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Edited Transcript of CEN.NZ earnings conference call or presentation 9-Feb-20 9:00pm GMT

Half Year 2020 Contact Energy Ltd Earnings Call

wellington Feb 13, 2020 (Thomson StreetEvents) -- Edited Transcript of Contact Energy Ltd earnings conference call or presentation Sunday, February 9, 2020 at 9:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Dennis Barnes

Contact Energy Limited - CEO

* Dorian Kevin Thomas Devers

Contact Energy Limited - CFO

* Matthew Forbes

Contact Energy Limited - IR Manager

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Conference Call Participants

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* Aaron Ibbotson

UBS Investment Bank, Research Division - Director & Research Analyst

* Adrian Atkins

Morningstar Inc., Research Division - Senior Equity Analyst

* Andrew Rupert Pelham Harvey-Green

Forsyth Barr Group Ltd., Research Division - Director & Senior Analyst of New Zealand Equities

* Grant Swanepoel

Craigs Investment Partners Limited, Research Division - Director & Head of Institutional Research

* Nevill Gluyas

Jarden Limited, Research Division - Director of Equity Research

* Stephen Hudson

Macquarie Research - Head of Research

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Presentation

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Dennis Barnes, Contact Energy Limited - CEO [1]

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Well, good morning, everyone, and welcome to Contact's Interim Results for the 6 Months ended 31 December 2019.

Usual disclaimer. We're going to go through the pack in 3 parts: I'll give some highlights, a bit of progress; Dorian will take us through the detail and then just a little bit of what's the market looking like going forward towards the end; and then Matthew will handle the questions, not the answering of them, just the administration of them.

It's fair to say that performance relative to the prior period always had a fair chance of being down given how strong the prior period was. For Contact, specifically in the half, obviously, the well-worn story of reduced gas supply and reduced reliability of gas supply impacted our earnings with higher gas costs, higher carbon costs. More importantly, from a shareholder perspective, the prudent management of risk such that we would actually [outlook] the C&I market for the period.

Despite all of that, the renewable part of our business performed well, costs performed well and we still achieved a cash flow which exceeds the declared dividend for the half, which is as per target and as per expected at $0.16.

So what has become clear to us through the period is that the future of the Taranaki Combined Cycle power station is increasingly at risk. And we've taken the decision to bring forward the useful life of that plant, thereby increasing the depreciation charge for the next 3 years or so. Given the unreliability and cost of gas and rising carbon costs, it's pretty clear that there's a great substitution opportunity as far as geothermal to gas, and we've taken the decision to accelerate the depreciation.

Now of course, that's just an accounting change. It doesn't mean the decision's made, but it's a pretty strong signal that, that plant won't be operating past 2023. The trend is still good on the efficiency focus that we have and the building of the capability that we've been doing for the last 3 or 4 years. The graphs can't always go in the right direction for every measure all of the time, but the trend is your friend. And you can see that customers are increasingly advocating. [As far as] -- we had a bit of a dip in the half as we rolled out broadband and the massive growth in that. Pleasing to see that that's now above [30] as we go into the second half.

Costs, obviously down. Some very low-severity incidents, employee engagement continuing to rise, and certainty for our shareholders around the dividend, and our target remains at $0.39 a share.

So we've always taken a holistic view on our business. But increasingly, we'll be describing that performance externally, and this is a bit of a taster. Clearly, we're one of the first signatories in the region for energy to the science-based targets initiative. Renewable generation and carbon intensity is an important measure for us.

As this has been a feature of the last year, the focus on vulnerable customers and how all customers are being able to access the competitive market, we'll show you more information there. And with our new range of products, we've been able to accept an awful lot more credit-impaired customers than we would have done in the past. And in fact, we're seeing more credit-impaired customers come to Contact because of the great products that we offer.

And of course, diversity has been top of the agenda of Contact for a long time. A couple of years ago, we were accounted by Reuters as #1 in the world. That's really a taste. We'll have more to come on a broader ESG set of metrics.

Now to the market over the last wee while. I feel like it's been a feature of my tenure to say that demand is flat. But demand was flat again if you strip out the irrigation-related increase on the prior period. Natural gas production is recovering. You can see that '19-on-'17 calendar year. And the gas market, runs on a calendar, was down 12 petajoules pronounced in the half. But we saw the first half of '20 recover, and we expect that to continue. And as you all have seen today in the supplementary press release that we have contracted some gas for 2020 through to 2025.

It's clear that petrochemical and electricity bear the brunt of any unreliability in natural gas supply, marginal field, marginal plan. And that's why we've had the underperformance in the half, but we do see that continued improvement in gas supply continuing.

[Technical] trade has been -- has [flatted broadly] for the last couple of months but hasn't actually translated in the half into a greater hydro generation proportion for the industry. But we do go into the balance of the calendar year and into winter with masses of storage, I think, only for the second -- [probably] since 2013, we've just tipped over 4 terawatt hours of storage in the market. So that bodes well for a well-managed winter, particularly as the gas supply is recovering, but you wouldn't say recovered.

Again, in the [P&E] -- you've seen this chart before, but it's important, increasingly, to look beyond the hydrology and look to all of the factors that are affecting the electricity market, including methanol prices, gas prices and availability, carbon costs. And I'll come to it later. But of course, [while] the aluminum starts up, (inaudible).

The long-term future prices are now actually trading much more like the short-run marginal cost of thermal. On the right-hand chart here, we have a go at what Contact's thermal SRMC was for the first half at $102 and had a little bit of a range for what we believe is probably the higher cost of coal. So we are seeing the market working, that is the supply-demand tightness, and the futures prices are trending towards thermal short-run marginal costs. And I think that's pretty evident now.

On to retail, it continues to be intense. A bit of a continued trend of -- net-net, the big players staying about flat, with some winners, losers and some flat players. But the Tier 2s growing significantly. And if you want to try and do the math between 13,000 and 68,000 customers, that's connection growth over 2 years. So you can see that the second-tier players, particularly Electric Kiwi and Nova, are continuing to compete and continuing to win customers. And that's partly why the electricity price for consumers is hovering about CPI increase rather than increasing at the rate of the input costs that we've seen over the last couple of years.

So our strategy remains unchanged. We are focused on optimizing our business for cash flows; disciplined and transparent approach to the portfolio we hold. I mean our Customer business continuing to leverage the brand and technology to deliver an operating model that is best in the sector. We've made reasonable progress on that in the period with significant improvement in the digital adoption in our business. We've now got robotics working across 14 key processes. The stuff that used to take 2 hours now takes 15 minutes. We expect that to improve the [market] over the coming years. All of that resulted in the best customer experience, with our share of complaints continuing to reduce and continuing trend for us that bad debt write-offs continue to fall. I mean we must be close to 0 now, which is actually pretty impressive.

