Meridian Energy Limited (MEL) Earnings Call Transcript & Summary

Good morning, and welcome to Meridian's 2020 Annual Results Call. I'm Neal Barclay, Chief Executive of Meridian Energy, and I'm appropriately physically distanced, just, from Mike Roan, Meridian's CFO, here in our Wellington office today. The results that we're about to present is a particularly strong one, especially as we manage to shade the FY '19 EBITDAF outcome. And FY '19, as most of you will be aware, was one out of the box. And whilst I know most people on this call probably can't wait till we get to the NZAS bit, you're going to have to just humor us a bit as there's a lot that has occurred in the last 12 months that we want to talk through. But a spoiler alert, probably can't add anything to the stage exit negotiations currently underway. That said, we aren't getting too carried away of ourselves as conditions have moderated in the second 6 months and clearly, there are a couple of sizable challenges on the horizon. And whilst EBITDAF was up, reported net profit was down by 48%, largely driven by noncash fair value adjustments of hedging instruments. Mike will get into that in a bit more detail, but I don't think it reflects the strong underlying business performance. Here are a few of the highlights. EBITDAF is up 2%, and that's a quality result. And that's the thing I'm most proud about, particularly when compared to the prior year. Our FY '20 outturn was driven by a significant lift in volume and pricing of contracted retail sales on both sides of the Tasman. We delivered strong growth across all customer segments. Our customer retention rates improved, and the Meridian brand sets the benchmark for retention in New Zealand. Our cost to serve per customer also continued its downward trend. Hydro conditions were favorable in New Zealand, but the team did exceptionally well getting away a record amount of generation, given the HVDC was heavily constrained in Q3. It costs a reasonable amount of money to hedge that outage, but even so we materially outperformed our expectation during the event. The continuing drought in Australia significantly impacted our hydro generation, which was around 40% of average, and we saw wholesale prices soften materially during the second half of the year. However, much of the position was well hedged and the business was largely immune from falling wholesale prices. FY '21 will be more challenging for MEA, but the silver lining is our hydro catchments are filling up fast, so hydro generation should recover during next year. My sense is that at our -- at the electricity sector in New Zealand and more generally in New Zealand corporates have responded well to the COVID pandemic to date and genuinely put customers first. I'm proud of how our team reacted and given that we are still a long way from out of the woods, you can expect us to continue to support our customers where we can. What worries me most in our business is keeping our people safe. And clearly, our safety performance needs to improve. We had 8 LTIs during the year, and 3 of those resulted in serious injuries. But worrying about it doesn't make it better, so we remain very focused on making tangible progress evolving our workforce safety culture. I am confident that the lag injury rate indicators will start to improve in line with the work we're doing to manage all aspects of what we do safely. Like most Kiwi and Aussie businesses, escalation of COVID levels forced us to quickly find new ways of working while continuing to deliver the essential services for our customers who themselves are facing significant disruption. Now the response of our people was awesome, frankly, and I couldn't be more proud of them. Mental wellness will continue to be a focus for us, and I'd like to acknowledge our team in Melbourne, who have been working from home since March, but continue to do an awesome job. Some of our gender balance targets remain stubbornly hard to shift, and we're particularly disappointed not yet to achieve our target of 40% of women in senior leadership roles. We need to do better, but I'd love to get investors out to some of our generation sites as we have some awesome women leaders now working in what have traditionally been male-dominated teams. Retaining skilled, engaged staff must be a goal for every business, and so we are committed to the New Zealand Skills Pledge. We will bring -- this will bring further investment in technology and training to better help future-proof our workforce. And lastly, as you can see from the chart, Meridian's team remains well engaged with our business, our customers and our purpose. Whilst the strategic direction is largely unchanged and hopefully familiar to you, obviously, responses to COVID and the NZAS exit are now part of our future. Over the next few slides, I will cover off some of the highlights and some of the challenges in front of us. We remain absolutely committed to demonstrating sustainable leadership and to our purpose of a clean energy for a fairer, healthier world. Operationally, we have many more runs on the Board in terms of our emissions footprint, climate and carbon reporting, and we have achieved changes in the certification of our financing and customer propositions. At a more strategic level, debate on the merits and consequences of pursuing 100% renewable electricity grid continues. We concur with virtually every study done that the current industry settings are pure, and pure economic fundamentals will deliver a largely renewable electricity system within the next 10 to 15 years. Eking out the remaining 5-or-so percent of gas firming will likely drive up the cost of electricity and reduce the incentive to electrify transport and industrial heat, and that is where the real decarbonization opportunity lies. Our strong view is government policy initiatives should focus on stimulating demand for electricity, not so much the supply. I'd also suggest that a strong transmission grid is the single largest enabler of generation competition, renewables growth and ultimately, lower prices to consumers. So policies that support Transpower continue to sensibly enhance the grid are also very important. Now I joined the industry in 2008. And since that time, collectively, I think the -- sorry, the sector has definitely delivered a more secure and more reliable electricity system. And most importantly, Kiwis are paying less in real terms for electricity than they did back then. But energy hardship remains a real issue for many New Zealand households. COVID has, in some case, exacerbated that as well as negatively impacting the cash flow and viability of many New Zealand businesses. We have responded by providing a greater level of support for our customers. As you will know, in 2018, we stopped clawing back PPDs from customers who were late paying. And during this pandemic, we have offered customers individualized