Good morning, everyone. Welcome to Meridian Energy's Interim Results Announcement for the 6 months ended 31 December 2020. I'm Neil Barco, Chief Executive of the company, and I have with me Mike Roan, our CFO. I'll start by touching on a few of the highlights. Operationally, we had a reasonably successful 6 months, but financially, the period was more challenging than the prior year.
We did deliver our 2nd highest level of interim EBITDAX. However, the highest level was last year and that was 9% higher. Mike will talk a bit more about that as he works through the financial performance. But in summary, the key factors impacting performance was our hydro inflows leading to lower generation volumes in New Zealand and lower wholesale prices in Australia. And when you stand back and look at it, I think it's reasonably clear that the electricity sector is performing well for New Zealanders.
We have a very reliable, mostly renewable grid, and importantly, residential prices are the lowest that they've been in real terms in the last 8 years. That suggests to me that there's a healthy degree of competition and choice for customers. And in the face of that competition, I'm very proud of our customer team's ability to continue to grow our retail share in both New Zealand and Australia, whilst remaining focused on supporting customers and financial hardship. Our customer numbers and volumes of energy sold were both up and prices also held well in New Zealand. A slight negative in Australia was that electricity prices followed the wholesale trend downward.
The project to migrate Meridian's customers onto the Flux platform is on track. But beyond the technology, I believe we're making really good progress in creating a lean and agile operating model that will ensure we remain competitive in the future. ANSYS. Last time an Aussie said to a KUE 4 more years, it was the cause of much despair in our country for quite some time. Fortunately, this time around those words suggested a much better outcome.
And whilst we now have time to progress our smelter exit mitigation strategy, we have no intention of taking our foot off the pedal. Obviously, the closure of the smelter will create room to service new demand and one of our responses has been to create a new 10 year product to support customers who choose to electrify their process heat. I expect to see some tangible sales progress this financial year. Also the opportunity for new large scale energy hungry demand in Southland is looking more likely than not as the proof of the pudding is in the eating, so time will tell. Needless to say, we're also very pleased with the progress Transpower is making, enhancing the grid in the Life South Island.
Now the certainty provided by the Ensis agreement, along with the confidence we're gaining in our mitigation strategy, has enabled our Board to take a couple of key decisions yesterday. Firstly, they approved the build of our $395,000,000 Harapaki wind farm, and secondly, they resolved to keep the interim dividend at a consistent level the prior year. Now the most significant and impactful thing marine can do to combat climate change is to efficiently operate our fleet of renewable generation assets and to build new assets. However, we are also very focused on managing our own carbon footprint and being an exemptor of sustainable business practice. In particular, we've made a commitment to halve our growth operational emissions by 2,030, and we're very focused on achieving that goal.
We've just sold the last of our petrol and diesel engine vehicles in our passenger fleet, and that feels really, really good. The next opportunity is to find electric alternatives for the utility vehicles that our hydro and wind asset maintenance team rely on, but we are aiming to be totally electric for the next couple of years. We are underway with our carbon sink project, plant 1,500,000 trees in the next 3 years. We've planted out hectares of our own land, and we're looking at both partnering with other landowners and acquiring additional parcels of appropriate land to get the 1,500,000 stems in the ground. I believe the rest of our SG reference points shown here are well established except maybe for process heat.
Now I mentioned earlier that we've developed a decarbonization product aimed at helping customers who rely on fossil fuels, mostly old coal boilers to electrify their heat processes. We're talking 10 year contracts, sustainable low pricing and a capital contribution towards the customers' conversion costs. We think the opportunity could be significant and could add an additional 250 to 500 gigawatt hours of demand into the system and I managed to sign our first MoU on that yesterday. So that's good news. You can expect to hear much more about this as we progress.
I'll call out one further project we have underway. We have committed up to $4,000,000 to roll down a new network of at least 200 EV chargers. The network will be comprised mostly of AC chargers as we're seeing strong use cases for this kind of charging network developing overseas. Also, the obsolescence risk is much lower than for DC fast charges. We have installed 12 to date, and we've learned a lot whilst establishing good capability.
We're now in a position to open the sales pipeline, which we pretty well pushed the go button on Monday. We believe certainly that we have secured with the 4 year end of this exit now will now shift this sector to a new phase. The industry is responding to high wholesale price signals with new builds. The absence of new demand growth means that these new developments will effectively displace existing fossil fuel based generation and it's happening because renewables are already cheaper to build and run. The age of the baseload coal and gas generator in New Zealand is just about over, and it certainly will be within the next decade.
New demand will also turn up. This country simply will not achieve its 2,050 net carbon 0 targets without scale electrification of of process heat and transport. As an industry, we have a lot more work to do to build the pipeline of new renewable projects large enough to meet the challenge. Certainly, a more flexible consenting environment will help with that. But I also think as an industry, we are getting ahead of the game.
Those of you who follow AGL in origin will be aware that the near term outlook in Australia is pretty challenging. The orderly function of the energy markets over there is arguably not being helped by the political intervention at both federal and state government level. But Australians do live in the same world that we do, and they must also transition to a new low carbon energy system over time. So for now, we believe that Australia remains a reasonable option play for Meridian. I'll now hand over to Mike, and he'll talk about the numbers in a little bit more detail.
Thanks, Neil. As you mentioned, we've had another strong 6 months. While EBITDA fell from record levels in the first half of twenty twenty, it remains the 2nd highest interim print for our business. The net profit after tax result was also pleasing up 19%, but as net profit after tax or NPAT includes an uplift of $88,000,000 from derivative and interest rate fair value movements that suggest a lift in cash in later periods. I tend to think of NPAT as a secondary indicator of current period performance.
