MCY FY2019 Results Transcript

Mercury FY2019 Results Transcript Annual Results 2019: Analyst briefing transcript 20 August 2019, 11am Transcribed by West Pages: 16 Start of Transcript Operator: Ladies and gentlemen, thank you for standing by and welcome to the Mercury Annual Results Analyst Briefing.

At this time all participants are in a listen-only mode. After the speakers' presentation there will be a question and answer session. To ask a question during the session you will need to press star-one on your telephone.

Please be advised that today's conference is being recorded.

I would now like to hand the conference over to your first speaker today, Mr Fraser Whineray, Chief Executive.

Thank you Sir, please go ahead.

Fraser Whineray: Thank you. Kia ora tÄ tou, welcome investors, analysts, media and also in the room a substantial part of the Executive and others from Mercury.

I'm joined here by William Meek, the Chief Financial Officer, and it's our pleasure on behalf of the Company and the Board to take you through this kĹ?rero today about the FY19 full year financial results.

We have published materials on the NZX this morning which we will click through on the slides here. I assume that comes up on the screens you're watching as well, or you have copies in front of you.

This year we've had to work much harder for the outcome. Last year we enjoyed some tremendous or record inflows into the Waikato catchment and that flowed through to a record hydro generation and a record result.

We executed on a lot of things last year. This year actually we've had to work much harder for the financial result and many multi items have reached key milestones. So this is a year that we are particularly proud of.

I will just go through a couple of highlights and then William and I will work back and forth through the slide deck, and then we'll come to Q&A at the end.

So the financial result of $505 million of EBITDAF, that was achieved through - there we go, ignore the disclaimer.

Right, the financial result of $505 million of EBITDAF was achieved through mean or average hydrology.

Though there was a great illusion across the 12-month period of mean or average because it was very strong in the first two months of the year, which followed two years of very strong inflows into the catchment. Then went to second percentile inflows from September through to May, which was quite an extended period.

Offsetting that was some record geothermal generation, with availability at pretty much 98%. That was very valuable in contributing an extra sort of $10 million or so with those record spot prices to our overall result of $505 million.

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The $505 million was also achieved with a part-year loss of Metrix, and William will touch on some of those normalisation aspects shortly.

The market conditions, moving across to the second box there, market thesis. That is the slide you'll see later in the deck which we've been talking to since August 2016, three years ago.

The market thesis is being realised through supply and demand coming more into balance. Though it was exacerbated strongly this year by thermal fuel and thermal plant constraints. Now we're increasingly seeing the impact of elevated gas pricing coming through to dispatch decisions, for those parties that own thermal plant, and also investment decisions, for those parties that can see a better counterfactual and renewable fuel rather than purchasing gas.

That is a sense of dĂŠjĂ vu from about 15 years ago when that happened last time. With gas prices elevating we saw wind go from about 0% to 6% of the national grid, and geothermal go from 7% to 17% of the national grid. At the expense of baseload thermal fuel, whether it was coal or gas.

So there's a bit of back-to-the-future there, and I'm sure we'll talk more about that market thesis as we go through.

I think this year, and it's not on this page but I want to highlight it in the third spot to talk to, is this year has seen a tipping point I think in recognition of New Zealand's renewable electricity advantage for the country being recognised for what it does today and what it will deliver into the future. In terms of energy sovereignty, structural costs and the economy, and the opportunity which is now inevitable around the intersection of wind turbine technology with the wind fuel resources here and transport technology becoming electrified.

Both those global activities are receiving tremendous amounts of R&D production scale economies. One's a few years ahead of the other one, but they almost face an inevitable marriage here in Aotearoa. I think there's no Herculean technological assumptions you need to believe for that now to roll out.

That recognition came through in a number of reports. The Interim Climate Change Committee report, MBIE's reset, its forecast, the Productivity Commission, IEA reports et cetera. They think broadly we're looking at sort of going from 40 terawatt hours to 60 terawatt hours over the next 30 years per annum of electricity through those themes I discussed.

Just to put that into context, that is a Turitea wind farm every nine months delivered by this sector to achieve that.

So that is quite a change to how it's been, certainly since about 2008 when demand went flat. Now William will talk to demand later on, but I'm just talking more to the medium-term and long-term activities and the outlook for the sector and the country.

The dividend, the final dividend - and I'll leave many of the financial metrics to William to talk to - of $0.93 per share goes to $0.155 for the year. The point I want to emphasise here is that that is the eleventh year of ordinary dividend growth.

I will challenge any analyst, I'm sure they will be able to whip it up before the end of this call, to tell me the names of the companies on the NZX that have actually done more than 11 years of ordinary dividend growth consecutively and are still on that path, i.e. haven't fallen off it.

I think that is a testament to taking long-term views. Again you can only create long-term ordinary dividend growth by having long-term ordinary earnings growth. That's why we must continue to think about capital reallocation out of things that we don’t think are going to produce that growth, and into things that we think will and are a core part of our future.

Customer value has been very important to us. Well, I'm sure we'll talk about this more. We are focusing, as we've said, our three customer promises - make it easy, reward and inspire.

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We are focusing on rewarding that loyalty by keeping the economics and the proposition to existing customers as we can. We haven't shifted headline prices to core customers since April 2018.

We have reduced acquisition activity in this retail market as we try to bring on more customers on headline rates using other non-price attributes than simply deep discounting, for which we cannot get the maths to go around on.

Capital reallocation, just talking to that, out of Metrix $272 million after owning that business since 1999. Turning it into a smart meter business from a legacy meter business. We've put more growth capital, supporting Tilt on its Dundonnell wind farm in Victoria. We've committed to the first large-scale wind farm or electricity generation billed in New Zealand since 2014 with Turitea. Combined with our original investment in Tilt, that represents over $700 million of capital reallocation within the business, and we are - those are multiple year projects which we are pleased to have done.