payment solutions. We've created a targeted credit fund for business customers in real need. We've implemented a blanket no disconnections policy for COVID-related debt, and we suspended all late payment fees. There is a cost to this, and we are carrying a high level of debt provision as a result, but it remains the right thing to do. We also wanted to do more to help families facing hardship. So we match the $1 million donation other generous Kiwis made to KidsCan. With that additional money, KidsCan are able to give children in hardship a hand up and the best chance of an education, and hopefully help break the cycle of poverty. We've shown support for our suppliers by shortening up our payment cycle to help support their cash flows. And in recognition of the new challenges our staff face during lockdown, we supported them with a working-from-home allowance. As I said earlier, I'm proud of how our team have responded. More generally, I think New Zealand businesses are playing their part where they can. There was enough pre-COVID organic demand growth to offset the shortened dramatic hit to demand that came during the Level 4 lockdown, but it is difficult to get any kind of gauge on future demand given the uncertain economic outlook ahead and the future exit of 5,000 gigawatt hours of NZAS load from the system. It is interesting to note that the sharp drop in demand during alert Level 4 is of a similar quantum to what we expect to happen when NZAS closes. To have a final TPM decision now in place is a welcome last milestone in a very long process. The Electricity Authority's estimates show Meridian's likely future cost reductions on this chart. However, it is worth noting these cost levels assume NZAS remains as a market participant. With their exit, we expect our share of HVDC costs to be higher than this FY '24 estimate, but it's difficult to ascertain by how much at this stage. On the negative side of the regulatory ledger, it is fair to say we were blindsided by the authorities' preliminary decision of an undesirable trading situation relating to the unprecedented flood events of December 2019. Our focus at the time was on managing an enormous amount of floodwater through our catchments. It's not readily appreciated how well hydro generators do this, I think. For comparison, when you look at the flood damage that occurred on the uncontrolled Rangitata River during December, which included 9 of Transpower's pylons being wiped out. The true level of avoidable spill during the flood is in the margin of error and customer impacts are small. Clearly, a few parties who speculate on FTRs and take exposure to the spot market missed an opportunity to profit during this time. But given prices throughout December were on average the lowest of the calendar year, it's hard to see how anyone can credibly claim to have been materially out of pocket. At a technical level, we believe the basis for the decision is incorrect as nothing occurred that is outside the past observed normal operation of the market. The preliminary decision also contradicts decisions made by the authority in previous investigations and effectively rewrites the rules of what defines the UTS, including a new test that prices need to be what the authority would expect to see, which is a very low bar. Clearly, we don't think this is the authorities' best work, but we do acknowledge there is a wide range of views on the matter. And we also believe that the Electricity Authority is a capable and constructive regulators. So being at odds with them on such an important issue is not where we want to be. We would prefer to work with the authority to find a sustainable solution, and we believe that should involve using the code reform process, supported by consultation and appropriate cost benefit analysis to establish the need for change and how to best implement any change as a result. These views have gone into our submission to the authority, and we'll see later in this year what the final decision is. On a much more positive note, the coalition government's climate program is moving forward with the strengthening of the ETS. Caps, containment and industrial allocation phasedowns will result in stronger price signals that will enable more efficient investment decisions and emission reduction. New Zealand has plentiful renewable electricity resources available to support the country's decarbonization, and I applaud the government's climate change response. Also, it was great to see the government's water reform program to improve water quality, sensibly recognizes the role of New Zealand's large hydro schemes and how they will play a part in a better future for our country. These reforms also put the concept of Te Mana o te Wai, the mana of water, as a central concept in the future water planning. This perspective and value -- sorry, the perspectives and value of Iwi will rightfully be more important than in previous resource management processes as a result. And so to NZAS. According to my spoiler alert, to be clear, we are working to an August '21 smelter closure date. There is dialogue with Rio Tinto on a possible staged exit, and I believe they're having further discussions with government in relation to transmission costs. But I don't have anything further to provide on that currently. Last month, we outlined the steps we will take to respond to the exit. The list of potential mitigations is growing, and we are getting traction in some key areas. Most importantly, Transpower confirmed a May '22 or earlier completion of the Clutha Upper Waitaki Lines Project. This project will allow all of the energy from Manapouri and Clutha schemes to be exportable from the lower South Island by most 9 months after the smelter scheduled closure and possibly even sooner. And a potential partnership with both Contact and Transpower, we are moving forward on our North Island battery development, and that will then further increase the economic capacity on the HVDC and allow export of more of the energy to the North Island. We've taken the decision to defer the build of our Harapaki wind farm in Hawkes Bay. The project itself is shovel-ready and economically viable even with the smelter hard close -- smelter's hard closure scenario playing out. So we will review the build decision as uncertainty around the smelter exit starts to dissipate. But at this stage, spring '21 would be the earliest possible commencement date. Whilst we cannot save our way out of the near-term revenue reduction from the smelter exit, that does create the opportunity and imperative to further optimize the business cost structure. And in light of the likelihood of restricted Manapouri generation between August '21 and May '22, we are reprioritizing asset management work that will lead to some near-term cost savings. We're also fielding plenty of inquiries from parties who would like to establish alternate industries and