorrow's technology. Global growth projections are mind blowing. New Zealand's domestic projections for hydrogen demand are likely to exceed the capacity of Southern Green hydrogen by a few times. So we see the project is also creating a foundation towards energy independence for our country. Data Grid have announced the Target University is the first anchor customer, and we understand consent for the site construction will be filed before the end of this year. Also, the supporting fiber connectivity is planned for completion in 2025. I think a phased build profile is likely to be modest and in 10-megawatt increments, but Data Grid still believe the facility could meet the 100-megawatt aspirations. So to sum up. We've made solid progress from where we were 18 months ago. Ironically, NZAS choosing to terminate their contract with us has driven us to act. And as a result, I think the strategic options in front of Meridian and New Zealand today are stronger than ever. The government submission reduction plan released in May unpacks more detail on how New Zealand will meet its first emissions budgets for 2022 through 2025. The plan kept submissions at 290 million tonnes over that period, which represents a reduction of around 4% over the current trend. Supporting this is a climate change package from the '22 budget totaling $2.9 billion over the next 4 years. 40% of that is earmarked for transport, including increased support for low and zero-emission vehicles. The clean card discount and a low income cap and replace scheme, a strong targeted policy interventions in our view. And along with the sizable uplift in the industry carbonization funding that I mentioned earlier and reforms to the emissions trading scheme, everything is pointing to a significant and positive uplift in future electricity demand. And in that context, probably the single biggest regulatory risk in our sector relates to changes occurring through the resource management reform process. The new framework for consenting is emerging through various consultations. It is a very complex interplay between the Natural Built Environment Act, NBEA, the Spatial Planning Act and subordinated instruments that will be created under the new legislation. These include the national planning framework and regional special strategies. As currently drafted, the NBEA wouldn't pose significant hurdles for many large infrastructure projects. The draft NBEA introduces environmental bottom lines that must be adhered to and are unable to even be mitigated. It seems highly likely that many renewable development projects are existing schemes that must be reconsented will encounter an environmental bottom line. That will make them hard or impossible to consent. We believe this would cause a massive own goal for our country. We don't believe that is government's intent, and we are engaging with the relevant ministers and officials to ensure the issue is addressed before the new RM framework comes into force. I do stress that we're not looking for a free hit for renewable projects. But the framework must allow for the localized environmental impacts of projects to be balanced against the climate benefits that renewable energy brings. The changes necessary in our sector over the next 30 years are significant, and we think it is important that the industry has a semblance of a plan to show that change can be efficiently managed whilst enhancing the energy trilemma. Meridian as part of an industry group, including generators and lines companies, who have commissioned Boston Consulting Group to develop a road map to achieve a low-carbon energy future in line with New Zealand's 0 carbon commitment. The findings from this work will be published over the next 2 months, and we believe it will provide a credible contribution to the government's energy strategy work. And hopefully, this is the last time I feel the need to comment on transmission pricing reform. In June, the high court dismissed [indiscernible] judicial review of the electricity authorities reform process. Not long after that, Nova indicated that they will take this to the Court of Appeal. But the appeal is on quite narrow grounds, and we are hopeful that the reforms in all material respects, at least will be in place in April 2023. Now on a like-for-like basis, Transpower's indicative modeling suggests Meridian's transmission costs will reduce under the new TPM. But this will likely be negated over time due to cost escalations in Transpower's operations and as further investment in the grid takes place. And if you consider the growth necessary to enable decarbonization in this country, I'd suggest we are at a low point in the cycle as far as transmission costs go. All right. I'll now hand over to Mike to go through the numbers.