Reinvestments continued. Hydro, Whakamaru and Aratiatia, geothermal, IT systems and also this year a four-year project concluded, or reached the end of its big milestone of getting three offices in Auckland consolidated into one here in Newmarket, along with a complete change in ways of working which is resonating well with staff and productivity.

I'll now hand over to William to talk through some of those key financials year-on-year.

William Meek: Thank you Fraser, and welcome everyone again on the call. We're on slide 4 now. It sounds like the CEO's done me out of a job and described most of the variances here anyway, so I'll just skip through quickly.

Energy margin dropping to $667 million for the financial year, largely driven by an 800-gigawatt hour reduction in generation volumes. Hydro trending out at mean, but certainly quite a different journey from wet to dry, through the financial year.

Operating expenditure is just under $200 million for the year, at $199 million, down $6 million. Again, IFRS 15 and IFRS 16 adjustment through there for revenue recognition and for leases. The delta really flat on the prior year after adjusting for the divestment of Metrix.

EBITDAF, I will bridge more fully in the next slide, and skip.

NPAT a record at $357 million, largely attributable to the Metrix gain on sale of $177 million, which happened in March.

Underlying earnings down $37 million to $161 million, again largely bridged by the reductions of $60 million-odd in EBITDA, offset by lower interest and tax. So, certainly we're seeing those - effects of those 10-year swaps rolling off, certainly lowering both interest expense and cash interest payments for Mercury.

Free cash flow down to $237 million, again driven by most of those EBITDA and tax interest movements previously. Also CapEx, which is down to $89 million, so down $23 million again, driven largely by the refurbishments on Whakamaru and Aratiatia, but also investments into IT, so Commerce Hybris, which is improving our customer experience for those on the Mercury brand.

Growth, $81 million, really driven by just two things; advance payments on Turitea, and $55 million into the Dundonnell capital raise for Tilt Renewables.

Dividend is up $4 million, eleventh year running, to $211 million, so fully imputed at $0.155, and no buyback this year. Certainly, in FY18 we did $50 million buyback at $3.21, which seems a long way back from where the share price is today.

Just bridging more fulsomely, the EBITDAF on slide 5, you can see here generation volumes worth about a $74 million difference downwards. That explains a lot of the bridge between this year and last year. Price effects, so we

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saw record high prices through FY19, so jumping up to around $140 a megawatt hour, and you can see the effect of the vertical integration in hedging across the firm, with a $356 million price effect there.

So, positive to our generation business, so the longs obviously benefitting from higher spot prices, offset by essentially decreases in EBITDA in our mass - our fixed price variable volumes, so that's from C&I right through to mass markets, physical sales, derivative settlements of $60 million and - with end users, and then other derivatives also $45 million. So, those three summing to $354 million basically the same number as $356 million in terms of the generation. So, the longs and shorts essentially offsetting each other. So, the bridge there, the $74 million essentially reducing net by about $10 million to give you that $505 million at the - in the end in terms of an outcome for EBITDAF. Back to Fraser.

Fraser Whineray: Guiding a lot of our activity in the business, which we've also enjoyed over the last few years, are five key pillars. You can kind of think of these as almost forms of capital. The way we consider them is if, in 10, 20, 30 years' time any of those is impaired or absent, then the business will either be atrophied or struggle to even exist.

So, that's why these five pillars, we - they're the same five pillars as the Group KPIs. You'll see in the extensive remuneration section on the annual report how the Group KPIs have these - have percentages against these. We have to make sure, as a company, we're bringing forward these, and investing in these each year as we head towards longer-term goals.

This year in our business planning we wanted to define what those longer-term goals look like, and so we have put in some 10-year success statements. We also have some three-year goals. Then they flow back through to the stuff that we're actually going to get on with in FY20, which ends up aiming towards the long-term goals that are established there.

So, we just wanted to make sure we shared those with you. We think it's important that you understand how we're trying to make sure that the company is enhanced over the long-term, what ingredients are necessary for that enhancement, because talking in analyst and investor language, if your terminal value is zero, I bet you your current market cap is a lot lower. Sustainability of cash flows as well is primary, and growing those cash flows is also important against that dividend track record that I talked about earlier.

There's a lot of volatility out there globally in a whole range of areas, whether it's technology, human capital, geopolitics, the capital markets et cetera.

We just certainly want to make sure that the business is in a strong shape into the future long-term, because that's good for value.

In terms of key performance indicators, against those pillars, we're just continuing to work out what the best sets of KPIs are to report against those. There's a range of them there for each of customer, partnerships, kaitiakitanga, people and commercial. I'll just touch on a couple.

The Mercury brand trader churn, this has gone averse to where it was. It is an intensely competitive market. We have eased back slightly on our acquisition activity by dropping the deep discounting in most instances. The Auckland market is a very competitive place where we happen to have a significant customer base. That churn is now at around 7.4% for trader churn. On total churn, we've still got a significant advantage to the market.

The other thing I'll just point out is the zero high severity health and safety incidents. I know people can look at TRIFR a lot, Total Recordable Injury Frequency Rate. That deals with medical treatment injuries and lost time injuries, or reduced work situations. It's avoiding extremely low probability, but extremely high consequence events.

That is a very big focus for this company, and I'm delighted that we had another year with zero high severity health and safety incidents.

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Unlike many other KPIs, which you can reasonably forecast as you're heading into 30 June, you don't get to tick this one off until you've passed 30 June. It's kind of never ticked off anyway, because you just have to keep getting up the next day and making sure people stay safe.