take advantage of the renewable electricity available in south -- in the South Island. Some of these parties are very credible, but any development is likely to be around 3 to 5 years away. So we're not relying on it as part of our immediate portfolio response. Continuing the momentum we have established over the last 2 years, growing our retail business is also a key mitigation measure. I've read some industry analysts calling out concerns around heightened retail price competition emerging. I think that is just the nature of the competitive market that we operate in. We've also noted comments made by other large generators about how things may play out after an NZAS exit. Now it's clear we've all got slightly different views of the risks and opportunities our respective businesses face, and that's not too surprising. But from our perspective, there are many moving parts, and the worst of the news is certainly out there now. But I'd make the following overall observations. One, transmission is the enabler of competition and must be prioritized. Two, being a long generator in a market with excess supply is not likely to be a winning strategy in the long run. Hence, you can expect Meridian's mitigations will focus on bringing our position into balance. In this regard, helping to facilitate new load in the South Island hands down as the most valuable play for our business, followed by growth in retail market share. Three, large volume intergeneration deal -- intergenerated deals have a part to play as they enable parties to better manage their risks through the changes ahead, but I would not expect them to have any real bearing on the economic fundamentals that will drive generation retirement and new development decisions. In summary, an NZAS exit was not something we would have chosen, but at the same time, it was kind of inevitable. In the mid to longer term, we are in the unique position of holding 5,000 gigawatt hours of renewable energy advantage, and I'm confident we will execute on our mitigation strategies and build an even more resilient business. Now during the year, we worked out how to gain access to the full consented range of Lake Pukaki. I know we've talked about this on a couple of investor calls previously, but for completeness, I wanted to touch on it again because it's a very successful initiative delivered by our hydro team during the last financial year. In simple terms, we now have access to another 367 gigawatt hours of fuel. That's the equivalent of new medium-sized wind farm for around $15 million. The additional gigawatt hours also create greater flexibility to balance out storage and production, particularly where there are constraints on the HVDC. We have modeled that in the order of $10 million to $15 million per annum of energy margin uplift. The next few slides provide an update on Meridian's operating units. I mean our customer team's performance during the last year has simply been awesome. We added over 1,100 gigawatt hours of contract load in FY '20 at improved average prices. Brand strength, service accuracy, higher retention rates and reducing cost to serve have all supported growth across all of our customer segments, and that's something that we've continued to see through July and August of this year. As I said earlier, maintaining this momentum is massively valuable going into a future without NZAS. But we're also very aware that the competition isn't going away anytime soon, so we'll need to get appreciably better to continue to win. We had record generation in New Zealand in both wind and hydro. And whilst we enjoyed above-average hydro inflows, the wind team managed to lift wind farm availability, and our wholesale crew navigated the significant period of interruption to the HVDC flows. So I think on balance, we've got the very most we could have out of our generation fleet this year. The strong generation volumes obviously helped offset the expected softening in wholesale prices, which saw our average generation price fall 28% in the year. The forward curve suggests the gas scarcity that has led to elevated prices over the last couple of years is going to be overtaken by the likelihood of an NZAS closing next year. A period of soft wholesale prices is probably inevitable. Like in New Zealand, our Powershop teams in Melbourne and Masterton continued to deliver the goods. Electricity customers and sales volumes are up around 24%, and our carbon-neutral Victorian gas offer is gaining real momentum. Our retail margins remained solid, but headline prices have fallen in line with the wholesale price reductions. The Australian market isn't without its COVID impacts either. Lower industry churn rates have slowed our acquisitions in recent months. We've also boosted our doubtful debt provisions significantly. We still see plenty of upside growth potential for our Powershop team in Australia. The now familiar New South Wales drought conditions persisted through FY '20. However, in what is hopefully something of a circuit breaker, storage is improving quickly, and we are now having the novelty of near seasonal average storage. Generation prices were well off during the year with record domestic gas production and less LNG exports ultimately driving lower electricity prices. Our team got ahead of the softening market and hedged a large proportion of our generation to both black and green prices, but the outlook for FY '21 will certainly be more challenging. However, over the medium to long term, the trading condition still look favorable in Australia as it comes to grips with the decarbonization challenge and as the aging coal-fired generation fleet marches towards their inevitable retirement. So we continue to actively seek generation development and firming options to support our planned growth of Powershop. Most recently, we completed feasibility work on the 130-megawatt Rangoon wind farm development option, and we've made good progress on a firming battery option adjacent to our Hume hydro station. Mike will talk to the project to migrate the Meridian customers to the Flux platform shortly. I'll just make some overarching comments that it's taken longer than we expected, will cost more, but not to a material degree. Most importantly, we're still confident in the benefits that drove the business case, and we've migrated over 100,000 customers now with very little fuss at all. Flux's continuing relationship with Powershop U.K. is uncertain though. Powershop U.K. are owned by npower, and npower have now completed its merger with E.ON. Both npower and E.ON have announced their intention to move their customers to the Kraken platform owned by Octopus Energy. But as yet, there is no decision about the Powershop U.K. customers. So on that not so cherry, but also not too surprising note. I'll now hand over to Mike to talk through the financials in more depth before I round up at the end. Thanks, Mike.

