Good morning, everyone. We hope you're well, and thank you for joining our results call for the first nine months of the year. Next to me is our Head of Financial Markets, Steven Fernández, and our Head of Financial Planning and Control, Jon Ganuza. We're going to run over the presentation first, and at the end, open the floor to live Q&A.
Note that given the no obligation to report on a quarterly basis and in light of the recent market volatility and regulatory uncertainty experienced in recent months, the board of directors has decided to follow a lighter approach on the intermediate quarterly results while maintaining full granularity and disclosure for the half and full year results. We are confident this will result in a more agile and equally transparent disclosure, while we continue to address any specific questions you may have.
With that said, I'm handing it over to Steven Fernández to go over the presentation.
Thank you, Abel, and good morning, everyone. As usual, we're gonna start off with slide four, an update on the energy scenario, where we're seeing a continued recovery in the regions where we operate. As you can see, electricity and gas demand in Spain, on average, 3% above the first nine months of 2020. Similarly, electricity and gas demand across LatAm, where we operate, experienced also an increase in average of around 6% and 27% respectively during the first nine months of the year.
If we move on to the evolution of energy markets in slide five, you'll find a comparison between the average of the key commodity prices during the first nine months of the year compared to the same period of 2020.
The third quarter of 2021 has been marked by the significant rise of commodity prices, impacting obviously the comparison for the period. As you can see, Brent prices have increased by 66% on average when compared to 9, 2020, while gas prices on the major gas hubs, for example, Henry Hub and TTF, have also increased on average by 62% and about 300% respectively during the first nine months of the year. The Spanish pool, for its part, has multiplied by around 2.5 times on average versus the first nine months of 2020, a fact that you guys are all aware of.
All in all, the significant increase in commodity prices, particularly in the third quarter, has been something to keep in mind as we approach the winter season. In terms of FX, if we move on to page 6, you can see also that the pace of depreciation of the LatAm currency has moderated, as you can see in this slide. When we compare FX rates versus a year ago, the depreciation of LatAm currencies against the euro translated into a negative impact of around EUR 63 million and EUR 20 million on the consolidated group ordinary EBITDA and net income, respectively.
In summary, FX depreciation is showing signs of a moderation in the recent months, although in Brazil and Argentina, we're still experiencing significant depreciation in the period.
If we translate these environments into the results, if we turn to page 8, I would like to start by highlighting that the results that we have presented today are not indicative of the expected evolution of the business for the remainder of the year. As a result, should not be extrapolated as a result of the regulatory changes in Spain and the volatility in international gas markets. Ordinary EBITDA reached almost EUR 3 billion in the period, up versus the previous year, but still below pre-pandemic levels.
It's important to highlight, of course, that when we compare it against 2020, you need to be mindful of the fact that we disposed of and deconsolidated CGE in Chile. So the comparison has to be done on a similar portfolio and a similar perimeter.
At the EBITDA level, non-ordinary impacts amounted to around EUR 430 million, corresponding mostly to restructuring costs incurred during the period. You may remember, we announced an employee voluntary departure plan that was completed by the company in Spain. You have details of the specific one-offs in the appendix of the presentation. In terms of the main business units, I'm gonna skip through this part simply because Jon Ganuza is gonna give you a little bit more color on this.
Just to focus on net debt and leverage, which are significantly down in the period, obviously following the disposal of CGE and the cash-in proceeds from that transaction, in addition to the resolution of our joint venture in Fenosa Gas.
Also, just a reminder that during the quarter and following the strategic plan presented last July, the rating agencies have consolidated our corporate credit rating at triple B with a stable outlook. With that, I think I hand over to Jon Ganuza.
Okay. Thanks, Steven, and good morning, everyone. Moving on to page 10, you will find a comparison of our results for the period from 2019 to 2021. As Steven anticipated, results remain below pre-pandemic levels, in particular in energy management and networks. Networks Spain delivered growth supported by higher volumes in gas and efficiencies across the board, which compensated the tariff reductions. Networks Latam was slightly down as demand recovery was not enough to compensate for FX devaluation.
Energy management benefited from a margin increase amid the volatile scenario if compared with the COVID-impacted 2020, but still did not reach the pre-COVID levels of 2019.
