Good morning, and welcome to Meridian's 2022 annual results presentation. I'm Neal Barclay, Chief Executive, and as usual, I'm joined by Mike Roan, our CFO. I'll start by calling out a few of the highlights. EBITDA 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 of water into our catchments. Hidden within the average numbers were huge volatility, and that included the lowest Q3 inflows into the Waiau catchment for 90 years. During that time, generation through the Manapōuri Power Station was severely curtailed.
In fact, for much of April, Manapōuri, which has a capacity of around 847 MW, was operating at around 80 MW. 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 repriced 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 heading into FY 2023 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 NZD 214 million dollar gain on sale, and more importantly, the sale proceeds of NZD 740 million have substantially boosted our balance sheet capacity to invest into New Zealand's renewable energy future. Our retail business has continued to excel and take market share from our competitors. Over the last three years, we have added an equivalent of half the Tiwai Smelter's 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. Unfortunately, none of the injuries suffered by people working for us have had lasting impacts on their lives.
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. I want to acknowledge the massive safety focus our project and contractor teams have established at 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 wraps 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 at 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. Tikanga, 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 company's 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 two highly committed and credible counterparties shortlisted now. Process heat electrification is becoming more viable with lifting ETS prices and a tenfold increase over the next four years in the government GIDI fund. Rio Tinto seem clearer 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 swaps and deal with Contact that we announced last week means our hedge book is in good shape and the risk position for 2023 and 2024 is sorted.
What happens beyond 2024 will 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 NZD 53 million or 13% increase in the Harapaki capital costs, which now total NZD 448 million. Critically, this additional spend maintains the original first and full power milestones in mid-2023 and 2024 respectively. Like 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.
Now, 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. 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. 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 it 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. Ruakākā Energy Park will be our next development. We're currently tendering for the battery, and we expect to receive consents within the next couple of months. We plan to commence build in 2023 and complete construction during 2024. I'd love it to be sooner as the system has experienced regular peak stress events during winter months. 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. We've also secured a second battery option site at Bunnythorpe. The Ruakākā Energy Park solar farm consent is expected to be lodged in early 2023, with construction complete in early 2025. We're in the process of acquiring an additional parcel of land adjacent to Ruakākā to lift the capacity of the solar farm to 100 MW. We're also preparing to lodge the consent application for the Mount Munro wind farm later this year. We expect that project to follow closely on the heels of Ruakākā 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. 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. Tough or not, it is necessary, and we need to get a rigor on. The growth in our retail business has come from hard-won market share gains, and having the best customer retention rates in the industry has helped maintain the momentum. 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 are also leading the deployment of our current EV chargers. We currently have 61 charging stations in 33 locations, making us the second largest provider of public charging in New Zealand. We have a further 82 charging stations committed and awaiting construction. We've made good progress selling our CER-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 KidsCan to start electrifying their vehicle fleet.
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. Now, I seem to recall possibly saying that this time last year, but we are truly down to unpicking the last set of complex C&I customers. Interestingly, the hardest segment to sort out are the customers with unmetered services. Now, we're 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. But mass market prices continue to trend below CPI, and in real terms, they've been declining for more than a decade now. All the evidence tells us strong competition is working for customers in the New Zealand electricity market.
That said, we know many Kiwi households still struggle to pay for their power. This year, our customer team launched a new energy wellbeing program. This is a pilot program aimed at reducing the impact of the four 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 wellbeing specialists and partners to look at the whole picture for individual customers and to support them to progress up the energy wellbeing 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 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 backing off our efforts.
NZAS have begun exploring options for the smelter's future beyond 2024. That process has a way to go, and I 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've built out a new drought hedge package that improves the diversity and carbon efficiency of our hedge position. In April, Transpower exceeded expectations by completing ahead of schedule the project to materially enhance the transmission export capacity out of Southland. I remember in 2020 when we started to talk to NZAS about an extended exit deal, the Clutha to Upper Waitaki lines project was scheduled for completion in late 2023.
The national grid operator has done a great job bringing delivery forward. While I've never done it myself, I do imagine installing 142 kilometers of transmission line duplexing through some very challenging terrain and conditions is no mean feat. Hats off to them. They've 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 GWh 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 burn 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 two shortlisted parties, Fortescue Future Industries and Woodside Energy. We expect to choose one party and agree 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 to a final investment decision in 2024 and likely commissioning in 2027. There is 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. We see the project as also creating a foundation toward energy independence for our country. DataGrid have announced University of Otago as their first anchor customer, and we understand consent for the site construction will be filed before the end of this year. The supporting fiber connectivity is planned for completion in 2025.