The brand refresh 18 months ago clearly is resonating with customers, not just the award circuit, and we can see how it's helped us win 20,000 broadband connections and grow that pretty quickly.

The Wholesale business continues with its decarbonization push. Simply Energy is, I say, integrated, but integrated is the wrong word. Simply Energy has been leveraged well to work with customers, including the contracted 13-megawatt boiler customer we've got who we can't name, but it's contracted. Our demand management platform is growing at an amazing rate, where a couple of months ago, it's 1 megawatt. We're now at 7 megawatts. This virtual power station idea is growing apace, with very high conversion rates with customers.

But of course, the big dial movement in that business is Tauhara. And Tauhara is -- that continued apace. You will have noticed, we had some rig wobbles plus the strategic review of the aluminum smelter that has made the push for [PID] today, which is what we may have said 18 months ago, somewhat irrelevant. But what we have seen over the last couple of months is a very hot resource in the first wells we've drilled. And we've continued to delineate that, where is it and how big it is. But it's clearly a minimum of 3 square kilometers and 300 degrees, which was our target resource.

And the tender process for the power station, which is more than half of the cost of the station, has come in very, very competitive and has exceeded our initial expectations on those prices. So the levelized cost of energy, the LRMC that we would have talked about when we hosted you in Wairakei last year, absolutely achieved.

And with that, I'll hand over to Dorian to give us the ins and outs.

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [2]

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Thanks, Dennis. So there are 4 key themes that are going to come out when I go through the financial and operational performance. The first is, Dennis has mentioned already, is that we've had relatively low levels of both stored and contracted natural gas impacting our supply risk profile. So we've been countering that by reducing the amount of fixed price volume that we commit to into the future and also conserving fuel. So it's been great to see that our risk controls have actually been functioning well because that binds our own sort of risk in a position that we are comfortable with, and that's very important. But when we go through the financials, you will see the ramifications of that good risk management in the numbers.

Our retail business has been -- considering the outcomes and the drivers of the Electricity Pricing Review and has now started to implement the findings, I mean, we think the way in which we sort of positively engaged with that process has led to what we think is a relatively good outcome for both Contact and for the industry. But you will see the -- again, the implications of that in our Customer business, and in particular, around pricing that we've achieved.

The rate of underlying OpEx reduction, you will notice, has slowed a bit, and that's only natural. The -- a lot of the low-hanging fruit has been picked, if you like. We're still very committed to getting our OpEx down. We think, strategically, that's the right thing to do. And obviously, we're still committed to any guidance we've given in this area. It's just more of a heads-up that you will see more transformational-type change required into the future in order to keep that momentum on OpEx reduction.

And the last point Dennis has mentioned. We now think it's unlikely that we're going to continue to use TCC post FY '23. We align our accounting behind that assumption, which has led to $9 million of additional depreciation at the half year and $18 million for the full year.

So now on to the numbers. Profit after tax of $59 million for the year. Comparison with the prior year is skewed due to the Rockgas disposal. You're better off looking at it on a continuing operations basis. In that regard, we're down by $40 million. The biggest variance is around EBITDAF, $57 million down. And we've put a neat waterfall in there to sort of make it easy to understand what's going on.

So if we just sort of talk through that, we've got a $19 million pricing headwind, and this is around the fact that we're able to get some lift and support the market when it was stressed, when we had that unplanned Pohokura outage. There was some negative consequences with that in that, with the high market prices at that time, things like location losses for us were higher, cost of acquiring generation was higher. But when you wrap all of those things together, you've got the $19 million headwind year-on-year.

We've seen lower hydro levels, as Dennis mentioned. We would normally substitute [that with] increased thermal at an additional cost of $10 million for that. However, because of this natural gas-constrained environment we're in, we've had to -- we haven't been able to do that as much as we normally do, and we've had to acquire more generation, and there's a negative spread on that, and also reduce the amount that we actually sell and, therefore, you lose the sales margin.

Also the gas producers are charging more for gas because it is a scarcity product at the moment. And we've seen our retail gas margins decline a bit, which is a timing topic. I mean, we probably haven't been as quick as we should have in terms of passing those increased costs through to customers.

Market making has gone $7 million the wrong way for us. We made $5 million profit in that prior corresponding period. We had a $2 million loss in this period. This is a more volatile part of our business. We are having to participate in market making. We don't think it is a true market-making environment and it does force the market makers into positions that they wouldn't necessarily take. Under the EPR outcome, we're having to commit more volume to market making. So this is a topic and an area that we'll be focusing on quite heavily to make sure we've got the right capability and focus to ensure that we get the right financial outcomes.

And in terms of our fixed cost, they're higher by $4 million, and this reflects that we haven't owned AGS for the entire 6 months of this period, whereas we did own it for 3 months of the prior corresponding period. So that explains why the EBITDAF is down by $57 million. We've talked about why the depreciation is high due to the TCC.

Interest costs are coming in $11 million lower. We have started to capitalize interest associated with Tauhara. Again, there's $3 million associated with that. Underlying interest is down by $8 million, and this reflects the fact we just got lower levels of average net debt because of the proceeds that we got from those 2 disposals we made last financial year. And the other thing I'm quite happy about is we've got our overall average interest rate down as we've been able to rejig our interest portfolio and get more exposure to variable interest rates, which are lower than our fixed. You've got tax coming in lower, which is the natural hedge for lower profits.

So that gives you the overall picture. If we now look at it on a segment-by-segment basis, you can see that the Wholesale business is down by $39 million, and that's a function of both exceptional prior year and this natural gas-constrained environment that we're in this year. The Customer business is down $18 million, and this reflects the fact that we have been focusing on the Electricity Pricing Review and are implementing the findings associated with that. So that has meant that we've been buffering customers from the higher energy costs and higher network costs.

We will be looking at what happens with the wider market, but obviously, with a view to recover cost increases over time. I should just add on this point is when we look at price changes, there are lots of different considerations. But one of the key learnings from the Electricity Pricing Review is we always look at it from a declaration index now when we make those types of decisions.

And the last segment there, corporate. You can see that's flat year-on-year, so the costs are under control in that area.

So now we go on to the Wholesale business and do our usual sort of deep dive here. So costs were up by $7 million due to higher thermal costs, and I'll talk about that in a minute. Acquired generation volumes are up year-on-year, reflecting we've got lower own generation that we would try to offset and some risk management positions we've been taking. But you'll see that the cost of that acquired generation hasn't gone up, and that reflects that acquired generation has been cheaper year-on-year.

