Meridian Energy Limited (MEL) Earnings Call Transcript & Summary

[Foreign Language] Welcome to Meridian's results presentation for the half year to 31 December 2021. I'm Neal Barclay, Meridian's Chief Executive; and with me is Mike Roan, our CFO. I'll talk briefly to some of our business highlights, then I'll hand to Mike to drill into the financial result. I'll then round out the presentation with some commentary on the wider market environment and Meridian's strategic intent. EBITDAF was flat year-on-year, but we think that's a pretty good result given the prior period included much better NZAS pricing. We have offset the lower NZAS revenues largely through continued great retail growth with a help in hand from higher generation volumes. The successful sale of Meridian Energy Australia kept plenty of the Meridian team very busy during the last few months, particularly this person sitting right next to me. I think the transaction was completed seamlessly, and we will recognize a gain on sale of around $240 million at year-end. And whilst the Board and management are keen to reserve the bulk of the sale proceeds for future growth opportunities, we are pleased to be able to update our dividend policy and lift this year's interim dividend. Harapaki works are now well underway. We had a fairly wet and soggy start to the project, but the last couple of months of good weather have allowed the team to get back on schedule. And we all know now that Rio Tinto wants to keep the smelter operating beyond 2024, but we still have no idea if they're willing to pay for price for the energy they consume. So our planning assumption remains that our contract with the smelter will conclude at the end of 2024. And critically, we have made tangible progress with our package of mitigations against the NZAS contract termination. These include site acquisition for our North Island battery and solar farm. Now of course, none of these business highlights happened by accident. We have a highly engaged and capable team at Meridian, who are delivering great results. I can't thank them enough for continuing to drive business improvement whilst keeping our customers and our major project goals front of mind. I'm going to hand over to Mike.