My key measure, operating cash flows fell from $266,000,000 last year to $187,000,000 this half, largely following EBITDAF. But it did get thrown around a little as we made the final tax payment from a bumper financial year last year and at $187,000,000 is still a strong level of cash production for our business. Even though EBITDAF and operating cash flows fell, they continue to support consistent levels of ordinary interim dividend payments. Yes, that means we'll pay an ordinary interim dividend of $0.057 per share again that is imputed at 86%. This might be getting a little monotonous.
This is the 3rd year in a row that the interim dividend has been set at this level. But just like last year, when I said that a repeat of the fin year 2019 interim dividend seemed like the right approach, this feels like the right decision again this year. We have, of course, resolved the uncertainty that drove our thinking last year, but doing so has come at a cost. And as you will have noted from our market release this morning, we're also investing just under $400,000,000 into what will become New Zealand's 2nd largest wind farm. So it's a balancing act when it comes to affordability.
To be clear, we don't expect material constraints in relation to dividend payments. But as I noted during the Envis investor briefing in January, we are working through our choices pretty carefully to make sure that shareholders not only see benefits now through strong dividend flow, but also that our balance sheet is flexible enough to manage future opportunity and risk. With this in mind, an option that Meridian is considering is the introduction of a dividend reinvestment plan. No decision has been made on it yet, and investors shouldn't expect that it will be introduced as we continue to work through alternative choices. And investors will be notified in the normal fashion if a decision to proceed is taken.
But given these moving parts, maintaining that interim ordinary dividend seem prudent as it doesn't signal anything in particular. So on to New Zealand energy margin. By now, you should be used to this waterfall chart. The first thing to note is that New Zealand energy margin fell by $58,000,000 when compared to the first half performance last year. As this explains the majority of the group EBITDA fall, it is useful to go into what happened.
So starting at the left, customer revenue actually increased by $69,000,000 reflecting ongoing growth in customer connections and prices. This was superb and follows on from what we presented last year, a focused and capable customer team at work. At the same time, generation spot revenues lifted, but total production volumes were down by 5 11 gigawatt hours on last half year, and this largely accounted for the fall in energy margin. Of course, and as you can see, the cost to supply customers lifted faster than customer and spot revenue, but our relationships with customers will endure, where spot revenues can be fickle, so we like our underlying positioning. Finally, the cost of derivative sales outweigh the value they created.
This is something that our wholesale team always works on, but there isn't much of a story here as some of the transactions that make up those buckets risk trades. So moving on. This slide builds on the customer growth story. We'll continue to grow our customer base we continue to grow our customer base successfully, both in terms of numbers and average price paid, which reflect the hard work our customer teams put into our brand position, product propositions and relationships. Specifically, our PowerShot New Zealand and Meridian customer teams lifted customer numbers by just over 9,000 in the 6 months across the residential, small business, agricultural segments while growing sales price.
The same direction of travel played out in the corporate and industrial segments with volumes sold and prices back lifting. And as New Zealand retail electricity market is amongst the most competitive on the planet, that's quite a feat. To reflect on the comments that Neil made at the start of our announcement, the Kiwi households are paying less for electricity now than they were 8 years ago in real terms, suggests our retail brands are in good health. This slide builds on the production point I made in the energy margin slide. In the first half of the year, we produced 6,676 gigawatt hours, which was 5 11 gigawatt hours lower than the previous comparable period.
The reason for this was twofold. 1st, production volumes in the first half of last financial year were the highest we've ever seen, so maintaining that run rate was always going to be a challenge. 2nd, storage in Lake Pukaki started the 6 month period lower than we might otherwise wanted, and it ended the period well below average as well. While that piece isn't as obvious on this slide, if you look at our monthly operating reports, see what I'm talking about. Now if you look at the combined catchment inflow graph, you'll see that in July August inflows were about average, so we couldn't build storage or generate large volumes.
And while inflows in September October look significant, unfortunately, the storm that arrived was too large to catch and we had to spill 255 gigawatt hours of energy past our power stations rather than use it to excite electrons. Those inflows were useful nonetheless as they lifted Lake Storage back to more normal levels, but then we ran into November, December January. One way to think about inflows during that period is that they were half of the inflows experienced over the same months in the prior year, a bit of a bugger for a business that relies on them. That said, and as anyone who relies on the weather knows, it never gives you quite what you're looking for. So our job is to deal with the swings and roundabouts.
And given our interim results strong, we are pretty happy. But the reason I'm slowing January 21 on this slide, even though it's not part of the interim period, it's important that you know that the Southern hydro lakes haven't had the rain they might expect so far this summer. We typically rely on 3 to 4 storm events to fill those hydro catchments, and so far, we've had 1. As our January operating report showed, we're currently biding our time and waiting for the next one. So production volumes and revenue will be lower than we hoped until the next storm system arrives.
This isn't unusual. It just reflects the business we're in, and we carry a strong balance sheet to make sure we can provide dividend stability even if and as operating cash flows go through a drought of their own every now and then. Everything reverts to average over time. And for those who think I might be trying to signal something, I'm not. I'm just stating the obvious, we're waiting for rain.
The graph on the right is fascinating, or at least I think it is. We had strong growth in customer numbers in Australia through April 2020, and then that growth slowed materially. If we had time, I'd ask you why you thought that might be, but you're probably already there. Yes, it's COVID. Our Aussie mates were locked up right for an extended period, and while they had time on their hands, obviously spent it doing things other than thinking about switching electricity provider, which is actually interesting as average wholesale consumption grew by about 20% during their lockdown period.