So, I talked about on the first slide - moving to slide 8 now - New Zealand's renewable advantage has received substantial press during the year. From the Interim Climate Change Committee, which was an extremely well constituted group, which actually turned around and said, we think we've been asked the wrong question, and then focused on a different question. Not how to get to 100% renewable electricity by 2035, but what would be a good percentage of renewability to optimise low-carbon outcomes for energy in total, remembering of course that electricity on an end-user basis is only half of the energy market.

It's that other half that I mentioned earlier, which we see as coming more towards electricity as it grows from 40 terawatt hours to 60 terawatt hours over the next 30 years.

That was a very good report. We've seen the government's response to that, and we commend that pragmatism that actually going for 100% doesn't make sense, because electricity is a solution to decarbonise the balance of the energy system.

It also recognised the value of hydro generation, both for deep energy storage and for peaking capability, as more uncontrolled renewables are brought into the New Zealand market.

MBIE revised its electricity demand and generation scenarios just last month. The Productivity Commission came out to the Low-emissions Economy Report that was from the previous government's targets. It came out in August no, that came out last year, and that also supports electricity - renewable electricity - as key enablers of the transition.

We also have submissions closing today on Minister Genter's feebate arrangements with respect to low emissions, like vehicles, for implementation in 2021. We support that. I think it will end up being temporary in the end, because electric vehicles are going to be a lay down misère for consumer choice in probably five to 10 years anyway, for most applications. Therefore, they won't need any sort of tilting.

So, therefore why is it important in the meantime? It's important in the meantime because I - we believe that upstream supply chains are going to become constrained as vehicle manufacturers turn towards electrification of their cars. If you're not serious as a country about it, I don't think the allocations of those vehicles will be forthcoming, and that's a structural disadvantage against New Zealand's competitive advantage in renewable power.

You're also seeing not just in cars, but in heavier transport coming to the fray as well for electrification. Waste management is converting 800 of its trucks, including rubbish trucks. We're seeing activity around electrification of ferries in multiple places. Ports of Auckland just announced it’s buying the world's first electric tug, which will match the power of its current largest tug. Of course, Air New Zealand is - and others are thinking about electrification of planes as well. All the transport bases seem like they're getting covered.

Coming up though, on slide 9, we still get to see the outcome of the Electricity Pricing Review. We look forward to that. We think the focus on vulnerable customers is important. Within that, we think dropping the low fixed charge tariff is important. We think addressing the issue that some retailers have with excluding vulnerable customers because of their payment methodologies and the way they service customers, fixing that is important as well. There are many other of the options contemplated there which we support. We look forward to seeing that.

There's more on transmission pricing and tax, and national policy statements, the last two with respect to fuel, namely hydro fuel and also indigenous biodiversity as an unintended potential consequence of that national policy statement on geothermal, which we believe will be satisfactorily addressed.

William, to the market.

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William Meek: Thank you, Fraser. This should be a familiar chart to those that have been following these decks over recent years. You quite clearly can see here where we graph both islands’ storage on a basis of deviation from average for every month, from '99 through to 2019, for both North Island and South Island.

We can certainly see against the trend lines, which have been rebased, which include the seemingly higher prices we observed in 2019. We can certainly see a breakout there, where actually small deviations from average storage levels in the South Island are leading to much, much higher prices.

Again, most of us on the call should be familiar with the - both the gas constraints and the - and basically the thermal constraints also, during 2019, which persist into 2020.

So you can see certainly in the legend there, price is at $59 in 2017, rising to $87 in 2018, so that's a delta of $28.

Then they get to $143 in 2019, which just so happens to be twice the difference from the year before. So hopefully we haven't got a geometric series there and staring at $171 price in 2020 if that trend is continuing.

So certainly a break out there from trend that is persisting through into future prices and really goes to the thesis we had about the market three years ago, that certainly the supply/demand balance is tightening, mostly I think on the supply side and in certainly thermal fuels and that leading to certainly over the medium term, an elevated spot and wholesale market environment for market participants.

So we'll step through on to slide 11 and this is really just looking at the Taupo catchment now. This is graphing the lake level across the financial year. The grey band really represents the range of storage or lake levels. You can see ‘full’ is notionally just below 600 gigawatt hours, about 580 gigs is a full Lake Taupo level and you can see that history since Mercury has operated that catchment from 1999 through to the current day.

So typically when we look at this, we're a winter peaking catchment, we on average expect wet conditions through the July-September period, the driest part of the year is January through April and you can certainly see that reflected in terms of the mean, which bells essentially up through the Christmas period, New Year and then you see it falling back through April. That's really reflecting the underlying hydrology of starting wet, moving to dry, in terms of an expectation basis.

So what you can see there in the ranges is through Q4 calendar, so that is the period from October through December. You've got a tendency to drive the lake towards the fuller end of the range, that's an anticipation of the dry period that happens through summer as we all go, a lot of us, down to Lake Taupo and certainly enjoy that lake when it warms up. You see particularly storage drawn down typically over that summer and early autumn period.

So that's a phenomenon that typically we look to optimise so that the lake level is protected from hitting that zero level, which we fortunately have not done in the 20 years of operation that we've enjoyed.

So that is really just working through that dynamic. You can see the wet conditions that persisted through July and August in the table. July, August, September there above average which really was a continuation of the bonanza hydro we experienced through 2018 and then quite a rapid turn where you see negative inflows occurring quite strongly through that October to May period. So we were sitting in the very low percentiles, so in the bottom two or three sequences we've observed since records began in 1927 for the catchment.

