Meridian Energy Limited (MEL) Earnings Call Transcript & Summary

Good morning, everyone. Welcome to Meridian Energy's interim result announcement for the 6 months ended December 31, 2020. I'm Neal Barclay, 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 second highest level of interim EBITDAF, however, the highest level was last year, and that was 9% higher. Mike will talk a bit more about that as we work through the financial performance. But in summary, the key factors impacting performance was lower 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 lowest 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 in 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 the 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. NZAS. Last time an Aussie said to a Kiwi, 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 produce 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 the 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, but 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 enhance in the grid in the Lower South Island. Now the certainty provided by the NZAS 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 million Harapaki wind farm. And secondly, they resolved to keep the interim dividend at a consistent level with the prior year. And the most significant and impactful thing Meridian can do to combat climate change is to efficiently operate our fleet of renewable generation assets and build new assets. However, we are also very focused on managing our own carbon footprint and being an exemplar of sustainable business practice. And particularly, we've made a commitment to halve our gross operational emissions by 2030, 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 within the next couple of years. We are underway with our carbon sink project, to plant 1.5 million trees in the next 3 years. We've planted out 60 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 1.5 million stems in the ground. I believe the rest of our ESG 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 $4 million to roll out a new network of at least 200 EV charges. The network will be comprised mostly of AC charges 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 chargers. 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 will push the go button on Monday. We believe that certainty that we have secured with the 4 year NZAS exit now will now shift the 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 2050 net carbon 0 targets without scale of electrification 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 and origin will be aware that the near-term outlook in Australia is pretty challenging. The orderly function of the energy market, so there is arguably not being helped by the political intervention of 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 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 will talk about the numbers in a wee bit more detail.

