Meridian Energy Limited (MEL) Earnings Call Transcript & Summary

Good morning, everyone. I'm Neal Barclay, Chief Executive of Meridian. And I have with me Mike Roan, our Chief Financial Officer. Thank you for joining us for our interim results presentation for the 6 months to 31 December 2019. We're really pleased to present fa record interim result with the EBITDAF up 20% on the prior year and net profit also lifted by 26%. To sum it up, the business has been buoyed by relatively high wholesale prices and significant hydro inflow events. But both of these factors create risk as well as opportunity, and I think we've managed the conditions exceptionally well. Meridian's near-term portfolio management has been very good, and our ability to win new customers at improved prices has really made this result. Last year, we shared our strategic themes with you, and these 2 charts address our progress against these. I'll make some general comments now, and we'll touch on most of these themes throughout the presentation. The Electricity Price Review concluded with a range of initiatives that we think, on balance, will improve the operation of the market, particularly as it affects customers in hardship. We also applaud New Zealand Parliament's progress in establishing bipartisan support for climate change legislation that will deliver a 0 carbon New Zealand by 2050. That said, we're yet to experience any real demand traction from decarbonization efforts. So the policy settings are in place, but the real hard work needs to commence. Our retail businesses in both New Zealand and Australia have real momentum. We've grown customer numbers, volumes sold and overall contribution from the segment across both markets. As I said earlier, this is underpinning the strong financial performance of the group. While relatively high wholesale prices are boosting our generation business at the moment, I'd argue that it shows the market is operating as designed. And as a result, we are seeing new generation being built, improved market confidence in gas supplies and transmission enhancements. And it may take some time, but we expect these factors will translate into lower forward prices. We remain very focused on our own development options in New Zealand, but clearly, competition is hot. We also have renewed our efforts to build our development pipeline in Australia, and we've added a wind farm option into the hopper. However, given current valuations, acquiring high-quality development options in Australia will be challenging in the near term. Now if we think it's tough retailing electricity in New Zealand and Australia, and we do, it's a breeze compared to the U.K. We see this first-hand with our partnership between Flux and npower. The retail sector over there is bleeding cash, and large players are having to find ways to slash costs. A small example of that is E.ON's decision to suspend deployment of a new Gentrack billing platform and instead focus on npower's integration. And amongst the npower-E.ON merger uncertainty, we have agreed terms to add another 200,000 more npower customers to the Flux platform by December of this year. So we remain part of the consideration set for E.ON U.K.'s future business, but we do acknowledge we're a very small cog in that wheel and we won't get carried away with ourselves. Now I'm sure what most of you want to hear about is Rio Tinto's impending decision on the Tiwai Point aluminum smelter, and I will talk to that later in the presentation. But for now, I'll hand over to Mike, who will run through the financial results in a bit more detail.