Thanks, Neal, and thanks, everyone, for joining the call this morning. I'm going to talk to our financial statements, as you might expect, and I might focus on them a little more than usual as their features that are lot complex given the sale of Meridian Australia or MEA. But first up, I'm going to focus on that sale and what it means for our capital structure and dividend. So what does it mean? The sale means that we have a balance sheet that's particularly flexible. And while we think this flexibility is important in the long run given the growth in front of us, decarbonization will take time to play out as well developments that flow from our pipeline. So in the shorter term, and when I say shorter term, think through 2024, or when we have further confidence on hydrogen, Rio Tinto or both, the sale and improved balance sheet has facilitated both the change in the dividend policy and a lift in the interim dividend payment. Changes to the dividend policy are twofold. First, we're lifting the free cash flow payout range between 80% and 100%. Second, stay-in business CapEx is captured within the policy of fall from $65 million to $50 million which has the impact of lifting free cash flows available for dividend payment. And we're lifting the interim dividend from $0.057 to $0.0585 per share, 86% imputed. I doubt these changes are surprising, but that lift in interim dividend is the first since I took over this role back in 2019. And we intend on extending the dividend reinvestment plan, even with the balance sheet in good health, as long run will still need this equity DRIP fee. So while it might feel a little unusual in the short term, equity accumulation over time is still valuable. That said, we're eliminating the discount to those that chose to participate in the plan for the interim dividend. As I noted in my intro, the sale dominates our financial statements but also represented a reasonable slug of work for both -- for folks on both sides of the Tasman, as Neal mentioned. We're extremely satisfied with the sales price of AUD 740 million or NZD 790 million based on the hedge exchange rate for the transaction as it represents an accounting gain on sale of over NZD 240 million. So recycling capital from Australia successfully is a great result for everyone involved. We're also super happy that the purchases of the business with Shell and Infrastructure Capital Group. As we noted back in Australia, there were 4 or 5 interested, so to sell to entities with real purpose and a clear desire to leverage and grow the business that the team in Australia had put together was very pleasing. ICG has a superb track record of managing renewable generation assets for its Australian Renewables Income Fund, and Shell has clearly articulated its vision of using Powershop Australia to pivot into more sustainable activities. And we expect to maintain and grow our relationship with Shell in particular in the coming years as we'll provide customer care and billing services to them by the Massena Call Center and Flux. Over the next month or so, we'll use the proceeds to optimize the balance sheet, which will initially see us retire bank facilities. I'd expect the net debt-to-EBITDAF ratio to fall from 2.4x as captured in the interim statements to around 1.5x and net debt to fall by around the same amount as proceeds received at least until we pay the interim dividend. And I can assure investors that the cash received will only be used to support value-enhancing activities. It won't burn a hole on management's pocket or see executives explore interesting ideas. That said, we do have an eye on the future and demand response will play a key role as the economy decarbonizes, so there may be some investment in activities in that space. But I'll be clear in framing that for you if it occurs, and Neal will talk to our investment pipeline shortly, so I'll move on. So we obtained a strong price for the business that facilitated a change in both dividend policy and interim dividends and leaves us in a superior position to support new wind and solar assets in the New Zealand market, while deploying the North Island battery at Marsden in the coming years, all up a superior result for investors, our team in Australia and the purchasers. We'll continue to keep an eye on Australia to see what plays out, but we see the challenge is largely a New Zealand one for the foreseeable future. And of course, it's a very interesting time for the industry here given the decarbonization challenge in front of us. So it will meet our entire focus. And from where I sit, the opportunity is substantial for our investors. It also looks attractive for residential electricity consumers who should continue to benefit from the increasing levels of competition and product choice that the market offers. And in my view, or my view is that any price increases they might face will be suppressed given the intensity of that competition and more so as new renewable investment starts to land. If I'm right, that would put New Zealand on a very different trajectory to most other parts of the globe that are transitioning their economies and energy sectors. The reason I say this, even as wholesale price pressure continues to affect spot exposed industrial customers, is that competition for investment continues to build and the cost of that investment falls. This is particularly true as solar development nears price parity with wind farms in some locations. And with low barriers to entry in this space, I expect considerable volumes and new projects being committed. In fact, if Energy News is right, then there is at least 1,000 megawatts of solar investment lining up with approximately half of that coming from new entrants. It's good to see new investors show confidence in our industry. So while wholesale market pressure remains intense, we, for one, are largely able to look through these prices when it comes to our residential customers. And I'd like to put a plug-in for our teams working with larger business customers who are definitely feeling the impact of the current pricing environment as they're working hard to extend contract terms to iron out some of that pain. The agreements may not be PPAs in the classic sense of the word, but they have similar tenor and provide fixed price cover for those customers. As Neal will point out soon, we'll continue to invest in new supply side assets, of course, but there's plenty of room for us and others as economy-wide decarbonization plays out. So the next few years will be interesting, and our sector of Meridian will have key roles to play to make sure our economy retains, and if possible, grows its international competitiveness. New Zealand is blessed with renewable energy and in time could become a competitive advantage if we're going to attract businesses that want to prove to increasingly discerning global customers that they're focused on delivering sustainable products and services. Right, at this juncture, I'm going to do a pivot and come back to the financial statements as the last bullet on this slide is pretty important for those tasks with deciphering them. So a couple of key points before moving on. First, and as noted on the slide, MEA was treated as a discontinued operation in the interim statements. And as a result, the income statement largely records and compares results from continuing operations or just those in New Zealand for the interim period this year and last, and I say largely, as there's $12 million of cost from discontinued operations captured in the income statement as a loss on sale. That $12 million represents transaction costs that flowed through the accounts before the end of December. The approximate $240 million New Zealand gain on sale mentioned earlier will flow through the year-end accounts. So you'll see that in August. However, the balance sheet shows continuing operations for the first half of this financial year, but it does not represent the first half of last year. So real to be aware, you're looking at apples and oranges on the balance sheet. And to top things off, the cash flow statement shows group cash flows, not cash flows from continuing operations. So it's a bit to unpack, but we help any reconciliation you may wish to undertake as we have a detailed note capturing the income statement, balance sheet and cash flows for Australia on Page 8 of those statements under significant matters. On to EBITDAF. EBITDAF tracked the prior period very closely, which is a superb result when you consider that we received $58 million more from NZAS in the prior period. The reason we're able to make up that difference was largely down to growth in New Zealand energy margin and I'll talk to that shortly. We also reversed a $7 million holiday pay provision that saw operating costs held flat to the prior period and transmission costs continued to fall. As the graph on the bottom right -- bottom left shows, at $394 million EBITDAF is right up there in terms of past performance and demonstrates the capability of our operating teams. If you want further good news, you need to look no further than the January operating report that showed that the second half of the year kicked off a lot better than last year. And while January was dry again, the driest ever in our catchments, Lake Pukaki started the month with about twice as much water as last January, and this allowed us to generate harder into strong prices. The tropical storm in early February then proceeded to restore Pukaki storage to its upper balance, almost perfect, although that storm surprisingly missed the wire. So we have a few operational constraints as we move through February. And that's a nice segue to New Zealand energy margin, as once again, customer sales supported revenue delivery, while spot exposed revenues predictably fell as wholesale prices were lower than they had been in the previous period, and our customer position grew, so spot exposed volume shrink. Operating conditions did support strong production volumes and these were up by 435 gigawatt hours on the previous period. Other than that, there isn't too much to add to this slide, but I did want to talk to January's lift in ASX prices, as this lift surprised us as much as anyone else. Spot prices remain buoyant as factors outside of hydrology continue to support them. While they attract attention, we, like others, largely took to the electricity authority confirm that price discovery in the spot market is reasonable. And the weekly reporting that the authority put in place following implementation of the high standard of trading conduct provisions last July provides guidance in that regard. From everything we can see, those reports suggest pricing is reasonable. That said, for the ASX to go on the tear it did was surprising. We can't tell what drove prices to lift by between $20 and $50 a megawatt hour for the 4 near-term quarters other than to note that there may have been concerned regarding the factors I mentioned. Fear might also be a factor, but it does feel a bit of rational that a short-term drought drove price lifts across the entirety of the forward curve. As we don't get to see ASX counterpart data and as 60% of the transactions on ASX don't involve a market maker, all I can tell you is what is captured in the January operating report. Providing liquidity in this environment cost us $5 million over the month. And to cover off the natural question of why didn't you sell into those prices that were higher than we expected, well, first answer is we did in small increments. But price sales through retail and wholesale channels meant we didn't have the 7,100 gigawatt hours of volume for sale to meet and match all ASX trades in January. I'm not sure if anyone recalls the graph that we presented on Page 10 of last year's annual results presentation that showed total ASX trading for fin year '21 was 74 terawatt hours or close to twice annual physical consumption in our market. So this market is no longer the small liquid space that people tend to quote when trying to explain why it moves the way it does. So for the most part, we either watch the action or close out positions that we didn't want as part of our market-making activities, hence the $5 million in cost. I can say it wasn't -- it obviously wasn't the income -- outcome we were -- expected or wanted as we kick into 2022, but regardless of views on reasonableness, the forward curve is signaling even more strongly that new development is both attractive and necessary. Right, New Zealand customers. My summary of this slide is our retail products and services continue to appeal to new customers at increasingly attractive prices. As a result, the retail team grew mass market and corporate sales revenues by $25 million and $33 million, respectively. While those are outcomes that investors might expect to see, it's important to provide some perspective for customers as well. While prices are lifting normally, they continue to fall in real terms contained largely as a result of New Zealand's open and competitive retail markets. Of course, and as mentioned earlier, our vertically integrated business model and scale also means we can take a long-run view on price for both residential and corporate customers to help manage wholesale price squeezes like the one being experienced right now. I don't have too much to say about this slide either other than to summarize what's presented. Inflows were strong, while wholesale prices were lower on average than they've been since 2017 for the 6-month period shown. If you remember my comments from August, I noticed -- I noted that we expect the group OpEx to fall in the $275 million to $280 million range this financial year. On the graph on the right of the slide, we strip out Australia and show that at $98 million first half New Zealand OpEx matched the same period as last financial year. We do expect the business to sustain a higher level of spend in the second half, particularly in the development space, and therefore, expect New Zealand OpEx to land in a $215 million to $220 million range by the time we're done. As for CapEx, at the start of the year, we suggested group spend of between $205 million and $215 million. With the sale of Australia, we now expect CapEx to track between $165 million and $175 million. Neal will talk to Harapaki, but in case you're wondering, the challenges at Navigators didn't result in the forecast revision you see here. Key to this slide, in my view, is the table on the right. Underlying net profit after tax was marginally below last year's result, which predictably flows from EBITDAF. And at that level, underlying net profit after tax represents the second best first half performance we've seen as an organization. Of course, if we use GAAP measures, the net profit after tax fell by 36%, driven by the large fair value movements from energy derivatives captured in the fin year '21 interim result unwinding. You can see the reconciliation between net profit after tax and underlying net profit after tax on Page 46 of the presentation. As I've said many times, I think that underlying net profit after tax and EBITDAF are better measures for tracking performance of our business over time. but the GAAP measures are what we report on. So I'll leave it to you to decide how you want to measure it. From my perspective, the operating business continues to perform well. And alongside the MEA sale and a bevy of other initiatives that were progressed, it was a sound 6 months. I'll now hand back to Neal, so he can shine a torch on those other initiatives, the regulatory environment and other elements that will both drive our strategic ambition and will influence performance over time.

