Norsk Hydro ASA (NHY) Earnings Call Transcript & Summary

Hello, and welcome to the Hydro Q3 Conference Call. My name is Jess, and I'll be your coordinator for today's event. [Operator Instructions] I will now hand over to your host, Line Haugetraa, Head of Investor Relations, to begin today's call. Thank you.

Thank you very much, operator, and welcome to the Q3 digital conference call Q&A. I'm here joined by our CEO, Hilde Merete Aasheim; and our CFO, Pal Kildemo, and we'll be taking questions throughout this conference call. So operator, we are ready to start the questions. Thank you.

[Operator Instructions] And the first question comes from the line of Liam Fitzpatrick from DB.

Got a couple of questions on REIN and then on Extrusions. So on REIN, can you elaborate on the alternative capital raise that you're now looking at in terms of what sort of stake? And can you also confirm, will this then set up REIN as a, I guess, a ring-fenced business from a financing point of view. And then linked to that, you have highlighted some REIN CapEx, which is coming through, how is that going to be reported divisionally both now and once REIN is set up? That's the first set of questions on Rein. And then on Extrusions. Obviously, it's a very uncertain backdrop into Q4, but can you give us any color on how you expect kind of EBITDA to trend in relation perhaps to Q4 last year and some of the previous week periods we've seen over the last couple of years?

Hello, Liam, and thank you for your questions. If we start with REIN, when we look at alternatives to the IPO market. We are still doing it from a same strategic starting point and also a similar model from a ring-fencing perspective. So the difference is how you raise that capital. And of course, the amount of partners you potentially have on the other side is that is the path we end up going down. REIN will be part of the Energy business area, as mentioned earlier, it's both REIN, Havrand and Batteries are business units within a business area and will be followed up accordingly. So no big changes apart from acknowledging that the IPO market there is looking quite challenging, and we need to evaluate other alternatives, as we had in Q2 also. On the Extrusions side, I wish I could provide you a figure with the 2 lines under. But I think as we see from consensus, but also internally that there is an expectation of a development into the fourth quarter, which reflects the uncertainty that we are experiencing. And our best guidance is really the volume from CRU. As you see, CRU volumes in Extrusions Europe being down 15% or so percent from the fourth quarter last year. We are largely having a similar picture, some pluses and minuses. And the same in North America, which is more balanced. So that would be our starting point. But then, of course, acknowledging that things can change. But I -- if things change, I expect larger effects into Q1 than in Q4. And we are not running very high costs currently in Extrusions. So we have been able to keep fixed costs and so at a more conservative level than we had going into the last crisis. So with that as a starting point, I don't think you should expect us to have the same fixed cost release. On the variable cost, it's, of course, a higher energy level than what we experienced externally. But here, we are working very hard to pass this on to customer, especially into 2023, where we have more open volumes. The last element you should take into account when looking at the third quarter, fourth quarter is, of course, the remelt. We are expecting to take down the remelt production around 20,000 tonnes in the fourth quarter, and that will also impact profitability...

Next question comes from the line of Amos Fletcher from Barclays.

Just a couple of questions. I wanted to ask a question about the CO2 compensation increase that you booked into EBITDA. You were mentioning the NOK 0.5 billion relates to the current quarter, that annualizes at NOK 2 billion, but then you were saying the total for '22 would be NOK 1.7 billion. So just wondering if you can explain why the difference is there. And should we also expect another NOK 0.5 billion in Q4. And is it reasonable to assume a sort of the 2023 number, you mentioned at NOK 2.2 billion, just divide that by 4 for the quarterly run rate through next year as well.