Thanks, Neal. During the 2019 year-end results call, we advised you not to expect another result like last year as the events and environment were unusual in our view. We'll wind forward to today and through the first half of this financial year with outperformed comparable period in fin year '19 by a comparable margin -- by a considerable margin. So I guess our direction was a little off, but we were trying to be straight up with you, and we definitely didn't see the wholesale prices extending as they have. More on this later. So we've had a tremendous 6 months. Through the first 6 months of this financial year, and as Neal mentioned, EBITDAF lifted by 20% to $465 million, and net profit after tax lifted by 26% to $191 million over the same period in 2018. And what makes this result more remarkable is that the first half result last year was a record in its own right. Execution in New Zealand, in particular, was outstanding. And while our Australian activities could benefit from some rain, like most of Australia right now, the customer side of our business across the ditch drove remarkable growth. Anyway, on to the numbers. So what do these results mean for our shareholders? It means we can maintain our fin year '19 interim ordinary dividend payment of $0.057 per share and top that up with a capital management program dividend of $0.0244 per share, for a total interim dividend payment of $0.0814 per share. A repeat of the fin year '19 interim dividend seemed like the right approach, given we have considerable uncertainty in front of us in the form of an announcement from Rio Tinto, and we didn't want to signal in any way that we had information as to how that decision might play out. As you'll hear from Neal shortly, we do not. At the August results call, we also said we'd provide direction on the capital management program, and particularly, we intended to update you today on whether that program might be extended. However, things have changed, so we're deferring guidance on that until later this year. I will say that sitting here today and with the result for the past 6 months playing out so strongly, our financial flexibility is stronger than we had expected, but it makes little sense to provide direction or further direction on either ordinary dividends or the capital management program until we understand Rio Tinto's decision. On to the driver behind our results. Net revenue or energy margin in New Zealand. As you can see, energy margin was up $88 million compared to the previous period, and this increase was really powered by growing customer sales revenue that lifted by $79 million or 25% over fin year '19. If you look at the slide, you'll see that sales revenue in the residential, small business and agri segments improved by $30 million over last year. This was attributed to increasing customer numbers as sales prices to those customers remained flat year-on-year. At the same time, we saw a $49 million lift in sales revenue in the commercial and industrial segment. This was driven by both price and volume growth as we extended our position and prices caught up with higher wholesale prices. And this increase in performance was playing out in an environment where wholesale prices fell by 19% compared to the corresponding period in 2018. Of course, they remain elevated by historical standards. With this in mind, the wholesale team did a good job of maintaining financial contract revenue at similar levels to last year. And financial contracts have more value to the business than might be immediately obvious, as they provide flexibility when times are tough while enabling the type of growth that you see here. In an absolute sense, they also added $32 million to energy margin, so they remain a pretty important element of what we do. All up, a very strong result in New Zealand, the best we've experienced. This slide provides further insight into the customer teams' performance. Our Powershop New Zealand and Meridian customer teams lifted customer levels, or ICPs, by just under 16,200 across the residential, small business and agricultural segments while maintaining the average sales price. And as the Electricity Authority has noted, New Zealand has continued to enjoy a highly competitive retail electricity market. So the teams feel pretty proud of this outcome, and we think it continues to be driven by the levels of service and product offerings that the Meridian Energy center in Christchurch and the Powershop call center in Masterton provide. Second, our wholesale and customer teams, again, worked well to target high-value opportunities in the C&I market. And as you can see here, the lift in C&I volumes and prices were 39% and 13%, respectively. And the majority of those sales are locked in through the next 2 years. In saying this, we realized that the real Kiwi business is paying more for their energy as a result of the increase in underlying price. So as I said last August, we continue to work with customers on energy efficiency measures where we can to help offset increases in price. We'd be the first to say that we did not expect prices to stay at these levels for as long as they have. However, having done so for some time now, it's clear that the market is responding by presenting new developments that don't rely on gas, which seems to be the fuel driving much of the volatility and lift in pricing. Along with the upside decisions already announced by others, we will construct Harapaki when we have certainty and the conditions are right. We had a lot of energy to sell in the interim period and produced just under 7,200 gigawatt hours of renewable energy in New Zealand. This level of production exceeds all comparable periods. And while prices were lower than they were in the same period in 2018, as I noted, they remain strong against our internal metrics and by historical standards. These high prices, alongside the 3-month HVDC outage that limits how much energy we can sell right now, is why we chose to produce those sorts of volumes. And talking about HVDC outage, as we look forward, we'll obviously be constrained by it through March, but all things being equal, we should have full lakes to power into winter. Looking further ahead again, ASX suggests moderating wholesale prices. Fin year '21 and '22 prices at Otahuhu currently sit at around $110 and $97 per megawatt hour, respectively, and these represent an average decrease of $10 a megawatt hour in prices seen in the forecast for this financial year. So moving on to Australia. The Meridian Energy Australia team has continued their growth mindset with over 14,000 electricity and 7,000 gas customers added during the first 6 months of the year. Meridian's Powershop brand added 82% of the electricity customer growth you see, with the balance largely attributable to Kogan, a white-label partner of ours in Australia, which only launched in September. These numbers