In renewables, as Australia and LATAM continue to grow back by new capacity coming into operation, while in Spain, most of our renewable energy is sold on a long-term fixed price to end customers. These sales have been negatively impacted by two effects. First, the CNMV issued a requirement to standardize the accounting treatment of the regulatory revenues in Spain. This is a non-cash effect that reduces the accounted revenues by the excess between the actual pool prices and the estimated pool price that was used in calculating the regulated revenue for the period.
Second, the lag effect. Our renewable sales price is approximately a trailing one-year average of the twelve-month forward output for the pool prices. This price has been lower in 2021 than in 2020.
This revenue reduction has been further enhanced as the taxes are linked to the pool prices that these past few months has been substantially higher. In supply, results were impacted by some of the contracts to our final customers in gas and electricity that do not always reflect the substantial increases in gas and electricity procurement costs that we've seen in the main hubs. In summary, the third quarter involves some transitory impacts in energy management amid the volatile scenario, which should not be extrapolated for the remainder of the year.
Thank you, Jon. If we move over to the net income on slide 11, as you can see, there's a trickle down from all the effects that Jon has mentioned. As a result of that, ordinary net income reaches EUR 865 million in the period.
On a reported basis, it amounts to EUR 777 million, and obviously impacted by the significant restructuring costs that we mentioned previously, together with the gains from the disposal of CGE Chile and the agreement to resolve the joint venture in UFG. It's also worth highlighting that the company continues to actively optimize its financial structure, which is resulting in an improved financial results and overall lower cost of debt. This is something that we can actually see on page 12
. As of the 30th of September, net debt amounted to EUR 11.4 billion, while the net debt to last twelve months EBITDA stood around 3.3x, compared to around 3.9x as of the end of the year 2020.
The net debt reduction and the deleveraging is mainly explained by the completion of the disposal of Naturgy's Chilean electricity network's subsidiary, CGE, in addition to the cash payments resulting from the agreement to exit UFG. If we shift over to CapEx, it amounts to around EUR 890 million in the period. That's up 8% versus the same period of last year.
The increase is mainly explained by greater investments in renewable developments in Australia, Spain, and U.S., as well as higher investments in supply and commercial efforts and digitalization. Having said the above, it's also worth highlighting that we are encountering some delays in some of our renewable plans. For the balance of the year, it's unlikely that we're going to be able to reach the EUR 1 billion CapEx target that we had envisioned for renewables.
In summary, the scenario is improving compared to last year, and the operating performance has improved as the COVID-19 effects subside. However, as you have seen, with these results, our numbers are still below pre-pandemic levels on a constant perimeter basis, which we believe provides us upside as the economy continues to recover. Ordinary EBITDA for the first nine months amounted to almost EUR 3 billion, mainly supported by the gradual recovery of energy demand and the transitory impacts from open positions in energy markets that John described.
The performance in energy markets and management in particular is not indicative of the expected evolution of the business for the remainder of the year, and that's something that you guys have to keep in mind.
That also explains the guidance in the range of EUR 3.8 billion-EUR 3.9 billion at the ordinary EBITDA level for the balance of the year. Finally, the board of directors has agreed for the payment of its second interim dividend against 2021 results, corresponding to EUR 0.40 per share, which will be payable in cash on the 15th of November. It is in line with the commitment of paying EUR 1.2 per share against 2021 results. With that, we conclude our presentation, and we are obviously happy to take any questions that you guys may have.
Our first question comes from Javier Suárez at Mediobanca. Javier, your line is open.
Hi, good morning, and thank you for the presentation. Three questions on the big picture, I guess, on the current scenario, very high electricity prices. What is Naturgy's contribution to the debate? What Naturgy believes that it should be done to reduce electricity prices? Any comment that you may have on the apparent proposal by the government, next proposal of the government to link the regulated tariff and industrial customer and industrial tariff to the cost of renewable energies.
If you have any comment on that proposal, and if that could be helpful to reduce structurally electricity prices for the Spanish economy. That is the first question.