Thanks, Mike. The next 4 slides cover what's topical from a market and regulatory perspective. The electricity market is still experiencing persistent and relatively high wholesale prices, Mike covered this, but even at times of relatively good hydro storage. Overall, electricity demand has proved resilient to the COVID economic disruption, and it's actually up 0.8% on the last 12 months. We've also seen an upward movement in coal pricing and a significant lift in domestic carbon prices. So despite positive potential expansion at Maui and Coupe, Pohokura decline continues. And that may be creating heightened uncertainty about the electricity sector's ability to secure flexible guests to help manage dry year risk. We believe this uncertainty is manifesting in a significant risk premium wholesale electricity prices and is probably driving what some have speculated as an apparent disconnect with the historic relationship between prices and hydro storage. And I don't believe this is any indication of an electricity market not working. The response to these price signals is clear. More renewable generation has been delivered and significant investment is going into upstream gas, and that is reflected in lower forward prices from 2024. But beyond that, you can see the industry consolidated pipeline of new generation development options building at pace to meet the expected demand lift that decarbonization will deliver. And most importantly, and as Mike observed, the cost of electricity to most consumers is not increasing in real terms. Now in October 2021, the electricity authority published the preliminary findings of their review of the wholesale market between 1 January 2019 and 30 June 2021. We don't concur with some of the authorities findings, most notably their observations on the revised NZAS contract. The authority is working through a process of consultation on their review, and that is highlighting the complexities our industry faces and transitioning to a mostly renewable system. To me, what is important though and what we can't lose sight of is tens of billions of dollars must be invested in electricity generation, transmission and distribution assets over the next 30 years if New Zealand is to achieve the zero-carbon aspirations. So more than ever, the industry needs regulatory certainty investors need to be confident they understand the risk parameters for the investment decisions, and I believe it is incumbent on government and regulators to provide that. The 9th of August power outages were a major fail for the industry. Multiple reviews have been completed, and it's clear that the outage need not have occurred. It's critical that we, as an industry, collectively take steps to ensure we don't cause another scale supply interruption of that nature again. Of the reviews completed, the NBA report and recommendations are particularly coherent and well thought through. And I think if we move forward with those recommendations, it will help avoid a similar situation occurring again. The process to transform transmission pricing to a new benefit-based methodology by 2023 is almost complete. It is fair to say the authority has had few supporters for its proposed reform. However, the beneficiary pays principal and the benefits to consumers still seem pretty sound, and there is no indication the authority are backing away from either. Separately, Trustpower's judicial review against the proposed reform was heard by the High Court during November and a decision is also expected soon. I'd say we'll understand the TPM of the future with some certainty within the next few months. Now I don't believe there has been any wavering in government or New Zealand business' commitment to a net zero carbon future. And the role the electricity sector will play in that decarbonization is still very clear and the growth potential remains massively exciting. But it is hard getting traction quickly and some of the early government milestones have slipped. May is now the deadline for the first 3 emissions budgets and the first emissions reduction plan. These are the required response to the Climate Change Commission's final advice published back in 2021 -- June '21. I personally don't think decarbonization -- the decarbonization challenges on government. I believe business influenced by consumer and investor sentiment will ultimately lead the transition to a zero carbon future. And what we need from government are the enabling policies that will support a just transition. I'm personally optimistic the signs are we will get that. Now the next 6 slides cover off the major business initiatives that we have underway. And for those of you who made it up to the Harapaki site during our Investor Day last May, it's almost unrecognizable now. Bulk earthworks commenced back in September and the main access road now exists as you can see from the previous slide. The progress that site has not been without its challenges. We've had to increase the scope of saw nailing works to improve the stability of slopes around the main road. We had restricted access to site early on due to the elevated COVID alert level settings and the Sunny Hawk pad delivered the opposite with a very wet spring and early summer. Thankfully. The weather has improved, but we've also put in place initiatives to mitigate the impact on the weather, including additional resourcing. The project schedule was the single largest driver of value for a wind farm project. And at this stage, we remain reasonably comfortable with the original CapEx envelope and time line. Importantly, the site switch hard platform, which was handed over to Trustpower on time, and our offshore procurement components are on schedule. We will have an updated view when we get to the end of the current summer build season. Now Mike has talked to the drivers of our retail growth. So I thought I'd just touch on a few initiatives behind the numbers. Our certified renewable energy program has gone from strength to strength. As always been our plan, we will reinvest all the net proceeds of that program back into decarbonization projects in the New Zealand economy. Presently, we have over 1 million to deploy and if demand for the product continues to build, we'll see that figure grow considerably. The issue of energy hardship continues to be a challenge for our industry. I'm confident that Meridian's practices to support vulnerable customers meet best practice. But we want to do more proactively to use our power to make a difference. A team of passionate experts from across our business have come together to build out a comprehensive energy hardship solution, and that includes education, support and dedicated resourcing to supplement the Arens efforts on energy made. We anticipate trialing this program this year and scale in 2023. I think this is a very positive step toward playing our part and improving outcomes for more vulnerable members of our society. And our EV charging network is rolling nicely and building pace. Contracted numbers have lifted significantly and deployment is following fast. And on EVs, I'll take the opportunity to congratulate Jeremy Ward and his East by West team here in Wellington, who have now built and are now operating in the Southern Hemisphere's first fully electric ferry commuter service. It has been a visionary and inspirational move. And clearly, whilst unbiased, you do have to love the color scheme on that boat. We've made solid progress with our development pipeline. We've secured 105 hectares of land in Marston Point that we have named the Harapaki Energy Park. This will house our new grid-scale battery, which we are driving to commission in the middle of next year. The land also affords us the option to deploy a utility-scale solar farm, and we have a conditional purchase in place for another 42 hectares close by that will further enhance the scale of that firm, all up the opportunity is between 80 and 100 megawatts. And we've