Dennis mentioned that hydro volumes have been lower year-on-year. So obviously, there's been a lot of talk about how wet it was, but that was only a small period at the end of the half year period. The first 4 months were relatively dry, and you're also comparing it to a relatively wet prior corresponding period.

Geothermal volumes are flat, that's why we like that type of generation. Flat, consistent as expected. And thermal volumes are down by 12 -- but we were doing some tolling -- gigs, sorry, down by 12 gigs. We were doing some tolling for Nova, tolling their gas and selling it back to them as a CFD. If you actually look at it excluding that, considering sort of our gas position, our thermal volumes were down by 171 gigs, which I think better reflects the sort of natural gas-constrained environment and the fact that we've been conserving fuel. So over that period, we've got our stored gas in AGS up from 4.5 PJs to 5 PJs.

And I'd also add, actually, the -- one of the beauties of having AGS is the flexibility it actually gives us in the marketplace, which I think is pretty unique. So when you have things like [White Valley] go down and there's surplus gas, we are the player that can take large quantities of gas at short notice, which we have been doing. And as we sit here today, we've got close to 6 PJs stored, which is obviously good from a risk management perspective.

Just quickly on our thermal assets, we talked about this at the full year and how our peaker availability hasn't been where we wanted it to be. That was linked to the fact that we've found some issues, extensive corrosion with the rotors on the 2 peakers and have been going through 1.5 years refurbishment program. That's finished in September 2019 and we now have no planned maintenance on those peakers. And we've also got TCC fully rated and fully available. So whilst we're in this relatively uncertain period because of the HVDC constraint, it's good to know that we've got both of those assets available on the North Island for us. And indeed, we are using them.

So just on the thermal costs that are coming in higher. If you look at the numbers going through our accounts, our cost of gas has gone up from $6 to $6.74 per gigajoule. For everyone, the surrender rate on carbon has gone from 83% to 100%, and the cost of carbon has gone from $20 to $22 per tonne. If you translate that into a thermal cost of fuel for us, we've gone from $65 to $71 per megawatt.

But that actually doesn't tell you the full picture because that's all based on the historic cost of when we bought our carbon and when we bought our gas. If you're looking at it from a current market perspective, you probably pay $8 a gigajoule for gas and $28, I think, carbon is trading at, at the moment. So if you start putting those through, you get to a short-run marginal cost of thermal which is well in excess of $100, which is what Dennis showed you earlier. And actually, that's one of the things that sort of played into the decision around TCC. It's the question, well, can you actually make money with base load thermal generation anymore based on wholesale prices, where they're going, and the cost of gas.

So now on to our contracted revenue for the Wholesale business. It's down by $10 million. However, there is a transfer price increase from a wholesale customer, which is plus $13 million included within there. If you adjust for that out and just looking it on a third-party perspective, we're down by $23 million. And that reflects the fact that we've had lower volumes. Volumes are down by $10 million. If you remember, I said earlier, that is a result of the natural gas-constrained environment and the lower hydro. We have to reduce the amount we sell. This is where you can see the negative coming through here.

We've actually got lower pricing of $7 million as well because we were able to get away some short-term CFDs into those high-priced -- high prices in October and November 2018, and those haven't repeated. And we're also, remember, supplying more to the smelter because at the [full top line], there's an extra 60 gigs going to the smelter year-on-year from us, which has an opportunity cost. So that's why it's -- pricing is down. And then you've got $6 million of other income being negative, which reflects the market making we've talked about.

So just to preempt a question, which I'm sure may well come up, why is our netback flat on C&I when everyone else's in the marketplace based on the operating stats seems to be going up. Now there's a good reason for this. I'm just going to repeat what I said earlier on. With natural gas availability issues, we've got there stored and contracted natural gas. So our supply position from a risk profile has changed. We need to adjust that, and we adjust for that by making sure we have less volume, fixed price volume committed into the future. And our mechanism for doing that is reducing our C&I book. So when contracts come up for tender, we don't re-contract for them. And that gets our volumes down and balances the risk. So actually, the fact that our netbacks on C&I are flat, I'm very happy with because that actually shows that we've got good risk management in place. We probably -- we could have pushed up our EBITDAF probably by recontracting more C&I, but that would have blown out our risk profile, and that's not what we're about.

On our wholesale trading and merchant revenue, this is relatively simple. We're down by $22 million. But you can see there in the middle that the price that we were getting on last year was $170, and that's dropped to $108 this year, and that reflects the fact that we've got [lent] in October ['18] and November when the market was stressed into those higher prices, which obviously hasn't repeated. So that's the Wholesale business.

If we now look at the Customer business. I've put in an extra table in here for you, which I think will better explain our electricity revenue. What I've done here is I've isolated the accounting impact so that you can actually see the business on a cash flow perspective, so what I call net revenue cash. This is how I look at the business, because what I want to be able to see is if our electricity gross revenue is going up because we're getting tariff increases at that level. I want to be able to check that we're not giving that value away through paying higher incentives to customers to acquire them. So I want to be able to see those 2 things to check that we're being kept in balance.

Also, you'll know that we've announced that for new contracts, we have stopped doing prompt payment discount plans. So the value of our prompt payment discount not taken will start to reduce. And therefore, it's important that you can actually see that in our financial performance.

So whilst this might seem like a bit of extra detail, I actually think that the complexities of retailing electricity in New Zealand, I actually think you need to be able to understand this level of detail to be able to understand the performance. So creating a bit of a [rock on] my own back here by being very, very transparent. But we're comfortable with that because we're comfortable we can perform. And to be honest, actually, capital markets really understanding what's going on with our performance is good because it provides that extra layer of tension for our performance.

So on that point, you can see that EBITDAF is down by $18 million. There are 2 key things feeding into this. We've had relatively flat pricing, and obviously, we've got those higher energy and network costs flowing through. So on the relatively flat pricing, as I said, we have been understanding and now implementing the findings from the Electricity Pricing Review. What that's meant is we've had relatively little flow-through from FY '19 price increases. We've been shifting customers onto plans which better suit them. So a good example of that is 16,000 low users going on to the low-user plan. So whilst that has an adverse impact on our short-term pricing, it obviously helps customer engagement and it also helps with reducing customer churn, which is a good thing in the longer term.

You can also see on this -- the slide, the impact of the PPD not taken. That's come down a bit, reflecting that we've now got 60,000 customers on non-PPD plans, so that's why we're seeing flat pricing.

Now when I step back from this and take a sort of bigger-picture view of it, our PPD not taken on an annualized basis is about $12 million. Based on customer churn and wins and losses, we'd expect that to unwind over about 3 years, which is a $4 million headwind every year for the next 3 years.