Thanks, Neal, and thanks, everyone, for joining the call this morning. Before getting under way, I have to say I love that slide. Meridian does have the power to make a difference. And beyond building renewable generation, I can't think of a better way to do that right now than supporting EV uptake. This move to embrace electric mobility is a necessary revolution if we tackle climate change. I recommend that everyone jump on board, whether it's a car, bike or scooter, and it's something I'm quite proud that we can support. And you can't quite see it in the slide, but also like the catch phrase on the side of the car as well. Goes like the wind. If you stop to think about it, it's pretty clever. Anyways, back to the financials. As always, I'll try and provide a little more insight than you might see on the slides directly so that you get something from listening to me as opposed to just reading the slides later. So into EBITDAF and operating cash flows. As you saw on the highlights slide that Neal talked to, we chopped up another solid year financially. While some may report on the net profit after tax figure that comes later in the pack, it'd be a bit disingenuous of us to use that figure as a headline as it contains the MEA gain on sale which is a one-off. So it doesn't compare directly to the last financial year. So while net profit after tax is important, here, we start with EBITDAF as it provides a better insight into our operating performance, at least in my view. And the 2.5% lift in EBITDAF that you can see on this slide isn't an easy thing to do as our operating teams will attest to. But once again, they delivered superbly this year. Now of course, a simple statistic like that glosses over a year that was both exhilarating and a bit nerve racking, particularly if you're a farmer down Southland. Not sure if we ever are on the line from down that way, but I doubt you would immediately remember the last time the Deep South experienced a drought like that one. It was the real deal and had a major impact on lifestyles in the production of white gold. Someone told me that there was one upside to that in the summer extended later into April, and that's unusual for Southland. But I'd rather it rain a bit more myself. Someone else told me that the last time a drought of that scale was seen in Southland was preterm shared bulk. Now I did a bit of Googling on that claim. And given he moved down that way in '93, it could be a bit suspect. But if I give the drought in energy context, we usually produce 1,400 gigawatt hours of electricity from Manapouri Power Station over the January through April period. This year, we produced just 760 gigawatt hours. That's 640 gigawatt hours of lost production or the equivalent of shutting Auckland down for a month. So the Southern drought was large. And regardless of how I frame it, the point is that it will be understandable if I was presenting EBITDAF that was lower than last year. But I'm not as Chris Ewers and the wholesale team kept us in the game. And when the rain returned south in late April, they put the foot down and delivered. It didn't hurt, of course, that Lisa Hannifin and the retail team have been working closely with customers to help moderate the impact on them and us but it was the wholesale team that came through in the end. So $709 million it was in operating cash flows, which is my personal measure of performance, tacked up by 7% as well. For those on the interim call in February, you may remember that following the sale of our Australian business, we adjusted our dividend policy. I was careful then to note that the majority of the proceeds from that sale will be plowed back into the New Zealand business given growth forecasts, but that subject to operating results, we had latitude to consider a progressive dividend as well. To reflect this sentiment, we lifted the free cash flow payout range to between 80% and 100%. And secondly, we dropped this time business CapEx as captured within the dividend policy from 65 million to 50 million. We said we'd revisit those changes most likely in 2024 or when we had a better handle on NZAS mitigation outcomes. As a result of the above, we've lifted the final ordinary dividend from 0.112 per share to 0.115 per share to be paid on the 23rd of September. In turn, that lifts the full year ordinary dividend to 0.174 per share imputed to 79%. And we'll retain 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. I've already talked a little about the year that was from an operational perspective, so I won't repeat that here. Rather, I'll point out that our retail team continue to grow their financial contribution within the business, but the financial contracts entered into to support that growth cost more than they did last year. Overall, energy margin or the results delivered by a generation wholesale and retail teams lifted by $28 million on last year. And this flowed through to EBITDAF, as you'd expect. Now this slide is not all about the dollars. Well, it is, but it also gives me the opportunity to digress and talk a little about how the market structure in our sector also delivers great outcomes for customers. First off, the World Energy Council again ranked New Zealand's electricity market as one of the best in the OECD across 3 measures: resilience, sustainability and low cost. And New Zealand is 1 of only 3 non-European countries in the top 10 out of the 127 countries they rank. At the same time, and as Neal mentioned, the data at the Ministry of Business Innovation and Employment Producers shows that residential customer cost per unit remained lower today in real terms than they were in 2013. Not bad. The New Zealand electricity sector punches well above its weight internationally. And when you compare consumer experience here to ours, where electricity markets have failed consumers at times, it's hard not to be proud of this performance. I'd also point out that confidence in the wholesale spot market continues to grow as evidenced by the massive increases in volumes traded on the ASX Futures Exchange. Last financial year, there was over 90,000 gigawatt hours traded on that market or more than twice the total physical consumption of electricity in New Zealand over the same period. This is an increase of over 20,000 gigawatt hours on -- from year '21. Now you only use that futures market, if you have confidence in the price formation process captured in the wholesale market, as you rely on it to settle contracts. And the combination of an effective