exceed our expectations, and with Jason Stein now working with that talented team, we expect this to continue. And in late breaking news, our Powershop Australia was awarded Electricity Provider of the Year by Roy Morgan last week. While not well known in New Zealand, this is a prestigious awards and a great accomplishment by that team. So it won't be a surprise that energy margin growth on the consumer side of our business has been pleasing. However, it hasn't been all plain sailing in Australia, and the continuation of the drought that I talked about back in August has taken its toll on energy margin from our generation assets. Production volumes and storage at our Greenstate hydro facilities have fallen to levels last seen during the 2007, 2008 Australian drought. And production levels at Hume, our main hydro-generating station, are now 60% below average, and storage is 32% of average. And we have contractual issues at our Mt Mercer wind farm, while Mt Millar is going through a half-life maintenance program. At Mt Mercer, our O&M contract [ Basimbian ] was placed into receivership in Germany, and we're working through changes that must follow. In facing this challenge, we've been able to leverage the expertise and experience [ power in ] New Zealand in order to mitigate the disruptions that would otherwise follow. LGC revenue, which is recognized upon generation, has seen prices fall from $68 a megawatt hour in the first half last year to $45 a megawatt hour this year. This reduction reflects the expansion of renewables in Australia, and I talked to this fall in price during our August call. Specifically, I noted that Meridian hedged its LGC position and that the value of these hedges would flow into this financial year. I can confirm that to be the case, and we will receive revenue from LGCs that exceed the $30 million figure mentioned in August. So even with the impact of the drought on generation, we're reasonably happy that energy margin in Australia was only $1 million lower than the comparable period in fin year '19. I will note that if the drought extends, then performance in the second half of the financial year could be challenging. Moving on to costs. First half total operational costs lifted to $143 million. This is an $8 million more than the first -- the same period in fin year '19. As signaled last August, this lift was driven by a growing business on both sides of the Tasman and refurbishment of the Ohau chain. And while I'm on the Ohau program, total program costs have lifted from $57 million to $74 million. And the program will extend for 1 year beyond the original -- or initial 6-year term contemplated. The reason for this is twofold: First, the [ AS ] found condition of equipment is worse than expected; and second, the scope of the program has expanded, so we can push other work that would otherwise have cost $70 million back 10 years or so. As the financial benefits of doing this are positive, we made the decision to increase the scope earlier this year. In August 2019, I stated that the full -- for the full financial year, we'd spend between $280 million and $286 million after adjusting for the change in treatment for operating leases that flow from adoption of IFRS 16. Having spent $143 million through half year, we're obviously tracking to the top end of this range. If that's where we land for the full year, it would represent a year-on-year lift of $10 million in total costs. And I'll discuss this further then. In August, we also forecast capital spend between $70 million and $80 million for the financial year. Through half year, we spent $32 million on capital items, $24 million stay in business CapEx and $8 million investment, which is $2 million more in total than the same period in 2018. Again, I'll talk to this more when we get to year-end. The combination of energy margin and cost produced EBITDAF. And as mentioned earlier, EBITDAF for the interim period was $465 million, a lift of $76 million or 20% on the same period last year. It was supported by New Zealand EBITDAF of $426 million, up 22% on fin year '19; and Australian EBITDAF of $39 million, down 5% on fin year '19. Of course, we need to remember that the adoption of IFRS 16 during the period inflated EBITDAF by $3 million as compared to fin year '19 as lease costs are now appreciated rather than expensed. And some will have noted that operating cash flow has only lifted $4 million as compared to the $76 million lift in EBITDAF. The difference is driven by higher tax paid and the timing of working capital items recorded. We expect cash to be closer to the earnings level by year-end. Regardless, it will be superb to double down on this result or deliver the same outcome as we did in fin year '19 and the second half of this year. But as noted, the HVDC outage will constrain performance. So we'll just have to wait and see. For the accountants amongst us, there are a few things to note that this slide captures. First, depreciation increased by 15%, driven by the $1.1 billion lift in asset revaluation that occurred in June 2019. And while derivative has moved net profit before tax around a little, it wasn't substantial. But the lift in net profit after tax and underlying net profit after tax of 26% and 28%, respectively, are worth noting. Having said this, they both flow from operating results discussed previously. As for IFRS 16, we adopted the standard this financial year. The impact was relatively minor, with $75 million in finance leases added to the balance sheet. And having stripped operating lease cost out of EBITDAF, that rose by $3 million as compared to last year. Depreciation lifted by $2.5 million, and finance costs also lifted by $1 million. The combination dropped net profit after tax by $0.5 million, not much to it, really. There isn't too much to talk about in relation to the rest of the balance sheet other than to note, net debt remains stable, even as the capital management program continues. But it is worth letting you know that we will likely come to market later this year for additional funding to support ongoing operations and potentially support the build of Harapaki, but we shall see. So an interesting space for us. Strong results delivered in New Zealand. We're executing our way through the 3-month HVDC added better than forecast. But there's near-term uncertainty in regards to Rio Tinto, and March will be a tough month, given the combination of HVDC and Pohokura outages. The good news is our focus remains sound, and we believe we have clear executable plans should Rio Tinto exit New Zealand. We have a superb team in Australia that continues to grow our business while managing through some challenge that renewable companies have inevitably faced. Our job remains the same regardless, look for ways to grow the value of the business and improve cash returns if reinvestment does not make sense. Neal, back to you.