So household costs would have gone up materially while they are thinking about those other things. Anyways, growth in customer numbers since April was lower than we wanted, but remember our team in Melbourne have been in lockdown and working from home for nearly 12 months now too. So they're doing it tough. Regardless, they remain focused on lifting that run rate while maintaining the positive progress that you see here. So a quick thanks and shout out to them for their commitment and the humor they showed during the tough times.
Energy margin in Australia in the 1st 6 months fell by $6,000,000 when compared to the first half of twenty twenty. While customer revenues in both electricity and gas segments lifted by $11,000,000 this was not enough to cover the material fall in wholesale prices experienced in Australia that Neil mentioned. And while we run the business in a similar way to New Zealand and that it's vertically integrated, we do like to run a little long to account for changes in hydrology. So this length was sold into prices that were lower than expected. I won't go into a soliloquy here about wholesale prices in Australia.
Rather, if you're interested, I recommend you read the transcripts from the large integrated Australian Electricity Businesses' interim announcements. My summary here is that they have massive incentives to find a solution to these wholesale price outcomes as they appear unsustainable from their perspective, and we should be beneficiaries of any adjustments that they have to make. While the work goes through, we'll continue to focus on customer growth and balance in our portfolio, while recognizing that if it takes time that these low wholesale prices could reduce energy margin in Australia more directly in FY 'twenty two as hedges roll off. And all this played out as Green State hydro catchments finally filled up after a multiyear drought. Regardless, we continue to like Australia as a place to invest as its long run decarbonization prospects are similar to New Zealand, and we want to ensure we're positioned to benefit from that adjustment without taking overarching risk.
Put another way, while EBITDAX delivery in Australia might be volatile in the short term, we'll continue to manage risk by being reasonably balanced between generation and retail while growing the business over time. Last, the eagle eyed of you amongst you, which probably sums up everyone on the call, will have noticed that on the previous slide, contracted sales revenue fell by $5,000,000 while on this slide, I noted that electricity and gas sales to customers lifted by $11,000,000 The difference is $16,000,000 in financial contract sales that were not made this year as compared to last and are bundled into this slide as part of the financial product set. I thought I might as well get ahead of any questions on that one. Nothing too much to note on operating costs. Back in August, I suggested that operating costs would land in the $261,000,000 to $266,000,000 range in the financial year.
That continues to look like a reasonable forecast given the $126,000,000 spent through the 1st 6 months. One thing that I did say that might be worth picking up on is that we were looking at our cost profile carefully, primarily in the generation maintenance and project space as given Envis' decision to terminate our contract effective August or 31 August 2021 at that time. I also noted that if it played out that this could result in material falls in OpEx. However, given the amended contract that we'll see Envis stay through December 24, those changes no longer make sense. So I don't have much as much to say on this front as I thought I would back in August.
That said, we do remain focused on operating costs given the expected revenue associated with that relationship is reduced by close to 40% over the next 4 years. And another thing I thought I'd update you on is that we continue to carry a reasonably large provision for doubtful debts. If you remember, I noted that we had lifted the provision from $5,000,000 in fin year 'nineteen to $15,700,000 in full year 2020. That provision still sits at $13,300,000 in the interim statements. And the last point I'd make is in relation to the CapEx forecast.
We noted that we expected to spend between $70,000,000 $80,000,000 this financial year, possibly a little more depending on what played out. I can now say that CapEx will likely land at the top end of that range this year largely due to the fact that the migration of customers from the Velocity platform to Flux is going well, as Neil had mentioned, we expect the majority of that spend to land this financial year. Neil will talk to this in a bit more detail as well in a bit. So what's it all mean? Largely repeated what I said at the outset.
We're the 2nd highest level of interim EBITDAF in the first half of this year. It was down $43,000,000 or 9% on last year, but that was to be expected. So we're pretty happy. That said, as I also mentioned earlier, the second half is off to a slow start. January landed with a bit of a thud and our wholesale team continues to exercise the financial contracts that we have to manage risk when it doesn't rain.
So we'll see where we land at year end. And going back to the start, for the 3rd but last time, NPAT lifted by $36,000,000 this half. We don't see that out specifically on this slide, rather we focus on underlying net profit after tax, which is the non GAAP measure. We do this as we feel it's useful as it strips out the non cash fair value movements otherwise captured in net profit after tax. You can tie it on the measure that works for you as to present them all in our financial statements, but the graph here shows that underlying net profit after tax fell by 28,000,000 dollars which is 15% or 15%, which is consistent with the fall in EBITDAF, another non GAAP measure.
Now I don't have a slide on the balance sheet this time around, largely as there's little to be seen on this front. But I would be remiss if I didn't go back to the Fin year 2020 announcements where I noted that if Enzu exited in August 2021, that we'd likely see a reduction in the value of our New Zealand generation facilities possibly by between $690,000,000 $1,300,000,000 The world has played out differently, which is great news, so there is no change to the value of our New Zealand generation facilities to announce. And that seems like a good place to finish. The agreement with Envis has created a really solid platform from which we not only need to restore, but grow earnings from. It takes some hard grafts to do this over the next 4 years, but that's what we're here to do.
We know that you've sacrificed short term earnings to do this given the lower contract price, but we can assure you that it's a far better place and stronger position to be in than the counterfactual. And of course, I back us to do just that, restore and grow EBITDA levels as we work through the next 4 years. Neil, back to you.