I think a phased build profile is likely to be modest and in 10 MW increments, but DataGrid still believe the facility could meet their 100 MW aspirations. To sum up, we've made solid progress from where we were 18 months ago. Ironically, NZ's choosing to terminate their contract with us has driven us to act. As a result, I think the strategic options in front of Meridian and New Zealand today are stronger than ever. The government's emission reduction plan released in May unpacks more detail on how New Zealand will meet its first emissions budgets for 2022 through to 2025. The plan caps emissions at 290 million tons over that period, which represents a reduction of around 4% over the current trend.
Supporting this is a climate change package from the 2022 budget, totaling NZD 2.9 billion over the next four years. 40% of that is earmarked for transport, including increased support for low and zero-emission vehicles. The Clean Car Discount and a low-income cap and replace scheme are strong targeted policy interventions in our view. 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. 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 and Built Environment Act, NBEA, the Spatial Planning Act, and subordinate instruments that will be created under the new legislation. These include the National Planning Framework and Regional Spatial Strategies. As currently drafted, the NBEA would impose 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 or 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 local, 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 while enhancing the energy trilemma. Meridian is part of an industry group, including generators and lines companies, who have commissioned Boston Consulting Group to develop a roadmap to achieve a low carbon energy future in line with New Zealand's zero carbon commitment. The findings from this work will be published over the next two months, and we believe it will provide a credible contribution to the government's energy strategy work.
Hopefully, this is the last time I feel the need to comment on transmission pricing reform. In June, the High Court dismissed Manawa's judicial review of the Electricity Authority's reform process. Not long after that, Nova indicated that they will take this to the Court of Appeal. 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-with-like basis, Transpower's indicative modeling suggests Meridian's transmission costs will reduce under the new TPM. This will likely be negated over time due to cost escalations in Transpower's operations and as further investment in the grid takes place. If you consider the growth necessary to enable decarbonization in this country, I'd suggest we are at the low point in the cycle as far as transmission costs go.
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 underway, 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're to 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. You can't quite see it in the slide, but I also like the catchphrase on the side of the car as well, "Goes like the wind." If you stop to think about 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 just reading the slides later. Into EBITDAF and operating cash flows. As you saw on the highlight slide that Neal talked to, we clocked 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. 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.
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. 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-wracking, particularly if you're a farmer down Southland. Not sure if we have anyone on the line from down that way, but I doubt you'd 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 and the production of white gold. Someone told me that there was one upside to that, and that summer extended late into April, and that's unusual for Southland. I'd rather it rained a bit more myself.
Someone else told me that the last time a drought of that scale was seen in Southland was pre Tim Shadbolt. Now, I did a bit of Googling on that claim, and given he moved out, down that way in 1993, it could be a bit suspect. If I give the drought and energy context, we usually produce 1,400 GWh of electricity from Manapouri Power Station over the January through April period. This year, we produced just 760 GWh. That's 640 GWh of lost production or the equivalent of shutting Auckland down for a month. The Southland drought was large. Regardless of how I frame it, the point is that it would be understandable if I was presenting EBITDAF that was lower than last year.
I'm not, as Chris Ewers and the wholesale team kept us in the game. When the rain returned to Southland late April, they put the foot down and delivered. 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. NZD 709 million it was in operating cash flows, which is my personal measure of performance ticked 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 would 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%. Secondly, we dropped stay in business CapEx as captured within the dividend policy from NZD 65 million- NZD 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 NZD 0.112 per share- NZD 0.1155 per share to be paid on the 23rd of September.
In turn, that lifts the full year ordinary dividend to NZD 0.174 per share, imputed to 79%. 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 that the financial contracts entered into to support that growth cost more than they did last year. Overall, energy margin or the results delivered by our generation wholesale and retail teams lifted by NZD 28 million on last year. This flowed through to EBITDAF, as you'd expect. Now, this slide's 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 three measures: resilience, sustainability, and low cost. New Zealand is one of only three non-European countries in the top 10 out of the 127 countries they rank. At the same time, and as Neal mentioned, the data that the Ministry of Business, Innovation and Employment produces shows that residential customer costs per unit remain lower today in real terms than they were in 2013. Not bad. The New Zealand electricity sector punches well above its weight internationally.