Thanks, Neal. As you mentioned, we've had another strong 6 months, while EBITDA fell from record levels in the first half of 2020, it remains the second highest interim print for our business. The net profit after tax result was also pleasing, up 19%, but net profit after tax or NPAT includes an uplift of $88 million from derivative and interest rate fair value movements that suggests 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 million last year to $187 million this half, largely following EBITDAF. But did get thrown around a little as we made the final tax payment from a bumper financial year last year at $187 million, there's 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, as this is the third 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 '19 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 million into what will become New Zealand's second 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 NZAS 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 will be introduced as we continue to work through our alternate 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 seemed prudent as it doesn't signal anything in particular. So onto 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 million when compared to the first half performance last year. As this explains the majority of the group EBITDAF fall, it is useful to go into what happened. So starting at the left, customer revenue actually increased by $69 million, 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 511 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, whereas spot revenues can be filed, so we like our underlying positioning. Finally, the cost of derivative sales outweigh the value they created. This is something that a wholesale team always works on. But there isn't much of a story here as some of the transactions that make up those buckets of risk trades. So moving on. This slide builds on the customer growth story. We'll continue to grow our customer base, where 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 Powershop 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 both lifting. And as the New Zealand retail electricity market is amongst the most competitive on the planet, that's quite a feat. To reflect on the comments that Neal made at the start of our announcement, the Kiwi householder is paying less for electricity now than they were 8 years ago in real terms. That 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 511 gigawatt hours lower than the previous comparable period. The reason for this was twofold. First, 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. Second, 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 and August, inflows were about average, so we couldn't build storage or generate large volumes. And while inflows in September and October look significant, unfortunately, the storm that arrived was too large to catch, and we had to fill 255 gigawatt hours of energy past our power stations rather than use it to excite electrons. Those inflows were useful, nonetheless, as they listed lake storage back to more normal levels, but then we ran into November, December and 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 are strong, we are pretty happy. But there's a reason I'm showing January 21 on this slide, even though it's not part of the interim period, it's important that you know that Southern Hydro Lakes haven't had the rain they might expect so far this summer. We typically rely on 3 to 4 storms -- storm events to fill those hydro catchments. And so far, we've had one. 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 is COVID. Our Aussie mates were locked up tight for an extended period. And while they had time on their hands, they obviously spend at doing things other than thinking about switching electricity provider, which is actually interesting as average wholesale consumption grew by about 20% during their lock down period. So household costs would have gone up materially while we 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 our quick thanks and share that to them for their commitment and the humor they showed during the tough times. Energy margin in Australia in the first 6 months fell by $6 million when compared to the first half of 2020. While customer revenues in both electricity and gas segments lifted by $11 million, this was not enough to cover the material fall in wholesale prices experienced in Australia that Neal mentioned. And while we run the business in a similar way to New Zealand and it's vertically integrated, we do like to run a little long to account for the changes in hydrology. So this link 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 fin year '22 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 EBITDAF 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 this call would have noticed that on the previous slide, contracted sales revenue fell by $5 million, while on this slide, I noted that electricity and gas sales to customers lifted by $11 million. The difference is $16 million in financial contract sales that were not made this year as compared to last and have 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 million to $266 million range this financial year. That continues to look like a reasonable forecast given the $1.6 million spent through the first 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 spaces given NZAS' decision to terminate our contract effective August or August 31, 2021 at that time. I also noted that if it played out that this could result in material falls in OpEx. However, given the amend of contract that we'll see and sustain through December '24, those changes no longer make sense. So I don't have 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 million in fin year '19 to $15.7 million in fin year '20. That provision still sits at $13.3 million in the interim statement. And the last point I'd make is in relation to the CapEx forecast. We noted that we expected to spend between $70 million and $80 million 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 Neal had mentioned, and we expect the majority of that spend to land this financial year. Neal will talk to this in a bit more detail as well in a bit. So what's it all mean? Largely a repeat what I said at the outset. We've the second highest level of interim EBITDAF in the first half of this year. It was down $43 million 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 third, but last time, NPAT lifted by $36 million this half. We don't set that out specifically on this slide, rather we focus on underlying net profit after tax, which is a non-GAAP measure. We do this as we feel it's useful as it strips out the noncash fair value movements, otherwise captured in net profit after tax. You can decide on the measure that works for you as we present them all in our financial statements, but the graph here shows that underlying net profit after tax fell by $28 million, which is 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 '20 announcements, where I noted that if NZAS exited in August 2021, that we'd likely see a reduction in the value of our New Zealand generation facilities possibly by between $690 million and $1.3 billion. 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 NZAS has created a really solid platform from which we not only need to restore but grow earnings from. It takes some hard graph 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 EBITDAF levels as we work through the next 4 years. Neal, 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 and parcel of a hydro-based system, the main thematic in New Zealand building is the tension in the gas market. Our delivery from Pohokura field is often the reference point on the supply side, a number of other fields appear to have also pass their production plateaus and into deliverability to clients. Guest 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. 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 the 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. As 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 sense some of these 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 reasonably 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 up 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 events has forced us to pull back from the start line on our Harapaki wind option. And following the 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 second largest wind farm and is located along the Maungaharuru Range, just north of Napier. Project has strong economics. It's a great fit for our portfolio and it 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 Hawkes Bay, and this will undoubtedly help boost the local economy and create some jobs. Harapaki will be Meridian's tenth 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 million and 3.8 million tonnes 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 as planned. We intend to host investors at the site in May, and you'll hear more from Owen 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 Hume 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 has 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. Now the Electricity Authority completed their investigation into the wholesale electricity markets during the flood of end of December 2019. And they concluded that a confluence effect has 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, ASX futures products, then we estimate Meridian's bottom line for that period will be reduced by less than $2 million. You may recall that we took out $5 million provision in the accounts as of June 30, 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 Commissions' words, "Lock in net 0 by 2050." It's very clear that the 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 1,300 gigawatt hours of geothermal is also committed. These developments tallied 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 were busily trying to migrate away from it. We also need solutions to manage hydro shortage 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 already starting to emerge. I've 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. 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 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 maybe what it sounds. We gave the NZAS story a good -- fairly good hearing last month. So we'll leave it there for now. Suffice to say, we will ensure we keep the market well informed as to how we've progressed with our smelter exit strategy. And that's laid out on the slide, consistent with what we showed you in January. After lingering uncertainty following big shifts in the U.K. retail electricity landscape, E.ON have committed to closing Powershop UK. The termination agreement with E.ON secures Flux 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 has proven better than we anticipated at this stage. So while E.ON has chosen a different path, we are still confident Flux offers a unique and advanced solution to energy retailers and Nick Kennedy her and 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 are achieving and the work we're doing to transform our retail operating models. There's still a lot of improvement possible and necessary if we want to remain competitive, and I can assure you, we do. January and February have been parched in our Southland flow and 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 NZAS pricing, will have a dampening impact on our second half earnings. The 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 balance sheet. I've made my views clear on the Climate Change Commission's draft advice. To my mind, it's the 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 their imperative to lock in net 0 by 2050. 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 phones.

Good to be back in the room. And no questions on the smelter, I think for a change for me, so that's good. Just a couple of quick questions really. In terms of your Australian growth profile around the wind, I'm assuming -- and I'm just taking what you're saying, in essence, you're looking to basically back in the growth in Powershop Australia, you're not looking to develop wind to sell to other parties?

Yes, Andrew, it's an -- if anyone on the floor has a question just announced yourself to -- just for the people on the call, but that Andrew Harvey-Green, as you've probably picked up from his voice. Yes, that's right, Andrew. We're running a retail led vertically integrated strategy. So our ability or our success in growing our retail business will very much drive the requirement to supplement that with generation developments. It won't perfectly match the whole way through, of course, but that's the nature of what we're trying to do.

Next question is just around Flux. And I guess, just understanding the changes that are going on in the U.K. 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 they might take on Flux?