When you also consider what's happened to network costs and energy costs over the last 24 months, there is a need to get more price effect through. We actually think it's very reasonable to be targeting a CPI-type increase on our electricity gross revenue. And if we are achieving that, that will more than offset the headwind in terms of the unwinding of the PPD. We also think that's good because it continues to buffer our customers from the volatility in the wholesale market. And we think that's appropriate because we see this as more of a long-term strategic channel rather than a commodity one.

So then when you consider the higher energy costs and network costs that we've seen coming through here, then actually, this becomes a timing issue. Because as you saw, the -- earlier on in one of the slides, the wholesale price into the future is predicted to plateau now at about $100, reflecting more gas availability and those wind projects coming online. And if you're getting CPI increases on your tariffs, then you're going to see a convergence there between the cost and the pricing.

On to our OpEx or our other operating cost movements. It's good to see it continue to come down there from $110 million to $102 million. We continue to be transparent about how we report this. So you can see the cost reductions that we naturally get through the fact that we've disposed of businesses and the fact that we've accrued less for bonuses, but there's a profit performance that's been lower year-on-year. We've continued to explicitly show that on costs associated with the rollout of broadband. And we do that because those costs should disappear into the future as we better embed that product into our business processes.

And then that gives you what we call our underlying movement. So you've got a bit of inflation, $1 million inflation. And then you've got $2 million of underlying cost savings, which is lower than we've been seeing historically. And hence, my point earlier, that whilst we're okay for all of the guidance that we've given to the capital markets, to keep the momentum going down, we will need more transformational changes into the future.

Well, this next slide is a new one. It's actually a very important slide. Based on our asset portfolio and how we operate, we've communicated that our expected and normalized EBITDAF is $480 million. And our operating free cash flow associated with this is $280 million, and we pay out 100% of that at the dividend, which is $0.39.

So the most important piece of information that we can actually share with you is how are we actually performing against that expected and normalized EBITDAF. So on the left-hand side, these are the assumptions that drive our expected to normalized profit to EBITDAF. These are the half year versions. So the half year version of the $480 million EBITDAF we talked about is $246 million. And there, you can see the reconciliation down to our actual performance of $221 million. I think you'll find this useful for your models. We've also got in the backup the full set of assumptions for the full -- $480 million for the full year.

I guess, the other comment here is to reconfirm that, structurally, we still think $480 million is expected to normalize, and we do. So whilst things like thermal costs are coming in higher than we expected them to do, we would expect our channels to reprice to offset that over the medium-term to leave us [whole].

In terms of our cash flow, operating free cash flow at $220 million is down $83 million on the prior year. That reflects the fact that we don't have Rockgas in our numbers this year and the underlying EBITDAF is lower, and also that the tax paid was higher because we paid the final tax payment for FY '19 in this period of FY '20, and that was particularly high because of that high profit performance.

We look at our ability to convert EBITDAF into operating free cash flow, so our cash conversion. We've got, I think, one of the best conversions in the industry, if not the best. We've dropped from 70% to 54% on that, but that reflects that tax payment for FY '19. So we're still performing very, very well in this regard.

And one thing I'm particularly happy about, when you look at our trade working capital there, $5 million reduction. That's even though we've been net injecting into AGS, and that represents the fact that we focus a lot on cash generation as a business.

And if you look at -- on our balance sheet, the contract asset number which feeds into that, which I keep a close eye on, has actually reduced. So this is the amount that we are having to give away to customers in order to convince them to buy our plans. Now it's early days, but one of the things you could read into that is that customers now see buying our products more for the value of our brand, for our service and for the fundamentals of the product and less for the sort of free giveaways that you get when you join. So it is early days on that, but we'll be keeping an eye on that.

On our balance sheet now, there are 3 things I wanted to highlight here. As I said earlier, our effective interest rate has dropped from 5.75% to 5.29%, which is good, and that is about the fact that we've managed to get 20% of our interest book exposed to variable rate. The BKBM is about 1.25%. Our fixed swap rate on the rest of the interest is about 4%. So you can see the more we can transition over to variable, the lower our rate will be.

We've got some refinancing we need to take care of over the next 12 months. We've got a wholesale bond of $50 million and a USPP of 70 million. We've got undrawn bank facilities that will cover that, so there's no issue there. What we will probably do, though, is we'll probably wrap that all up with the financing for Tauhara. We do want to be in a position where we've got financing in place for final investment decision. And on that, when you look at our net debt-to-EBITDAF, so our S&P measure on a normalized basis and [statural] basis, it's 2.3. We want to remain BBB, so you have that sort of 2.8 ceiling on that. [All the rest], you can see, we have gone above that. And S&P are comfortable we're going above that for a build phase as long as we've got a trajectory that's down into that BBB area. And of course, we would do the 50 (inaudible) of EBITDAF through coming online associated with that. So we're still comfortable that we've got capacity on our balance sheet to fund Tauhara.

So the last slide is on the dividends. So hopefully, this won't be a surprise to anyone. So we still believe, as I've said a couple of times now, that our expected normalized EBITDAF is $480 million, and the associated operating free cash flow of that -- of $280 million is still sound and that we pay out 100% of that, which is $0.39. We normally split our dividend, interim-final, 40-60, which gives you $0.16 for the interim, which is what we're declaring. And that's 10% imputed based on our tax position. So hopefully, that wasn't a surprise for anyone. Hopefully -- this is the second year in a row of this dividend policy. So hopefully, sort of the repeat of it adds even more to the clarity that investors get around this type of policy. It's our balance sheet capacity that actually allows us to buffer investors from hydrology and give this level of clarity around our dividends. And if you're interested, that gives a 5.4% dividend yield, which isn't bad.

So with that, I'll hand back to Dennis.

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Dennis Barnes, Contact Energy Limited - CEO [3]

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Thanks, Dorian. And I'm not going to talk about much here because [I only have] a few big topics. Obviously, the first one being the smelter. Our view remains that the first step in decarbonizing the country is not to send low-carbon production offshore to a higher-carbon world. So we think that the smelter, fundamentally, is a good thing for New Zealand.

But any disorderly impact -- any disorderly exit impacts many, many stakeholders and all of the [gen savers].

So with that in mind, we're actively engaged in trying to keep the smelter, provide electricity supply. Obviously, Meridian take the lead on that as the counterparty, but you can rest assured that we're behind them and supporting them at a level which we think is reasonable and a level which we think is manageable in our earnings outlook to maintain our assumptions on the earnings and dividends.