Then turning to spot prices, you can see in October the world changed for the market, gas outages a bit and we saw October prices spike to $300, hold up around $200 and then have trended somewhere in the sort of low to mid $100s thereafter, from December through July and that continues August, we're tracking at the moment around $145, so we're still seeing those high prices in spot persisting.

Then you look at the futures prices at the bottom of that table and see how they've moved. So you had a tendency there to track around the $70 to $80 range on a monthly basis and then you've certainly seen those step up into quite high numbers. I think one of the interesting things to observe in this table is we topped the market some time

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before it realised that the effects of October and November weren't just temporary and that they were actually going to persist in terms of actually tightening in thermal generation. That has continued.

So that takes us through to the thesis, which is a slide on page 12, which again working through, supply and demand has rebalanced while demand growth has been pretty staid, so we're really looking at flat demand, which we'll talk to next. Certainly we have seen a supply contraction, so if you look at gas constraints and pricing and in thermal availability, you've seen quite a profound effect from April this year between the Huntly side and TCC down in New Plymouth.

You've probably got a capacity there of north of 1100 megawatts baseload and those stations there are struggling to hit 700 megawatts average on a monthly basis. So you're certainly seeing lower gas generation, which is feeding into those higher prices. Spot gas is trending at about $12 a gigajoule, so again almost double where we potentially were 18 months ago, so you're certainly seeing some effects there into the thermal market.

Difficult to see those abating in the short to medium term, so I think generation development and certainly you will see an acceleration there, not only by ourselves, but also from some of our peers in terms of bringing new power stations to market. They don't happen overnight, so we're potentially in an environment where you are looking at elevated wholesale pricing for at least the next couple of years.

The conditions for demand growth, obviously we take a longer term view, certainly based on the reports from the ICCC and the Productivity Commission certainly expecting to see that fuel substitution in transport and industrial process energy to renewable electricity, which is certainly positive, so potential for reasonably significant demand growth through time. We have seen increased volatility in pricing; Monday we saw prices again going into multihundreds.

Futures prices have increased and we've got a chart on that next. C&I pricing is happening now, those renewing at this point in time, they are looking at pricing lifts of at least $20 a megawatt hour from the prices they enjoyed a year ago, so that is happening relatively rapidly. We have not seen a reduction in retail churn at all, so retail churn has continued unabated in the low 20s. So as of yet, we still haven't seen significant upward pressure on retail prices.

So certainly when we look at what this means from our portfolio for Mercury, we do decide to, particularly we're integrated, we make a decision how we will sell our output. There are really three choices: you can sell spot; you can sell to the C&I market; or you can sell through to mass markets. Certainly, given these outlooks, spot and C&I looks like a better return than mass markets at this point.

So that really flows through the final point that we are surprised, you're still seeing very aggressive acquisition offers out in the market, which Fraser will touch on shortly and our view is those offers are out of the money based on a two to three-year view of energy costs.

To demand, pretty straightforward chart here, again it's always a tug of war. Certainly Tiwai potline 4 starting up late last calendar year has been helpful, though that's not running, it's not really flowing through into an overall lift in demand, so you are seeing certainly industrial. So certainly industrials would appear to be responding to the higher prices by slightly reducing their demands. So really you've got industrial volumes, excluding Tiwai down and the sectors flat to slightly rising, giving us a basically flat curve year on year.

Finally, touching on those futures prices, so the line chart on the left on slide 14, you can see a period of very low volatility in medium-term futures prices, so prices in Auckland trending in a very narrow range of $75 to $80 a megawatt hour and then essentially from January 2019 a significant repricing, really up to sort of low $100s, so a big step up. As discussed, that is feeding through into commercial and industrial renewal pricing. You can certainly see those effects are persisting through FY20 and FY21.

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So certainly interesting; Mercury's view is we can't see other than very wet conditions and that supply/demand dynamic is going to alter significantly over the medium term.

Fraser Whineray: Thanks William. Just turning now to slide 15 on retail competition, we touched on this. You're well aware of the proportion of our book that is retail, which is circa 40% of sales and value that that contributes, which is probably slightly less than 10% of the business at an EBITDAF level.

The churn rates are shown there where Mercury has on trader switches come much closer to the market; the last data point pushed by a change to a Fonterra Farm Source contract and I'll touch on that shortly. But it is very competitive, particularly in Auckland. The neat numbers that people quote on churn, whether you're going forward or backwards by 1000, of course hide the iceberg of the 3000 to 5000 that every large generator retailer is losing every month in terms of customers with looking for, I guess in some instances, a matching or greater gain.

So the core thing is to focus very hard on the in-pipe and the out-pipe to your retail customer base and think very carefully about the ones you're targeting and the ones you're trying to retain and that's certainly a lot of investment in IT systems throughout the year is helping us focus much harder on customer lifetime value and to do the best for our loyal customers.

There is a lot of, as William touched on, competitive offers out there in the market I think they are challenging unrealistic assumptions of churn to make work at the moment relative to other channels of spot and C&I. As such, a slight relaxation in our portfolio from committed sales is where we're biasing at this time and that was also, as we look to lengthen slightly on average hydrology, given the dynamics in the market, are not too benevolent when it comes to running short positions.

On slide 16, we just talk a bit more to the points we made earlier about trying to attract customers on headline pricing, rather than discounted pricing and certainly reducing the depth of those discounts where they are offered, retention and also we haven't touched our headline pricing since April 2018. So as a retailer facing that large lift in futures prices, whether you're vertically integrated or not, you can think about do I increase my headline to deal with that cost impost, or do I deal with the fact that there's a whole bunch of acquisition pricing going on to actually compensate for yield overall. You can see our position there.