Thanks, Mike. I'll now touch on a few key elements affecting the market and regulatory developments as we go. So aside from the current dry period, which remember is part of impassable of a hydro based system, the main dramatic in New Zealand building is tension in the gas market. Well, delivery from Powacora field from Powakora field is often the reference point on the supply side, a number of other fields appear to have also passed their production plaipos and entered deliverability decline. Gas demand is concentrated in a small number of large industrial users and they are facing an uncertain future.
The decisions that Methanex make and they are by far New Zealand's largest energy user will have major implications. Now the electricity sector needs gas and coal and or coal as a firming solution for at least another decade. So finding options to provide the upstream gas players enough certainty to continue to invest in a reliable level of service is a challenge that we all need to get our heads around. I personally believe a market led approach will achieve that and ultimately the market will deliver a diverse and efficient range of dry year firming solutions that will reduce our dependence on fossil fuels. An example, Meridian is looking at the possibility of a flexible hydrogen production plant that can reduce electricity consumption during dry years and sell that demand response as a service to the market.
And there are other ideas built bubbling to the surface. But there are plenty of skeptics, and I've seen some unease with our current governments, fair enough. So our industry will need to demonstrate progress sooner rather than later. And the abrupt nature of this country's level 4 lockdown and the ongoing economic impacts weighed on electricity demand in 2020. I think we were all surprised with the bounce back and the recently firm demand following that level 4 lockdown.
However, not surprisingly and given how COVID has changed our lives, demand was characterized by higher residential and lower business demand. All that though, it's difficult to draw any conclusions from the actual demand observed in the recent past to what we might expect in the next few years. Last year, the uncertainty relating to the future of Ensis forced us to pull back from the start line on our Harapaki wind option. And following the Ensis deal in January, we tasked the Harapaki team to reconstitute the business case Quick Smart. They've done an awesome job doing just that and we were able to present the business case to our Board yesterday, which they duly approved.
Harapaki will be New Zealand's 2nd largest wind farm and is located along the Maungakuru range just north of nature. Project has strong economic. It's a great fit for our portfolio and will support future retail growth. Also working with our suppliers, we believe we will produce the most sustainable wind farm in New Zealand to date. And I'm personally quite chuffed about this one because I hail from the Hawke's Bay, and this will undoubtedly help boost the local economy and create some jobs.
Harapaki will be Meridian's 10th wind farm development, and it will bring the total annual energy production from those farms to 3,800 gigawatt hours and total carbon abated to between 2,000,000 3,800,000 tons per annum. We've learned a lot from each of the previous projects, so we are confident in the economic projections for the wind farm and also our ability to deliver it as planned. We intend to host investors at the site in May, and you'll hear more from Arne on that shortly. Now the team will now get on and get it built, and we'll continue to focus on deepening our future development pipeline. We're also moving forward with a couple of development options in Australia.
Having a robust capacity firming strategy in Australia is pretty fundamental, which is why we have been progressing battery augmentation at the Shipton Hydropower Station. The battery now has development approval, and we're hoping to bring an investment decision to our Board later this year. The Rangoon Wind Farm development is in the process of gaining development approval also and any investment decision will likely not be till about 2022. Like New Zealand, our relative our vertically integrated Australian position is tilted to a long generation position. So the future success of our organic retail growth strategy and Australia has a bearing on the timing of some of these new builds.
The Electricity Authority completed their investigation into the wholesale electricity market during the flood events of December 2019, and they concluded that confidence of factors led to a highly unusual period of wholesale market activity and as a result an undesirable trading situation or UTS occurred. The next step is for the authority to consult on how they want to correct the UTS and they'll probably do that later in March. If they choose to reset prices for the UTS period provided that process includes resettlement of hedge contracts and in particular, the ASE Futures products, then we estimate Meridian's bottom line for that period will be reduced by less than $2,000,000 You may recall that we took out $5,000,000 provision on the account as of 30 June 2020. We welcome the Climate Change Commission's draft advice on the need to increase our national effort to tackle climate change and in the Commission's words, lock in net 0 by 2,050. It's very clear that electricity sector is a big part of the solution to reducing our country's emissions.
I've touched on my following points already, but it is telling that as of today, there is around 2,000 gigawatt hours of new wind farms either being built or about to be built in New Zealand and about 1300 gigawatt hours of geothermal is also committed. These developments tally to more than 7.5% of total electricity demand in New Zealand, yet over the last decade, we have seen virtually no growth in demand. So all these new developments will displace existing fossil fuel based generation because renewables are already cheaper to build and run. The growth in renewable energy does create challenges that need to be overcome. I mentioned that the reliability of the gas system will require further investment at a time when we are busily trying to migrate away from it.
We also need solutions to manage hydro storage in a dry year without gas or coal. But most critically, in my mind, we need to dramatically speed up the consenting process for the massive amount of new renewable generation transmission and distribution assets that we collectively need to build. So I think these challenges are certainly not insurmountable and some of the solutions are starting to emerge. I'm no doubt that with RMA support from the government, our industry has the capacity, the capability and the innovative chops to build the renewable generation required to decarbonize the bulk of the energy sector. And most importantly, we will do it cheaper than ever before and faster than we previously imagined.
We simply must. Our job at Meridian is to ensure we do our bit. As a rallying cry of troops, we remain committed to a target of maintaining our market share of grid scale generation. And if you do the math, that goal is actually a bit more exciting for our team than what it sounds. We gave the Enzo story a good a fairly good hearing last month, but we'll leave it there for now.