Having said that, as the smelter review is a more real step than just a bit of noise, work on the mitigations continues. And as it's more real, the mitigations get more real. So a few years ago when the smelter was under review, everyone had an expectation that it would quickly [stay]. The lower South Island upgrade project was referred to as being [3 summers] and a lot more money than we're seeing today. So this is an example that the creativity that the industry can bring to bear, in my view, will mean that, that lower South Island upgrade could complete as early as mid-2021. The reality of an exit makes [a significant small deal] as well, that you'll see a creativity in the industry.

And it's certainly not as bad as the market cap loss across the industry. We've shown through contracting our own dairy conversion that the electrification is real. It's real that price is way north of the smelter price, but as you would expect, south of the ASX price.

And there's much commentary about the impact on Contact of the closure of the smelter [on a thermal kit]. You can see today with the accelerated depreciation of TCC, smelter aside, we don't expect that plant to be making any money. So we struggle to see how it can be an impact. But the summary is, we're actively engaged. Obviously, it's in their hands and there should be news over the coming weeks and months. If that doesn't work, then the mitigations are stronger and more real. And the response, I think, will positively surprise everybody.

Just [going to stop. Probably] a couple of regulatory matters I wanted to comment on. Firstly, undesirable trading situation [claim] and market making that it impacts us in the half. [Due to valuable change in situation, you'll see these for yourselves] when you're looking at a large, complex industry which is responsible for an essential service. So although it's quite media worthy to see pictures of second-tier retailers with our spill gates open, [the filter] received more than twice the water it was able to process through the turbines. So unless you want to spend billions of dollars on new dams and transmission lines for infrequent high inflow sequences, then it's clearly a ridiculous claim.

[Want to just] lead you through, though, is a call for a more monitoring approach by the regulator rather than a big noisy investigation. Does no one any good to see the industry played out in the press. So I think the monitoring approach by the regulator would certainly support a smoother operation of the industry.

Somewhat related is market making. Market making volumes have risen over time. As you can see in an earlier chart, the growth of the second tiers doesn't appear to be being constrained by market making. And in fact, market making has a number of non-retail speculators participating, including speculators that own second tier retailers. So we don't think the timing of the market making arrangements add to the benefit of consumers. We think it adds cost to the industry. And ultimately, that will be borne by consumers.

As I mentioned, this is not a simple industry. It's an essential service. And having a prudent approach to retail is what is more appropriate, in my view. You can see in the U.K., the disruption cost to customers of retailers coming in and out of the market, and it does no one any good.

So a bit more specifically to Contact and the announcement we made today that given the improving gas supply outlook, we have contracted gas. A bit of a 101 on why we need gas, and it's essentially because we do have variation in our hydro production. And on average, we do need 8 petajoules, but can, if it's dry [further], need more.

So we have announced 3 transactions today. One is a new swap arrangement for this year, a notification of our pre-committed contract with Maui for next year and a new purchase from OMV for 2021 through to 2025. So with the masses of water in the system, plus the gas in storage, we feel very comfortable that the short-term gas supply for Contact, short to medium-term, is resolved.

Now that's coming at a higher price. We showed what that meant for first half results in the earlier slides, but we are now seeing the short-run marginal cost of our plant going to the 90s. That's on the average gas price. If you were to take the highest-cost gas in our portfolio, it would be even higher.

Dorian has mentioned that through the period, we were impacted by risk management. And the reason why we are prudent is clearly because of the dividend certainty that we provide, which we think shareholders like. And the chart on the left, albeit without too many numbers on it, shows what would have been possible if we had taken a riskier position in terms of EBITDAF. But you can see along the bottom, our earnings and risk increases materially. And we look at this all of the time with the Board, and we think we've reached a reasonable balance where our risk settings are such that we can continue to give that dividend certainty through multiple scenarios.

The easier thing to do, of course, where your risk is driven by supply and demand, is if the supply isn't there, is to drop the demand, and that's what we did in the period. But we are now, with the new gas contracts, [significant] storage [and] some of the contracts looking to reenter the C&I market, and that will obviously drive improved earnings.

And then just finally on the right-hand chart is if we have an [average] year in 2020, are we okay? The answer is yes. And if it were dry, still yes because there's a lot of stored water and stored gas around.

Priority areas. Near term, in my language, might be the next 3 weeks, but for the organization, probably goes a little bit longer. As I mentioned, the constructive engagement with Meridian and the smelter, get back into the groove, given we've now seen a more confident gas supply outlook, continue to drive costs and get those input costs more appropriately passed through to our customer base.

It was announced recently that the transition has occurred in (inaudible) on the 24th, I finish on the 28th. [Within our compliance]. So it's unlikely Mike and I will be sitting at the same desk -- sharing a desk. But as I committed to the Board and the market, there will be a smooth transition with no gaps.

And of course, as the smelter, you can [tuck] and tail this section and say as the smelter resolves one way or another, then we expect Tauhara to resolve one way or another.

And then longer term, same story, continuing to lower the cost and capture scale efficiencies in both of our business. And we've seen in this half, with [Simply], with the governmental and societal push on decarbonization, a real acceleration of the interest of customers in decarbonization opportunities, which will result in, at the moment, [growth].

What does that mean for our confidence in the cash flow of the business and our ability to continue to support the dividend? Continued confidence that we have gas in place and the continued efficiency program. The EBITDAF, and therefore, cash flow is under control. We have not changed any of the cash items versus guidance at the full year. Of course, depreciation will go up. Interest will go down for the reasons that Dorian explained. So we fully expect to be able to cover the FY '20 dividend target of $0.39 per share.

And with that, we'll go to questions. Matthew?

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Questions and Answers

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Matthew Forbes, Contact Energy Limited - IR Manager [1]

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Thanks, Dennis. This is the question-and-answer section of the presentation. (Operator Instructions)

[And the first one]?

Yes. Well, maybe we'll start in the room with Andrew.

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Andrew Rupert Pelham Harvey-Green, Forsyth Barr Group Ltd., Research Division - Director & Senior Analyst of New Zealand Equities [2]

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Technology limits. So a couple of topics I just want to just sort of cover off. One is, first of all, the $480 million and when you think you might get back to that, because obviously, you're not in the C&I market right now? So when one assumes the second half earnings for this year and, I guess, given the first half earnings next year are going to be [heavily weighted] as you get back into the C&I market. Is that a fair and reasonable assumption? That's the first question.

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Dennis Barnes, Contact Energy Limited - CEO [3]

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Yes, yes, yes.

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Andrew Rupert Pelham Harvey-Green, Forsyth Barr Group Ltd., Research Division - Director & Senior Analyst of New Zealand Equities [4]

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And secondly, with the HVDC constraints we're seeing in the market right now, I guess, you've got a lot of work, [you can't get North Island], pricing is being impacted. So net-net, is that, I guess, being a positive (inaudible) view at the moment?

