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Edited Transcript of CEN.NZ earnings conference call or presentation 11-Aug-19 10:00pm GMT

Full Year 2019 Contact Energy Ltd Earnings Call

wellington Aug 15, 2019 (Thomson StreetEvents) -- Edited Transcript of Contact Energy Ltd earnings conference call or presentation Sunday, August 11, 2019 at 10:00:00pm 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

* Grant Swanepoel

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

* Nevill Gluyas

Crédit Suisse AG, Research Division - Research Analyst

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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 our full year '19 results presentation, conducted in a different format. We have a cost drive. This saves about $12,000, and it will also save me the salary of an Investor Relations manager if it fails. Usual disclaimer. And then we'll take it through in a normal format. I'll give a little bit of a look at the highlights. Dorian will go through the detail. I will do it in a way which describes the market and the business, Dorian will obviously take us through segment level. And then some comments about current market and our outlook.

So suffice to say, we've had a good year with every financial measure on we improved. So we completed the sale of 2 assets in the year, receiving cash proceeds after tax of $390 million. That has put us in a great position with a strong balance sheet, high-quality renewable generation assets and low-cost operations, which has given the Board confidence to affirm the target dividend we mentioned at the half year the $0.39 for the full year, $0.23 for the final. Now [that I've] been through this presentation of organizing ourselves for success and also you all have seen in the years unreliability and increasing cost of gas and good planning or good luck, we're now in a great position to take advantage of that.

So very confident in my final results to be able to save the company's operating well, with great financial returns, as you see on this chart and the real strong position and win further geothermal development.

Of course, many stakeholders are important in that conversation, maintaining financial discipline, so we can continue to show great EBITDAF to cash flow provision. Again, an improvement in our customer advocacy score going up to 26, in a period where with regulatory oversight, we managed to release more products than we have ever done, rebrand and reposition the organization. And we did that because we have safe and engaged employees. We had a 1.3 TRIFR in the year, which is the best we've had and engagement scores stay high.

And as I mentioned, all that sums to great cash flow conversion and ability to be comfortable about increasing the dividend to $0.39 a share. We expect to keep going on those measures with continued reduction in OpEx and CapEx. You'll know that the target is a little bit higher than we would have foreshadowed last year. And although we refer to midpoint, our target is actually the lower end of the range, of course. Suffice to say the retail market is incredibly competitive with regulatory oversight. A fair bit of investment has gone in there this year, which obviously changes the year-on-year trajectory. Continued focus on safety. The injuries we had in the year will be minor slips and trips, and we obviously look to 0 for those continued safe organization.

We look to build customer advocacy, 26 is good, but world-leading organizations are in the 50s and 60s, and we'll keep progressing on that. And we strive for best-in-class employee engagement.

And all of that, as I've mentioned, has allowed us to show that distribution trajectory and the FY '20 target remains the same.

A little bit on the market. There's obviously a huge momentum behind decarbonization and a great societal push and increasingly a policy and customer behavior push. But the facts are the facts, electricity demand has been flat for a long period. So as we think about the future decarbonization of New Zealand, we take that picture into account and look at the lower cost opportunity first, which is the substitution of gas and coal with geothermal rather than wholly relying on that momentum behind decarbonization.

And again, we reminded that we do have to keep the overall supply-demand in balance when you look at chart like that. A bit of a more short-term question around hydrology. We did see hydrology rebound in the South Island. I think as we run through '17 and '18, we thought, "Oh my God, is this a systemic shift," but 89 years of data doesn't lie, and we've seen the reversion to mean. And we can comfortably say that the cycle has restored. And although the South, the North Island had lower hydrology for a period, that has also started to come back.

Now the big story in the wholesale market, of course, is not that normal hydrology dynamic, but the effect of gas in the wholesale market, increasingly important in our digitalized world.

The wholesale prices, we had the normal noise of hydrology, and we're all very familiar with that. But I think the big feature in the year was the impact of gas supply interruptions and the prospect of gas supply going forward. Clearly, with our portfolio with peakers and gas storage and very strong risk management practices, we were able to benefit from that in the year. I was predicting that we would see a quicker return to more normal electricity prices, which we haven't seen, which reflects the ongoing uncertainty, which from our perspective is pretty good because we will continue to use our gas storage prudently and our peakers prudently and also perhaps take a little bit more exposure to shorter-term markets, i.e, spot and CFDs over the next year or 2.

In terms of the operating businesses, there were 2 stand-alone strategies. Obviously, let it down from optimization of our business to deliver comp -- strong cash flows. But we're all here to create sustainable volume for New Zealanders and connect it to our brand promise. That's about putting our energy where it matters.

The Customer business in the year improved an awful lot of metrics. I mentioned customer advocacy churn relative to market, and impressively the number of phone calls reduced to drive a higher netback.

Now in the year, we have the regulatory oversight, I've mentioned, which, of course, is not finalized yet. We did accelerate some of our plans, and we delivered more products, including PrePay, weekly/fortnightly paying, and importantly, the basic plan, which is the removal of PPD for our customers over time, which, all of that in itself, comes at a cost, but the team did a really good job to maintain cost to serve while delivering on all of those accelerated plans. Now our plan was to have all of that product set in way of serving our customers in place over a couple of years. We've done it over a year. So that gives a bit of a tailwind to the metrics in the Customer business going forward.

So Wholesale business, again, impressive metrics on safety and cash costs. Geothermal and hydro volumes are pretty good, but that's mainly a hydrology story.

The big story in wholesale, of course, is the unreliability and the increasing cost of gas and historical insurance products has meant that the importance of developing our geothermal business and developing in a low cost way has increased. So a lot of the effort in the year was about that, which is, of course, virtuous, because the more we do to reduce our cost of operations, which is shown in those figures, the more competitive the next development gets. But Wholesale business itself got 2 connected activities at the moment. One is that continued lower cost of geothermal. And we're talking about geothermal in a gas equivalent, which is $4 to $5 a gigajoule. So you compare that to where gas and coal has gone in the last June. So pretty compelling activity for the team. But of course, the Wholesale business is also managing what that means in the medium-term for the operation of our gas plant.