just acquired 52 hectares of land at Bunnythorpe, which secures us a very good second North Island battery site. We will subdivide that land and sell what we don't need. We're also working hard on bringing forward a number of other renewable options and the overall pipeline is now around 2.3 gigs or 5,700 gigawatt hours. And of that, 1 gigawatt are secured options and 1.3 gigawatts are opportunities in evaluation. As part of the process of accelerating our pipeline of options, we've made the decision not to proceed with the previously consented wind farm located in the Central North Island project Central Wind. The site complexities and project economics are significantly less attractive than other potential projects we have in our sites. I intend to talk more about our pipeline as the year progresses. Now whilst we've been clear that we haven't been in any discussions with NZAS about a new electricity contract between -- beyond 2024, we certainly aren't averse to having such discussions. If and when we do enter into a negotiation with NZAS, we will advise the market. To their credit, the smelter owners and the NZAS team are putting genuine effort into reestablishing relationships with their key stakeholders. And it's clear that the economics and emissions profile of the smelter suggests the decision to close would be a very shortsighted one. But I think that was also clear 1.5 years ago when the smelter gave Meridian notice of a contract termination. So we're certainly not counting our chickens. And we also have no intention of resigning from what we previously said we'd need to see from Rio Tinto before we'd consider any form of contract extension, and that is: we'll need to be able to offer seasonal demand response. They will need to demonstrate proper environmental responsibility. They'll need to be willing to pay a fair and enduring price for electricity and the need to make a long-term commitment to New Zealand. I think the overhang on our industry on whether the smelter is going to close or not becomes even more intolerable as we forge our way toward a zero carbon grid. So plan A for us assumes a world without NZAS from 2024. And accordingly, we are putting considerable effort into progressing our NZAS exit mitigation strategy. But we also believe it is feasible to have our cake and eat it. And in particular, we believe the industry can support both green hydrogen at scale and the continuation of the smelter. The wind resource in South Linde is exceptional, and it's underdeveloped. We take away the risk of a disruptive sudden reduction in demand, there is massive potential to advance economic growth in Marijke powered by renewable energy developments. Now most importantly, Plan A is progressing well. We now have contractual arrangements with Nova for a call option and an offtake with Napa to support our position beyond the end of this calendar year when the swaption we have with Genesis matures. We've got more work to do, and we continue to talk to all the usual suspects to advance our dry year risk cover. Trustpower are close to completing the Clutha Upper Waitaki Lines project. This project doubles the transmission capacity Northwood, and it's a big comfort to see it progressing to a successful completion. I've talked about our North Island battery developments. The primary driver for Meridian is the battery will increase north in reserves and will unlock more of the current HVDC operational constraint. But the opportunity is much broader, and the technology can potentially fulfill multiple system support roles, which further enhances the business case. Our process heat initiative continues to grow and will include a dairy component with coal conversion at A2 Milks Mataura plant. Overall, we are halfway toward our target of 600 gigawatt hours of new electricity demand. Interesting some of the conversion opportunities also lend themselves to an even dry year demand response solutions. The concept is simple. The customer converts to electrode boilers for their process heat, but keep their thermal boilers commissioned and capable of burning biomass when dry hydrology conditions emerge. The product structure is like a swaption agreement. The customer receives an availability fee and then a fee per electrical megawatt avoided. We're very confident in the economics of the service look outstanding for the customer and will enhance their overall electric conversion economics. The availability of flexible biomass fuel will be the main hill to overcome to make this idea work as a commercial reality. Probably the largest challenge for process heat conversions is the required investment in transmission and distribution assets. These often make up to 2/3 of the overall capital cost to convert to electric. ICA's government investment and decarbonizing industry fund or Getty has been a key enabler to overcome that cost hurdle, but all of that funding has now been allocated. From a dollars per tonne of carbon abated perspective, these projects are about as good as it gets. So we are hopeful the government will top up the [indiscernible] fund in a meaningful way and soon. Data Grid recently acquired land for their proposed hyperscale data center in Southland. Construction is expected to commence on the first of potentially 10 modules later this year once consent are received. Supporting this was the announcement back in November that the construction of the Hawaiki new fiber optic cable network plan to link the South Island to the United States, Australia and Asia. Construction is expected to commence this year and the link between the South Island and Australia is expected to be in service by early 2024. And this connectivity materially enhances the data center proposition. Contact of Meridian Southern Green hydrogen team is continuing New Zealand-based development activities, including water access, land use and consenting. We have shortlisted 4 sizable and very credible potential development partners to work through an RFP process. The aim is to announce a partnership and/or consortium by the middle of 2022, and it's feasible that development activities can commence in the second half of the year. So if you summarize all of that on 1 page and which I -- hopefully, you're now familiar with, it feels like we have good momentum across the different mitigation work streams. But some of this stuff is really hard, and the future milestones and pathways aren't all clear at this stage. However, from my point of view, we have great people on it, and focus on the right strategic areas for the business. So to wrap it all up, a year-on-year flat EBITDAF result is a pretty credible financial outcome given the negative impact of the NZAS reprice. Our continued retail growth momentum has been a big enabler of that performance. We were wrapped to successfully complete the MEA sale. Overall, our latest Australian business venture turned out to be successful, and it's created considerable capital capacity for future growth in New Zealand and our intention to support the long-term decarbonization of our country. We're making sound progress on our development pipeline and on the NZAS contract termination mitigations. I'm confident we will have more progress to cover off at the year-end. And if the Rio Tinto Group are now genuinely serious about decarbonization, and my sense is they are, then that creates some interesting opportunities going forward as well. Finally, I'd like to acknowledge the Meridian team again. We have a lot on, but the opportunities are huge and the positive vibe in the company despite all of the COVID drama is palpable. From the Board down, we have alignment on what's important, and I'm confident in our ability to execute and continue to deliver for our customers and our shareholders. All right. I think that concludes our presentation. Thank you all for your attention, and we can now move to questions. None from the floor, obviously, so we'll go straight to the lines.