Thanks, Mike. The next few slides cover off the latest market developments and political and regulatory policy settings. So if we look at wholesale prices, we saw a structural shift in the spot and forward markets that coincided with the unplanned gas outages at Pohokura during the last quarter of 2018. The forward curve has remained relatively high since. And as Mike indicated, we are expecting some moderation in wholesale prices over the medium term, particularly as those new generation projects come onstream. This is clearly putting pressure on retail margins, and prices have lifted considerably in the corporate and industrial segment as customers have renewed their contracts. The impact on mass market pricing is more muted. And certainly, in Meridian's case, we take a longer-term view of the underlying wholesale costs, and we're also able to pass through network charges -- our low network charges in some regions as a result of reduced corporate cost of capital for regulated alliance companies. In our lower South Island hydro spill during November and December has attracted attention, and a claim of an undesirable trading situation or UTS has been made to the Electricity Authority, led by Haast Energy Trading, who trade energy futures and FTRs in New Zealand. The UTS claimants argue Meridian in context spilled more water than was necessary and that both companies should have priced the energy offers at short-run marginal cost while they were spilling. Now the authority is working through the events, but to put this claim into perspective, I'll make the following comments. One, throughout November and December, we were dealing with a massive flood event across both of our catchments. And the amount of spill in question is around 1% of the total flow that we managed. Lake Manapouri received the highest inflows on record, and Lake Te Anau, the second highest. We were dealing with these events without perfect hindsight that the UTS claimants said. And we know for many years' experience that picking weather forecast, particularly in the Fiordland is fraught with challenges. Two, the notion that generators should offer all of their generation at short-run marginal cost is not in the market rules. And if it were, it would actually be counterproductive to the market objective of incentivizing new investments. And three, the UTS mechanism is designed to deal with circumstances where there has been market manipulation and a result in loss of confidence in the market. There's been no loss of confidence. Forward prices remain relatively constant. In December, spot prices did what they have historically done and fell in line with Christmas demand as the chart on this page demonstrates. So we are supporting the EA with its investigation into the UTS claim, and we clearly dispute the claim. In terms of demand. Spotting a trend in demand is challenging, and irrigation load can swing the overall demand materially. So the chart we present on this slide excludes irrigation volumes. But when we dig into the drivers of demand, we maintain a view of modest organic demand growth. The balance in the system is undoubtedly a little bit tighter, and we believe the outlook is positive, albeit with uncertainty about when the decarbonization pool will start. All that said, I note the growth observed over recent times has only got us back to the level of consumption where it was about 4 years ago. Now our strategic aim is to maintain our market share of generation in New Zealand and grow our market share in Australia. And to be fair, we're coming off a low base in Australia. Obviously, we aim to do this in ways that create shareholder value. So we are reasonably discerning of opportunities. Our 160-megawatt Harapaki wind farm north of Napier is close to being shovel-ready. During October, we received the consent variations we were seeking, and the tender and engineering solutions for what will be the highest altitude wind farm in New Zealand are close to being finalized. Now as Mike mentioned, we'll put on hold our final investment decision until we learn the outcome from Rio Tinto's strategic review, but it is possible that Harapaki, and it's because of where it is located electrically, will get the green light even if Rio choose to close the smelter. And we've been actively working on engineering solutions to get access to the bottom 3.5 meters of consented water in Lake Pukaki. And we've solved the asset constraints, and we're confident now that we can access that water. As such, we've introduced the full consented range of the lake into our operating framework, and that adds 367 gigawatt hours of additional hydro storage to the New Zealand power system, about enough energy to power every household in [ New Zealand ] as it turns out. In Australia, we purchased 115-megawatt wind development license in northern New South Wales, and this should clear final regulatory approval shortly. But it won't be a couple of years until it's ready to be built. More immediately, we're working on a 20-megawatt battery solution to complement our Hume hydro station, which is part of the Greenstate assets. This will provide us with firming support and further reduce our reliance on caps to manage our retail exposure in Australia. It could also provide us with good learnings as we think this kind of solution may be a cost-effective way to increase North Island reserves and, therefore, commercial HVDC capacity in this country. We've recently decided to add people and resources to our renewable development team, so we can deliver on our ambition to build a strong and deployable renewable development pipeline on both sides of the Tasman. Now the increase in resource is not a material cost, but we believe it will create a material lift in our development capability. Looking at the policy and regulatory side of things. There's been some significant movements on a number of policy fronts over the last 6 months. During October, the government decided to move forward on most of the recommendations made by the Electricity Price Review. And yes, whilst I could pick on 1 or 2 of the 32 initiatives, we think, is a package that makes sense, and that overall, we're supportive of that recommended change program. Transmission pricing reform remains a hot topic, and it feels a bit like a mirage that whisks away the closer you get to it, certainly at Meridian. But we expect or hope the Electricity Authority will finalize its reform package around the middle of the year. The most recent interesting development has been the authority's consultation on changes to the prudent discount mechanism. The proposal would allow large participants to obtain a discount on their transmission costs and their comparable stand-alone costs would be less than what they would pay under the existing pricing mechanism. Now this could be very helpful for NZAS as there are very few people, if any, who argue that NZAS is not paying too much for transmission. In reality, NZAS have been subsidized in New Zealand homes and businesses for years. This prudent discount mechanism needs to be introduced [ to code ] immediately to give the smelter owners confidence they will get a fairer deal in the future, and we just can't see why it can't be. There's been 2 major pieces of legislation progressed by government in respect to climate action. The Climate Response Act was passed into law in November last year with strong bipartisan political support. I think we can be proud of our politicians on this occasion. They've