spot market and a liquid forward market is often overlooked by commentators, but it's an important measure of confidence in the sector and the prices that emerge. And then you move to investment. Of course, this is the most important feature of any market, our participants either adding or removing supply and/or demand in response to price signals. Well, given market prices, over $2.3 billion has been invested in new renewable generation that will help decarbonize the economy, and this is going on without any government incentive in advance of meaningful growth in demand. And as a collective, the World Energy Council view MB stats, forward market activity and investment, they're pretty impressive. And taken together, they suggest that the electricity sector is helping Kiwi businesses compete on the global stage while attracting new business to the country as we step into a future. It will be very different to the one we've seen over the past 10 to 20 years. I back us to do that, grow our competitiveness as a nation that is, but our sector will only play a supportive role if consumers continue to see good outcomes. And if the high global ratings and recognition New Zealand receives in this respect is retained. I hope that diversion was of some use, but now I'm going to come back to operating costs. There's always a bit more on this one that I think is necessary. So long story short, operating costs lifted by 10 million over the last year or 17 million if you strip out the MB holiday pay provision. But as you can see, other than for changes in accounting, lifts and insurance premium and COVID-related costs, money was spent on staff and growth activities like our development team and Flux. These are areas that our investors would want us to spend money on in the current environment. At interim, as I said, we expected to spend between 215 million and 220 million for the year and we spent 218 million. Last comment on this slide, while it isn't captured, we've retained an elevated provision for doubtful debts as we enter year '23. At 8 million, it's lower than the 9 million provision held at the end of '21, but it's higher than normal. Short and sweet here. Total capital expenditure for the year landed at 175 million, the top end of the range presented at interims. Sand business CapEx didn't change materially, but Harapaki spent approximately 86 million to stay on schedule and navigate the abysmal weather that the Hawke's Bay is renowned for in summer. And while I'm on Harapaki, I do want investors to know that we've got a cracker team up that way, working hard to land that wind farm. Harapaki Manager, our project manager, Rob Batters, probably didn't appreciate the size and nature of the challenges that he and his team might face, but with the steadfast support of Chris More, Guy Waipara and the fellow sitting next to me, they're doing a great job in challenging circumstances. If you're wondering what the remaining $49 million of growth CapEx was spent on, it was largely land support and extend the Ruakaka Energy Park and a new battery site near Parmesan North. Now costs are going to lift in fin year '23 as well, there's no doubt about it. As you can see here, fin year '23 operating cost guidance for the group is $242 million to $247 million. That suggests a $24 million to $29 million lift in operating costs year-on-year. What you may not be able to see is where costs will rise, so I'll provide a little more detail. First, staff costs were left by a little over 8 million this year. In order to retain and attract people where necessary, room was increased across the group by 7%. With low, no or potentially reverse migration forecast, it was our view that retaining and motivating our people this year was a priority. Second, we're spending more money to build capability in the development team again this year and also within our subsidiary, Flux. We've lifted spend across -- by $7 million across those 2 activities so that Flux can grow into Australia now that the Meridian migration is largely complete, and so that we can continue to extend the pipeline of development options here in Aotearoa in advance of decarbonization led demand growth. Last, fin year '23 will also see a full year of Masterton call center costs. That cost have historically been eliminated, but now that the team has a contract to support Powershop Australia, it will show up in operating cost directly. Of course, that cost at approximately 6.6 million will be recovered through the contract we have in place with Shell, so there'll be revenue offsetting it. All other operating costs will be held flat to fin year '22. The CapEx forecast also lifts this year driven by the ramp of Harapaki spend. Forecast range for this year is $410 million to $435 million, broken into stay-in business and growth CapEx, as you see here. And we'll introduce a new forecast to add a little more visibility. It's a total cash forecast for our generation team. When I say total cash, I mean, the combined operating and capital cost for that team and in fin year '23, I'm forecasting it to land between $83 million and $88 million. There's nothing wrong with a bit more visibility. As the 2 graphs show, our preferred measure of performance, underlying net profit after tax lifted marginally on last year. I'm sure this makes sense, given we saw a lift in EBITDAF. And as I mentioned at the start, while net profit after tax lifted by 55%, when you strip out the $214 million MEA gain on sale, it lifted by 9%, driven largely by year-on-year fair value movements of treasury instruments. As shown here, these noncash items continue to move materially year-on-year. My simple message is that financial performance in fin year '22 was sound. At the start of my speech, I briefly mentioned that our balance sheet was particularly flexible following the sale of our Australian business, but that's not news. We do have a tranche of the green NZX listed retail bonds maturing early 2023, and will likely replace those with a sustainability-linked bond, but I'll save my thunder on that until we've actually made the call. So I don't have too much to add to the statements captured on this page. Therefore, I'll finish as I started. We've delivered another solid result for investors in Meridian. And as importantly, we're well placed to navigate future challenges with a strong balance sheet and formidable operating teams. Fin year '23 is shaping up to be interesting already, but I'll hand back to Neal so he can make a few closing comments.