Yes. We -- 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 developments we've done in New Zealand, particularly in the C&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 her team, reasonably confident probably also in Australia, there's some opportunities that are starting to emerge so we'll see how we go.

And just last question for me. You're two competitors who announced over the last week or so, both talked about interest in the Trustpower retail assets, you're noticeably absent in talking about that. You have any comments around that? And any interest?

Well, if we did have an interest, we would have signed a nondisclosure 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 on to the table, we always have to think about it. And yes, so we'll see how that plays out.

Tim Mowbray, AMP. Just on the Harapaki wind farm development and any potential development. Can you just -- you have to kind of give a bit of an overview on the timing of the spend on that and potential mix of funding in terms of cash flow, debt and also later on, any other potential future generation development, what the lead-in time generally from, I guess, decision made to spend would be? Just trying to get an overview of your potential spend over the coming years and funding?

You want to handle it?

Yes. So payments actually flow either today or tomorrow, having completed the signing of contracts to get to the major vendors underway. And then payments are staged -- $395 million of payments are staged over the next 36 months, right? So depending on specific milestones struck. And as I kind of -- I did on 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, year -- early mid 2024. So a year before that, we expect first power.

And in terms of -- any comments on in terms of funding mix, cash flows, debt? How are you thinking of that or really?

So we've got adequate facilities and balance sheet bundle 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 Neal mentioned, we got a couple of options out of Australia and we're 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, there's probably not too much more to say right here.

I think you asked a question about the life cycle of it.

Yes. Just in terms of...

Look, I think rule of thumb, we've it's usually about a 10-year cycle from an idea through to potentially sticking a shovel on 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 with the RMA reform that's 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 for it. We do have a few couple of wind farm options that are far more progressed than 10 years. And just a bit more color. 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 a new wind farm and delivering it every 3 years.

Nevill Gluyas, Jarden. 3 questions for me. Just on Harapaki to start with, the cost per megawatt hour or cost per megawatt -- perhaps a bit higher than I might have expected. And I'm wondering whether or not there's any kind of COVID impact on the CapEx and/or timing to think about when we look at potentially other future wind farms, are they likely to be cheaper high capacity factors? I'm just wondering if you could give us any color on that.

I guess, it depends on what you're expecting, Nev, in terms of unit cost. 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 that project, primarily settled in our risk. And so we feel pretty comfortable that both number in terms of unit costs and numbers that we 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 in sort of at the margins. But a good news last night, we managed to lock in the currency at a reasonable gain. I'm not going to let the team have that as contingency. So the headline price will drop a wee bit.

So another way to phrase that question is you see it as competitive with future wind farms to follow from yourself and competitors?

Yes. I think certainly in the sort of $60 to $65 range, there's no reason to suggest that the value of wind farm, the cost wind farms have been significantly higher than that. And yes, as you know, the technology is getting bigger. It's making itself more available for sort of level 2 type sites -- sorry it's not level 2.

Class 2. Class 2.

Class 2 sites. So you can get more generation but a lower capacity factor, cheaper.

Great. Next question on the 250 to 500 gigawatt hours of demand stimulation in South Island and boiler conversions or industrial heat conversion. You sort of 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 to 500, what kind of range of capital should we expect? And if we're trying to guesstimate pricing, is that somewhere above where you've signed the extension deal for NZAS but below we're seeing all foreign C&Is trading today?

Yes. My notes originally said sustainable NZAS-type pricing, but then we realize that the NZAS pricing has changed quite a lot. So we're talking about pricing consistent with what NZAS were paying before they canceled the contract. So it's pretty compelling, I think. And it looks like it's a price point that's good enough to get a number of customers to motivate and the costs 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 million, all that.

Great. Okay. That's really clear. And just the last point, with an extraordinarily high forward curve, for the next 4 years at least, you marked -- I mean, I recognize your comments about retail or pricing. So in terms of your own recovery, up $5 a megawatt hour by C&I 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&I and mass market.

Look, I think we will look beyond the immediate wholesale market that we're seeing and that, that has been driven by, as we know, concerns and constraints in the gas market. We're hoping that some forward investments 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 I would have bought. So I think long term, I would not expect to see a significant change in retail pricing in the country because the underlying economics wont take it in.

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 NZAS and sort of do some kind of averaging between then and forward curve now?

Look. The market discovers the price that the market discovers. That would -- that's a logical suggestion, but that doesn't mean to say that, that will play out by that.

Analyst predictions are always wrong.

Everyone okay? So we'll take questions from the phones now.

[Operator Instructions] We have a question from the line of Grant Swanepoel from Jarden.

Grant? We can't hear you, Grant.

Can you hear me now?

There you go. Yes.

IT system change. IT system changeover?

Grant, your connection is not good and we only picked up the end of it. I suggest you find another line and try calling in some other way. There he was.