shown leadership on an international stage and done our country in the world a great service. But at the same time, it is a bit disappointing that the fee base scheme designed to incentivize EVs has been scrubbed as this is one tangible policy that supported the larger goal. The Emissions Trading Reform Bill is progressing through the parliamentary process and is expected to pass into law by the middle of this year. The bill will enable price signals to emerge that align with New Zealand's 0 carbon target. I personally believe that such price signals and a well-regulated market are the strongest tools that we can wield to accelerate clean electrification of fossil fuels and decarbonize our economy. And it's a hell of a lot better than some central planner picking technology winners. Significant proposals for the management of freshwater are a major reform in their own right and have implications for all hydro operators. Key to this is the health of water bodies and a central framework for a new national policy statement on freshwater management. There is recognition within the policy statement of existing large hydro schemes but with some caveats. Overall, we think the direction of trade was positive for Meridian in the sector, but the reforms are dealing with a complex intersection of climate, environmental, commercial and Iwi interests. The work so far represents the groundwork being undertaken for a more significant reform of the Resource Management Act probably following this year's election. Meridian's near-term imperative is to reconsent the Waitaki chain by 2025, and the freshwater debate is pretty fundamental to achieving acceptable outcomes with those renewed consents. So the bit you've been waiting for, no doubt. As I explained during our investor call in October, we have been working with NZAS to enhance our contractual relationship in ways that benefited both parties. We're going to go into market to test the appetite of other generators to provide support for an enhanced NZAS commitment to New Zealand. We did this before and after the strategic review where it was announced with subsequently agreed terms of contact for more volume at the Tiwai node on better terms in our existing back-to-back arrangements, and we've been able to offer an improved deal to NZAS as a result. There's been little interest from the rest of the sector, so the NZAS software probably isn't as strong as we think it could or should have been. We have offers on the table to provide 622-megawatt and 450-megawatt options. 450-megawatt is an option for the smelter because they face a large upgrade bill in respect to potline 1 between, we understand, $60 million to $80 million. And the smelter owners could choose to retire that potline and avoid CapEx. From what we can tell, most industry analysts, some of them in this room, consider the likelihood of Smexit is low. I can't fault the logic as NZAS is reasonably unique in the high-purity and low carbon-intensive product they produce. And despite a relatively high cost structure, most of us still model them as being cash-positive. But it's not that straightforward. Two days ago, the smelter reported a $36 million accounting loss for the year. It's also a small part of a large Rio Tinto portfolio. And having met some of the senior Rio Tinto executives, I get this distinct impression they don't understand our nation's free market and nonprotectionist approach for large industrials, and they don't enjoy the same level of sovereign support as elsewhere. And lastly, the package of contractual enhancements that we've been able to put together goes nowhere near Rio's request for 1/3 of their current delivered energy bill. So what may seem logical to external commentators may not seem logical to the ultimate decision-makers in this instance. What I am confident of, however, is that if Rio decide to keep the smelter operating, they will provide a much stronger commitment to New Zealand through term. We've been very firm that we'll only entertain price relief if the effective termination notice period has extended significantly from the 12-month overhang we have today. I'm also confident that the deal we have on the table represents Meridian's point of inference. Smexit would be disruptive in the near term, there's no doubt, but it would also facilitate a significant restructure of the competitive landscape in both New Zealand's retail and wholesale electricity markets. And whilst the industry has not been keen to wear a fair share of the cost of the NZAS contract, Smexit will force the redistribution of low-cost hydro generation. And beyond that, Meridian's strong brand positions and renewable cost structure means we are well positioned to benefit over the medium to long term. The first tangible mitigation to a possible smelter exit is well underway. Contact and Meridian agreed to jointly fund the early phase of Transpower's lower South Island grid upgrade. This work was necessary to avoid around 1,500 gigawatt hours of annual spill through Manapouri and Clutha schemes that would occur if the smelter closed. And we understand work is progressing well on this. And because Transpower have got it going, it is now feasible that the entire program could be completed by middle of 2022. The potential constraint would then move north to the HVDC in central North Island. Transpower have identified around $500 million of unapproved spend that may be needed before dispatch -- full dispatch of southern generation into Auckland can be achieved. However, this being -- may be mitigated to the extent more cost-effective North Island reserves can be procured. The growth in customers on our Flux platform continues, and we're now past 400,000 customers. Our project to migrate the Meridian customer base to Flux -- to the Flux platform is tracking slower than planned. But we've recently reaffirmed the business case benefits, and they are as strong as ever. And most importantly, the 60,000 customers migrated to date have all had a seamless experience. So on balance, I'm satisfied with progress. As I mentioned earlier, we had quite a win late last year when we agreed with npower to add a further 200,000 U.K. customers to the platform this calendar year. In the context of the merger between E.ON and npower and the massive cost-out initiatives being contemplated by the merged business, this is a vote of confidence in our platform, we believe. Our job is to demonstrate that the platform can scale efficiently, both technically and operationally. In the context of Meridian's business, Flux remains an interesting proposition for us as it has significant potential upside for relatively modest ongoing investment. So to sum up, we've had a great first half, and the momentum is continuing into the second half of the year despite some constraints with the HVDC this quarter. Rio Tinto's decision on the smelter due at the end of this quarter is fundamental, but our job is to ensure Meridian is well positioned to respond to whatever that outcome may be, and I believe that we will be. Further ahead, the government's environmental policy set will lay the foundation for a cleaner energy future. And that, I will -- believe will be made possible by the renewable electricity advantages this country has, and few others can match. Thank you. That concludes our presentation. We're now happy to take some questions. And I think we'll start with people in this room in Wellington, our office here, and then we'll go to the phones.