When you compare consumer experience here to Oz, 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 GWh 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 GWh on financial year 2021. Now, you only use that futures market if you've confidence in the price formation process captured in the wholesale market as you rely on it to settle contracts.
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. Then you move to investment. Of course, this is the most important feature of any market. Are participants either adding or removing supply and/or demand in response to price signals? Well, given market prices over NZD 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 and demand. As a collective, the World Energy Council view, MBIE stats, forward market activity and investment, they're pretty impressive.
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 that'll 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 gonna come back to operating costs. There's always a bit more on this one than I think is necessary. Long story short, operating costs lifted by NZD 10 million over the last year or NZD 17 million if you strip out the MBIE holiday pay provision.
As you can see, other than for changes in accounting, lifts in 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 interims, I said we expected to spend between NZD 215 million and NZD 220 million for the year, and we spent NZD 218 million. Last comment on this slide. While it isn't captured, we've retained an elevated provision for doubtful debts as we enter FY 2023. At NZD 8 million, it's lower than the NZD 9 million provision held at the end of FY 2021, but it's higher than normal. Short and sweet here. Total capital expenditure for the year landed at NZD 175 million, the top end of the range presented at interims.
Same business CapEx didn't change materially, but Harapaki spent approximately NZD 86 million to stay on schedule and navigate the abysmal weather that the Hawke's Bay is renowned for in summer. 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, project manager, Rory Blundell, probably didn't appreciate the size and nature of the challenges that he and his team might face. With the steadfast support of Chris Moore, Guy Waipara, and the fella sitting next to me, they're doing a great job in challenging circumstances. If you're wondering what the remaining NZD 49 million of growth CapEx was spent on, it was largely land to support and extend the Ruakākā energy park and a new battery site near Palmerston North.
Costs are gonna lift in FY 2023 as well. There's no doubt about it. As you can see here, FY 2023 operating cost guidance for the group is NZD 242 million-NZD 247 million. That suggests a NZD 24 million-NZD 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 up, staff costs will lift by a little over NZD 8 million this year. In order to retain and attract people where necessary, rent was increased across the group by 7%. With low, no, or potentially reverse migration forecasts, 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 by NZD 7 million across those two 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. FY 2023 will also see a full year of Masterton call center costs. That cost had historically been eliminated, but now that the team has a contract to support Powershop Australia, it'll show up in operating costs directly. Of course, that cost at approximately NZD 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 FY 2022.
The CapEx forecast also lifts this year, driven by the rump of Harapaki spend. Forecast range for this year is NZD 140 million-NZD 435 million, broken into stay in business and growth CapEx, as you see here. 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 costs for that team. In FY 2023, I'm forecasting it to land between NZD 83 million and NZD 88 million. There's nothing wrong with a bit more visibility. As the two 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.
As I mentioned at the start, while net profit after tax lifted by 55%, when you strip out the NZD 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 non-cash items continue to move materially year-on-year. My simple message is that financial performance in FY 2022 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 we'll likely replace those with a sustainability-linked bond, but I'll save my thunder on that until we've actually made the call.
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. FY 2023 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 risky position on 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. I didn't want to throw Owen into a flat change in all of our slides for today. 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.
We've become deeply engaged in forging ahead as the leader in the emerging global market for green hydrogen. 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 a zero 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. Let's not take it all for granted, we've continued to execute extremely well, supporting and growing our customer base. That's it from us. Well, I think we can move to questions, and typically we go to the audience here in Wellington and give you guys the first crack. Please grab the microphone.
First question from me, and it's probably-
Andrew, do you mind introducing yourself?
Oh, sure. Yeah. Andrew Harvey-Green with Forsyth Barr.
Thanks, mate.
Right. 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. Also probably what I'm most interested in is probably your views and thoughts on the implications of the EA intervention.