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Dennis Barnes, Contact Energy Limited - CEO [5]

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I mean, January, [we will offset] back end of the week. Well, first, most of them look like similar to last year. Obviously, February has got a little bit more price separation. But with our North Island plant available and the way the reserves market works, it's -- you wouldn't say it's a tailwind, but (inaudible).

One of the things that has become clear through this period is that the modeling one has to do when there's a significant event like the HVDC not working, there's [always a] complexity, which I think is actually instructive to the smelter. So if the smelter were to close, how one manages the location factors, the reserves market, security of supply, there's a degree of complexity that tells me it wouldn't be as bad as we might have first thought. And this, clearly, is actually quite instructive for that. But net-net, at the moment, we'll [start] similar to prior periods.

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Andrew Rupert Pelham Harvey-Green, Forsyth Barr Group Ltd., Research Division - Director & Senior Analyst of New Zealand Equities [6]

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Okay. And the second question I have is just around Tauhara and thinking about the size. (inaudible) in the past, you talked around about 130 megawatts or thereabouts. I just -- I guess, I'm thinking your commentary around TCC and its profitability as this figure also applies to 5 [Genesis] And sort of are you having negotiations, discussions around it, which you might see as -- up 130 megawatts?

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Dennis Barnes, Contact Energy Limited - CEO [7]

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I mean, we said before that we're actively happy to sell elements of Tauhara to long-term PPA arrangements with either gentailers or other industry participants. So the answer is yes. I mean the primary focus at the moment though is alleviating the resource. If you could sell more, you might not sell more in the first phase anyway because it's a resource that we'll learn more about as we go.

I joke that [Wairakei] took 57 years to reach its full potential with Te Mihi. I don't think you'll see us go above 140 initially just because you do need to really understand the results. It may be that more of that 140 goes to third parties and not Contact. But yes, an ongoing discussion.

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Andrew Rupert Pelham Harvey-Green, Forsyth Barr Group Ltd., Research Division - Director & Senior Analyst of New Zealand Equities [8]

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Thanks, and all the best for the future, Dennis. I've enjoyed our interactions in the past. [We're not so sure if it's still the case, anyway].

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Dennis Barnes, Contact Energy Limited - CEO [9]

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Yes, it's been fun the last 9 years. I was -- I didn't make a [joke, but] I think just over 9 years ago, [David and Liz] also produced the -- an earnings-at-risk chart, and some of you may remember that far back. So they actually had numbers on it. [And I've said, really] -- seriously, I'm going to achieve versus those numbers. So I didn't want to leave Mike with an earnings-at-risk chart. But it's the same thing for him. Thank you, Andrew.

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Matthew Forbes, Contact Energy Limited - IR Manager [10]

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Okay. Thank you. We will go to the lines first. Stephen Hudson will [promote] Stephen's questions. Stephen?

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Stephen Hudson, Macquarie Research - Head of Research [11]

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Just a quick question on Tauhara. You've talked about a dollar cost per megawatt across the full sort of 250 megawatts. I just wondered if you can sort of chunk it down in terms of the phases and what the costing may be. And also given, I suppose, a favorable repricing or repricing of the [NZX] contracts, what -- when you would expect first production on the first phase? So if you can just sort of talk us through production and costs on a phasing basis, that would be useful.

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Dennis Barnes, Contact Energy Limited - CEO [12]

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I mean, I think [with respect to] 250 megawatts, it works out about $4 million a megawatt. If we were to do half that first, so 140 megawatts, it'd be lower than the average, maybe more like $3.6 million a megawatt. Obviously, that's not all the story because ongoing operational costs make up a good few dollars of megawatt hour.

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Stephen Hudson, Macquarie Research - Head of Research [13]

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Yes. Look, I'm just trying to...

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Dennis Barnes, Contact Energy Limited - CEO [14]

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So the first half is cheaper. [Until the] timing, assuming the smelter passes, then the TCC end-of-life is instructive, we would expect to be overlapping slightly. So TCC [owes us] in year '23 towards the back end depending on hydrology and Tauhara starts to commission earlier.

There's a technology [charge] on Tauhara, which I won't go into. It's too much detail because we're actively negotiating with [tenderers]. But if we were to go a big [plus] plant, [then] single units [but with smaller] units, we'd still achieve those long-run marginal costs. So you might get some of the other unit commissioning in early '22, late '21.

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Stephen Hudson, Macquarie Research - Head of Research [15]

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And Dennis, just a quick follow-up. Would the EPC contract be sort of full -- you're fully off-risk? Or would you contemplate sort of some variation on the EPC contract where you pass forward some of the construction risk?

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Dennis Barnes, Contact Energy Limited - CEO [16]

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No. I mean, obviously, we will take the risk on the steam field because that's our equipment. We deliver steam to a power station inlet. But past that inlet, it's all the contract with liquidated damages, provisions if they don't deliver. So we're not taking any -- you can't say not taking any risk. But as you saw with Te Mihi, where we -- [about $250 million for these] contractual arrangements, we would be looking to replicate something of that nature.

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Matthew Forbes, Contact Energy Limited - IR Manager [17]

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Next, we will go to Grant Swanepoel from Craigs Investment Partners.

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Grant Swanepoel, Craigs Investment Partners Limited, Research Division - Director & Head of Institutional Research [18]

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Can you hear me?

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Matthew Forbes, Contact Energy Limited - IR Manager [19]

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Yes, we can.

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Grant Swanepoel, Craigs Investment Partners Limited, Research Division - Director & Head of Institutional Research [20]

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Fantastic. So now that you're going to -- you've got gas, can I see the C&I book expanding another 500 gigawatt hours? Or is that too aggressive?

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Dennis Barnes, Contact Energy Limited - CEO [21]

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Over time, Grant. Obviously, because we got gas and [made it] available, it doesn't mean that the other side of the equation is there. But over time, over the next 18 months, yes.

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Grant Swanepoel, Craigs Investment Partners Limited, Research Division - Director & Head of Institutional Research [22]

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And then looking at your gas book, I know you gave a [whole lot of] metrics there at $6.74 a gigajoule at the moment. The calendar year '21 looks like you average about $7.20 a PJ, which means you've probably contracted near $8. Is that what your new contract price is around about?

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Dennis Barnes, Contact Energy Limited - CEO [23]

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Obviously, they're confidential. But if you average just over $6 and around about $8, you get low $7s. So you're thinking it about right.

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Grant Swanepoel, Craigs Investment Partners Limited, Research Division - Director & Head of Institutional Research [24]

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Perfect. And if Tiwai does actually have a surprise one-year closure announcement come April this year, do you have the ability to exit some of those gas contracts you've now committed to?