Thanks, Neal. We've just had another tremendous year. And the results that I'll talk to in a minute are driven by a very talented and committed team in New Zealand and Australia. That not only delivers in the current environment, but has been testing how it might overcome the set of challenges that closure of the Tiwai aluminum smelter might bring. So alongside taking pride in the outcomes from fin year '20, if that plays out, the team is looking forward to proving to you, our shareholders, that we can create more value than we would have, had it stayed. Time will tell where the smelter does go, of course, but competition is a wonderful thing, and there's plenty of value to unlock going forward. But back to the year that was. As you all know, the financials were solid. While accounting measures like net profit after tax were well off last year's run rate, noncash items drove that reduction, and we tend to look at EBITDAF as both a comparative measure across energy businesses and across time. And the small lift in EBITDAF this year to $854 million is very satisfying. If I dive into that figure a little, and as I stated during our interim announcement, this outcome was driven by outstanding execution in New Zealand, where EBITDAF lifted by $20 million, while Meridian Energy Australia more than held its own as the team there lifted EBITDAF by $2 million. The reduction in transmission expense in New Zealand that started to flow through in April didn't hurt either, but our increased costs while being well signaled brought us back a touch. All in all, and as I say, very satisfying. Alongside EBITDAF, I tend to look at operating cash flows as my measure of underlying performance. And here, again, we had another strong year with net cash from operations at $605 million. If I compare this to operating cash flow from 2 years ago, it's up a whopping 42% or $178 million. That said, it is $30 million lower than last year, but largely because cash tax was $43 million higher in fin year '20. And the strong cash flow is crucial, not only given the change coming at us, but also has helped maintain a strong balance sheet while letting us support our people, customers and suppliers during the first lockdown due to COVID. It also meant that financing needs were well down on last year, even as we lifted the ordinary dividend. As a result, net debt only lifted by $52 million over the year and the key S&P ratios that supported our BBB+ credit rating, net debt-to-EBITDAF and EBITDAF interest cover at 1.8 and 10.3x, respectively, didn't move substantially during the year, which is a perfect segue to dividend flow. On 10th of July, we announced the cessation of the capital management program, so that doesn't factor into the conversation today. However, given the strong year and our healthy cash flow and balance sheet, we've decided on a final ordinary dividend of $0.112 per share. This means the total dividend for fin year '20 is $0.1934 per share. And while this represents a fall of 9% on last year, that fall was driven by the cessation of that capital management program. With this in mind, the lift in ordinary dividend of 3% is pleasing. And to save on valuable question time, we recognize that there's uncertainty about future earnings and cash flow of the business, but we won't be moving away from our policy of not providing earnings and dividend guidance today. So on to New Zealand performance. As you may recall, we had a strong first half in New Zealand this year, the best first half ever, in fact. While second half wasn't as strong, the teams navigated a 3-month HVDC outage expertly and without fuss, as I suggested they would, COVID and towards the end of the year, the beginnings of a drought that's extended into August. At the same time, I can categorically say that we have a customer business with strong momentum. In Neal's earlier slide, you would have seen that customer numbers, volumes and prices were all up in 2019. Here, you can see how that momentum translated into value. Contract sales across our customer segment lifted by $142 million year-on-year, and that, in turn, delivered an $18 million lift in energy margin for the customer team. At the same time, strong generation volumes supported higher wholesale derivative sales. But as prices fell year-on-year, the value of those derivatives sales fell by $17 million. The wholesale team also did a stellar job of managing risk during the 3-month HVDC outage where they bought over 500 gigawatt hours of derivatives and 150 megawatts of FTRs over the past 4 years to make sure our position remains sound. And these hedges contributed to the $43 million lift in the cost of derivative purchases. I won't focus on COVID specifically as while it did have a material impact on electricity consumption in April, the effect were shorter and smaller than expected. Overall, New Zealand energy margin lifted by $14 million. And that may not sound like much and it is down from the first half uplift of $76 million, but I can tell you that retailing and wholesaling electricity is very competitive, and improving results takes considerable coordination, discipline and grit. So both teams have done a tremendous job. And while we're in New Zealand, as you know, we are contesting the Electricity Authority's preliminary findings that there was a UTS in December 2019. While we do this, we booked a $5 million provision in case the regulator maintains its position. We do not believe that would be the right outcome, of course, so time will tell whether this is a reasonable call to make or not. Moving on. As you can see from the graph, the customer story in Australia are similar, strong retail performance with electricity and gas customer numbers and contracted sales lifting. The wholesale story is similar too, with wholesale prices falling materially during the year. It can be a bit tough to pick this apart from this side of the ditch, but the volume growth across both electricity and gas businesses drove the $29 million lift in contracted sales showing here, whereas the price falls held this lift in check. And while wholesale prices did fall materially with Vic fin year '20 futures trading $110 a megawatt hour in November 2019, but falling to $73 per megawatt hour by June, as can be seen, the position was well hedged in those derivatives, added $9 million to the team's result. We also had a significant benefit from having hedged our LGC sales, which settled in February at much higher prices. And we gained $14 million from this. But unfortunately, that gain will not be repeated in fin year '21. At the same time, Meridian Australia's retail electricity prices, net of distribution, fell by 8% over the year. And the reason they fell is that there are 2 regulated price frameworks in Australia. One for Victoria, Victoria Default Offer, or VDO; and the other, for the rest of their national electricity market, Default Market Offer, or DMO. As wholesale prices fall, both VDO and DMO track with them. And as customers can access VDO and DMO offers from retailers, oil prices tend to fall or rise alongside those frameworks. While I won't do the calculations justice here, both use wholesale prices are component of their calculations, and therefore, they both fell and retail prices went with them. And before someone says that we should deploy this here, there are plenty of pitfalls in both. And given volatility in underlying wholesale prices in New Zealand, I doubt customers here would accept the price swings that would bring. At the same time, the Australian drought that I've talked about this time last year continued. For the full 12 months of fin year '20, the Green State hydro assets only produced 113 gigawatt hours, down from 203 gigawatt hours the previous year and a full 175 gigawatt hours of their average generation levels. The good news is that, while the above dynamics were in play, Meridian Energy Australia managed to lift its energy margin contribution by $4 million. This is solid outcome, given at interims the team was down $1 million on last year. And I noted that should the drought extend, our second half performance might be challenged. As we sit here today, there is some further good news and that the drought has broken and hydro storage lakes are filling nicely, but this is tempered by the fact that wholesale prices remain low. So the Australian business is in for another bumpy ride in fin year '21. At last year's results announcement, we look to set expectations in terms of cost by introducing a range for both OpEx and CapEx. At that time, we said that the fin year '20 OpEx was likely to fall in a range of $280 million to $286 million. I'll come to the waterfall chart