Well, again, a great operational year, significant trash cost reduction and foundation for the future. So with these opening remarks, which (inaudible) driven by a few technological pauses, I'll hand over to Dorian, and I'll come back at the end.

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

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Hello, everyone. Well, as most of the things that are going to come out as I go through the operational and financial performance, the concept for FY '19. The first is the -- that it's been a very strong year in terms of renewable generation, hydro, in particular. The second is we've seen a material increase in the cost of thermal generation. And with thermal generation being the -- one of the key risk management tools in the industry that directly or indirectly and also the price setter for large part of the year is not surprising. We've seen sort of higher wholesale prices. We expect them to remain elevated relative to historic levels until we see more reliable and reasonably priced gas coming to the market.

The third point, again, Dennis has mentioned, this is about, we haven't seen tariffs from the retail space adjust to the higher cost environment. So we're seeing our margins being squeezed in. We do think that's probably indicative of what you're seeing around weakness in electricity across the industry more generally.

And the fourth point, which is very specific to us, we do have a relatively strong balance sheet now. So if and when we make a positive investment decision on Tauhara in FY '20, we're sort of ready to go in terms of funding that.

This slide that I've got up here sort of talks about the key statutory profit performance, it's standard slide for us. We've got $132 million to $345 million. The breakdown of that is $175 million of discontinued operations, which is broadcast. We made $10 in terms of trading up until when we disposed the business at the end of November. And then we made $165 million actually on the disposal itself. Underlying -- nonunderlying profit of $4 million, the largest we've had, and that is $5 million of profit derived from the proceeds of the AGS asset, which takes you to sort of underlying profit of $166 million, which is up by $56 million on the corresponding number from the prior year. The majority of that growth has come from EBITDAF, and is driven by a lot of the same things we talked about at the half year in a good renewable generation and the ability to leverage our flexible asset base that when the market requires additional volume in October and November, we were able to use our gas stored in the ground to push thermal harder. We were able to push our key thermal plants harder, and indeed even with Wairakei 4-year inspection into December, so that's pushed up the EBITDAF.

We've seen depreciation being lower. We don't depreciate assets that are held for sale. Those are $3 million benefit from that. But then we are -- we have seen a sort of lower CapEx environment over the last few years. We see that being for interest, depreciation. Interest rate, interest cost -- net interest costs are down by $14 million. You'd expect that we got $477 million less net debt year-on-year. And tax has gone up, you'd expect that in line with high profit. Our effective tax rate is marginally above the statutory rate, which relates to some timing differences.

On to the performance of our underlying -- of our continuing businesses from an EBITDAF basis. You can see there very strong performance in terms of the Wholesale business, and that performance is achieved even though, all things being equal, our costs have gone up by $12 million because of the offset arrangement we've now got with AGS in gas storage. And what's driven the improvement in profit there is 752 gigawatt hours have increased hydro generation. If you price that on a marginal cost of thermal generation, which is what that hydro at this price is, that's where $55 million of additional profit. The increase meant that I talked about at the right times into the higher price environment also drives the benefit. We have had some headwinds. The constraints around natural gas have been a headwind for us. It has meant that we've had to acquire more generation and the risk management tool, whereas in the past, we have been using more thermal to do that.

In terms of the Customer business, that's come down by $9 million. That's a bit of a switch from the first half of the year, where the Customer business EBITDAF was actually up. And this is all about, what I call, price cost recovery. Oil price is going up enough to recover cost inflation, and you can see it clearly on the chart here. They're not. Price effect is $8 million in relation to higher tariffs, but we're seeing the cost inflation for networks and for electricity going up by $14 million. So it's under recovery sitting there. There is a transfer price involved with this, from electricity, from our Wholesale into our Customer business, but that transfer price reflects the same price that a prudent independent retailer would be seeing he is hedging their volumes out -- from 3 years out. So I guess, what I'm saying here is, we think this is probably indicative of what you're seeing across retailing electricity across New Zealand.

So I'll now move on to the Wholesale business. We've got a few slides taking through that. The first one is around generation cost, which have risen by $30 million, even though we've had those higher renewable volumes. And that is about higher acquired generation cost because we're having to use acquired generation as a risk management tool and also because there's some profit benefits there. We would like to buy low and sell high, so we've been able to make a spread on some of our acquired generation purchases. We're obviously seeing those higher thermal costs flowing through here as well.

If you look at our sort of individual asset performance, hydro, very strong. We talked about that. That's the difference between a wet year and a dry year. And the timing was obviously very good in terms of those offsetting those natural gas supply constraints we've had. If you look at geothermal, the volumes there were down by 67 gigawatt hours year-on-year. That reflects the Wairakei 4-year inspection because we have to bring that plant back online slowly to ensure that bioreactor is working properly and the bacteria come back to life, as that ensures we comply with (inaudible) consenting officer Waikato River. Whenever you bring a plant back online, slowly you'll lose a bit of efficiency. So that's what's driving that 67 gigawatt hours. The good thing is it's a nonrecurring topic. So we go back to normal in FY '20. We've had a positive and a negative also within the geothermal (inaudible) incident, which has been talked about (inaudible) forum and some of may go into detail around that, but that cost us 30 gigawatt hour of generation. However, that has been offset by the fact that we've strategically invested more money in more workovers and that's allowed us to get more generation out of Wairakei.

So from a thermal perspective, volumes are down just under 400 gigawatt hours, and that relates to the natural gas constraints we've seen. We have seen -- I'm being very honest, we have seen peaker reliability in FY '19 being an issue. It hasn't impacted us financially because we haven't had much gas, and we've had shed load of water. But obviously, the peaker is our key part of our asset portfolio, and we need -- and we'll have the more trading reliability -- reliably going into FY '20.