Just touching on Fonterra Farm Source, that's going to be, I think, slightly north of 10,000 ICPs that come out with that. We used to have a partnership running there, it's a multiple panel approach that Fonterra Farm Source runs and in the competitive market that it is, we did not renew that, which we're happy with. The farm accounts tend to have quite significant load in Q4 calendar and Q1 calendar and that's a key time, as William mentioned, when actually we'd prefer Lake Taupo to be heading slightly higher to deal with the autumn runoff there.

So those power accounts are giving us a little more flexibility by not having them in Q4 and Q1 and of the 2000 ICPs last month that we lost, probably selling for slightly less than $100 on energy yield, they're yielding us, as I speak, $185 by selling power into the spot market. So that's a reasonable outcome.

Capital allocation has been important. I'll just hand over to William to talk about that.

William Meek: So we're now on slide 17, pretty simple histogram there, early bridging operating cash flow and then uses of funds, so around $90 million of stay-in-business CapEx which we're already discussed around hydro refurbishments, IT et cetera. Ordinary dividends $211 million and then growth CapEx of $81 million being into Dundonnell and Turitea.

So those sums, the $381 million, against operating cash growth $326 million, giving us a negative delta of $55 million. We did divest our Metrix business giving us $270 million and debt repayments of $215 million. Certainly Turitea as we steer forward over the next two years, project costs there $256 million.

Looking at other uses of capital, Tilt Renewables, you may be aware, is looking to sell its interest in Snowtown 2.

Certainly that looks like it should clear most of their core debt, so we're not expecting to see necessarily a

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significant capital contribution required in the meantime in terms of Tilt continuing to invest in both New Zealand and Australia, which Fraser will touch on more shortly.

Fraser Whineray: So as mentioned, 11 years of ordinary dividend growth and to take that out to say 20 years, you've got to keep on pursuing commercially responsible growth that is also aligned with the other four pillars that we run, as mentioned earlier.

So we've made the commitment to the Turitea wind farm on the northern zone. It has got a wonderful intra-island alignment with the Waikato Hydro Scheme which is net long capacity with a peaking power of 1050 megawatts and an average utilisation of about 450.

So that is very nice coordination to put more energy against that long capacity system, but I note that that coordination in terms of co-optimisation isn't part of the business case. It wasn't part of the business case for that, but we're certainly expecting some good benefits from leveraging that capacity in the Waikato Hydro Scheme, which we're reinvesting in further.

We think, as we've touched on earlier, the issues with upstream thermal supply or plant reliability and certainly the pricing of gas at the moment and the ability to get gas commitments at the moment, means that many parties are looking at renewables as a cheaper counterfactual to provide, not necessarily firm energy but certainly energy, which they may be able to co-optimise with other assets. That's an interesting dynamic which, as I want to mention, is a back-to-the-future moment.

The investment in Tilt Renewables significantly in the money so that's going fine. We have governance representation now on the Board so that's good, and as I said, which is outlined in the first bullet there, we said this would be an active investment and it has been. Every five or six months there's something material happening and I expect that we will continue to look actively at that investment to maximise the value that we get from it.

We're pleased to see how the Tilt management and Tilt Board are going with adding value there in a fairly interesting Australian market, and I think it's helpful that it's a bit interesting over there because that means that you've really got to be committed and disciplined and skilled to be able to create development margin.

Just turning now to the guidance, we've bridged it out there in terms of EBITDAF going through to $485 million, so taking about $10 million off for generation adjustment that's largely due to geothermal, we've got some outages this year, planned outages this year, which we didn't have last year.

We lose the earnings from the Metrix divestment and we've got a slight uptick in OpEx because we do have some of those additional outages this year in geothermal compared to last year. We've got quite a heavy program and then we have further growth in the core business, taking us through to our guidance of $485 million on mean hydro and geothermal generation, which is listed there.

The guidance on dividend up 2%. That'll be our 12th year in a row so at $0.158 of growth, that's $0.158 per share.

Stay-in-business CapEx $105 million. We've got a couple of wells going on which makes it a bit lumpier this year, and we also have three hydro power stations at various phases of refurbishment. Aratiatia and Whakamaru getting the last units and prework going on at Karapiro before we start taking units out there in FY22 through to FY24.

Before moving to Q&A, I just want to certainly mention the huge effort that's gone on from the people at Mercury and our partners this year, and also you for your support and guidance as investors and analysts. It has been a very satisfying year but also a very challenging one for many of the reasons that we've already covered on this call.

I also, before going to Q&A, just want to acknowledge our Chair, Joan Withers, who actually isn't in the room here today, as is normally the case for the investor call. She's not normally here. Joan is completing a decade’s tenure as Chair at the September ASM.

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She's shown a huge amount of courage, works harder than just about I believe any Director in New Zealand at understanding everything, reading everything and thinking right across the business, from customers to assets to partners and all of the pillars which we hold dear for our long-term value and sustainability of the Company. Has shown great courage and provided great support to the Board and the business throughout that period.

So we acknowledge Joan's tenure there. Those 10 years also happen to be the same 10 years which form the trend for the ordinary dividend growth.

Prue Flacks is going to be our new Chair. Prue's been on the Board of Directors since 2010, has strong knowledge of the business, a strong belief in the Company and strong alignment with the directions we are going with, having had good ownership of everything from the five pillars, the rebrand that we did three years ago, and what the Company's trying to do to continue to succeed.

So I just note those governance changes and certainly acknowledge Joan's contribution over that period, as I'm sure you will do as well.

So with that, I'm happy to hand over to Q&A. Thank you.

Operator: Thank you very much. Ladies and gentlemen, we will now begin the question and answer session. If you wish to ask a question today, please press star one on your telephone and wait for your name to be announced. If you wish to cancel your request at any time, please press the pound or hash key.