I'll try and get this straight, Amos, because there's a lot of moving parts here. And the reason why there may be some confusions between 2022 and 2023 is potentially when you build it up and account for it and when you actually receive it. So when we talk about NOK 1.7 billion, that is the accumulated effect for 2021. But that NOK 1.7 billion will be paid in 2022. So from an EBITDA perspective, it hit 2021. From a cash flow perspective, it hit 2022. And that is also one of the reasons why we have a higher receivable on the operating capital side. Then for 2022, we used the average CO2 prices for 2021, which were higher than what they were in 2020, which was the basis for 2021. And that, all else equal, increases the figure. But then on the flip side, there's been twist in that floor on CO2 compensation of around [ NOK 200 million ]. So that cuts it a bit down. But when you have all of these pieces together with the CO2 conversation on power, that becomes NOK 2.2 billion for 2022, payable in 2023. Then for 2023, you will be using the average power -- CO2 price in 2022, which is higher than what it was in 2021. And if you use the same methodology, I think the full year effect for 2022, payable in 2023, is NOK 3.7 billion, NOK 3.8 billion.

Got it. Okay. Okay. And then I just wanted to clarify on the NOK 1.6 billion of EBITDA from Slovalco power sales. Can you just clarify that was a quarter-on-quarter increase that you expect in Q4, is that right?

It's a quarter-on-quarter increase, but it's not just Slovalco, it's also the power sales from the curtailed operations at Husnes and Karmøy. And so the total power sales from Slovalco is higher than what we have indicated earlier, which also brings the total figure higher.

Yes. Okay. Got that. And then you were saying at the sort of in-person presentation, is there a mix between where that gets booked? Does some of it get booked in Primary Metal, some in Energy? Or is it all in Primary Metal?

No -- of the figures we're talking now, it's all Aluminum Metal. So what Aluminum Metal has found this period is that they've sold the power to Energy, and then Energy takes it into the total portfolio and optimizes along with their own position. So the figures are locked for Aluminum Metal. But for Energy, there's still an uncertainty as to what price you end up selling them in the market. But they are currently placing these volumes in the market. But these are NO2 volumes, so the power market, there is not extremely liquid, so it's not something you do overnight. We also need to take into account the collateral and bilateral [indiscernible].

Got it. Okay. And then last question I just wanted to ask around the potential of physical rationing of gas Hilde was mentioning in the presentation, potential to move volumes from one part of the business towards Europe, if you need. What sort of spare capacity percentage do you have outside of Europe? And as a result, what kind of reduction in gas availability could the business accommodate, if required?

Well, for extruders, you typically don't run 100% capacity. It varies a bit among -- so maybe run down 50%, 60%, somewhere closer to 80%, 90%. And that is either product-based or it might be to be able to capture short-term demand et cetera. So within these guidance on gas consumption necessary to be reduced that we're operating with now, these are within some of the flexibility we have at plants if you get hit in one country and not another anyway.

Okay. So I suppose the question is if you were, let's say, hit with, to pick a number, 20% reduction in gas availability, is there the capability to make that volume up from elsewhere within the business? And what sort of hit to gas availability could you accommodate?

Yes. Well, if you get it across Europe as a total, you couldn't. But if you got it in 1 country, you could potentially move it to another country. But it depends a bit on what country gets hit and what countries don't, because there's different utilization in the different countries. I think our comment is mostly that, as we see it now, we are not reducing production due to gas to match the falling demand. And I think that is the most likely outcome in scenarios. That demand is actually what triggers. But if you have 1 country that gets hit and then we have other countries that we could move volumes to, and there is quite a lot of flexibility given that we've already reduced production. The question becomes more like, how far does it makes sense to move it given transport cost and margins and elements. But I think the main point from the presentation earlier today was that this separates us a bit from peers that we have a larger flexibility than those purely operating in a single country.

The next question comes from the line of Daniel Major from UBS.

Just a few clarifications just to start. Just on the power sales, and sorry for repeating this slightly, is that NOK 1.6 billion expected in Q4 more than the NOK 0.6 billion that you achieved in Q3? Or is it NOK 1.6 billion in absolute terms?

More.