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Dennis Barnes, Contact Energy Limited - CEO [25]

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Well, we've obviously got the stakes in gas storage [in] the retail business. And you still have hydrology risks, so the gas needs are still reasonably material. The -- so we don't -- what we bought, this is a trade-off. We could have bought more, we chose not to, and we'll use gas storage to manage that risk.

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [26]

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We have a little bit of flex in the outer years of them. And that sort of actually helps with the uncertainty around TCC and what we do with that. So yes, it was a bit of flex, but not huge.

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Dennis Barnes, Contact Energy Limited - CEO [27]

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So the [R&D one] drops in '24 and '25 or (inaudible). So we're quite comfortable. The combination of our hydrology risk needs and retail and it's...

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [28]

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And then we've got gas storage.

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Dennis Barnes, Contact Energy Limited - CEO [29]

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Yes, [it's all manageable].

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [30]

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Yes.

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Grant Swanepoel, Craigs Investment Partners Limited, Research Division - Director & Head of Institutional Research [31]

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And then with Mike starting on the 24th and you're transitioning out end of the month. The Tiwai scenario, do we expect some sort of decision by the end of this month based on that timing? Or do you think this is going to drag out indefinitely?

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Dennis Barnes, Contact Energy Limited - CEO [32]

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I think given Rio are a $100 billion company headquartered in London, they're not running their timing based on my exit, although I'd like to think I was that important. That's it. The only honest answer, Grant, is that the (inaudible) electricity that's been made has a shorter expiry than the end of March. But you would have to say that if the smelter were looking to go through to the end of March for the decision, then they're going to drive that time.

I'm not -- I would love to be [funding] an announcement in the back end of the month, but I doubt that will occur. But to give you some comfort, the Chairman, Dorian, all [over] it in the detail. So there's very little transition risk of me moving on.

But as I've said, we're one step behind. Meridian will remain the counterparty.

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [33]

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Yes. I mean as we said before, there's a lot of reasons why Rio would want to wrap things up as quick as they can because they've got the uncertainty for employees and things like that [down with] as well. But as Dennis said, unfortunately, he doesn't have that level of impact [substantially].

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Dennis Barnes, Contact Energy Limited - CEO [34]

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I think it's been useful -- in our industry, it's been useful to have my departure sooner than the smelter. So it -- from our perspective, it's not run to the wire. We are actually engaged.

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Grant Swanepoel, Craigs Investment Partners Limited, Research Division - Director & Head of Institutional Research [35]

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Sorry, there is a final question on that. So can I interpret that actually there's an alignment of your thinking with the Board and with Dorian. So Mike being a man of action can come in and get his head around all the issues with the Board and Dorian potentially leading the charge on Tauhara's mix with a Tiwai stay-or-go decision?

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [36]

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Yes.

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Dennis Barnes, Contact Energy Limited - CEO [37]

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Yes, absolutely.

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [38]

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Absolutely, yes.

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Dennis Barnes, Contact Energy Limited - CEO [39]

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And some of you will have known Rob a long time. Rob's pretty actively engaged with us, with Dorian.

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [40]

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Yes.

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Matthew Forbes, Contact Energy Limited - IR Manager [41]

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Next on the line, we'll have Aaron Ibbotson from UBS. Aaron, are you there?

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Aaron Ibbotson, UBS Investment Bank, Research Division - Director & Research Analyst [42]

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Yes. Let's try this out. Can you hear me?

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Dennis Barnes, Contact Energy Limited - CEO [43]

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Yes.

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [44]

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Yes.

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Aaron Ibbotson, UBS Investment Bank, Research Division - Director & Research Analyst [45]

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Fantastic. So a couple of questions already asked. But first of all, best wishes to you, Dennis, in your future adventures. My first question is, how much sort of more electricity do you think could move to the North Island after The Clutha Upper [Wairakei] lines project is completed? And I appreciate it's not an exact science, but at least my experience is I'm hearing quite different messages from the North and South Island-dominated gentailers. So I would love to hear your thoughts on that.

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Dennis Barnes, Contact Energy Limited - CEO [46]

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[Beside the] -- we think the project relieves [many nearer] constraints. And obviously, there's a lot of averages and averages in a mean year that can be driving that. But we think it moves 1 to 1.2 terawatt hours. [Then whether it hits the ball that further North] is another question. But the [CUWLB] can move 1, 1.2 terawatt hours more than it moves today.

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Aaron Ibbotson, UBS Investment Bank, Research Division - Director & Research Analyst [47]

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Okay. That's very clear. And second question, just on TCC where you've introduced some not-so-surprising clarity on your thinking. I was wondering if you could update us just, what is the operating cash cost, if I put it that way, of TCC today, ignoring any fuel or carbon costs, i.e., should we expect a certain number to sort of come out of the OpEx when -- if you close it?

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Dennis Barnes, Contact Energy Limited - CEO [48]

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Yes. Including gas transmission, which is the -- [few ones in the] answer...

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Aaron Ibbotson, UBS Investment Bank, Research Division - Director & Research Analyst [49]

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I heard that whisper by the way, so I kind of already knew that.

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Dennis Barnes, Contact Energy Limited - CEO [50]

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I was going to say 15, but [Mike's saying it's] closer to 20.

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [51]

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Yes.

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Aaron Ibbotson, UBS Investment Bank, Research Division - Director & Research Analyst [52]

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And what about -- there must be some people working there, with -- must be a bit more.

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Dennis Barnes, Contact Energy Limited - CEO [53]

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Yes, that's included, so gas transmission and OpEx. And because it's a big efficient plant, there's quite a bit of consumables, chemicals and the like. So yes, all of that is close to [20].

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Aaron Ibbotson, UBS Investment Bank, Research Division - Director & Research Analyst [54]

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Okay. And final question, on my favorite topic of dividend. So if I run your sort of $480 million normalized EBITDAF, less what, at least what you guide for this year when it comes to CapEx, interest, cash taxes and cash interest, I get to just shy of sort of $300 million, call it, a normalized cash per year, which translates, my estimate, around $0.41. So can I invite you to suggest or confirm, nay or yay, that your base expectation would be for dividends to remain largely flat until Tauhara or something else unexpected or future happens?

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [55]

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Yes. Yes.

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Dennis Barnes, Contact Energy Limited - CEO [56]

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So $0.39 until there's a systemic change. We're not sure TCC is systemic enough on its own. But if it were, then that would cause us to increase dividend. But Tauhara is the trigger for increased dividends. (inaudible) and I thought you were a little shy, saying we got [a 41] on Tauhara, where Tauhara is much more cash-generative than that. Given its contribution to EBITDAF, the capacity goes up. So if you're looking for a longer-term view, it's -- I think we've said Tauhara would deliver $0.06 to $0.07. The first phase is [half-sized] phase. And we would love to return most of that because the capacity goes up to fund Wairakei with Tauhara. Well, that's post smelter, post FID, 3 years away. But flat till then is a good assumption.