Your first question today comes from the line of Grant Swanepoel from Craigs. Please go ahead.

William Meek: Hi Grant.

Grant Swanepoel: (Craigs, Analyst) Morning Mercury team. Just a couple of questions. On your OpEx: so flat yearon-year, do we assume that organic OpEx, excluding the geothermal outages, is going to continue flat in nominal terms, or can we look for improvements on that end?

Then just my final question, just talking about your guidance bridge. Should I assume that a $485 million normalised, if you take - didn't have the geothermal outages - you can add back the $5 million OpEx and the $10 million generation adjustments, so actually now you've got a $500 million normalised number?

In that context, if I recall the start of FY19 you were looking at an average hydro year and predicting or forecasting a $500 million EBITDA, take-off Metrix, you're at $472 million. So in effect that $472 million, now to $500 million, that's phenomenal growth or am I missing something? Thank you.

William Meek: Okay, thanks Grant, I think I've got that. So I can answer that pretty simply. Around geothermal maintenance timing so we are working through in terms of those timings. Historically we've had - it's been a little bit lumpy in terms of being three stations versus one, so we're looking to effectively smooth those through. So you either get two out one year and the other two out the following year. Sometimes we may be able to push those to three, depending on where we are around conditional or statutory inspections.

So this year is impacted by higher maintenance on those geothermals, but you're still going to end up with some volatility through time when you're talking about - you're talking small millions.

OpEx, in terms of base OpEx, at the moment our forecasts are expecting to see OpEx lift $5 million year-on-year, and then on a normalised guidance in terms of getting to $500 million in terms of steady state. That would be a phenomenal lift so your bridge there from last year, if we take last year's number guidance this time of the year, was $515 million which included 200 gigawatt hours above mean hydro, which should take you back to $500 million.

Then you pull Metrix out which gets you, as you've said, back to $472 million. We're currently staring at $485 million so you have got an improvement in the core, which is that $15 million in the EBITDA bridge.

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But certainly as you look forward, obviously pricing, ongoing efficiencies - but as a normalised number, $500 million, that would be - in 2020 that would be large even with normalised geothermal maintenance.

Grant Swanepoel: (Craigs, Analyst) Thank you.

Fraser Whineray: Thanks Grant.

Operator: Your next question comes from the line of Aaron Ibbotson from UBS. Please go ahead.

Fraser Whineray: Hi Aaron.

William Meek: Hey Aaron.

Aaron Ibbotson: (UBS, Analyst) Hi there. Hi there, good morning gentlemen. I've basically got one question, but I'll split it into two, and that's - slightly longer term on Turitea and on Tilt - so first on Turitea I just wanted to know if you've had any reason to change any of your assumptions, or if you're still thinking $30 million EBITDAF impact?

Am I right in assuming that is for FY22 and that we should see maybe half of that in FY21?

So that's my first question. The second question, which is Tilt and through [to your dividend], you've obviously highlighted that in order to have progressive dividend policy you need progressive earnings policy. So I'm a little bit curious to know how you want to guide us or how you want us to think about both Turitea and in particular Tilt when it comes to contributing to your dividend capacity.

So with Turitea for starters, if I use your 70% to 85% range, we could get anything from 0% to 100% of that extra $30 million in dividends. When it comes to Tilt, I basically don't really understand when we're going to see anything of that $250 million capital tied up contributing to dividends. Keen to hear your thoughts, thank you.

William Meek: Yes, so I'll respond to Turitea. So certainly the phasing on Turitea hasn't altered. We're still on-track for commencing commissioning late 2020 so that's where we are. Obviously the EBITDAF guidance was predicated on numbers that were probably more in the $80 range than the $100 range that are currently trending.

So potentially at the front end you've got some uptick there on a $20 price delta but we'll see when we get there.

Who knows, but certainly the way things are pricing at the moment you'd expect to see that revenue contribution to lift if prices persist, because Turitea should be the first generation development project to complete commissioning.

So there's no changes there in terms of where we're expecting Turitea to land.

Certainly given price outlooks at the moment and where we're solving and the ongoing issues on gas and thermal generation, certainly the market prices are indicating that generation development is required. We're continuing to look about what that means for the southern zone and for Puketoi.

So just on Turitea and Tilt, Aaron that's a good question - when does money actually flow? Well the core thing with renewables, as you're well aware - and you've done some great research on this - is that it consumes a lot of capital at the start for which you need equity or debt or a mix of, and then you slowly dig your way out of that over time, with the biggest mortgage on day two.

So whether it's Turitea or Tilt it's kind of a similar thing. It's just that the Tilt investment is bundled up in a vehicle.

Which if it grows, it will continue to reinvest and ultimately then that grows value that way and - but against that value, then that also gives us probably better ability or better comfort to think about how our ordinary shareholders are remunerated from that.

If it doesn’t grow - or it will - it’ll have a lot of yield because, like a Turitea investment would, which you wholly own.

There can be combinations in between such as capital recycling, which is currently mooted that Snowtown is under its strategic review.

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Either way, renewables do consume capital, which I know is a core part of your consideration and investment thesis in the sector here, particularly if there is going to be some significant investment in renewable capital.

But we think through our own investments that that can be supported for growing - and growing dividends over time. Through Tilt, well, it’s active, we said it would be active and I still think there’s a wide range of choices out there for value to be created beyond what the good management and Board of Tilt are actually doing.

William Meek: Sorry, Aaron.

Aaron Ibbotson: (UBS, Analyst) Okay. Yes? William Meek: I think one of the questions was, what does Turitea mean for dividends? So, insofar as Turitea is lifting EBITDA and that’s therefore lifting free cashflow, you would expect to see under the dividend policy that will flow through at…

Fraser Whineray: Yes, correct.