Okay. I alluded to the fact that the smelter has recommenced the process to look at their prospects beyond 2024. We're now involved in that process. Any conversations as part of it will be under a confidentiality 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 and public with what the conditions that we'd like to see before we'd consider an extension to beyond 2024. 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. Even that contract actually passes the tests that they've introduced to the code amendment. You know, whether it needed to happen or not, you know, is neither here nor there. I don't think it's gonna be a major issue for us going forward. Certainly, any of the contracts we're looking at in the future in relation to other, you know, the other large potential customers being either NZAS or Hydrogen.
Second question I just had was around your swaptions, and I think you indicated you're well covered, I guess, through to the end of 2024. I guess we heard last week from Genesis in terms of they've got a new product which is being launched, I think it's 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 wanna answer?
Yeah. You're right, Andrew, as we went through a pretty lengthy process to secure cover for 2023, 2024, recognizing the Genesis swap option terminate at the end of this year. Genesis was part of that process. We've gone in a different direction. Be interesting to see what that product actually looks like. We are set for 2023, 2024. Of course, we'll have a look at it. As you say, you know, 2025 is too early to call. We'll see kinda what happens between now and 2025, but we feel pretty good about our 2023, 2024 position.
All right. 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 Mount Munro. Just beyond that, just there's a little bit of a gap here. I just wonder, 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? Actually the ones beyond that, what stages are we talking about here?
Yeah. We haven't moved to financial close on any of those projects.
Yeah.
It is clearly our intention. We know enough about the economics to be confident that we will move to that point, but that'll happen over the next year or two. Yeah, beyond that, you know, a secured option for us is an agreement with the landowners. So we've got access to the resources, effectively exclusive access. To firm them up, obviously, you've gotta take them through the design phase, but get them into the consenting process. Once you've locked in place the consent, you know, 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 up faster.
As I indicated, I don't think that, or I hope, but it's unlikely the consent framework in this country is gonna get any easier. The sooner we get them into that process, the sooner we'll get them out and into a buildable form. Yeah.
That's all from me. Thanks.
Thanks.
Morning, team. Neville Gluyas, Jarden.
Great.
Okay. That's useful. Thank you. Yeah, sort of now to tread some of the same ground. I'm very interested in your comments about the team putting together, you know, some of the decarbonization, but also demand response ideas. Thinking beyond the next two years where you're 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 gonna be there?
Well, first off, the significant slab of demand response we see in the hydrogen opportunity and, you know, that's potentially up to 600 MW. The work that we have done, and it's been peer reviewed by Concept Consulting, would suggest that would meet about 40% of New Zealand's dry year cover necessary to cover a drought. We haven't put a clear target, but, you know, I think there is a lot more potential with large industrial country 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.
You know, when you're talking about large scale, thermal, plant being kept in reserve, for using biomass, well, then you get into a biomass availability. Even if you were burning coal at times of hydro drought, that would still be a much better outcome than burning coal all year round every year. On top of that, I think with the market in terms of mass market availability, in terms of demand response, it's 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 through technology in their own homes to participate in the electricity market and be rewarded for that. I can't give you any numbers yet, but 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-
Yep.
-to help with those boiler?
Yep.
Okay, great. That's one place to go. 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-NZD 20 a gigajoule range?
Oh, look, I'd probably need to get you to talk to the team working on it, Neal.
Will do. Thanks. Okay. Just a question then about how we should look at your demand profiles there. Just a detail question, really. Is that the build start dates you've got pinned on that timeline?
No, that's the delivery dates. You're talking about the-
The site.
...the pipeline.
Yeah.
Yep, yeah. No, that's when we'd expect them to be delivering-
Great
...first or full power.
The last one for me is if we think about you've given on that pinned 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?
Yeah, well, we've never built one before, but the expectation is if we can get the FID sort of late 2023, early 2024, then mid 2027 is feasible. There's a lot that goes into it. It may be that the actual build profile is phased. You've got 200 MW. You know, well, 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. As part of that potential, we're gonna have to build a lot more renewable energy, particularly in the South Island. We think we've got time to actually get on and do that.
Fantastic. Thank you.
Hi, Tim Mowbray, Macquarie Asset Management. Just want to touch quickly on the development and kinda CapEx pipeline. It's kind of been covered off a little bit already, but just clarify, you know, in terms of possibilities bringing forward the projects. You mentioned the RMA constraints. Is there any other constraints you see around, you know, capacity-wise? Kind of just following on a few more ones, cost increases you're kind of seeing, so Harapaki, a good indication, or expect, you know, more cost increases going forward. In terms of, you know, expectations around funding, you know, FY 2023 CapEx, obviously you've got the sale proceeds. Just any guidance on debt versus sale proceeds, expected funding there? Thanks.