Of course, I've some exciting negative there. I mean, something very positive with the great job that the team have done reengineering TCC over the last couple of years. So we can now operate at a turndown level of 170 megawatts. That means at a reasonable heat rate. So we're actually able to turn it down overnight now when wholesale prices are lower, but it has also meant we've been able to enter into a tolling arrangement with a gas producer, where we can use the gas producer's borrowing the space owned for the plant, and that then allows us to put our own gas for using TCC as a closing peaker, introducing more operational flexibility to our operations and also improving our financial performance.

So just on those thermal costs that I mentioned. You can see here on the slide, thermal costs were up by $8 million even though volumes are down by 21%, and that's driven by marginal cost at thermal generations of carbon and natural gas push our cost per megawatt hour from $60 to $74, [safety and] surrender rates of 100%, you've got a higher unit cost of carbon now, and you've also got higher unit costs of natural gas flowing through.

So in terms of our wholesale contracted revenue, that's up by $37 million (inaudible). We've had upstream, but we required to produce more volumes, so we have to sell it. So there's some volume here. And also we've got higher pricing flowing through here. I just wanted to talk about the channel switching is going on. We've switched volume out of the C&I channel into CFD. That's deliberated. It's a risk management tool. Whilst we talk a level of uncertainty around the amount of natural gas that's available, and therefore what our thermal generation is going to be and our cost of energy into the future is going to be, it's sensible to limit our exposure to longer-term, fixed-price contracts, which is the C&I business. So we've been -- haven't been recontracting. It's there pushing that volume into short-term CFDs and some of it flowing through decrease length with grid.

In terms of pricing, pricing into the Customer business has gone up based on the transfer price -- on to the transfer price. The issue is, you'll see that the Customer business hasn't been able to recover that fully from its customers, so its margin is being squeezed. C&I pricing has remained flat. Now we took a lot of questions on this at the half year. And the reason why it's remained flat is because we haven't been recontracting, therefore repricing volume in the higher wholesale price environment for the risk management reasons that I talked about previously. Where we are seeing higher prices, it's in the short-term CFDs because those are linked to ASX pricing, and you can see that coming through here.

Just around off the slide you could see other net income is up by $10 million. A lot of that is around market making. We do see ourselves having a level in-house expertise on this, so we look to make some money in it. We do need to make some money because with the new prudential requirements of the ASX that we're being more conservative. We've actually got $17 million of potential now, which has an opportunity cost, and therefore we need to be making money or market making to offset that. So it's good to see that coming through.

In terms of our trading performance, trading with the grid, it's up by $60 million, a big number. And what that's been driven by increase length. So we've got 266 gigawatt hours of increased length, and the pricing that we're getting on that length is $142 per megawatt. So whilst we're not seeing price increases in C&I, we are seeing price increases, that I showed in the previous slides, in short-term CFDs and in our length that we're getting in terms of trading with the grid. That price increase in length is $53 per megawatt hour year-on-year. Location losses have gone up by $20 million. You'd expect that because that's proportional to the higher wholesale price environment.

On the slide, you can see our location loss spread, our LWAP/GWAP has moved slightly against this from 6.7% to 6.9%. You'd expect that with less than North Island generation due to the natural gas constraints. So that's the Wholesale business. I guess, there's a lot of topics up around that are linked to natural gas, in particular.

I guess, it comes (inaudible) probably get around. This is in the year, we've been able to risk adjust our business, all that and still yet deliver a strong financial performance.

So on to the Customer business now. And we're seeing revenue down by $12 million in spite of tariffs going up a bit, and that's driven by volumes being down 3%. So average customer number is down by 3%, and consumption per customer is down by 1%, which is following that sort of longer-term trend you have there. Our customer numbers actually improved in the second half of the year. So if you compare June '19 with June '18, they are only down by 1%. What does that mean in terms of our EBITDAF, it is down by $9 million. And this is about that price cost under recovery I mentioned. You can see this on the chart. Our electricity tariff is up by $2.10 per megawatt. The network cost -- electricity network costs are up $1 per megawatt and our electricity costs are up by $2.80. So you can do the math there. You've got $3.80 per megawatt cost inflation, yet only $2.10 in terms of tariff increase. So you got $1.70 on recovery. You apply that to 3.6 total megawatt hours, it gives you about $6 million of profit and cash reduction. The rest of the variance, which is down to lower volumes. You can see that the business has done what it can around its controllable lever around other operating expenses. It's got that down by $1 million from 82 to 81, but that's not offset -- not enough to offset that major price cost under recovery, which does talk to the competitive nature of the industry. As this is a key point for us, I have got a slide just to sort of go into a bit more detail around this. So our Customer business is facing some headwinds, as I believe the industry is more generally around this topic.

You can see on the left-hand side, this is a construct of our average electricity tariff, broken down between the cost of this recovery and then the profit that we're making. And you can see really, actually, the largest component of the retail electricity is basically just hauling business to collect that network costs and pass them back to the alliance companies. And the issue you've got is that -- if that cost is going up on average by 2% every year. The next biggest component is electricity cost. From all sides it remained relatively flat. In this higher wholesale price environment, we're starting to see costs in FY '19 and '20 go up. So now we're forecasting that's going to be increasing by 2% on a compound aggregate growth basis, yet the tariffs are only going up by 1% due to the competition. Customer business has done what it can with its lever. Cost to serve or operating costs that it's showing there is down by 3% every year. So that's a good result. But that's not enough when you're seeing EBIT, the margin there being squeezed, and it's coming down by 12% on a compound aggregate basis. And what does that mean in absolute terms for the profit that we're making from electricity retailing, we're coming down from $34 million in FY '16 to just a forecast of $19 million in FY '20, which is a 2.2% EBIT margin. Great for consumers. You can see the average revenue from electricity that we're getting per customer is dropping by 1% every year. That's on a normal basis. On a real basis, it's dropping by 3% a year. And this talks to the competition in the marketplace. You ask anyone how competition manifests itself, and its the inability to recover cost increases from your customers, which is what you're seeing here. It's not sustainable, though, in the long run. So what we've been doing is making sure we have the lowest cost to serve, at least within the Tier 1s within the industry. And we have a flexible IT platform, and we've tested that by rolling out broadband on it. So when there is a move to increase scale or even some cross-industry convergence phase happen, we are in the best position to maximize value from that for our shareholders and also push the customer experience for our customers.