William Meek: …in terms of the 75% to 85% of free cashflow. I’d expect you’ll get half of that appearing in FY21, given a late 2020 commissioning and then…

Fraser Whineray: Full year.

William Meek: You’ll get a full year in ‘22.

Aaron Ibbotson: (UBS, Analyst) Okay, I guess I’ll just spell it out - my question then, on Turitea because obviously, shareholders or whatever you want to call it are contributing to you building a wind farm. I - personally, I’d expected you to grow your dividend faster than the inflationary 2%. My question basically is, do you think you’re likely to signal to the market that you don’t have to wait 10 years for this wind EBITDA to show up in the dividend and within your 70% to 85% range? You obviously have a flexibility to do nothing or to do quite a lot with the dividend. Just to clarify, should we expect 70% to 85% then of that additional $30 million to show up in dividend? Or will it be consumed by your range? That is my question.

Fraser Whineray: Yes, so our expectation is that the increase in earnings from Turitea will flow down - will flow into an increased ordinary dividend payment because you are going to get a step change in earnings.

Aaron Ibbotson: (UBS, Analyst) That is crystal clear. Thank you very much.

Fraser Whineray: Yes, thank you.

Operator: Your next question comes from the line Andrew Harvey-Green from Forsyth Barr. Please go ahead.

Andrew Harvey-Green: (Forsyth Barr, Analyst) Morning team.

Fraser Whineray: Morning Andrew.

Andrew Harvey-Green: (Forsyth Barr, Analyst) A couple of questions from me. First one is just around the - I guess, the customer side and the retail side. Look, it looks to me that - I mean, you’re certainly pulling back a wee bit, I guess, on the mass market space and you’ve just made that previous comment on that C&I sort of margins you’re sitting in and are they that much higher than - or are they higher than the retail margins you’re getting?

Fraser Whineray: Yes, I could answer that. The C&I is largely - when it renews, is largely repriced off where the ASX curve is - there or thereabouts. You’re starting to see a little bit of a premium come back, I think of the FPVV rather that CFD - which it should have a premium in it because of the optionality that it presents to the buyer and that got discounted away a while ago so there’s a bit more in that.

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You don’t really have margins on CFDs. Of course, it’s just a – [unclear] - what it is, is it’s a function of timing as to when you sell so the yield - yes, the yield in C&I, if would go and sell a contract today, would be superior to retail certainly, acquired retail. Absolutely. Like, [unclear].

William Meek: Andrew, I think it all…

Andrew Harvey-Green: (Forsyth Barr, Analyst) I’m sorry, what were you going to…

William Meek: It all comes back to what’s your view of forward price and, as Fraser said, the futures price for commercial industrial pricing is a good indicator. But certainly, all retailers can make that decision themselves. But if you’re sitting there with forward price trending at $100, then a residential customer in Auckland is going to have an energy cost of about $115 a megawatt hour. That’s just the energy cost before you even overlay cost to serve and that’s the challenge. Last - based on the offers we can see, we’re just not seeing acquisition pricing delivering a yield that’s anywhere near that number for residential.

Andrew Harvey-Green: (Forsyth Barr, Analyst) Yes. I mean, I guess the residential side is similar to the - our longer-term game mode. I mean, how do you, I guess, kind of factor that thinking in? I mean, the - I guess the numbers have been falling back, the volumes have been falling back quite a bit and it is quite expensive to get back into it if you do want to get back into it in a bigger way. I mean, how do you think about it from that sort of long-term perspective?

Fraser Whineray: Well, the cost of getting back into and the cost of getting out of it is a - remember that a net - it’s a net thing. Everyone is spinning their tyres on swapping 4,000 customers a month. So, you can get back into it if you want to get back into it and chase volume.

I know it’s a long-term game on average, whether you book, but it’s not with an acquired customer because you create a moment of truth when the acquisition pricing runs out two years later and half of those customers will leave you. Then you’re looking at two lots of - having cost of acquisition, plus the discounted cost to serve in the meantime where you’re under water on buying that power off spot or hedge markets if you’re looking at a true counterfactual.

Then you try and put them up, in terms of pricing, to some sort of normal pricing to match what your existing customers are paying and you find that it won’t stack up. So, you can actually - you can actually get back into this when you want. What we’re focused on is if you look at the overall total yield of that book, there’s two ways to adjust it. You can look at your headline pricing, or you can look at discounts which don’t actually go to your existing customers and so against our three customer promises.

Thinking about the pressure that’s come under the spot and wholesale markets, particularly the last year, I think the spot market averaged - what - $140, $150 bucks. Every sale was under water against that. Then we’re confident, if we need to push play on that, we will. But at the moment - so, I think everyone gets quite obsessed with net numbers. I think it’s probably better that everyone publishes gross numbers because then I think - then we’d get a better focus as to just how much money is being spent acquiring a whole bunch of customers. A lot of that money isn’t - as you know, Andrew - turning up in OpEx, it’s getting capitalised. Not here, but it’s - to any great extent, but there’s a lot of stuff on balance sheets which is masking that dynamic.

You know any sales person, even in your shop or cars or telco, they love volume. Right, and I think we are in exceptional circumstances here around thermal fuel supply and constraints and so I’m kind of aligned with William in terms of I’m surprised churn is still running at 20%.

Andrew Harvey-Green: (Forsyth Barr, Analyst) Yes, okay. No, that’s - thanks for that. That’s good.

William Meek: Thanks Andrew.

Operator: Your next question comes from the line of Stephen Hudson from Macquarie. Please go ahead.