Okay. I'll handle the first question, then I'll hand over to Mike. In terms of capacity constraints, yeah, look, the resource consenting process is by far the largest, but beyond that, it's our own capacity constraints. That's why we've signaled that we're investing more in our development team. We need more capable people. They're doing a fantastic job, but they are stretched. To progress a project through to build, we need more concentrated capability there. We're gonna have to either build or develop that within our own ranks. Sorry, buy as in recruit people or develop within our own team. Mike?
Yeah. Your question on cost increases, I think you mentioned Harapaki specifically and whether that would translate to other projects. I think the cost we've seen at Harapaki, as Neal mentioned, they were pretty specific. The majority of it is roading. There's a bit of inflation in there, too, though. You know, there are inflationary pressures sitting out in the wider market. We know, as we're looking at other initiatives, that the cost of investing in either wind, solar, or battery technologies has risen as well. You know, the cost base for new investment is rising. The price curve is reflecting that. You know, you see ASX kind of moving to accommodate those prices. 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.
You know, like the big one that I signaled today was a cost in wages, people, and I think everyone's feeling that. A lot of that feels like it's gonna come down to migration settings. You know, are we gonna have people coming into New Zealand with skills that we can use to offset some of those pressures? It's a harder one to call. Might be the wrong person to answer it. Hey, on funding mix, as I mentioned, we've got a retail bond that rolls off next year that we will replace. You know, we'll probably go to market for something between NZD 150 million-NZD 200 million when we've got a retail bond that rolls off over the following two years as well. We'll see what we do with those and subject to the investments that we intend to make. Balance sheet's well set. We don't have funding constraints.
Yeah, thanks.
I think we can probably go to anyone who has a question online.
Certainly, sir. For telephone participants, if you wish to queue for a question, please press zero followed by one on your telephone keypad and wait for your name to be announced. That is zero followed by one on your telephone keypad. Thank you. Your first question from the phone is from the line of Grant Swanepoel of Jarden. Please go ahead. Thank you.
Good morning, Meridian team. First question around Mount Munro and wind costs. It seems from your competitors they're talking about 20%-30% increase in costs associated with wind. Is this what you're also seeing you say you have a handle, economic handle on your new builds?
Well, we haven't gone out to tender for it, Grant, but certainly, you know, the indications are that it's. You're talking cost increases circa that. I mean, civil does play a strong part and, you know, one of the interesting things about Harapaki, it was built in a mountain range in a pretty challenging environment. As we come out of the hills, some of those risks start to dissipate a wee bit. Yep, no, wind costs, commodity costs across the board have escalated. I mean, how long that's gonna stick around for? I mean, it's changed in a hell of a hurry. It could change back. We've all seen these cycles shift around. We've still gotta discover fully what the cost implications are.
Thanks, Neal. Next question, just on justifying a Manawa build. You talk about demand response and the marginal supply needing for capacity. What do you guys think of the long-run marginal cost changes based on your view on what's gonna be the marginal supply over the next few years? Does that increment from the old NZD 80 long-run marginal cost we used to use justify new wind builds?
Yeah.
It's moving around, Grant. I think that's the best answer. You know, we have used NZD 80 MWh previously and quite consistently for a long stretch of time, and that was recognition that the cost of new technology, supply-led technology was falling. Just you know, becoming more and more efficient. We've seen the same thing that you have. Our long run forecasts have lifted, and you know, you mentioned 20%, Grant, so you know, they can move in that realm. There's a really interesting dynamic emerging between I'll call it long-run prices. Is how quickly can you build renewable assets into this market versus rely on some form of thermal backup? That's a little less clear than it was.
Neal's points on the RMA as being constraints in terms of getting these new renewable projects away could be as even bigger impact on price as anything else. Our forward curves are showing a reasonable difference subject to your ability to develop for our scenarios of the future.
Mike, thanks for that. Can you elaborate a bit on how you see the world playing out from a New Zealand market over the next 10 years in terms of what the new marginal supply be when you're talking biofuel at NZD 20-odd a gigajoule? How does demand response shape up to that, and do you see demand response as the marginal supplier?