in a minute, but fin year '20 OpEx actually ended at $294 million, so well above the top end of that range. At first blush, that's not flash. But as with most things, it is explainable. To do that, I first want to talk to the table that provides a legend for the waterfall chart. In fin year '21, we've moved electricity metering expenses into direct costs. We've done this as electricity metering expenses tend to move up if customer numbers are growing and down if they're not. So by removing this category, you should be able to gain further insight into operating expense movements generally. Therefore, and to provide a comparison between fin year '20 and fin year '19, we need to deduct metering expenses from operating costs for both years. We also need to adjust for IFRS 16 that I talked to at our interim results. Simply put, implementation of that accounting standards drops operating costs by $6 million year-on-year, and of course, lifts EBITDAF by the same amount. Having made both adjustments, the fin year '19 operating cost base was $243 million. And in fin year '20, it lifted to $258 million. This lift in cost was due to the following elements: a provision that we took for holiday pay of $6 million. The reason for this is there are risks that Meridian has to pay holiday pay on incentives, and this matter is currently before the court. We thought it prudent to capture this year just in case. There was also a $3 million lift in asset cost that is largely due to the Ohau refurbishment program. While we're also in the closing stages of a 3-year remediation program at Te Apiti wind farm, that brought that farm back to respectable levels of availability, and that program costs a little more than expected. I'll talk to our New Zealand asset maintenance program further at interims. As with the Tiwai exit in front of us, we'll likely reset our work program for Manapouri, White Hill and the Waitaki assets. If we do, do this, it will reduce our fin year '22 OpEx -- fin year '22 and '23 OpEx materially. And as we near fin year '23, we'll also begin to see the benefits of the customer team's transition to Flux. Both arrive at the right time, but I'll talk to that when we present our interim statements next February. The Australian asset cost increase was driven by Senvion, who provided O&M services at the Mt. Mercer wind farm being placed into receivership. I mentioned this at our interim announcement, where I said that we were able to leverage wider relationships to manage this failure. We did this. And as a result, we now have Senvion as our O&M partner at Mt. Mercer. This outcome did cost us some coin, as you can see here. And while most of this was legal cost related to the receivership and renegotiation, there was about $0.5 million uplift that represents an ongoing cost as opposed to a one-off. Insurance costs are an ever increasing, but important nuisance, and Neal talked to the COVID impact. Here, we simply frame up the costs across outstanding leave balances, working-from-home benefits and KidsCan, who does and do incredible work, by the way. And while it isn't captured as a cost item here, we did lift our provision for doubtful debts from $5 million in fin year '19 million to $15.7 million in fin year '20, given the risks COVID poses for the wider New Zealand and Australian economies. We haven't experienced any erosion in the quality of our debtors to date, so we will see in time whether this was overly cautious or prudent. So $250 million in OpEx came around pretty quickly. But when you strip out the fin year '20 one-offs like COVID and holiday pay, our OpEx lifted by $8 million year-on-year to $251 million. Looking forward, we expect to spend between $261 million and $266 million in fin year '21 or between $10 million and $15 million more than fin year '20 when removing these one-offs. The lift largely comes from growth initiatives that I don't want to lay out today for competitive reasons, but I will provide insight in them -- on them in time, either as this year progresses or as they deliver fruit. As I said right at the outset, we can see opportunities to unlock value given Tiwai's nearing departure in New Zealand, but we can also see them in Australia. As mentioned earlier, our net profit after tax fell by a sizable 48%. But when you add the fair value movements in electricity and treasury hedges, impairments that I'll talk to in a minute and the tax effect of those adjustments, the non-GAAP measure, underlying net profit after tax, only fell by 5% year-on-year, but still well up on 2018. As for those impairments, last year, we signaled that we were likely to take further impairments on our Australian wind farms, given forecast revenue streams for those assets fell faster than the depreciation expense associated with them. Back then, we took a $5 million impairment on Mt. Millar. This year, that lifted to $33 million, and the fall in Australian futures curves saw us impair Mt. Mercer wind farm by $24 million as well. And finally, in a note to the financial statements, we're providing an indication of the impact that an NZAS exit might have on the valuation of our generation assets should the smelter shutdown in August 2021. While that impact will become clearer in time, we consider that it could be an accounting devaluation of between $690 million and $1.3 billion. As I note, the outcome is uncertain, and we'll update it again when we present our interim statements. But if it proves accurate, this is similar to the uplift in value written into last year's financial statements. Not much to talk to here really. We spent $64 million in CapEx in fin year '20, which was below our forecast range of $70 million to $80 million. We'll roll that same range into fin year '21. In saying this, we might need to lift that forecast during the year as we expect significant progress on the project that is moving our customers over to the Flux platform. That initiative has been making good progress, but as captured in our integrated report, it has been rebaselined. The original schedule had completion of the transition by December 2020 and a total cost for the initiative of $31 million. We now expect it to be complete by September 2021, and total costs have lifted to $48 million. And while those changes dropped the net benefit of the initiatives, those benefits still remain strongly positive, and they continue to tell us that the Flux engine has real value moving forward. So if we do revise that range upwards, it will be because the initiative is making sound progress. I've talked too much of the slide, so I only want to cover one thing. And as well as unveiling our annual results today, something else we're unveiling as Meridian's new Green Finance program. As you'll be aware, as a company, we're deeply committed to sustainability. It is at the heart of our purpose and one of the key reasons we only generate electricity from renewable resources. We know how important it is for us to play our part to help combat climate change and recognize the critical role renewable energy plays in driving decarbonization of the wider economy. Meridian has a deep understanding of how climate change can impact its business now and in the future. We're the first company in New Zealand to prepare and publish a climate risk disclosure report. In addition, Meridian reports to the Carbon Disclosure Project and the Dow Jones Sustainability Index and is committed to the Sustainable Development Goals 7 and 13, which have been integrated into our business and our business reporting. As part of Meridian's ongoing commitment to sustainability, we're adding this Green Finance program to those initiatives. Our overarching goal is to reach a wider community of likeminded investors. And to do this, we need to keep building our credentials with those who may not know Meridian Energy directly, but are looking to place their money with businesses like ours. The Green Finance program should help us do that. It will also be used to finance or refinance projects and assets that deliver positive environmental outcomes. As of tomorrow, all of Meridian's existing funding will fall under the umbrella of this program, and our retail bonds listed on NZX will be designated as green bonds. We believe this will benefit investors by providing an opportunity to invest in a broad range of accredited green debt instruments. I'd like to thank Westpac for their help in implementing the program. And as you check -- and you can check out our website for more information. So alongside a great result, this is a nice addition to underpin the fact that we remain one of New Zealand's largest and most sustainable businesses. Neal, back to you.