Suffice to say, we will ensure we keep the market well informed as to how we progress with our Enzo exit strategy, and that's laid out on the slide consistent with what we showed in January. After lingering uncertainty following big shifts in the UK retail electricity landscape, E. ON have committed to closing PowerShop UK. The termination agreement with E. ON secures Flux UK revenue stream for the next 2 years, but we do expect to complete the migration of PowerShop customers onto E.
ON's new system hopefully by September this year. 80% of our customers have now been migrated to the Flux platform and we're now starting to move our more complex billing and time of use customers. The scalability and usability of the platform is proving better than we anticipated at this stage. So while Theon have chosen a different path, we are still confident Flux offers a unique and advanced solution to energy retailers and Nick Kennedy and her executive team now have the clear ear to focus on marketing their product internationally. I'll just wrap up with a few closing comments.
I think we remain very pleased with the customer growth we're achieving and the work we're doing to transform our retail operating model. There's still a lot of improvement possible and necessary if we want to remain competitive, and I can assure you we do. January February have been parched in our South Island catchments, and the outlook for the next few weeks at least also remains dry. Accordingly, we are working to conserve lake storage, which along with the new Ensis pricing will have a dampening impact on our second half earnings. Analysts will have seen our January operating report for our generation volumes were down 19% on the prior year.
That's just the nature of the game we're in. And as Mike pointed out, that's also why we run a reasonably conservative challenge. I've made my views clear on the Climate Change Commission's draft advice. To my mind, it's a bold pathway this country needs to take to achieve the low carbon future we must aspire to. I believe the electricity sector with a little RMA help can handle all the demand thrown at it, and the technology is improving at such a rate that we'll do it cheaper than in the past.
We will probably see significant wholesale price volatility at times as new firming solutions emerge, but there is nothing in my view to suggest that the electricity market as it operates today cannot meet New Zealand's needs and support the imperative to lock in net 0 by 2,050. Thank you. That's a wrap from us. We can now move to questions. And I think we'll start by taking questions from anyone on the floor and then we'll move to the
Good to be back in the room. And no questions on the smelter, I think, for a change from that's good. Just a couple of quick questions really. In terms of your Australian growth profile around the wind, I'm assuming I'm just taking what you're saying that in essence, you're looking to basically bank the growth in Australia, you're not looking to
sell to other parties.
Yes, Andrew. So can if anyone on the floor has a question, just announce yourself too just for the people on the call. But that's Andrew Harvey, Greg, as you probably picked up from his thoughts. Yes, that's right, Andrew. We're running a retail led vertical integrated strategy.
So our ability or our success in growing our retail business will very much drive the requirement to supplement that with Generation Development. It won't perfectly match the whole way through, of course, but that's the nature of what we're trying
to do. Okay. Next question is just around Flux and I guess just understanding the changes that are going on in the UK. Obviously, you had some exclusive relationships there, which prevented you from marketing that further. I mean, what's, I guess, the degree of confidence around the ability to find an alternative party or parties that might take on flux?
Yes. As part of the wind up negotiation, the exclusivity is now lapsed. So we can market to other parties straight off. We do have and based on the development we've done in New Zealand, particularly in the C and I and complex billing into the market, we think we've got a pretty compelling and unique proposition that covers all market segments. So more work to do, and we certainly don't have a sale on the books today, but that's the focus for Nick and his team.
Reasonably confident, probably also in Australia, there's opportunities that are going to emerge. So we'll see how we go.
And just last question from me. Your 2 competitors who announced over the last week or so both talked about interest in the Trustpower retail assets. You're most pretty absent in talking about that. Do you have any comments around that and any interest?
Well, if we did have an interest, we would have signed an disclosure agreement, so we wouldn't be talking about it. But we've been reasonably successful growing our retail business organically. We think that's probably the smart way for us to progress. But look, when assets like that come onto the table, we always have to think about it. And yes, so we'll see how that plays out.
Hi, Tim Mowbray, AMP. Just on the Harapaki wind farm development and any potential development. Can you just as you have to kind of give a bit of an overview on timing of the spend on it and potential funding in terms of cash flow, debt and also lead on any other potential future generation development, what the lead in time generally from, I guess, decision made to spend the beat, trying to get a overview of spend over the years in funding? Yes.
So payments actually flow either today or tomorrow, having completed signing of contracts to get the major vendors underway. And then payments are staged, dollars 3.95,000,000 of payments staged over the next 36 months, right? So depending on specific milestones struck. And as I kind of I did in my answer there, I said that we expect First Power about a year before the wind farm comes online. So if you kind of jump 36 months from now, early, mid-twenty 24, so a year before that, we expect 1st power.
And in terms of any comments in terms of funding that's cash flows, debt in that or clearly?
We've got adequate facility balance sheet funded as we are. But as we as I noted when I was talking earlier, we are looking through balance sheet flexibility and what mechanisms we might want to support the delivery of not just that wind farm, but as Neil mentioned, we've got a couple of options out of Australia and obviously looking at other things in New Zealand. So we're thinking those through pretty carefully. The one that I mentioned here was dividend reinvestment plan. But until we actually finalize, confirm the approach that we take with the Board, it's probably not too much more to say right here.
I think you asked a
question about the life cycle of Yes.
Look, I think rule of thumb, it's usually about a 10 year cycle from an idea through potentially sticking a shovel in the ground. Some of that's involved in just understanding the wind resource, organizing landholder agreements and so forth. But then the consenting process is also very protracted in New Zealand. So that's why we're quite hopeful that the RMA reform is currently underway that we'll get a bit more of a streamlined process for these renewable projects and bring that 10 year sort of time frame forward. We do have a few couple of wind farm options that are far more progressing in years.