That sort of segue is quite neatly onto our other operating costs, which continue to go down the trajectory of producing plus 5% on a compound aggregate growth basis, down from $223 million to $212 million. The -- I'll split into the sort of four key drivers. Structure and performance is around the cost of (inaudible) when we disposed the Rockgas and AGS. Performance is around higher bonus costs because the financial performance of the business was strong. So it's nothing you can do about that category, but the underlying movement is down. We've had wage and salary inflation coming through there of $2 million, but there's some good high-quality cost savings coming through here. And when I say high-quality, these are cost savings, that when the business tells me to lose something, I can actually track the initiative and see the benefit in our P&L and in our cash flows. So I know that these actually flow through. So these are topics like moving IT team. We've been outsourcing more of our applications into the cloud, saving us money. We've introduced configuration management databases, which allow us to optimize our systems, applications and save on license fees. The wholesale operations team has become leaner, saving on some people costs. We've got procurement. So it's across multiple other categories. And we've got this lower cost to bad debt, which has come down by $3 million year-on-year. So good quality savings, good to see those coming through.

We have decided to accelerate some investment. So we've invested $3 million more in our brand, digital automation and product development. And we're already starting to see some digital savings in the year in terms of our OpEx associated with that. So that's pleasing to see. And we've invested $2 million, as I said previously in terms of well workovers which have increased our geothermal generation. You've seen the benefits of that in our gross margin.

Being very open in those, not everything has gone according to the plan, and we're seeing costs going up by $1 million in terms of broadband, which is an opportunity to learn and improve. Lots of positives around broadband. Customers like it. 12,000 customers already at the end of the financial year tested our brand and our IT stack and our electricity and gas product. But we had so we can leverage our fixed costs and we haven't been able to do that as much as we thought. So we have seen more staff come on. So we're working through how we optimize processes around that to get the cost back down again.

So on these investments that we made for going forward in OpEx. So $3 million, as I said, has gone into brand, automation, digital products development. And how we're actually seeing that is we launched 5 new products or billing variations, which to our understanding is more than we've ever done in the past. We -- in terms of the billing variations, we don't think there's a coincidence around the fact that we've got a record low age debt associated with that and also record low cost to bad debts. So we're making it easy for our customers to pay their bills. They're getting into this financial difficulty. It's a virtuous circle. We then incur less costs. So that's good to see that happening. The other indication that customers like it, we have seen customer numbers go up from electricity perspective by 2% on an annualized basis in the second half of the year.

In terms of the digital journeys around things like processes around moving house, paying bills. We can see the benefits of those coming through because you actually took out the increased cost into our call center, the broadband to get an underlying view. We are seeing a number of calls coming down, which is directly proportional to our cost of service. So it's good to see that. So we will continue to work on that. We need to continue to demonstrate the benefits to our customers around digital channels that we -- that you get the behavioral change and more and more of them switching to these cheaper channels for us, and then you will start to see real reductions in the cost of service associated with that.

And then in terms of geothermal refueling. So of that $2 million investment in Ohaaki that increased our injection (inaudible) which allows us to produce 33 gigawatt hours more out in the year. Great piece of business because based on a $100 per megawatt wholesale price, that's $3 million of profit for a $2 million investment. But the bigger picture here is, you can see the cost of well workovers has been coming down drastically. We do see ourselves as being a global expert in terms of geothermal and managing steam fields. So it's good that we are developing this IT and reducing our costs, but maintaining our steam fields. This will serve us very well with the Tauhara business case that it means the actual cost of maintaining the field is coming down and the profitability and return on that business will go up.

In terms of our cash flow performance, we had a strong year. Operating free cash flow is up by 40, driven by that strong EBITDAF. This is on a total business. Previously, I was talking about continuing business. I did want to just call out the fact that trade working capital has gone up, which is not bad from a cash flow perspective. You were probably expecting it to come down, but just we've net extracted gas from the ground and our inventory has dropped by 15 million a year. This is because our accounts receivable has gone up. We were previously securitizing some receivables, actually we noticed that. For financing purposes, I've stopped doing that, but it's just more effective and efficient ways of financing. And also, we had a very strong June '18 from a wholesale perspective. They are the large receivable with year-to-date, which has been paid and we had good cash flow performance in July '19.

So we understand that, and there's no issues around trade working capital.

Lots of proceeds from asset sales and disposals, which bring our free cash flow up to $731 million. In terms of how we've used that, if you look on the right-hand side, dividends paid in the year have gone up from $0.28 to $0.35 to a share and the value with our investment, which is good. You can see a major pay down of debt, which is great, because that's creating the headroom that we require it from where we do the Tauhara project. You can see the cash flow we're holding is going up. Some of that is linked to the higher ASX potential. Some of it is just linked to an arbitrage or benefit that you actually get holding your cash deposits. It's great these days than pay down some of your shorter-term debts. We've also done a little bit of M&A. We've invested $7.5 million from a cash perspective in terms of Simply Energy to drive our decarbonization strategy, and we're putting capital to drive against carbon.

So on to our dividends, that's around to our balance sheet. As I said at the start, it's a robust balance sheet. You can see the net debt profit by $477 million. Our average interest rate has popped up a little bit to 5.59%. This is just a function of when those proceeds came in, you have to pay down your flexible debt, which tend to be the bad debt, which is the cheapest. So that's just a mix thing.