[Operator Instructions] The first question is from the line of Grant Swanepoel from Jarden.

I have 3 themed questions. The first one, with risk mitigation to Tiwai exit. It looks like realistically, there's about 600 gigawatt hours that you've got in place for calendar '25. Is there anything else we should look forward to that could fill that 4,000 gigawatt hole that you always have.

No, I think, Grant, the mitigations of what we've laid out, we see the opportunity in respect to process heat delivering potentially 600 gigawatt hours. I mean, depending on how successful the data center is and attracting customers largely based in Australia, that could be up to another 1,000, I think, gigawatts. And then the real big swing opportunity is with hydrogen. There is a large-scale opportunities still looking out there, but any conversations with that party are on hold at present.

Just continue in terms of the 4 things you want to look. I mean to you to do in order to get a contract. If hydrogen is the onset that come '27, '28, would you consider not bothering about a long-term commitment and just having stick around until you don't need them anymore.

Grant, as I said, we're not in a conversation with the smelter at the moment. They've indicated that they seem interested in one. So we'll see how that plays out when they want to actually talk to us and make the running. But I still think from a New Zealand perspective, for large-scale demand like that, we need surety. We need to know how long they're going to be there for, so that we can get on and invest with confidence. I think most likely, and everything I've heard and if Rio Tinto are genuine about decarbonization, decarbonization then 10, 15, 20 years is not unreasonable to expect them to ask for that facility. So we'll see what they want to do.