Neal and Mike, great result. I'm sure everyone's very happy with that. A few questions from me. Actually, starting with just making sure I heard it properly, Mike. You'd sort of alluded to some capital raising for funding Harapaki. Was that right? Or is it -- and I'm assuming if so, that's more debt as opposed to equity.

It is, yes. It is. Yes. You heard me right. And it is debt funding.

Okay. I can relax now. Second question, just around the smelter. I mean what is your level of confidence around timing sort of before the end of March? I'm sort of aware that there has been some suggestion in the office had an expiry, well, close towards the end of this week. But what's your sort of thinking around timing?

Look, we're working with them progressively. That will give us some guidance as to their timing. They haven't given us anything more than they told the market. So that's still aiming for an end of first quarter decision. We'll make sure that whatever we've got on the table works with that.

Okay. Next question is just around, I guess, the C&I market, and I know that's been something that you've done particularly well on over the last 12 months or so. And Contact was talking about -- and they effectively exited the market -- but looking to come back and [ offer ] that contract for years. How do you see that playing out from a competitive perspective in terms of your C&I book going forward?

Yes. I mean we tend to run our customer business alongside margin available in the respective segments. And so we're looking at levels of competition in the C&I space alongside the residential, agri and small business and trying to make the best decisions that we can to increase margin for the business. C&I space, as you mentioned, is becoming more competitive as others see that it's an attractive proposition. So if that played out, you might see us deploy our position in other segments.

Yes, I'll just add to that. I don't think there's any secret, but we've always said that Meridian historically has been heavily weighted towards C&I, in particular, with the NZAS arrangement. We're heavily weighted to top-end business, and it's our strategic goal to rebalance that weighting more towards the mass market. But we'll -- yes, we'll assess how the market is behaving at any point in time. And that sort of can drive a push back into C&I if the opportunity is there, yes.