Oh, hey, Grant, it's good. We haven't got there, I think is the simple answer. We're in the process of exploring arrangements with, you know, smaller industry that's decarbonizing. You know, whether we continue to get demand response in 2025, for example, from a peaking asset, or extend the existing arrangements that we've just entered into with Nova and Contact as opposed to engaging with those consumers. You've heard where we'd like to go, right? Which is we think consumer engagement in this market or customer engagement in this market is very, very important for its function and the transition that's underway. We are engaged with them as deeply as we can, but we just don't have that answer in terms of are they gonna provide the marginal source of demand flex in the short term.
In the long term, there's no doubt. You know, as that transitions to more of a residential demand flexibility as opposed to industrial demand flexibility, like we're considering for 2025, 2026. The technologies that are supporting that residential demand flexibility are exploding, and you see examples of them all over the world where consumers are getting paid for providing that service.
Thanks, Mike. Just moving on to solar. It appears from your competitors that the near-term economic risks are around securing land, which is getting more and more expensive, but Ruakākā, you seem to have in place. My question is around the Taranaki 200 MW options you've got in for the back end of this decade. Is that pushed out to the end of the decade because you are worried about the economics of solar, and it's not quite stacking up if you haven't secured panels and land at this stage?
It's actually just based on our view, if we stacked all the projects up based on what we know, Grant, from what we expect the costs to look like, and that's, you know, still some a large range of uncertainty there, where that one fits in terms of the merit order.
Thanks, Neal. The last question, I'm not sure whether you can answer this. This is on NZAS or keeping the smelter around. You indicated there's a large gap between the old contract and where you would think a new contract would sit if you wanted to play in that game. You have started negotiations with them. Is that commentary on large gap just about trying to highlight that 35 was? Or the old contract was a really deep discount contract and has nothing to do with your early conversations with them around a gap that's developed already?
No, I think I mean what I'll repeat what I've said previously, which is there's four conditions that we would consider, you know, working with the smelter beyond 2024. One is they do need to show that they've got a committed environmental remediation plan. Now, we're not gonna be the arbiters of what an appropriate plan looks like, but we will look to local council and iwi to inform us as to whether that plan is acceptable to key stakeholders. Two, we'd need to see a long-term commitment to New Zealand. You're talking, and I might have said 15 to 20 years, I think it needs to be at least that. We can't have this sort of one-year exit clause stuff. You know, managing that through Prudential will be interesting.
Three, we think because they are and they have been, and possibly will be, a large chunk of the electricity sector, they need to find a way to work more in sympathy with the electricity sector. That's where we expect the smelter to bring back demand response type options and ideas. There are some available to them. I think they are thinking about that more strongly these days. Lastly, yeah, the price needs to be more sustainable. The price in the staged exit deal was a cents in the dollar type transaction, as we've said many times. It's not something that's sustainable for the long term. It's nowhere near reflective of the marginal cost of new generation to support that facility.
You know, if there's an element of realism on the Rio side around what they actually have to pay for energy, then, you know, things might happen. If not, I think they'll struggle.
Grant, just picking up on your-
We're-
...just picking up on your last point. Two things. One, we've seen your numbers, so we know kinda your view on what a reasonable contract framework might look like. Two, really clearly, we're not trying to signal that there's a gap in any form of conversation with Rio Tinto. That's not what we're trying to say, today. We haven't had those conversations. If we did, and assuming we will, we probably won't share them in public. We'll work with them to see whether something satisfactory can flow from those conversations.
Yeah, that's a good point, Mike. I mean, conversations at a very early stage.
Thanks for that clarity, Mike. Early stage with a comment from the smelter or from Tiwai about a couple of months ago, wanting to have some certainty for Southland before 2023. Is that still realistic?
You probably have to ask them, Grant. Don't know if we have Rio on the line, whether we could open up another line. Hey, yeah, you know, it's like any. I think where there's a will, there's a way. You know, if people are serious about providing stability and security and confidence, then there's no reason why you can't get there. You know, we're ready. We know what we need to do. Neal just mentioned it again. You know, we've been pretty clear for the last 18 months, I think, what we feel reasonable looks like. Until we get into that conversation, you know, we don't know. As I say, you know, three months is a long time if you use it wisely.
Yeah. Thanks very much for answering my questions, team.
Cheers, Grant.