In terms of maturities of bond, we've only got one coming up in FY '20. I guess, the key story here is our net debt-to-EBITDA is dropping. And with the announcement we made out recently with (inaudible) signing up to a long-term contract for storage on AGS. We've had agreements from S&P that they will no longer capitalize that onto our balance sheet anymore. So that snapshot to 2.1 for FY '20 is where we expect the S&P measure to convert into the future, which is growing (inaudible) that headroom we want to remain within the BBB S&P band that we want to stay below 2.8 which we're well within that.

On to our dividends. So no surprise here, $0.39. Just recapping on this. We've now got a balance sheet, which allows us to protect our investors from hydrology and variations in our staying business CapEx. So as I said in getting whether we're going to do a share buyback or a special dividend or anything like that, it is $0.30, $0.39. The only time the dividend, we got to change the dividend would be around -- if it's at a structural change within our business. For example, we do Tauhara, that in part increased EBITDAF and operating free cash flow coming in associated with that. Or I have to caveat it that our Board obviously reserves the right to change on our dividend policy. So it won't surprise you. Also as Dennis has said it already that our final dividend for FY '19 is going to be $0.23, is imputed to 65%, which is $0.15, so that brings the total paid and declared dividend for FY '19 up to $0.39. The details around the dividend in terms of record date and payment date on the slide. Great to see that positive upward trajectory in the dividend and also the amount of operating free cash flow we're paying out, that's up 82% for FY '19, we paid and declared. The reason why it's not a 100%, remember, it wasn't a main hydro yet. It was far better than the hydro year, so we haven't paid out 100%. Expectation next year, because we're only early into the year, it will be a mean hydro year, and therefore dividend of $0.39 will be 100% of our operating free cash flow.

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

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Dennis Barnes, Contact Energy Limited - CEO [3]

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Okay. So quick -- presenting a couple of slides at the half year as to the near-term priorities and medium-term priorities. And I define medium as, I think, after 6 months, which is increasingly a redundant statement from ourselves. But on the near-term priorities, we did contract gas wherever there is a contingent element to some of that gas and that's why the tick is a red tick, rather than a green tick. You'll have seen the concept, consulted report that came out in draft form last week on the future supply-demand for the gas market. They've got a few scenarios in there. But suffice to say the next couple of years are going to be driven by a little bit of uncertainty in the gas market, which, when it comes to the longer-term priorities, it's probably pretty concise. But what that means is that we have to manage that wholesale volatility in the short and medium term. We've done that through a reduction in fixed price sales. You've seen the price differential we've achieved on spot and CFD sales. The outlook numbers we give assume are pretty benign environment, where we don't get any upside from the volatility in the wholesale market. And as you've seen from previous presentations, we're pretty good at protecting our downside. So there's some work to do over the next -- meanwhile on how do you balance short-term availability of gas versus your risk management position. As I say, our outlook figures are all driven on a pretty benign basis that we sell what we sold, and we don't capture any upside from that.

In terms of customer, clearly, a big year. I think the continued delay and the reduced -- in the production of the electricity price review tells you something, but that's not stopped us getting on with the job. As Dorian mentioned, 5 new products, including a very smooth delivery of no PPD for new customers, a conversion of a lot of our existing customers already to the basic plan.

Now the broadband numbers are actually pretty impressive. We're now at 12,500 customers. Now is the time to put the right service and fulfillment model behind it. We've taken no risk on that so far. We've now got comfortable that broadband does deliver loyalty. It does deliver lower cost. And now what we have put behind it is a different fulfillment model, which you'll see it turn profitable pretty quickly. Yes, which is in itself 3 years after launching, something to be showing free cash flow on its own is pretty impressive.

Cost and efficiency program. Obviously, we hit the top end of our range this year rather than the bottom end, which has been our history. A little bit of bonus accounting for some of that, but the big year in terms of getting ready for geothermal, having the customer business deliver what is delivered. So it's not unsurprising.

Gas storage. Early next year, it will be fully expanded. The new views are obviously is useful from a S&P perspective, but the real value in my mind is having more deliverability out of that facility, and that will obviously be important if gas is going to continue to be unreliable and more expensive.

In terms of the longer term, on decarbonization, as I've mentioned, there's 2 parts in our mind: one is the substitution of -- wait for it, of existing supply, and that is very much simply a TCC versus geothermal conversation. And the numbers which C&I are drilling and tendering for Tauhara sets towards that. We're seeing gas price equivalents which are significantly south of $5 a gigajoule. So obviously, there's a connection here between the short term and the long term. If gas is going to be unreliable than more than $6 a gigajoule, then we'll take control, and we'll produce geothermal at significantly less than $5 a gigajoule and that will seal the fate of TCC. A few months to run on that, of course. The drilling has only just started, and we're expecting responses from equipment manufacturers in November. So we should be able to update you on that in early '20.

The second leg of decarbonization, which is that demand growth. I'm completely convinced that, that will clear first with commercial and industrial customers. And you saw the Transpower process heat report a few weeks ago. And Simply Energy are just well embedded with a lot of large customers. They have a great capability in turning out people who work at Simply, and I think that will accelerate opportunity for the contract book, importantly for Contact at the front of that opportunity. And then finally, just on this theme of decarbonization and scale. Clearly, we've proven something we've brought on, which we now have to deliver to fulfill the model behind for our customer base. But I think the work we've done so far tells us that as convergence or consolidation occurs, we're pretty well placed. And the margins are coming out of the competitive market, tell you that, that's probably where we have acceleration.

Want to -- what does all of that turn into our numbers? I mean, it's hardly a fancy valedictory speech. Well it was exactly 12 -- 4 years ago today, that Origin sold its shares in Contact. Now within 4 years, I think we've proven that we deliver on what we said we would deliver. The numbers there are for your models and your reading pleasure. But tell you that we've delivered on the cash flow we said we would deliver. We delivered in on the dividend we said we would deliver. And as a present for my successor, I will point you to, in the last 4 years, our operating free cash flow cents per share was actually in the low 40s. So a great foundation for the future. And I hope, as shareholders, you see the clarity and the commitment we provide to these numbers.