Second, just a little one, just in terms of solar. It looks like you guys have got about 80 megawatts lined up if you get to age that's only 140 gigawatt hours. You've got Genesis out there with trying to do 500 hours loads don't do hilt. Where do you see solar going? Can the grid really handle the sort of intermittent or daily charge coming through without using all the capacity of the line?

Yes. The 80 to 100 megawatts I talked about is just 1 option. We're looking at a range of different development options. So part of that 1.3 gig that we talked about, Grant, does include solar options. So our portfolio of sale potential is a lot bigger than what I just talked about. But we'll talk more about that as we firm up on them. Can the grid cope with it? I mean we have seen issues in Australia recently, in fact, where concentrated solar in certain regions has caused significant disruption to spot wholesale prices, particularly during the day when the solar is all on. I think providing we manage it, and it will just evolve naturally with a lot of the solar is distributed around the country, then the grid is well capable of handling that. And the thing we have in this country, obviously, that so they don't have an Australia is a very flexible and capable hydro fleet. So that enables us to complement intermittent renewables like solar and wind, which are quite complementary in their own right. a lot more than, say, a coal-fired, a coal-based system like the Australians have or a nuclear based system like the NZAS.

I got it. And then the final thing is just on pricing. You guys have been growing your retail book quite strongly over the last few years. But with the ASX now showing very, very good pricing over a 3-year period, when do you actually change this growth strategy? I know that it's mostly Meridian is you've been pushing into recent years probably the longer duration. But if you guys did start eating back, would you see C&I pricing lifting to something that people would be more willing to contract or in the market? So what I'm really asking is, when do you change your strategy from growing retail? And do you see some further uplift in C&I pricing for the market over time?

Well, I don't think -- I don't see us changing our strategy in terms of our push into retail, particularly mass market. We're playing a long game there, Grant, and we see the most valuable channel for our generation capacity is through particularly mass market retail channels. And you may or may not disagree with that, but that's our strategy, and it's working to date. C&I, we will -- we'll modify our strategy there depending on how much we can actually cope with in our portfolio and our ability to hedge those positions. But my instruction to the wholesale team is if the retail guys can build those customer relationships and sell a proposition to customers that they enjoy, then it's the wholesale team's responsibility to find a way to do that to support that. So that's our approach. I mean in terms of long-term pricing, look, all the price signals, all the signals are in place today that the wholesale market, and it's attracting investment, I would expect the prices to moderate over time from what we're seeing today. And that's just my expectation and could be wrong. But certainly, if you look at the cost of new renewables that are coming down, so that would likely happen, although it could be quite -- it could be very volatile. That's fair to say as we move to this more renewable state. So yes, look, I wouldn't want to predict one way or the other how C&I pricing will go. All I'll say is that I think we'll be there and we'll be offering a competitive proposition to customers for sure.

Your next question is from the line of Andrew Harvey-Green from Forsyth Barr.

A few questions from me. First of all, just on your development pipeline. How much of that 1 gigawatt that you talk about is actually consented at this point in time?

I'm just looking at the list here. Probably about -- look, can I get back to you, Andrew? Because I'd have to do some math in my head. We don't have a massive number -- we don't have a massive amount of consent at the moment, but we are moving into a consent phase over the next 6 months to a year on a couple of projects. I don't want to talk about those too openly because we've got work to do with stakeholders before we launch that into the public arena. But yes, we are looking to move some of these options from well-understood developments into consented and buildable options. But we'll get back to you.

Yes, that's all good. Second question kind of related, I guess, in terms of your development pipeline after Harapaki, you've got the solar project up in Northland. Just slightly curious as to why 2024, you hear as the date for construction, just given where wholesale prices are if you'd want to try and get that underway as soon as possible. Is it a physical reason why you are not bringing that forward?

This is the solar development.

Yes.

Yes. Yes. No. Look, yes -- no, there is an intention to bring that forward, Andrew. If it was consented today, we'd be building it, to be frank. So -- but there's a work to go through. I think you're still looking by the time we work through, get the geotechs on-site and so forth consent through, construction is probably back end of next year at the earliest. It's just how long these things take. But certainly, hopefully, early '24 would be better than late '24.

Yes. All right. Next question I just had was just around, I guess, your book and just thinking about, I guess, risk profile for Meridian, I guess one of the key features over the last few years has been the big growth in your fixed price volume sales. And just thinking, I guess, beyond the end of this year when this option ends, how does your risk profile change? It kind of feels like at the moment that the downside risks are increasing, but particularly given the cost of that backup generation is increasing quite significantly.

Not sure if we share that view, but I'll give Mike a chance to answer that since he sees the wholesale the past.

Some experience in that space. Andrew, I mean, we've got some further work to do is the simple answer. We don't expect to change our risk profile at all in relation to tail risk. So Neal mentioned earlier on the call that we have completed a transaction with Nova, but we're also in conversations with plenty of others so that we do manage that risk effectively, given the size of our portfolio and our strategy to extend our relationships with customers. So no concerns sitting here around our risk profile once the Genesis option terminates. We just got a bit of work to do.