Thanks, Mike. Look, in summary for me, I believe the business has performed well, and we've had a successful year. Certainly, if you think about it in terms of executing on our strategic intent. We've successfully exited an ever-increasing rescue position in Australia, and we've done that for good value. We've made material progress with our NZAS exit strategies. Actually, when I was thinking about this last night, I concluded we need to just adjust our language in respect to NZAS. But I didn't want to throw it on into a flat change in all of our slides for today. But from where we are today, whether the smelter stays or goes has become much less relevant in my view. More importantly, we've become deeply engaged in supporting customers to decarbonize and grow demand for renewable electricity in Aotearoa, and we've become deeply engaged in forging ahead as the leader in the emerging global market for green hydrogen. So the way we think about it, we're no longer focused on mitigating some form of smelter exit. We're focused on playing our part to grow 0 carbon economy. Now to support that future demand outlook, we've made great progress building out our pipeline of renewable development options. Clearly, though, this is an area where we need to continue to increase our level of investment. Unless we take it all for granted, we have continued to execute extremely well supporting and growing our customer base. So that's it from us. Well, I think we can move to questions. And typically, we go to the audience here in Wellington. Give you guys the first crack. Who's got the microphone?

Andrew Harvey-Green with Forsyth Barr. The first question, just around, I guess, the smelter and I thought it was quite conspicuous. You didn't talk about the fact that they've recommenced negotiations. And also probably what I'm most interested in is probably your views and thoughts on the implications of the EA intervention.

Okay. We alluded to the fact that the smelter had recommenced the process to look at the prospects beyond 2024. We're now involved in that process. Any conversations as part of it will be under a confidential agreement, so we won't be able to say much really until it's concluded. I think the key point from our perspective is we've been pretty open in public of what the conditions that we'd like to see before we consider an extension beyond 2024. And we've got no intention of resiling from those sorts of conditions. Second point was the EA. Look, we're not 100% aligned with their concern. But having said that, the nature of the urgent code amendment that they introduced last week, we don't think causes us a problem. We actually think the staged exit deal with Rio Tinto, which was a unique transaction and done for a particular purpose, which was to buy time not only for the Southland region but the electricity sector is unlikely to be repeated. But even that contract actually passes the test that they've introduced to the code amendment. So whether it needed to happen or not, is neither here nor there. I don't think it's going to be a major issue for us going forward. And certainly, any of the contracts we're looking at in the future in relation to the other large potential customers being either NZAS or hydrogen.