Cheers, Grant.
Thank you. Your next question is from the line of Stephen Hudson from Macquarie Securities. Please go ahead with your question. Thank you.
Oh, good morning, Neal and Mike. Thanks for taking the questions. Just first one from me, just on wind. Can you give us a feel for what your current mean wind generation is across your portfolio? Just noting obviously that there has been a bit of variability in the last sort of two or three years. Has there been any change there in your thinking?
Might have to get you the actual number, Stephen.
Yeah. Capacity rates have been about average, Stephen. We've had a couple of issues with one of the wind farms in particular, Te Āpiti, and we've just completed a half-life refurbishment, so we've got the availability rates at that site up from the mid-50s, they were languishing in the mid-50s for two years, up into the 90s. So, it's nice to have that done. But yeah, we'd need to go back and check, but we're not seeing, I don't think, I wouldn't call it a structural, but a climatic shift in the wind environment in New Zealand.
No, we'll come back to you with a number, but you can see-
Okay. No, of course. No, sure.
It's kinda moved between 1,100 gigs and 1,300 gigs per year over the last few years. Probably a little higher than that, possibly.
All right. That's useful. Just a second question on your OpEx post the Australian sale. Are there any sort of stranded corporate costs that are washing around there that you might be able to tidy up over time? I know you've given a lot of detail, Mike, for the OpEx for the coming year. I'm sort of thinking, you know, sort of two or three years out, are there any sort of costs that you might be able to strip out that have been stranded there post that sale?
No, I mean, not related to MEA, Stephen. You know, we've got two contracts-
Okay.
...in place with Shell, one for the Marsden Call Center and one with Flux. So, you know, subject to how they play out, we might need to make some changes, but you know, we're building a relationship with them. We hope they're interested in those products long term, so that might be one year. Other than that, there's nothing longer term that we haven't already worked our way through. We're in a bit of a transition, so we've got a transitional services arrangement with them over nine months, where we're providing them with a couple of services through the next couple, but largely done. No, nothing meaningful.
Just back on NZAS, it's been done to death, but can you just give us an update on potline four and the suspension of that line and you know what whether or not potline four's operation is obviously being rolled into negotiations and the chances of that coming back online?
It has come up in the initial conversations. So, you know, we'll see what that means for any longer-term arrangement. Again, you know, given it's been suspended now for all of 2022, most of 2021, and would only run through. It's suspended through October. I think it's unlikely that it comes back for those last couple of months. Again, I can't talk for Rio. The contract facilitates them bring that back to service for a couple of months, but. They could run it after that, but they would be running it, you know, on spot as opposed to contracted. We'll see. I'm sure it'll be part of a conversation.
Okay. Thanks, Mike. Last one for me, just on wind. Again, there's been a lot of questions here, but I don't think we've had a third for 18 months, and a lot of discussion about why that is. You've raised the domestic constraints that are operating, getting allowing wind to get away. Mercury raised the issue around some OEM capacity issues versus step change in demand. How relevant is New Zealand to the global OEM players in wind at the moment?
Well, we haven't run into that sort of capacity problem in the past. You know, the world's changing as we speak. Because we haven't gone into a tender process on another wind farm, you know, we can't make a firm call on that. I would have thought New Zealand would still remain relevant in a global context just 'cause of the quality of the wind resource here. We're always a, you know, iconic type project status typically attached to New Zealand projects. Look, why aren't more wind farms being built? Look, if I was being brutally honest, I think probably five to seven years ago, this industry lost its mojo around, you know, the likelihood of demand growth.
The world's changed a hell of a lot since then, and it takes a while, probably a good 10 years, to get a wind project from concept to understanding the wind resource through the consent process and then designed and built. You know, we took the foot off the pedal, not just Meridian, but the whole industry probably, like I say, five, seven years ago, and it's taking a wee bit of time to get that momentum back up. I'd say by the back end of this decade, we should be in full flow again. That's certainly where we intend to be.
That's useful. Thanks very much, Neal.
Thank you. There are no further questions from the phone lines. Please continue, gentlemen. Thank you.
Well, thank you all very much. Thank you for the questions. Hopefully, the analyst workload will reduce over the coming days 'cause big Wednesday is about the end of it, I think. Anyway, thank you for your attendance and good luck and have a great rest of the day. Cheers. Bye.