Thanks, Mike. So I think today draws the line under a remarkable couple of years of financial performance. And based on forward wholesale prices, I wouldn't expect to see that level of performance replicated, at least not until the market fully transitions away from the loss of NZAS. That said, I can assure you that management and the Board remain strongly focused on managing the business and our balance sheet in a way that delivers a competitive dividend to our shareholders. The ongoing effects in both New Zealand and Australia of a lasting global pandemic is still highly unknown. The economic contraction and the lasting loss of business activity must ultimately weigh on electricity demand. But if I take a half glass full perspective, we now have certainty that an NZAS exit will happen. If not in the next year, then certainly within the next 4. The mitigations that we and many others in the industry are now turning our minds to, most notably Transpower, will make more renewable energy available more quickly than was the base case assumption prior to 9 July. I believe Meridian's low-cost asset base, a strong retail brands and our exposure to Australia still leaves us strategically well positioned to lead the sector. We've certainly got some near-term headwinds. But beyond that, the Meridian valuation in the sector fundamentals are strong. We are at the start of a great opportunity to reshape our business, the sector and drive New Zealand's decarbonization, and that's something that we will all benefit from. Thank you. So that's our presentation. We're now available to take some questions online.

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

Couple of questions. Firstly, on Harapaki. You've delayed your decision on that. I was under the impression that you didn't have the ability to extend your resource consent. Can we just start on how far you've been able to extend that consent until?