Second question I just had was around your options. And I think you indicated you're well covered, I guess, through to the end 2024. I guess we heard last week from Genesis in terms of they got a new product, which has been launched, I think, early next week. Just I guess you'll probably wait and see what it is. But at the moment, am I right in saying that you don't foresee any need to probably take additional cover unless maybe it went particularly dry?

You want to answer that?

Yes. You're right, Andrew, is we went through a pretty lengthy process to secure a cover for '23, '24, recognizing the Genesis option terminated at the end of this year. Genesis was part of that process. We've gone in a different direction. It'd be interesting to see what that product actually looks like. But we are set for '23, '24. So of course, we'll have a look at it. But as you say, '25 is too early to call. So we'll see kind of what happens between now and 2025, but we feel pretty good about our '23, '24 position.

And the last question I just had was just, I guess, around the development pipeline. And it sounds like you're almost guaranteed to go ahead with the battery, the solar and then Mt. Munro. And I guess beyond that, there's a little bit of a gap here. I just wondered how should we think about some of those other options that you're even further out? I mean how far -- what does secured options actually mean? And then still the ones beyond that, what stages are we actually talking about here?

Yes. We haven't moved to financial close on any of those projects, but it is clearly our intention. We know enough about the economics to be confident that we will move to that point. But that will happen over the next year or 2. Beyond that, a secured option for us is an agreement with the land owners. So we've got access to the resources effectively exclusive access. To firm them up, obviously, you've got to take them through the design phase, but get them into the consenting process. And once you've locked in place the consent, you've got a live option that you can execute on. I think we've been reasonably conservative with the pipeline in terms of how we schedule the delivery of those projects because we'd certainly like to accelerate them faster. And as I indicated, I don't think that -- I hope, but it's unlikely the consent framework in this country is going to get any easier. So the sooner we get them into that process, the sooner we'll get them out and into a buildable form.

Nevill Gluyas, Jarden. I'm probably going to cover a lot of the same ground that Andrew did, but maybe to start with something different. I mean you highlighted when you talked about the HVDC charges going forward that there's the importance of growing the grid capacity is there. From your perspective, specifically the HVDC capacity is very important to how the financials of the business work. Are you confident that the HVDC in its current form without any major investment will last you through to the 2030s?

It will require investment. I think that's clear. I understand and I'm not across the detail fully, but Transpower looking at a tactical project that would increase capacity on the DC by potentially up to 200 megawatts. I think it's roughly in that order. And that could occur within the next 5 years. So we'd be supporting them to get on and do that. I think it's -- and I've said this plenty of times, but I think transmission is the single biggest enabler of competition in our market. And with the level of growth that we need to build into, we're going to have to come up for a mechanism that allows transmission to get there probably before time rather than just in time because just in time will likely be too late and constrain potential renewable development.

So we're right to think then that if they do proceed with that 200 megawatts and you've got the 100-megawatt battery, are we getting close to sort of a realistic 1,400 north?

Yes, we believe so. But we've also given ourselves another option on batteries and other parties are looking at them as well. But I think you're starting to get into the realms of a significant lift in HPD's capacity, which would again mitigate any loss of NZAS.

And I guess then there's the kind of the risk reliability question, pretty confident about that as well with that work.

Yes.

Great. Okay. That's useful. Yes. And sort of the some of the same ground. Very interested in your comments about the team putting together some of the decarbonization but also demand response ideas, thinking beyond the next 2 years where you set, you say, what do you think your target for demand response capability is? And how much are you bringing to market? What proportion do you think the market need for demand response is going to be there?

Well, first off, that the significant labor demand response we see in the hydrogen opportunity and that's potentially up to 600 megawatts. The work that we have done, and it's been peer reviewed by concept consulting would suggest that would meet about New Zealand's -- 40% of New Zealand's dry year cover necessary to cover a drought. We haven't put a clear target -- but I think there is a lot more potential with large industrial customers in the country. We haven't put a clear target on that yet because we're still discovering and we don't have a working example of it, but it is well possible and it works -- from what we've seen, the economics will work for both customers and ourselves. When you're talking about large-scale thermal plant being kept in reserve for using biomass, well, then you get into a biomass availability. But even if you were burning coal at times of hydro drought, there probably -- there would still be a much better outcome than bending coal all year round every year. But on top of that, I think the -- with the market in terms of mass market availability, in terms of demand response is just totally untapped. We've relied on ripple control and really basic almost brutish mechanisms in the past. We think the future is about enabling customers with -- through technology in their own homes to participate in the electricity market and be rewarded for that. So I can't give you any numbers yet, but I can tell you it's getting a lot of focus, and it's where we see the future.