And just a bit more cover, if we look forward to the sort of demand growth we think is going to be required to decarbonize the energy sector in this country And the amount of new renewables needing to be built, we're planning on an outlook where Meridian is building new wind farm and delivering it every 3 years.
Thanks. Neville Goliath, Jarden. Three questions from me. Just on Harapaki to start with. The cost per megawatt hour or cost per megawatt has been higher than I might have expected.
And I'm wondering whether or not there's any kind of COVID impact in the CapEx and or timing to think about when we look at potentially other future wind farms, are they likely
to be high capacity factors?
I just wonder if you could give us any color on that.
I guess it depends on what you're expecting there in terms of unit costs. I think the way I'd frame it is our unit cost has gone up marginally since we looked at it last July, August, but that's only because of the identification of some risk that was always going to play out in the project, primarily support risk. And so we feel pretty comfortable with both number in terms of unit costs and numbers that were released in terms of overall spend for the wind farm. We still see it at those sorts of levels. We see it easily in the money.
So there were some shipping cost increases and split up at the margins. So good news last night, we managed to lock in the currency at a reasonable gain. I'm not going to let the team have those contingency. So the headline price will drop a little bit.
Another way to phrase that question is you see it as competitive with future wood farms to follow from yourselves competitors?
Yes. I think certainly in the sort of $60 to $65 range is no reason to suggest that the value of wind farms, the cost of wind farms will be significantly higher than that. And as you know, the technology is getting bigger. It's making us more available for sort of Level 2. Sorry, it's Class 2.
Class 2. So you can get more generation at a lower capacity factor cheaper.
Great. Thank you. Next question on the 250 to 500 gigawatt hours of stimulation in South Thunder and boiler conversion or industrial heat conversion. You talked about a contract product, sounds very interesting. How should we as analysts think about it in terms of pricing and perhaps your share of the capital involved?
If you got to the $250,000,000 to $500,000,000 what kind of range of capital should we expect? And if we're trying to estimate pricing, is it somewhere above where you've signed the extension deal for business but below where St. Northland C and I is trading today?
Yes. My notes originally said sustainable NCS type pricing, but then we realized that the NCS pricing has changed quite a lot. So we're talking about pricing consistent with what Ensis were paying before they canceled the contract. So it's pretty compelling, I think, and it looks like it's a price that's good enough to get a number of customers to motivate and the cost in line so that they can actually do the conversion. In terms of our capital contribution, it's going to vary by each instance, so we're not trying to put a firm number around it.
But certainly, anywhere, I don't know, probably south
of $10,000,000 Great. Okay. That's really clear. Thank you.
Just the last point, with an extraordinarily high forward curve for the next 4 years at least, you marked your comments about retail pricing, in terms of your own recovery, dollars 5 anigawatt hour by C and I in the mass market channels. Should we expect that trend to continue, do you think?
By wholesale prices?
The flow through to retail pricing in C and I and mass market.
Look, I think we all look beyond the immediate wholesale market that we're seeing and that has been driven by, as we know, concerns and constraints in the gas market. We're hoping that some forward investment starts to resolve that. But certainly, also this build program that's been announced with ourselves and our competitors must have a softening impact on the forward price curve, I would have thought. So I think long term, I would not expect to see significant change in retail pricing in the country because the underlying economics won't take you there. So maybe to expand
on that one, I think you're suggesting perhaps the market will look forward to an end of 2024 exit of Enzo and sort of do some kind of averaging between then and forward curve now?
Yes. Look, the market discovers the price of the market discovers. That would that's a logical suggestion, but that doesn't mean to say that will have play out like that.
Analyst predictions are always wrong.
Very good. Thank you. Everyone okay? So we'll take questions from the phones now.
Certainly, sir. We have a question from the line of Grant Swannepo from Jordan. Please go ahead. Thank you.
Good day, Grant. We can't hear Grant. Okay.
We'll go to the Can you hear me now?
There you go. Yes.
Flex IT system changeover? Yes. Grant,
the connection is not good and we only picked up the end of that. I suggest you find another line and try calling in some other way. Okay. Will do. There he was.
Okay. Your next question is from the line of Stephen Hudson from Macquarie. Please go ahead. Thank you.
Hi, Neil and Mike. Can you hear me okay? Yes. Just a couple from me. Perhaps 2 for you, Neil.
On Envass, and look, forgive me, you may have actually covered this off post the January announcement, but I think on the spot, aluminum and aluminum premiums, the small city generating around $300,000,000 of a unit. And as you've previously pointed out, it's positively leveraged to New Zealand and global carbon prices. So I guess my question is why do you why are you sort of convinced that the smelter leave in December 2024? That's my first question. The second question really for you is around the wind development team that you've been carrying for the last 10 years.
I think
with decent hindsight, that's proven to be the right decision. Can you give us an idea of how big that team is? And can you contrast that with perhaps some of the other development teams out there? And then a quick question for you, Mike. On hybrid capacity, can you give us an idea what that is and what your current tool on hybrid level is?
Okay. Thanks, Stephen. So yes, on ANZUS, I guess the point is they may, in fact, not close shop, but what they but they lose the option to buy energy at least off Meridian. So our mitigation strategy is very much focused on building alternate sources of demand and also sources of demand that we think are more aligned with the decarbonization efforts for our country. So if we're successful on that, then they will struggle to, I think, get the sort of firm pricing commitment from the market that they've enjoyed today.