Grant, the consent lasts until 2023. So we'd have to have a meaningful project underway sort of late '23 to live within the existing consent conditions. So we've got a few years of time to work with.

So that means you've got a 6-month window to pull the trigger, is that correct?

No, no. That's 2023, Grant. So we could pull the trigger effectively earlier in that year.

On Flux, can you just remind us what those benefits were you mentioned about a year ago? Is it -- was it about $10 million a year?

Yes. It was about $80 million over a 10-year period. So -- and we've already actually taken some of them onboard with the restructure of our ICT group 1.5 years ago. With the additional cost on the actual project delivery, those benefits are reduced by about $15 million. But we're still looking at about $70 million to $75 million over the term of the life of the asset, if you like.

The UTS outage, the $5 million, is that the max penalty do you believe? And if it's not, what do you reckon the range of impacts and the timing of when you might have to pay up?

Well, I think the -- it's interesting. UTS isn't a penalty regime in itself. So if the EA want to restate prices, if that's where they go, then it's quite a complicated process because you'd have to restate prices for about 3,000 separate trading periods, which is -- creates some complexity in its own right. But when we've worked through and assumed a very low price, like around $6 or so, $5 million would be the maximum impact on our business.

Genesis in their results presentation mentioned that they would be looking for a long-term PPA with yourselves. Can you just talk to the trade-offs that you see in terms of putting one of those in place to give yourself some earning certainty in the near term against what you might give up in the longer term by putting in a 10-plus year contract with them?

Yes. It was interesting to see that from Genesis Energy because we certainly haven't agreed to a 10-plus year long-term contract with them. We are interested in talking to them on a range of issues and any other party for that matter. But certainly, we'd be looking at a -- if possible, we'd be interested in transition hedges that went out sort of out to maybe 5 years. We've also got the virtual asset swaps that start to wind out -- wind down in 2023, and we'd like to talk to both Mercury and Genesis about extending those transactions. They work well. They're market linked. So they don't leave anyone exposed and outside of the market for a long period of time. We'll always, as a South Island hydro generator, be interested in talking to parties about peaking or firming load in the North Island. So there's a range of options to discuss with our competitors. But I think -- yes, and you would have got the message earlier, our strongest, from a Meridian perspective, our strongest option is to grow load in the South Island, and beyond that, to continue to -- with the momentum that we've got in our retail side of our business. So a long-term hedge would have to be balanced off against those aspirations.

A nice segue to my final question, which is, can you give some color on the demand response in the South Island that you're talking to earlier on other than just dairy that we're all expecting something to happen in?

Look, there's a range of parties that want to talk to us and talk to other folks as well. It's -- yes, I don't want get into the details on any of them because the conversations are commercially confidential to a certain extent. But you would have heard talk of data centers, hydrogen facilities, carbon capture facilities. So there's a range of industries and some pretty credible players behind them that are pretty keen to engage.

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

A couple of questions for me, following on from Grant. First of all, just in terms of your ability to retail on the North Island and then your sort of confidence levels about being able to do that successfully, given the South Island basin and sort of dealing with the basis risk.

Yes. Thanks, Andrew. We're very confident about our capacity to run a retail business, both South Island and North Island, as you note. There are some products that we need to purchase to be able to do that, but the team has been well aware of this risk and understands that risk pretty well given we do retail in the North Island today. So they've either bought a number of products and will continue buying a number of products to help manage those exposures. But I think the kind of the key message, Andrew, is we're confident our capacity to grow that position and manage the risks associated with it.

Okay. And following on, I guess, around the Genesis question and then what Genesis was saying. So they made pretty clear that they weren't interested in the short-term contract, and I suspect 5 years might be viewed by them as too short term. How comfortable are you about operating without any agreement with Genesis? And is that a plausible scenario?

I'll tell you one thing I'm not comfortable about, Andrew, is having a negotiation on intergeneration hedge in public. So we'll probably park that there. But like I say, it is for us. And I understand their position, but our position is different. So these things you tend to work through and try and find a middle ground. And we're not only talking to Genesis about the sorts of cover that we're looking for, for the future.

Yes. Sure. Okay. And last question from me was just around sort of transmission costs. So I think you've provided some guidance around the DC cost expectation for FY '21. I'm assuming the other connection charges will be dropping as well. So are we sort of looking at around about $70-odd million all up for transmission costs as a reasonable assumption for FY '21?

Yes, Andrew, slightly higher, but in that ballpark.

Your next question is from the line of Stephen Hudson.