I presume thinking about your capital involved, will your capital potentially be involved in either as a cost or an outlay to help with those boiler?

Yes.

Okay, great. That's one place to go. And in terms of cost of biomass, if it is biomass, I mean, what price do you think you could pay up to if you're interrupting, say, exported timber? Are we talking mid-$20 a giga joule range.

Look, I probably need to get you to talk to the team working on it, Nevill.

We'll do. Okay. Just a question then about how we should look at your demand profiles there, just a detailed question really. Is that the build start dates you've got pinned on that timeline?

No, that's the delivery date. So you're talking about the pipeline. No, that's when we'd expect them to be delivering to full power.

And the last one for me is, if we think about -- you've given on that Venn diagram sort of a date for FID on hydrogen. How long should we think it takes between FID, assuming it proceeds and actual first hydrogen and full power?

Yes. Well, we've never built one before. But the expectation is if we can get to FID sort of late '23, early '24 then mid-'27 is feasible. There's a lot that goes into it. And it may be that the actual build profile is phased. So you've got 200 megawatts. I might as well touch on it now, but I mean there's a potential that both the smelter and hydrogen are part of New Zealand's future. And as part of that potential, we're going to have to build a lot more renewable energy, particularly in the South Island. But we think we've got time to actually get on and do that.

Tim Mowbray, Macquarie Asset Management. I just want to touch quickly on the development in kind of CapEx pipeline, just kind of been covered off a little bit really, but just to clarify, in terms of possibility of bringing forward the projects mentioned the RMA constraints, other constraints you see around capacity-wise. And kind of just following on a few more ones. Cost increases you're kind of seeing. Is Harapaki a good indication, or we expect more cost increases going forward? And in terms of expectations around funding FY '23 CapEx. Obviously, you've got the sale proceeds, just any guidance on debt for sale proceeds expected to fund that?

I'll handle the first question, and then I'll hand over to Mike. In terms of capacity constraints, yes, look, the resource consenting process is by far the largest. But beyond that, it's our own capacity constraints. And that's why we signaled that we're investing more in our development team. We need more capable people there doing a fantastic -- the people that we have are doing a fantastic job, but they are stretched. And to progress a project through to build, we need more concentrated capability there. So we're going to have to either build or develop that within our ranks -- sorry, buy as and recruit people or develop within the own team. Mike?

Yes. Your question on cost increases. I think you mentioned Harapaki specifically, whether that would translate to other projects. I think the cost we've seen at Harapaki, as Neal mentioned, that were pretty specific, the majority of it is eroding. There's a bit of inflation in there, too, though. So there are inflationary pressures sitting out in the water market. We know as we're looking at other initiatives at the cost of investing in either wind, solar or battery technologies has risen as well. So the cost base for new investment is rising. But the price curve is reflecting that. You see ASX kind of moving to accommodate those prices. So those projects, while the cost base changes, the revenue changes as well and they look reasonably economic. It's hard to tell generally beyond that, like the big one that I signaled today was a cost and us, people. And I think everyone is feeling that. A lot of that feels like it's going to come down to the migration settings. So are we going to have people coming into New Zealand with skills that we can use to offset some of those pressures? So it's a harder one to call. I might be the wrong person to answer it. But on funding, funding mix, as I mentioned, we've got a retail bond that rolls off next year that we will replace. So we'll probably go to market for something between 150 million to 200 million. When we got a retail bond that rolls off over the following 2 years as well. So we'll see what we do with those and subject to the investments that we intend to make. But balance sheet is well set. We don't have funding constraints.