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Fraser Whineray: Hey Stephen.

William Meek: Hi Steve.

Stephen Hudson: (Macquarie, Analyst) Morning Will and Fraser. Mine are sort of iterations on what have been asked but I’ll try and rattle through them and get your response. The 70% to 85% free cashflow payout range, you’re obviously higher than that this year and next. There’s a lot of moving parts. But what’s your best guess at the moment as to when you return to the middle of that range, assuming that that range is still sort of relevant?

In terms of geothermal, I think you talked about pre the maintenance program that you’ve announced today as sort of a 2,800-gigawatt hour per annum geothermal number. I just wondered if you can give us an idea on when you return to that level and if that could be some efficiency gains?

Just in terms of the $15 million growth wedge on your guidance, can you give us an idea of how much of that is passed through versus trading? Then just finally, your NZU cost this year, can you give us that number and what you’re expecting that to be next?

William Meek: That’s a lot of questions. Yes, the dividend this year is slightly outside that range if you actually take the actual CapEx number on a normalised basis it falls within. The policy is on average, so it is smooth so we’re not concerned about, certainly, that range causing us an issue. We expect to see earnings grow through time, not just from [generation development], but in terms of yield and then financial performance of the firm, but that’s a work in progress. The $15 million growth in the bridge, I mean, that’s just a combination of a whole lot of factors. There’s just small improvements everywhere. Certainly, yields are a chunk of that, but that’s just - yes, better performance across core business. It’s not - some of that will be in trading, some of that will be in mass markets. It’s just everywhere, [unclear] higher prices, et cetera, et cetera.

NZU costs - we’ve got long-term forestry contracts. They were in the - sort of - certainly below the cap of $25, but in the sort of $20 to $25 range.

Fraser Whineray: Yes. [Oh, geo] - there was one other question?

William Meek: Oh, was it geo?

Stephen Hudson: (Macquarie, Analyst) Sorry, Will, and the 2,800-gigawatt hour geothermal number, is that the right number and when do you think you will return to that?

William Meek: Yes, so that’s - on a normalised basis, 2,800 is correct, yes.

Fraser Whineray: Yes. Stephen Hudson: (Macquarie, Analyst) Sorry, it - will it be below that level for the next five years?

William Meek: No, 20 - no.

Unidentified Participant: The TPC is…

Fraser Whineray: Yes. William Meek: Yes. Unidentified Participant: So, the 2,600 [unclear]…

Fraser Whineray: Oh, yes.

Stephen Hudson: (Macquarie, Analyst) But I think you’ve guided for 2,600 previously?

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William Meek: Oh, so you may - yes, you see when you look at the operating stats, you - our 25% stake in Tuaropaki Power Company is worth 200 gigawatts so that obviously doesn’t, obviously, impact EBITDA because it’s below the line because it’s equity accounted.

Stephen Hudson: (Macquarie, Analyst) Got you.

William Meek: So, the 2,600 gigawatt hours would be the normal range for our normal accounted or our owned geothermal.

Stephen Hudson: (Macquarie, Analyst) It’s on a consolidated basis?

William Meek: Yes, on a - if you take everything, you add another 200 for TPC. Fraser Whineray: Yes. Stephen Hudson: (Macquarie, Analyst) Thank you.

Fraser Whineray: Thanks Stephen.

Operator: Your next question comes from the line of Nevill Gluyas from Jarden. Please go ahead.

Fraser Whineray: Nevill.

William Meek: Good day Nevill.

Nevill Gluyas: (Jarden, Analyst) Thanks. Easy question from me, I guess. You talked about the growth wedge in the guidance. I guess we would expect, if you believe the ASX forward curve for year two - year three ahead, you would still get some continued gains in the C&I book, particularly if you start biasing your sales that way for year two - year three. I’m just wondering if you’d sort of give some order of magnitude on that? As a sort of a question maybe it clarifies - what have you assumed in terms of ASX or forward pricing in the guidance you’ve given?

Fraser Whineray: Well, a lot of the year ahead stuff is - so, in the next financial year, is largely squared away so years two and three and kind of year four, as we roll through this year, we’ll start to look at pricing stuff for ‘21, ‘22, ‘23 unless something comes up now which has got a significant forward start because we’re trying to ease a bit of our portfolio link through to the commissioning of Turitea when we get another sort of 470 gigawatt hours of energy in net length. There is a - it’s - in the guidance we’ve given, that’s largely in the book. It’s not really relying on any renewable assumptions for C&I and we’ll be largely looking at ASX pricing in looking at our own internal spot price and wholesale price views for working out what we have beyond those years.

But yes, it does roll through, apart from a very significant long - or quite substantial long-term contract of about 700 gigawatt hours. The balance rolls of that every three years. Yes, you will - if those prices remain 100, 110, then you’ll see that flow through into the C&I book. The C&I book is about - excluded…

William Meek: 2,500 gigawatts.

Fraser Whineray: 2,500 gigawatts, excluding that large contract, and so 2,500 times $10 is $25 million.

Nevill Gluyas: (Jarden, Analyst) Great, yes, thank you.

Operator: There are no further questions at this time. I would now like to hand the conference back to today's presenters. Please continue.

Fraser Whineray: Well, look, thank you once again for joining us for the FY19 Mercury Annual Results Investor Call. We appreciate the questions and the engagement. Looking forward to catching up with many of you over the coming weeks, both here and also in Australia. Then for any of those further afield in November/December for other jurisdictions.

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If you’ve got any other questions and comments please don’t hesitate to get in touch with Tim Thompson who is our Head of Treasury and Investor Relations.

We wish you a good day. Thanks very much for your time, kia ora tātou.

End of Transcript

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