Just a couple of quick ones from me. Firstly, I just wondered if you could have a stab at estimating the cost of the HVDC outage over the second half. Secondly, I think Standard & Poor's have estimated that your trough EBITDAF on a hard exit would be around about the $470 million mark. I just wondered if you can give us a comment on the veracity of that number. Thirdly, could you just give us a bit of an update on Waitaki reconsenting and what, if any, risks surround that process? And just lastly, if you can sort of sweeping back to NZAS, give us a feel for how the $50 million to $70 million step-up in your offer actually behaves and why there is that step-up?

I'll cover the last 2, you cover the first.

Yes, yes, yes. Stephen, the cost of the HVDC outage hedging. I mentioned in my notes that we bought about 500 gigs of derivatives and about 130-odd megs of FTRs to cover that position, but are bought over a reasonable period of time. You would have noted that our overall cost derivatives lifted by $43 million over the year. Much of that was due to the covering that HVDC outage. In terms of the S&P kind of forecast for EBITDAF, I think you mentioned $470 million. You know we don't provide guidance on that, but we're probably a bit more optimistic in our opportunities as we approach that year. So that would be my response to that number specifically.

And Stephen, in terms of Waitaki reconsenting, yes, that process is going quite well. We've been -- we've had a strategy in play now for a couple of 3 years. We're maintaining strong relationships with all the key stakeholders, particularly those that we think will be critical in decision. And I'd call out Ngai Tahu dock, ECan, obviously. I'd point to the changes in the freshwater consenting -- well, freshwater regulations that the government announced, they do actually point to the importance of maintaining flexibility for those major hydro schemes around the country. So that supports our position in the reconsenting process as well. So yes, that's tracking well. No real red flags at this point, but it is a big process and it will go right to the 2025 deadline, I suspect. In terms of the step-up in the NZAS. This is the NZAS offer that we had on the table before they decided to exit New Zealand. I think that's what you're referring to. So it's kind of moot at this stage, Stephen, and it's not part of the transaction going forward in terms of the staged exit deal that we've got on the table. It had a number of components, but the reason why it stepped up between now and 2023 is we had a demand response part of the package on the table, and that would replace -- or a component of it, not most of the existing swaption that we have with Genesis that winds down in 2023. And there's been no secret that Contact have provided some support for the offers that we've had in place and the nature of their pricing changed a wee bit as well. So that sort of led the offer to improve over time. The other bit that was part of it was potentially a transmission underwrite. But again, it's all kind of moot in history because that's not what we're talking about with the staged offer exit -- staged exit offer.

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

Just a few questions for me. Just in terms of the demand stimulation ideas you've got in the South Island. What's the sort of earliest time frame you think we could see some material growth there? Are we sort of talking 3 years to 500-gigawatt hours or 3 years to 2,000? Just to set some kind of envelope around your expectations.

It's really hard, Nevill, but I would expect maybe 1,000 gigawatt hours. And so it depends on the nature and who actually gets the business case up and what actually ends up happening. But 3 years would be the earliest for a material chunk of load, I think. And probably within 5 years, hopefully, we would have filled the entire gap.

Great. And what sort of gap size do you think that is?

Well, we're losing 5,000 gigawatt hours with the NZAS exit. There's a potential to grow demand to that level and beyond, to be frank.

Right. Okay. Okay. No, that's great. Next question, just on the UTS. You suggested maybe a code change might be the better way to address the issues you think that EA is concerned about in the UTS decision or preliminary decision. Can you suggest what sort of code changes you think would be best?

Well, what we've put in our submission is we -- yes, we'd be up for actually talking about some sort of code change that went to spill pricing. It seems to be an issue that they're concerned about. It's -- like I say, I don't think we've done anything that's inconsistent with practice previously adopted by ourselves and other generators, but it is a concern for the Electricity Authority. So we should address that head on, I think.

Okay. That's useful. In terms of Flux as in Europe, if -- do you have an option to withdraw from the scheme? Can you -- I guess I'm wondering whether or not you can take the Flux idea to other potential partners over there if E.ON is going to move with Kraken and Octopus?

We did have a -- yes, we had an exclusivity arrangement with npower, but that expires at the end of this year if they don't hit certain customer targets. And it appears that they won't at this stage. So the exclusivity now we're locked in. We do have a 2-year termination right on the contract as well with the chunk of fixed revenues associated with that. So we've got wee bit of time to work our way through it. But as I say, we don't really have any clear guidance from npower or E.ON at this stage in terms of what they want to do with the Powershop U.K. customer base.

That's great. Very useful. And the last question for me is really just in relation to your Flux conversion here in New Zealand. I suppose it's a difficult time, given what we think might be happening with the retail market, competition increasing to be changing your billing platform. Are you comfortable that you're sort of in a good position to compete for new customers and sort of potentially elevated levels of churn as you go through that transition?

Yes. I mean it's running slower than we would have liked, but like it should be complete by September next year. We've already got 100,000 customers on it. We'll have most of the mass market customers on it before the end of this calendar year. And really, the time delay is down to the complexity in developing the product to manage the C&I segments.

There are no further questions at this point. Mr. Barclay, please continue. Thank you.

Okay. Well, thank you all for your attendance. We'll wrap it up there. Have a good rest of the day. Thank you.