Okay. Second to last question, hopefully, they are very quick. Just on the smelter comment about being wanting to provide seasonal support. Are you looking more wanting them to do seasonal support versus dry year support?

Well, it will be -- the objective would be to provide dry year support to the industry when you got such a large chunk of demand participating in a hydro backed system like ours with a relatively small amount of storage. I think they need to find ways to work more in sympathy with the electricity sector. We were open to how you can actually construct that, and we totally understand some of the operational constraints with operating an aluminum smelter. But there's certainly a hell of a lot more possible than what they've been willing to bring to the table in the past. So we're hoping a bit more of a can-do attitude from our friends if and when we actually start a conversation.

Sure. Okay. And last question is just around OpEx. And you highlight here the provision release which I think a number of companies are doing. But is that -- was that booked in the first half? Am I correct in saying that?

Yes. Yes, it was, Andrew. So it's picked up as part of the first half accounts. So that was my comment. Second half, we expect the lift in our OpEx profile. Some of it's -- you can see it from our history, but also the focus on development, but that specific provision was captured in the interim accounts.

Your next question is from the line of Stephen Hudson from Macquarie Securities.

Mike, Neal. Can you hear me okay?

Yes.

Just 1 for you, Mike. Just the PS, I just wondered if you could give us the free cash flow payout for the first half have calculated that and where you see sort of full year dividend sort of landing in that 80% to 100% range that the Board has left today? And then 2 questions for Neal. If you were to guess what Harapaki would cost if you recontracted a whole lot today, where do you think that sort of $400 million would land given what's happened to sort of the civil market and steel market and so forth? What sort of change would you get? And the second 1 for you, just your comment on fair and enduring for the NZAS price paid. I just wanted to explore the word enduring and also relate that back to the sort of reference that you made to a 10 or 20-year operating life. Do you think both parties would be minded to sort of build in a mechanism to share the economics of the smelter and in particular, the value that Manapouri delivers the smelter through a lower emission intensity and higher VIP sort of 2 value sources that they simply can't derive without Manapouri. Would you envision the kind of some sort of variabilization of the price paid through a new contract?

Steve, I'll kick off because I think your first question was on interim dividend and what it represented as a percentage of forecast cash flows. Is that right?

Yes, just percentage of flow.

Yes. So I'll tell you what we've historically tended to do is we've tended to pay out in the low 30s, and the only reason I don't reference a number today is we don't provide a forecast of free cash flows for the full year. But unlikely to be a change in our historical practices as it relates to the percentage of that free cash flow forecast. And then I think with the second question, Steve, question on...

Harapaki and the cost escalation issues and the current inflationary environment.

Sorry, Mike, just a button, the question is the 5.85 interim, what percentage of your free cash flow was that? And you're obviously targeting now to 100% payout. So where do you think the full year is going to end?

We don't provide dividend forecast, Steve, but I think I did answer as I heard the question, which was the payment of the interim dividend typically represents low 30s as a percentage of expected free cash flows for the year.

Okay. Got you.

So if you want to, I mean I'll follow up with you, but hopefully, that answers that.

Yes. No, that's clear.

Steve, on the Harapaki side of things, I mean, a big chunk of the wind farm investments of about 70%, I think, is actually in the turbines. And I'm not sure there's even global supply chain issues and the like. I'm not sure if the cost pressures are upwards, probably downwards because the technology is improving all the time. If you look at the civil aspects of the project, I mean we have inflationary escalators built into our existing contracts. Certainly, the inflation pressures are higher than what we anticipated when we entered those contracts, but we have quite a degree of contingency. So we think we can live within -- well, we currently think we can live within that $400-odd million. So I don't think we would have done -- while we're not picking that it would be massively more expensive to contract today given the amount of contingency we've factored into the schedule as it was. So it's that. In terms of -- look, we're not in a conversation with -- I like your questions and some interesting ideas in terms of how to structure pricing and something along those lines. But we're not in a conversation. And if we were, I probably couldn't talk about it here anyway, I could talk about that we have in, but not talk about the details. So I don't really want to get into guessing about how things could play out in that regard. And like I say, we're a long way to go before we could even contemplate seeing a deal to continue beyond 2024.

Could I have another crack, Neal, though? I mean you've used the word enduring price, does that sort of support kind of what I'm saying, which is fixed price 10 years, it's just not going to particularly enduring?

Well, I think in my experience, long-term fixed prices cause problems ultimately for 1 party or the other. They create winners and losers. So we always take that sort of thing into account. If you look at the contracts that we've had with the smelter in the past, they did have aspects of aluminum escalators in them. So we're always mindful of the fact that you don't want to create a situation where in 5 years' time, your main customer or your counterparty spends every moment from when they get out of bed in the morning contemplating how they get out to contract with you. So these are the sorts of things you have to work through when you're looking at long-term contracts.

Yes, that's useful. And from memory, the escalator sort of kicked in about for the USD 2,700 range?

Yes, it would have been well in the money in today's terms for sure.

[Operator Instructions] Your next question is from the line of Nevill Gluyas from Jarden.

Hopefully, you can hear me all right.

Yes.