Right. Okay. So it's a total of, what, that NOK 2.2 billion, okay. That makes sense. And then just a second, just a clarification on the numbers, you gave around guidance on costs for primary aluminum in Q4. It was NOK 400 million to NOK 500 million, part offset by NOK 100 million to NOK 200 million, so net-net, should be a reduction of NOK 300 million to NOK 400 million,. Is that correct?

Yes, the raw material development into Q4 from Q3 is NOK 300 million to NOK 400 million.

So in total, it's NOK 300 million to NOK 400 million because I think you said raw materials were down NOK 400 million to NOK 500 million, but seasonally you have higher fixed costs of NOK 100 million to NOK 200 million, so NOK 300 million to NOK 400 million...

Exactly, yes. [indiscernible]. That's correct. Sorry, yes.

Perfect. And then next part of the question, just to follow up on Liam's question on REIN. Obviously, you hope to raise capital in the fourth quarter, but it's a difficult market in many respects. Can you tell me, one, how much have you actually consolidated in terms of CapEx into REIN so far? How much would you expect in Q4? And what would the rate of expenditure be if you were unable to sell a stake in 2023, either on a quarterly basis or an annual basis?

Yes. I think the guidance that we gave last quarter on the REIN on the CapEx side, that still remains. And in -- I would say, in all scenarios, that remains. These are projects which are ongoing and you don't stop them. These are projects which are delivering very attractive power in today's market to our operations also, so there will be more than just the impact of stopping from the REIN side. Then going into next year, we will get back to at Capital Markets Day in a scenario where this looks challenging what the CapEx outlook for REIN will be. So we're not in a situation to give a guidance for next year, we will update that at Capital Markets Day.

Okay. And so just to follow up on that one. Because I think the guidance was NOK 1.5 billion to NOK 2 billion, how has that been -- how much did you book in this last quarter in terms of spend on REIN, and therefore, what's the implied spend in Q4? We can take it offline if you don't have it in front of you.

No, okay. It's probably of interest. I think we spent around NOK 900 million on growth in the REIN year-to-date Q3. .

And just final one and I'll open up the line again. Just on the Energy business, what was the split between the area pricing? Well, what was the EBITDA on the area of pricing spread this quarter, so we can have a sense of how it might progress into next quarter as pricing progresses?

Around NOK 2.5 billion.

NOK 2.5 billion positive from the area of pricing.

Next question comes from the line of Ioannis Masvoulas from Morgan Stanley.

A few left from my side. First of all, on realized premium, the guidance for Q4 is $550 to $600 per tonne. What would that figure be in 2023 if spot premiums persist?

Well, it depends on the composition of the portfolio. But we did a back of the envelope on using current market premiums, and then we end up around the $450 level for realized premium. That is not something you would see in Q1, most likely. But from Q2, Q3, et cetera, when you have less price contracts, that's when you start seeing these levels.

Great. Great. Second question around the aluminum cuts in Norway. Assuming demand stays weak or weakens further from here, how much more could you cut in practice? Are there any limitations around contract structures or any other considerations that put an absolute limit on how much you're going to cut?

I think, as I said -- this is Hilde. As I said in my presentation, we will continuously evaluate further mitigating measures in terms of a weakness in demand. And there are no, let's say, structural or contracts that avoid us or stop us from further cuts. It's more to understand the -- how the market is developing, how long the market will stay down before we talk about further electrolysis cuts, but we will evaluate that as the market is developing.

Understood. And 1 more question on the Norwegian state budget. Around the windfall profit tax, which, from what you're saying, it doesn't have much of an impact to your business. But are you exposed to that additional tax when it comes to the spot power sales or when it comes to the volumes exposed to the price area difference? Or are you not exposed?

Our understanding of the current framework is that the only exposure we have to the change in tax rate is the absolute 8% increase in resource rent tax, and that will impact all the volumes that we produce as it does today, but then based on the internal contract price between Aluminum Metal and Energy. So where -- we have very limited volumes that are exposed to any high price contribution.