And certainly, if our strategy is successful, the pricing that they're getting for the next 4 years is in no way sustainable. It was a deal struck to buy a bit of time for Southland for the economy and for the industry to manage the exit in orderly fashion. That's not sustainable pricing going forward. I'll just add one more comment in case anyone from Envis is listening. I think the only way they could continue to operate in this country would be if they got serious about providing reasonable demand response to the market.
They have the capability. It's a very valuable part of well, a very valuable solution for the industry, and that would be an angle for them. But certainly, they've lost the option at this stage. I think you're right. They are making a lot of money for the next few years, and we hope that they invest some of that in tidying up the site.
As a New Zealander, that really does need sorting. On the wind development team, thanks for recognizing that, Stephen. We have carried the team or we've kept them very busy. But just to give you an example, the project director on Harapaki, the project manager and the chief electrical engineer were all involved in Teuku and Mill Creek, our last two wind farms. They've experienced a lot.
They're massively capable guys, and that gives us a lot of confidence that we will deliver that project to the plan. And we've also we understand the risks very well within it. Beyond that, the team is probably another 3 key individuals that are very, very that have good IP, particularly around modeling and understanding wind results, which is really when you're looking and working out the levelized cost of generation from these things, the amount of wind you get has a big bearing on what that actually turns out to be. So we spend and have developed a lot of IP in that area. So I think the team that core team, I would call it, are about 6 individuals and are all deployed on Mill Creek sorry, on Harapaki.
Hydro capacity, Steve. And just so everyone knows, I'm simply reading from the daily hydro summary that comes out, right? So anyone wants to grab the figures, they can do the same thing. But it's interesting, at least I think it's bloody interesting. New Zealand storage sits at about 74% of average.
I'll use average numbers. I can talk about percentage is full as well. South Island storage about 71% and our storage facility, Pukaki, 65%. So Pukaki is a little less full than average storage. Interesting, North Island's at 90%, but gives you a sense of how small North Island storage is compared to South Island storage.
The bit with droughts that gets more and more interesting is, 1, your storage level, but 2 is what sort of inflows are you receiving? And the inflow level is probably as interesting as the storage level at the moment, Stephen, is we're getting inflows into the wire, which is Fiordland, that's just under 30% of average levels right now. And it's been dry down there for a bit. As I say, of course, there's a bit of a storm system going on down there, which touchwood, let's hope it rains more than the forecast suggests. So it's reasonably dry.
But you're hearing that now from other circles as well as it's not it doesn't only affect hydro storage obviously, it affects drinking water and water in your garden. And you start to hear those stories at fixed farming on the East Coast and South Island. So we're pretty careful, hopefully, as you've picked up over the years that both the balance in our portfolio and the way we manage our storage can manage our way through those. The obvious impact is on our revenue profile. But as we've I think both said this morning is it's part of the business that we're in really and we carry a good balance sheet to work our way through whatever Mother Nature's got to throw at us really.
And Mike, that is actually useful color. It's you possibly misheard my question, and that's my fault. The actual question was about your hybrid capacity or your debt equity instruments.
I got the equity.
That received equity recognition, understandable, it was framework. So that answer was useful.
Steve, apologies. I must be the only one in the room. Everyone's looking at me like I'm crazy. But our hydro our hybrid capacity, balance sheet capacity, we're working through at the moment. So you can look at our balance sheet metrics and look at our S and P ratios and requirements and work out if we're spending just under $400,000,000 on a wind farm, what it might mean for any form of hybrid instrument alongside considering things like dividend reinvestment plan.
So we could take on a few hybrids if that's the choice we decided we needed to make.
Yes. That's very clear. Thanks. Thanks, guys.
Thank you very much. Your next question from the phone is from Peter Wakeman. Please go ahead. Greetings. I just wondered what you sort of see with the planning with Genesis and Mercury and the future plans for the possibility of Menapuritiana power making its way up to Auckland?
Do you have a crystal ball on that possibility long term?
Well, Peter, first thing I would say is, and you might need to rephrase the question, I've got a bit of a habit of missing the point, but the power obviously from the WAO obviously does flow into Auckland at the moment. I'm guessing you're talking about augmentation via the HVDC connection from Southland to Auckland. Is that what you're thinking?
Exactly. And all the other things connected with wind farms and just the way the connections happen at the moment in the future?
Yes. I mean that has been muted, a new high voltage cable between Southland and Auckland where most of the customers are and where there is a brilliant wind resource. That would be, in my view, a nation building sort of decision, quite visionary. So I'm not sure if it's on TransPower's to do list just yet. But certainly over the next if you're sort of thinking over that 30 year time frame, Peter, that sort of transmission capacity, I think, would be in New Zealand's long term interest.
But with the point I'd make about transmission, I'll make it to anyone who listens, it's the single biggest enabler of competition in our market. So it is important that the transmission has kept up to speed with new developments. Ideally, they're a wee bit before new generation gets built so that that enables all the generators to compete hard against each other, which ultimately gives you a much better outcome for New Zealanders.
And batteries, do you think a lot of people will be going into batteries for that purpose?
I think I'll just we have
been looking at a battery ourselves in terms of when Ennsys leave and we've got surplus supply of energy in the Lower South Island, assuming we haven't soak that up with new demand, there's transmission improvements that can get the energy out of the Southland region, then you run into constraints on the HVDC and potentially north of Wellington but sort of south of Taupo. And a battery, something of a large scale 100 megawatt type battery can provide, if you like, further capacity or reserves that allow you to increase the capacity on those transmission lines. So that gets really quite interesting so that we get the most out of the transmission that's already in the ground relatively cheaply. Yes, that's certainly an option. That's a live option for us that we are progressing and I expect us to do just that and build that within the next 4 years.