So with that, we'll move to questions. And there will be some technological process, which Matthew will run.

We'll go up to the room first. Matt needs some time. So unfortunately, Mr. Grant Swanepoel, you're not going to get the first questions. So in the room.

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Questions and Answers

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Unidentified Analyst, [1]

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A couple of questions, Dennis and Dorian. Just wanted to, I guess, in the past, I think you talked about, I guess, after the sale of Ahuroa and Rockgas sort of indicated underlying EBITDAF was around about $480 million, and I just sort of seeing, I guess the OpEx number is a little bit higher and -- but I see that just -- somewhat higher wholesale prices will get on to that significantly higher. So I mean, where do you still see things now for FY '20? You're still around about that $480 million or a little bit below?

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Dennis Barnes, Contact Energy Limited - CEO [2]

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No, I think $480 million is a good number. I mean, it's the $10 million of I won't say tramped in because it's more than $0.01 per share, but -- whether OpEx comes in at the bottom or the top of the range, whether we get a bit of upside from wholesale volatility, I don't think it's that material. We're pretty comfortable that 10 years, 20 years, $480 million and the free cash flow per share will be about $0.40. You can do the math yourself on that last page. It actually adds to a little over $0.05 a share. We're pretty happy with $480 million. The reason why we don't get a lift because of increased wholesale prices is that in the short to medium term, our fuel cost has (inaudible) cost increase. And that's why we focus on Tauhara because although we talk about the stretch from fossil fuels to renewables, it's also a very economic fuel cost, which -- yes, long answer, $480 million is okay for next year. Doesn't assume any upside from what wholesale volatility might do, and of course, no more caveats around hydrology there.

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Unidentified Analyst, [3]

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Yes. The second question was just around -- you haven't been in the C&I market over the last 6 months -- last year due to those gases issues. Now that you do have gas largely contracted in terms of -- are you kind of looking getting back into that market? Or you're going to -- you're happy staying in the CFD space for the next year or so?

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Dennis Barnes, Contact Energy Limited - CEO [4]

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The gas street, [Paul,] has a contingent nature to it. So we're not worried about that contingent nature. For our risk management, what was suggested was we should stay out. And so it becomes noncontingent. But putting that aside, it actually looks better to us to be in shorter-term trading blocks. So spot and CFD actually looks better to us. Particularly, with the lift in the shoulders. Few years ago, it very much used to be an exciting period based on hydrology going into winter, but now we're seeing shoulder periods, summer periods seem quite high and with a hydrological tendency to summer than they're actually reasonably profitable relative to a full year fixed price commitment.

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Unidentified Analyst, [5]

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And I guess, last question for me, for now at least. Chief Executive replacement process, how that's tracking?

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Dennis Barnes, Contact Energy Limited - CEO [6]

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The board only has 2 jobs, affirm the strategy and hire and fire the CEO. So you've got to let them do that. So they're in-charge of it. And as they announced in June, they're undertaking a global search, along with internal assessments, and expecting they'll conclude that in the next month or 2.

Nevill?

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Nevill Gluyas, Crédit Suisse AG, Research Division - Research Analyst [7]

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All right. Just push a little bit further on the sort of portfolio perspective. I guess, you secured -- so it isn't really enough, at least from my numbers for all of Stratford throughout retail gas and TCC. So I guess, folks, just first of all, on TCC. I mean, in the numbers, you talked about here and in your outlook for the next 3 to 4 years, possibly its remaining life. How hard do you expect it to generate? And how conditional is that on sort of gas contracts?

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Dennis Barnes, Contact Energy Limited - CEO [8]

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You've answered your own question in that -- yes, there's always -- you've got a look at the portfolio in quite deconstructed way. You might look at annual numbers or daily numbers, but actually the need for gas is an hourly need. It's the morning peak and the evening peak. You need to run a mile at [fortnight] and that storage clearly allows us to do a better shape in that regard. Well our TCC has been running 300 megawatts peak and 170 megawatts off peak since May. And we expect that to be the pattern. Some of that has been under a tolling agreement. We would expect some of that to continue as well just on efficiency. Gas is less reliable and more expensive than plant efficiency actually is reasonably important, yes, it's chicken and egg. There isn't lot -- there's not just the gas we've contracted. There are lot of conversations happening on what gas is out there.

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Nevill Gluyas, Crédit Suisse AG, Research Division - Research Analyst [9]

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So in terms of the reliability of those plants, and obviously TCC currently is 65 megawatts derated sort of restricted when out and all this -- you mentioned earlier, so some of their reliability, that's -- what's your view on -- particularly on the peakers, on their lifetime and reliability, but also what's your thinking around TCC reliability?

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Dennis Barnes, Contact Energy Limited - CEO [10]

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TCC has actually been pretty good since we got it going again in May, June at 300 megawatts. It wobbles a bit above 300 megawatts. We don't yet know whether that's a permanent feature of the plant. But because we've not taken it out since we brought it back in, in June -- May, June, we don't have an answer for it. I fully expect it will go back up to 380. We just need a couple of weeks of an outage to figure out why it's 5 rating.

On the peakers, the outage is somewhat related to gas availability. You do more tidier work to ensure longer-term reliability. I'm not particularly worried about that longer-term reliability.

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [11]

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Probably better than what it was when (inaudible).

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Nevill Gluyas, Crédit Suisse AG, Research Division - Research Analyst [12]

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And so lastly on sort of gas costs. Previously, you've given numbers of -- particularly major plenty of numbers like $6.50 per gigajoule gas at least in the next 2, 3 years, also seeing much higher numbers in stock market up to today. Is that sort of range still sensible?