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Matthew Forbes, Contact Energy Limited - IR Manager [57]

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We'll go on the line to Adrian Atkins from Morningstar. Do you have any questions, Adrian?

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Adrian Atkins, Morningstar Inc., Research Division - Senior Equity Analyst [58]

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No, thanks. All my questions have been answered.

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Matthew Forbes, Contact Energy Limited - IR Manager [59]

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In the room, we'll go to Nevill from Jarden.

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Nevill Gluyas, Jarden Limited, Research Division - Director of Equity Research [60]

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Okay. So a few questions from me. First one, the -- you talked about CPI increases and sort of your [confidence in the guidance, basically,] for the next 3 years as you bridge over to what presumably will be a greater renewable penetration in the market and lower prices than [forecasted]. So do you think your competitors will do that as well?

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [61]

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It's difficult to tell. I mean, obviously, when we're making decisions, we're always very mindful about what's going on with the overall market and we feed that into our decision process. But as Dennis showed on a slide, if we look back historically, retail prices have been going up by about CPI. So if history is a good trend, then maybe.

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Nevill Gluyas, Jarden Limited, Research Division - Director of Equity Research [62]

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And the deals sort of on offer to Tiwai at the moment, of course, you can't tell us -- I presume, can't tell us exactly what those are, but at the moment, the expectation will be...

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Dennis Barnes, Contact Energy Limited - CEO [63]

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Nice try.

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Nevill Gluyas, Jarden Limited, Research Division - Director of Equity Research [64]

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$50 million to $70 million per annum has been sort of the range you talked about in the past. The deals you've got on the table, are they going to surprise us compared to that expectation?

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Dennis Barnes, Contact Energy Limited - CEO [65]

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I don't know because I don't know what Meridian have put to the smelter. I mean I know our contribution goes up both in value and -- both in volume and price, which I think is highly manageable. And Dorian's (inaudible) transformation is related to that.

I wouldn't be surprised if (inaudible) between us, Meridian and Transpower (inaudible). I just don't know.

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [66]

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Asking the same question there, but in a slightly different way.

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Dennis Barnes, Contact Energy Limited - CEO [67]

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Which is [$200] a tonne aluminum. And that convenient description of their position in the smelter world forgets to mention that, that curve is incredibly flat and that the Canadian smelters are [wrong], so there's no return on capital assumed in the electricity price. So I think it's material. And there's lots of people [writing] about carbon-free aluminum and the reduction in alumina costs and [the like]. But I think the industry is [set up].

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Nevill Gluyas, Jarden Limited, Research Division - Director of Equity Research [68]

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Right. Third question. What's your view on the long-run gas price? So obviously, we've seen a lot of compression now, a lot of tightness, high prices. [It's good] some of the stuff at higher cost. But is that indicative of where -- where do you think this is in 3 or 4 years' time?

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Dennis Barnes, Contact Energy Limited - CEO [69]

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You've got to start with methanol (inaudible) because although methanol is a little bit lower at the moment, $4 to $5 equivalent per gigajoule and [it has that] higher equivalent. And if gas prices sit at -- let's use Grant's number of $8, then the returns Methanex are making reduce significantly relative to the international options.

So it's going to be a bit of a -- [so I'll say this, I believe]. So I don't think [I can say] much higher because then Methanex doesn't work and that gas comes to market. And because the gas is an associated product, the producers will still produce [electric] and gas prices will fall. So I struggle to see it come in higher.

And then I think there's another phase in the decade where the gas really is [lesser than if the] (inaudible) gas is really at the end of life. The gas from our sector is so small, like you're beginning to think about import or onshore-only supply. And then because it's only 3% to 5% of supply, of electricity supply, then the price is somewhat irrelevant. It becomes a reserve cost. Barring anything crazier, I think you've seen a new benchmark in the $7s, possibly the $8. As this investment comes out on the existing fields over the next year or 2, I think we'll be able [to beat the high] (inaudible) in that.

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Nevill Gluyas, Jarden Limited, Research Division - Director of Equity Research [70]

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That's great. And the last one, just you talked about having up to 6 PJs. We're at 6 PJs now at Ahuroa. The higher extraction rates, [it would be] comfortable with the 65 TJs per day. Is it achievable when it's [done]?

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Dennis Barnes, Contact Energy Limited - CEO [71]

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Yes.

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Nevill Gluyas, Jarden Limited, Research Division - Director of Equity Research [72]

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Okay. And...

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Dennis Barnes, Contact Energy Limited - CEO [73]

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(inaudible) costs.

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Nevill Gluyas, Jarden Limited, Research Division - Director of Equity Research [74]

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True. Yes, you get 45 of it.

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Dennis Barnes, Contact Energy Limited - CEO [75]

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Yes.

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Nevill Gluyas, Jarden Limited, Research Division - Director of Equity Research [76]

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And are the 6 PJs fully available, so that is -- make sure my understanding is correct, that is fully stored. That's not [fully cushing].

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Dennis Barnes, Contact Energy Limited - CEO [77]

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Yes. That [cushing] is not (inaudible). You'll see a note in the accounts for full transparency, that every year, you do an assessment of what's working volume and what's cushing volume. And every year, we would have an [argy-bargy] with [origin] of ourselves. And you'll see there's a note in the accounts that we're having an argy-bargy with the new owner. My experience is that it always resolves itself, the reported volumes, the volume of -- [across the] full year contract [number] for full transparency.

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Andrew Rupert Pelham Harvey-Green, Forsyth Barr Group Ltd., Research Division - Director & Senior Analyst of New Zealand Equities [78]

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I just have one quick follow-up question. Just to clarify the $480 million, if the smelter deal comes through. I'm assuming the $480 million is probably based on (inaudible) smelter (inaudible)?

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Dennis Barnes, Contact Energy Limited - CEO [79]

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No.

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Andrew Rupert Pelham Harvey-Green, Forsyth Barr Group Ltd., Research Division - Director & Senior Analyst of New Zealand Equities [80]

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No?

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Dennis Barnes, Contact Energy Limited - CEO [81]

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It comes in all the time, and we'll adjust the rest of the business.

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [82]

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Transformational change kind of stuff.

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Dennis Barnes, Contact Energy Limited - CEO [83]

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So we're not fully contributing day 1.

It sounds like that's it. I'll see all of the New Zealand contingent over the next week, probably won't see the Australians again unless I appear (inaudible) business.

Thank you for your time, and see you all soon.

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [84]

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See you.