So 3 questions from me. Just maybe to work around the wound, just a little bit more on TY. I guess another way to rather than talk about pricing to talk about terms. How do you avoid TY 2.0, where, as you say, they're taking every opportunity at some future time, trying to get out of the contract. I guess the -- harking back to the pre-2013 agreement, there was a sharing of electricity and aluminum price we built into that formula as well. And that's what they've been out of their way to avoid. What kind of mechanisms can you build to make sure that doesn't happen in the future, but is that part of the bottom line of an insurance agreement?

Look, again, it's a bit -- I think it's a bit dangerous for us to get into a conversation about a negotiation. It's not even occurring. And if it did occur, it would have to be -- it would be commercially sensitive right to the last minute. So yes, I don't really want to comment too much more on how that contract could play out at this stage.

Okay. I understand. And sort of the second part of that question really is then is there a deadline for them to engage before things become too late?

Well, as I said, we're working very hard on our Plan A and my belief and my intention or our intention as an organization is to execute on plan A, particularly on the hydrogen opportunity, but also -- I mean we're doing process. We're all in on that, irrespective of the outcomes. We will support the data center to the extent -- to the size that it turns out to, and we are committed on this hydrogen opportunity because we think it's a fantastic opportunity, not only for the country and the economic benefits that will bring to our country, but also the global environment and climate change and the like. So we are committed on our plan A. If the smelter want to be involved in New Zealand, then the sooner they engage the better, obviously, but the contract ends in 2024. So I guess that's the last moment. And of course, when we're talking a contract, that doesn't mean to say the smelter closes. That just means the relationship between the smelter and Meridian ends. There are other parties that could provide fixed price services or they could actually look at spot market exposure. So there's many ways they could continue to operate in this country.

Okay. Great. Second question really around swaption replacement. I think you laid out sort of a suite of novel and sort of some homegrown kind of alternatives. Should we take that to mean that you don't feel a need to enter into swaption or any kind of talking contract negotiations with Genesis around the rankings in the future? And just to extend that, would you be able to spend also as an offtake -- as option offtake partner in the thermal co-proposal for those are necessary?

No, Nev. No, we're working with all parties to build out our dry year risk cover. We would -- the Nova deal and the Napa offtake are not sufficient. We do have the SDR component in the smelter contract, which is sizable. But we are working with all parties to continue to enhance our dry year risk cover. And I wouldn't preclude doing a transaction with any party. I think what we do need in this country, and what we're not seeing enough of is committed parties willing to contract that will enable flexible gas to be brought to the table to solve -- to help solve our dry year risk without leaning too heavily on coal. And not -- I think there is a missing chunk of the market that aren't contracting. And if everybody steps up, rights reasonable contracts, that will give the upstream guys a bit more confidence that they can actually acquire it, get the flexibility and make it available. In terms of thermal -- sorry? Yes, in terms of thermal core, I mean...

I was going to say it's unforeseen, but you would add your commitment to -- that commitment to take those longer term contracts for peaking gas, that's something you're also willing to step up on the platform?

Absolutely. Yes. And that's what we're working on. And so what I was going to say with thermal coal, if it came to pass, we would look to transact with that entity like any other commercial organization that had a product that was valuable to us to help manage our dry risk.

Brilliant. Last question for me then was around -- sort of a hypothetical, obviously, like the Onslow and Ensek battery projects proceed, I'm just trying to get a sense of how important they might be through your investment decision-making strategy. If hypothetically they sort of committed tomorrow to proceed like on slow, how would that change you're sort of thinking about your project time lines? How you change your thinking about the market?

Well, it depends on how it looked at the end of the day. I mean, there's still a lot of work to be done to tick -- check the feasibility and get to a commercial proposition that could be built, and that will take a long time to build as well. I mean we're keeping a close eye on it. It's not going to be there tomorrow. So that is very much a hypothetical question. We'd have to understand the size of it, the scale of it when it would actually be in play, how it would operate within the market rules as we see them today or a competitive free market sort of framework. And that would all feed into any future investment decisions that we had. But I mean, personally, I mean I'm not anti the idea. I think we'll probably need some pumped hydro to complement things like demand response and other options to actually manage the security in the system going forward. So we're open-minded, and we'll see what comes of it.

Your next question is from the line of Steve from Energy News. [Operator Instructions]

Steve, we can't hear you. If you can hear us, so if you want to make contact with us afterwards, feel free to do that instead.

Neal, I just got a quick question about Mount. Monroe, which your presentation says is -- Neal?

Steve, I can hear you.

Can you hear me -- no?

Yes, we can.

Sorry. Okay.

Steve, if you can hear me, I could give you a call afterwards because it seems like we're either -- we can't hear you or you can't hear us, something is going wrong.

It looks like there's a delay. Just wondering how many megawatts Mount Monroe would be?

I've got a chart here somewhere.

There's a delay. How many megawatts would Mount Monroe be and what's the time line?

Yes. Mount Monroe is about 16 megawatts, roughly 235 gigawatt hours. Our design around the wind farmers reasonably well developed. So yes, potentially, a year or 2 to having a spade in the ground. It's not consented yet though, so we've still got to work through that process. I think we'll have to get back to Steve. It's not working.

There are no further questions at this point. I will now hand the floor back to Mr. Neal Barclay for any closing. Please go ahead, sir. Thank you.

Okay. Well, thank you very much for joining us. Hopefully, you found that useful. I wish you all the best for the rest of the day. And no doubt we'll see some of you in the coming weeks as we do the rounds to answer the more in-depth questions. Cheers. Bye.