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Dennis Barnes, Contact Energy Limited - CEO [13]

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Well, I mean, it's -- again, it's chicken and egg, paying $6.50 during (inaudible). So it's just not economic of that for us to buy the gas. And we ask -- the conversations would have been in that range. I think availability is the question. And you've seen this before on the Maui determination. As soon as there is no gas available -- as gas available because the economics change. And that's some of the conversations we're having. We're the marginal buyer if the margin will plum. So have a little bit of control in that conversation. And the more we see of Tauhara, it's less than $5 a gigajoule.

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Nevill Gluyas, Crédit Suisse AG, Research Division - Research Analyst [14]

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I've got a few more, but I'll -- I'm sure others are going to ask this question, so.

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Dennis Barnes, Contact Energy Limited - CEO [15]

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So we're going to go online. And the first questions come from Mr. Grant Swanepoel.

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Grant Swanepoel, Craigs Investment Partners Limited, Research Division - Director & Head of Research [16]

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Three broad questions. The first one, just on the EBITDA. You have on Slide 34, a $480 million number that you're talking to. Can you just talk to the $7 million extra costs that's depicted there. Is that due to market making? Or what is this?

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [17]

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That's right, Grant. It's just -- we're expecting to make less money on market making next year. So still we're expecting to make money, but sort of $3 million expenditure.

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

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Okay. And then if I just follow your guidance down from $480 million and then add the low and high on the different dividends making numbers from cash tax all the way through to EBIT, I mean, stay in business CapEx. For some reason, I'm getting a dividend expectation of 100% about a $0.42 to $0.40. So $0.39 doesn't quite stack up. Is this something above stay in business CapEx that you're putting in there that we're not aware of?

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [19]

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No. I mean, it's -- the dividend policy, Grant, has a degree of formulaic nature and a degree of subjectivity, and you never want to go backwards. I know, look at the last 4 years, it's been above $0.40. So it's being able to deliver comfortably and not surprise. But you're right, your math simply is one of the [faster sense].

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

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Okay. And then just on to where the prompt payment discount. If I can have the similar sort of effect that we've seen in your competitors. You've around about $3 million to $5 million of impact?

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Dennis Barnes, Contact Energy Limited - CEO [21]

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This is why I was a little bit animated about it earlier last year, when it started to be removed. Because done in a good way, it's actually good for customers because it's simpler. It improves the operations of Contact because we're not having to deal with complex structures. And we've actually seen it being net positive. So -- in a perverse way, the door to door salespeople are finding it too hard to sell the basic plan because it's easier, and some of that conversation relies on describing complexes. Digital take-up of basic plan has been really hard because customers see how easy it is to do price comparisons. Along with the payment methods, the products per customer, we're now at 1.33 products per customer. I put all of that together and say, it's actually net neutral, maybe even a bit positive. But it's at the net level, not the gross margin level where that shows itself.

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

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And my final question, just on broadband, it seems to be going phenomenally well. I think you're adding 1,500 customers a month, you had 12,000 already. Are you expecting this sort of trend to continue in the near term? And then have you moved off workers directly with Chorus now and that's where some of the margin improvement will lead to a profitable FY '20 from that product?

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Dennis Barnes, Contact Energy Limited - CEO [23]

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Yes, Nevill (sic) [Grant], the service costs that we've been experiencing with broadband is the lack of visibility of the customer journey. So if you go to a wholesaler who works out everything for you, you don't get to see what's going for the customer, and that's resulted in a lot of calls and a bit of cost, and I would expect some over the next few months, subject to some commercial negotiations, so that's a change, which will deliver a better customer experience, but also lower cost of fulfillment. That's probably a long far too away.

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

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And the current run rate has continued in terms of capture?

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Dennis Barnes, Contact Energy Limited - CEO [25]

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Yes, we're about 1,000 a month.

Who is next, Matthew?

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Matthew Forbes, Contact Energy Limited - IR Manager [26]

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Yes. Aaron is on the line.

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Aaron Ibbotson, UBS Investment Bank, Research Division - Director & Research Analyst [27]

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I had 2 questions, if I may, very straightforward and simple ones. So first of all, just on your little bridge that Grant just mentioned, you have $10 million there on recovery of wholesale prices. And I'm just curious to probe a little bit, it seems hopefully conservative, I must say, particularly in light of your earlier comment that you would focus on the CFD markets, which seems very prudent, in my view, in light of the different pricing. So as far as I can see, I struggle to see how you could sell anywhere in the wholesale CFDs, C&I market for only $3 more per megawatt, which is what I get to for your C&I book. So I just wanted to try to understand that.

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

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Yes, this mainly was actually related to the retail market. The -- what we're assuming is we've had some higher short-term CFD pricing and some higher pricing on [lead] in FY '19, which isn't going to repeat to the same degree because wholesale pricing lost that is expected to remain high in FY '20. They are. It is expected to reduce relative to the prices we saw in FY '19. So what we're seeing is we increase our tariffs to the retail customers. So that comes through, which is good. What you're seeing there in terms of the $10 million, we'll start to get some value around C&I because we will start to recontract some of that stuff and reprice it. So you'll see the price drop in C&I. So what you will see is -- what we are expecting is whilst short-term CFD is going to be much -- to be good value, we're not going to get the same level of pricing in FY '20 as we were able to achieve in FY '19.

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Aaron Ibbotson, UBS Investment Bank, Research Division - Director & Research Analyst [29]

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But, sorry, if I could just probe and refer back to Slide 18, then a little bit. Because I'm not sure you seem to be getting [74, 73] or something like that for CFD on average, and I know there's some long-term contracts in there. And then around [82] for C&I, so if your $10 million is referring to customer, do you not then expect anything above that level for FY '20

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

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We're expecting the things to offset basically.

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Aaron Ibbotson, UBS Investment Bank, Research Division - Director & Research Analyst [31]

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Okay. I guess, I'll have to accept that...

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Dennis Barnes, Contact Energy Limited - CEO [32]

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Aaron, there's also -- you focused on the price, but it's a price x quantity question as well. And we often talk about our risk management practices. But in very simple terms, we avoid being short in July and August, when it's freezing and there's no hydro. So that does limit the quantity you can sell. And that's a fuel question and that's the constraint at the moment. If that wasn't constrained, then there would be no problem. But then, if it wasn't constrained, you won't have those prices.