Okay. Next question is just around Flex. And are you able to give us any sense of what earnings impact you might get from taking on those 200,000 customers?

It's in a few million dollars per annum, yes. So it's still modest in the scheme of Meridian's profitability, but the growth potential is massive if we're successful.

And second to last question from me. Just the drought conditions in Australia and the numbers, the metrics you've reported around Hume, is that sort of current up-to-date numbers? I mean I guess they have had a fairly significant rain. And so has that kind of bypassed Hume? Hasn't it just come over to Fiordland?

Yes. So the drought continues for our assets in Australia. As you said, they had localized rain on the Coast, but those catchments are in land and haven't received any rain. To give you an idea, the -- on average, those assets produce about 280 gigs of energy a year. This year, we'd forecast that they might produce about 180 gigs given the drought that started some time back. They run multi-year droughts in Australia. And the forecast that we have now are just above kind of 120, 130 gigs. So you can see how it naturally starts to bite as the kind of years progress. So hopefully, that helps.

Yes. And very last question. Just I know you don't like giving guidance at all, but I mean when I look at where are your positions, January was a pretty good month, notwithstanding the transmission constraints that were in place. What's your level of confidence, I guess, that you are going to be looking at a better result in FY '20 versus FY '19?

Look, we don't give guidance, Andrew, and we're not going to change that. We do give our monthly operating stats, and you can probably form as good a view in terms of where we're going to end up as we can, to be honest. Good question, though.

Four for me. First question. Your retail mass market, specifically strategy in New Zealand, you've also been growing that book for a while. So what's your goal in that space?

Continue to grow it.

And in a similar vein, if you just sort of reiterate or update us on what your portfolio and sort of strategic goal is for Australia around, obviously, retail and now with a bit of wind as well to sort of where you see that heading. Third one is a bit of a pointy-head one. It's just to get a feel, with the accounting depreciation taking another step up yet again, whether or not this large gap growing between the tax cash yield and sort of the notional accounting one and how that's affecting sort of the cash tax side of the business. And the last one just on decarbonization, your thoughts on the likelihood of, particularly process heat conversion with some comments from Fraser Whineray just today, suggesting that he thought boiler conversion at current sort of -- or at the expected sort of ETS pricing would be breakeven for a process load, would be below LRMC of any of the projects available to electricity generators.

Okay. Well, I'll probably cover the first and then you get the second. So our retail mass market goal in New Zealand, as I explained, the overarching strategy is to reweight our customer base more into mass market. That just takes away customer risk, customer concentration risk, and the margins tend to be stronger in the long run. We are pushing heavily with our power shop brands. So that's our hero brand, if you like, and residential, in particular, at the moment, and we're getting good traction there. But we'll adapt to how the market operates and behaves, but that's the overarching goal. We don't have any headline numbers that we'll be satisfied at this point, Nevill. It's just it's got to be quite a bit more than what we have today. And in terms of Australia, look, a year or 2 ago, we were talking about -- and when we had, I think it was, close to 100,000 customers, we were talking about at least quadrupling the size of that customer base. So we want to be to 400,000 to 500,000 in residential customers with a reasonable amount of business flow to go along with that. That goal hasn't changed. In fact, we might start to get a bit more ambitious in that ultimately if we continue to track the way we're going. So yes, we are looking for a sizably larger business in Australia. And with that will come a need to provide more generation support and potentially [ firming ] support with that.

Very good. On your last 2, the accounting depreciation versus tax depreciation. I'll come back to you after this. I don't have the numbers to hand, but your general sense would be right. On decarbonization itself, I think your comment was the economic value or cost of decarbonizing was below LRMC for process heat needs in New Zealand, and we'd agree with that. The obvious rub there is how the price for emissions just in the mergers, right? So it's really a trade-off, what's your cost of electricity versus what's the cost that you're paying for emissions that you'll be making for process heat.

Thanks, Mike. Yes. So I think what that means is that you wouldn't expect to see a rapid conversion of that, at least on pure economics grounds, until we see a much higher ETS price.

Yes, yes, I think that's right, Nev. We're obviously open to -- we've been in that conversation with Fonterra and others for some time to get a sense of those economics. We know that the boilers in those facilities have economic lives that extend beyond the next couple of years as well. So there will be some decisions that are made. There will be both economic decisions and people thinking about their reputations as well, but there are some economic challenges in that space right now.