And going forward with people's private finances and provisional bad debts, percentage wise, retail versus commercial, what would be the percentage as a total?
It's Pete, you got me on the fly. I have to do the numbers. I have to grab a calculator. But as I just said, it's like the kind of carrying provision we've got at $13,000,000 on a customer kind of set of contracts that sits over a year, just $1,000,000,000 or $1,300,000,000 off my head. So the level of provision that we're holding for bad and doubtful debts is particularly low.
And on
the level
sorry, Pete, I'll just add to that. The level of bad debt we experienced is very, very low. And since you give me the opportunity, I'll just point out that Meridian does have the last disconnection rates in our industry as well and has done for quite some time. And that's not accidental. We have an awesome team that works specifically with customers and hardship and vulnerable customers.
And we think they do a bloody good job and get us good result and get those customers a great result.
Yes. I was only looking at the future of income people with high levels of unemployment with COVID retirements and the CPI, the inflation rate really not measuring the cost of living increases as opposed to reduced prices for cell phones and big TV. So I'm just saying that the payments the government make and pensions don't seem to be keeping up with the cost of living, yet the power price seems to, as you've seen earlier, have come down. So I was just concerned about people's financial ability to continue that. That was my main area.
And I was trying to ascertain private versus retail customers just as a barometer of what the trend is, New Zealand versus Australia?
Look, Peter, I think we've all got views in terms of people and hardship in this country and the level of poverty that none of us would be comfortable with, I suspect. But it's the electricity industry, we will do what we can, but the levels of income and housing quality and things like that have a big bearing on some of those aspects. But anyway, I think we've got to move on because I know Thank you. Thank you, Peter. I know Mr.
Swanepo will be out there somewhere trying to get another line.
Thank you, sir. Your next question is from the line of Cameron Parker from Craig's Investment Partners. Please go ahead. Thank you.
Hi, guys. Just a couple from me. Look, how should we be or how have you been thinking about Haripaki's offtake agreements or PPAs? And do these potentially relate to what Genesis is running in terms of its program? And also just with regarding to the sort of termination of the swaption, any update on that yet?
Hi, thanks, Cameron. No intent on PPA ing off the back of Harapaki. I think you heard us say we've our customer team has done a phenomenal job of growing our business organically. And we at least our portfolio analysis is that we'll soak up that energy for our own use at the rate that we are growing. So of course, we're always open to any form of commercial arrangement that makes sense for Genesis or anyone else.
But for right now, we haven't had strong enough interest in a PPA off the back of Harapaki and our portfolio growth says that we can use it ourselves. So it follows that vertically integrated proposition that we mentioned for both New Zealand, Australia. In terms of swaptions, there's no real update. We've reinitiated the RFI that we started back in 2018. We haven't made any calls on that as yet, but we're just working through with the counterparts that might be able to provide a product to us or not.
And those counterparts, your traditional counterparts through to, as Neil mentioned, conversations with demand side and possibly if they find interest in that demand product and solution. So we don't know where it will land yet. We know we've got some time to land it and we're pretty comfortable that we've got a suite of options that if we can't complete in a traditional sense that we can manage that risk anyway. So we'll see where it goes.
All right. Great. Thanks guys. That's all for me.
Thank you very much. Your next question is from the line of Grant Swinopold from Jardan. Please go ahead, sir. Thank you.
Yes. I'm back. Can you hear me this time? I'm very proud.
Brilliant. I
have a quick question. Just on operating costs. Are we still on track for about a $10,000,000 benefit from the Flux system IT overall? Yes. For next year or the following year?
Yes. For next year, I think the benefits were a little larger than that over time.
So some of those costs benefits were avoided CapEx in terms of maintaining systems or upgrading to alternative supplies as well, Graeme, but we're pretty confident we're seeing the value already starting to emerge, to be honest.
Fantastic. And then just following on from Cam's question on PPAs. The big catch point in the industry appears to be when Enzys leaves. Are they considering negotiating with you on a delayed contract or is that still off in the future?
Nothing to say. We filled the 4 year deal last month, and we've got no intention of reengaging because like I say, we've got an alternate strategy.
At this stage. Perfect.
And then my final question is just following on from levels on our patent. It just appears that $395,000,000 of CapEx, 5.42 gigawatt hours, 1000000 of OpEx or $11 per megawatt hour of OpEx. When you compare it against Waipi and Teritiere, so excluding WACC considerations, it appears about $5 to $8 more expensive than those of wind farms. Is there something I'm missing?
Might be what's the basis, Grant? We've got about $62.4
per megawatt hour levelized cost on the project, Grant. So I'm not sure what those others are showing.
But I'm
not sure what Sorry? What WACC are you using for that assumption?
Our underlying. Yes. So just around 6% growth.
Okay. That are the observations about other people's project economics. I'll just say that we've learned quite a lot in the previous wind farms that we've built. And I remember at the time we were building Mill Creek, Snowtown 2 in Australia was being developed, and it looked like it had a significant cost advantage over Mill Creek. A year later, Snowtown's wind resource was written down for the life of the project and the costings came in at about square actually.
Perfect. Well, thanks for asking my questions. That's the end of it. Thanks.
Thanks, Grant.
Thank you. There are no further questions from the phone. Please go ahead.
We'll wait till the man tells us. Okay. Thank you. I think that's all the questions. Thank you for tuning in.
Hopefully, that was informative. Have a good rest of the day.