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

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Yes. Because Aaron, the other end of it is that $142 per megawatt that we were getting on the left -- the grid as well. That's obviously not going to -- we're not expecting that to continue at the same level into FY '20.

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Aaron Ibbotson, UBS Investment Bank, Research Division - Director & Research Analyst [34]

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Okay. So there was a sort of gross number here. That's how I read the chart. But we can take that off-line. My second question was just on your comments on Tauhara and your $5 versus $6.50, et cetera, imply the gigajoule cost. And I guess, Dennis, this is sort of a bigger picture question. If I look at the stability of the New Zealand electricity market overall, the gas and even the fact that you do have sort of incremental and somewhat unreliable gas suppliers at times, is it crucial to -- in my book to provide some sort of stability around prices? So I'm just curious how you think about Tauhara, and if you replace basically your entire gas book with Tauhara, how you see the stability of pricing in the whole New Zealand wholesale market?

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Dennis Barnes, Contact Energy Limited - CEO [35]

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Well, I think the nature changes, and that's what we've obviously seen with the reduction in flexible thermal plant with the replacement of most run renewables. So Tauhara, in average terms, is a very simple decision. Depending on what peak rate you assume and whether you assume what your hurdle returns, the fuel replacement cost is $4 to $5 a gigajoule. But, of course, you take out the 300-plus megawatt plant and replace it with let's say a 120 or 140 megawatt plant, then you do drive a little bit more volatility into the types of periods. And I think that's a feature going forward. And one of the things that will puzzle us prior to the investment decision on Tauhara is how we make sure that, that all happens in a smooth way. So what's the capacity support for more renewables and how do we think about that is probably the outstanding question. It's good to see (inaudible) sign into gas storage because that gives you some comfort that junction route is real. And I think that will just be more of that. Add-on will -- and TCC are the rankings will be the next on target here in the list of plants that close and get replaced by renewables. But clearly as an integrated player, we've maintained some stability in prices for consumers, and some of that's been driven by the competitive market, of course. So I get your question, but I think we're going to have a few years of volatility actually, as this transition continues to occur.

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Matthew Forbes, Contact Energy Limited - IR Manager [36]

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Are there any other questions on the line? If you have a question, please, can you raise your hand using the function at the bottom of the screen?

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Dennis Barnes, Contact Energy Limited - CEO [37]

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Okay. No more questions. With that, we'll let you get on with the day. Nevill's got another one.

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Nevill Gluyas, Crédit Suisse AG, Research Division - Research Analyst [38]

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And it's really just sort of speak to the guidance front, operating costs. So you had a more aggressive sort of cost out guidance, (inaudible) I'm wondering should we still think the trajectory is the same as you'd talked about in the past, with respect to the FY '20 guidance.

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Dennis Barnes, Contact Energy Limited - CEO [39]

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Yes, I think the business is now seen as a normal activity to take out a few percent a year. As Dorian referred to good quality cost reductions. There is always going to be a bit of a path to it. I think like lots of our competitors at least there's a downward trajectory. There's also few more things to do this year, and we expected when we gave our guidance, it's probably as far back as 18 weeks ago, but trajectory is the same.

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Nevill Gluyas, Crédit Suisse AG, Research Division - Research Analyst [40]

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So what I thought 1 month prior (inaudible)

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Dennis Barnes, Contact Energy Limited - CEO [41]

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And the reality is, you're always playing a -- not playing, what is it? There's always so many people to do things. So you can't look at OpEx without looking at CapEx. And if we were to pull the trigger on so hard, you probably expect SIB CapEx to come down. Because there's always so many engineers to do so many things. So there is an interrelationship between the 2. One of the things that we're still puzzling through as well and it's getting clearer, in digital retailing, it was CapEx and was OpEx is becoming increasingly academic because your capital spend is on technology that's almost disposable. So we do go for the totex number and the trajectory is, as we've previously described but -- that might be 6 or 12 months later.

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Nevill Gluyas, Crédit Suisse AG, Research Division - Research Analyst [42]

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So in the same vein, the stay in business CapEx guidance beyond FY '20, we're used to talking about description of about 60, 65, we've still in mind?

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Dennis Barnes, Contact Energy Limited - CEO [43]

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Yes, yes, yes. And the only thing that excludes is any Wairakei, any consenting costs.

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

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Yes. And that will vary depending what we're doing (inaudible)

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Nevill Gluyas, Crédit Suisse AG, Research Division - Research Analyst [45]

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Only 1 more, I promise. TCC, if you removed it, no longer needed some 2 or 3 years, what is the OpEx cost reduction?

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [46]

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$8 million roughly.

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Dennis Barnes, Contact Energy Limited - CEO [47]

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Okay, that 60 to 65 is now 55 to 60. And the TCC, most of the impact would be noncash on its closure. But as you saw with our target, you do get cash tax benefits, if you close it. So yes, the some of things to think about with TCC is the noncash write-down, but that would probably be through the accelerated depreciation methodology. OpEx down by $8 million a year. But in the year you abandon it, you do get cash tax benefit. So if you look at 5- or 7-year cash bonus, cash tax is actually reasonably material in the decision.

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Nevill Gluyas, Crédit Suisse AG, Research Division - Research Analyst [48]

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From a cash -- sorry, from a cash perspective, what's on books at the moment about one quarter written down tax value.

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Dennis Barnes, Contact Energy Limited - CEO [49]

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Unlike Otahuhu, we don't likely to be able to sell the line for $40 million.

All right. No more questions have emerged online. So thank you all for your attention. We'll see you -- most of you or all of you through the next few days.

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Dorian Kevin Thomas Devers, Contact Energy Limited - CFO [50]

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Thank you.

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Dennis Barnes, Contact Energy Limited - CEO [51]

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Thank you.