So we -- I think we've dealt with the questions here, so we can go to the phones.

[Operator Instructions] Your first question is from the line of Grant Swanepoel from Craigs Investment Partners.

First question is just a bit of a [ clarify ] first. You talked about subdued demand growth. You're talking about carbon conversion being low in the medium term. And now you got all this wind that's coming online. You've got Genesis and [ Artis ] in solar. You've got Contact, probably having that contract with Tiwai changed linked to a build-up of geothermal. And you guys have just added another 400-odd gigawatt hours to your Pukaki production -- gas production. So where does this really leave your wind opportunity with oversupply facing the market?

Grant, I think the way we look at it, I mean, we'll look at the project stand-alone in the first instance, will it be economic based on our view of forward prices over the term. So it is an economic project today. It's probably -- it's more than likely that it is today. Then we look at the portfolio impacts and the wider market implications. So we do take that into consideration, and that's why the NZAS decision is quite -- will have an impact on the way we think about Harapaki. But the point I made about that particular wind farm is it's electrically uniquely placed in terms of it joins into the 220 kV line that hooks into the Wairakei Ring. And that potentially leaves it on the northern side of constraints that will start to develop if the -- if it were to exit New Zealand. So it's got an interesting angle from that perspective. We're still trying to analyze it and understand it, Grant, and how that would work with Meridian's portfolio overall. But that's -- so that's how we're thinking about our particular wind option.

I'll add to it. And it's a good question. It's an obvious question that sits out there, right, as -- but we've modeled this for a long time. Different demand growth assumptions are alongside the developments that others have got, all of which we know and everyone else knows. We think there is room for those developments, including Harapaki. And we would note that we expect effectively thermal to renewable conversion to take place. So there will be some retirement of pretty sizable contributors on the supply side over that period that we'd invest. So we think the energy can be fitted into the energy system effectively given underlying demand growth and the conversion from thermal to renewable fuels over time. But as Neal said, we've got to be confident and careful of the decisions that we make.

The next question on the lower South Island link upgrade. While you are indicating that mid-'22 is likely the new clean state, is this a binary release of that 1,000 to 1,500 gigawatt hours of blockage? Or does some of the project lead to some release at an earlier stage?

You're the closest we've got to a transmission expert at this -- certainly at this table.

It is binary, Grant. So there is a complete release of that energy. The majority of the -- yes, sorry, go.

All right. The date you use of mid-'22, I was under the impression that the work program [indiscernible] earlier. Or are you just using the old date at this stage?

So we're using the date that we have signaled publicly previously, Grant. There is obviously potential if they get good conditions that, that work could be finished earlier. And then as you noted in your question, they might complete components of that work that might release marginally increased energy flows through that area of the grid, but the big upgrade and the value comes from the Livingstone to...

Roxburgh, right?

Yes. To Roxburgh line. Right? So that's the line. When you duplex that facility is when you really do release that renewable energy. And it increases the transmission capacity down there from about 600 megawatts on average to 1,200 megawatts on average. So that's the one to look for in terms of timing. And Transpower, as Neal mentioned, Transpower is making good progress on the work that they're doing today, and as we are understanding it, not spending as much money as they contemplated originally. So things going pretty well.

And my final question is on -- just a follow-on from Nev's question on retail margins. So your retail pricing was flat, and Genesis been showing some recently, they've been bitching that you guys are the ones that aren't passing on the cost of generation. You're cross-subsidizing. What is your view on this? Or is this more that you're taking a longer-term view on retail contracts?

I don't think Genesis should really be commenting on our pricing strategy. We have our own view here, Grant, and as I said, we do take a longer-term view of what we think is happening, particularly in wholesale prices, and we reflect that into our retail position. So we've got our own position. We've got our own view of the future, and we price as a result of that.

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

A couple for me. Just wondered if you can give us an update on your expected RCP3 savings. I think you had talked about something like $26 million annualized from March of this year. If that was still the right number to be working off. Secondly, could you just help us try and size the benefit of the Pukaki contingent storage increase? Obviously, I think that's available only under certain hydro risk curves. So just wondered how we should think about that sort of the benefit of that increased storage in the mean year. And then just on tax, you've paid roughly your full year '19 number in the first half of '20. Could you clarify whether or not you're expecting to pay any more tax in the second half?