The second question is an update on any ongoing negotiation with Algeria to increase security of supply to Spain. Any update on that would be extremely helpful. The third is on the numbers. I think that during the presentation, management has made reference several times to that the numbers that has been already released cannot be extrapolated as a consequence of volatility in international gas market. That is one of the reasons. You can be a little bit more specific on what is included in your number that may be considered as a one-off and extraordinary and should not be seen during the fourth quarter. Many thanks.
I mean, thank you, Javier. With regard to the electricity scenario, I think that there was many questions in one. First of all, I think that no one really right now has an outlook of how the electricity prices are going to evolve. No one foresaw six months ago that we would be at the current level, so no one really knows when the prices are going to continue or not. I think in this sense our Executive Chairman today has announced that we have a commitment to the society, and that's why we think it's really important and really believing in the ESG and the S part, the society part.
That's why we've decided that we're going to be more active in the way that our inframarginal energy is being sold to our customers. We're going to in fact impose a cap of 65 EUR/MWh in the inframarginal energy that we're going to sell to our customers. Regarding to the government proposals that they want to increase long-term sales, I think that that's the strategy that has been implicitly defined for the last few years by all of the utilities in Spain, that in the liberalized market we've always been favoring long-term fixed price contracts.
Actually, it was the CNMC within the past said that they did not want to have this kind of contracts, that they rather have that the PP, PVPC was linked to index contract to the pool price.
I think that trying to move as much more volume as possible to long-term price fixed contracts is a movement that is welcome because we think that is something that reduces the volatility in the end customers. It's something that has been done in the past by the utilities. The way it's implemented or it's done, I think that's something completely different and it I think that the best thing is to wait and see what the final measures by the government are, and then maybe it would be better to give our opinion. Moving to the second question, with Algeria security of supply, I mean, we...
Already in 2018, we were really candid to the market, saying that in our base case scenario, the EMPL was not going to continue, that we said that in July in 2018 in London. All of our balances and as far as supply and demand is concerned in Spain for our end customers do not rely on the Algerian volumes. Actually, what we're doing is we are working with Algeria to put the compressor station in Medgaz into operation as soon as possible. We are also in talks with Algeria and Morocco in order to see whether we can extend the concession with the EMPL.
Again, we do not need those volumes currently for this winter because we knew in advance that those volumes were not going to be there. A completely different question is if you think on a Spain basis, on a European basis, but as far as our customers is concerned, I think that we do have the volumes, we have the firm volumes, and that's independent of whether we are able to reach any agreement with Algeria, that would be at most an upside.
Regarding why the results cannot be further extrapolated, I think that when Steven was describing the current energy scenario, there's one thing. If you look on a yearly basis, on nine months maybe, the results do not, the commodity price evolution does not fully reflect what's currently happened if you will look on a monthly basis. If you look November or October, some of the commodity prices are five to six times higher the levels that they were last year.
That means that things that a year ago or usually would have been a non-event, now they might have a material impact in our results. That's why we don't think. I would say that it's more out of caution than saying that there's something that we definitely know that's going to happen.
Because if we knew that something that this was going to happen, we would have given a more precise guidance. We've given a range of guidance precisely because we see that with the current price levels, everything can substantially move lower or higher the results. To give an example, in the previous years, if one LNG cargo would have come one week later, so for example, instead of arriving in December, it would arrive in January, that would have been basically a non-event.
With the current prices scenario, that's something that can have a material impact on our P&L results. I think that that's the kind of things that we see right now that might happen in this next two months.
Despite of the fact that most of our commodity positions are closed, and therefore, under a normal energy prices scenario, volatility that should be, or uncertainty that should be expected would be really low with these current prices scenarios, even a slight open position, be it positive or negative can substantially impact the results. That's why we don't feel comfortable giving a more precise or a more exact energy scenario. It's not something that precisely we foresee that's going to go wrong or it's going to go right.
Many thanks.
The next question.
Next question, please.
Comes from Jorge Guimarães at JB Capital. Jorge, your line is open.
Good morning, everyone. I have three questions, if I may. Firstly, regarding the LNG, in past presentations, you indicated to the market that you were running down or de-risking the area going forward. Has the current price scenario made you change your mind on that? The second one is a detail about CGE. Is all the capital gain of CGE already included in the nine months results or will some still come until year-end? This would be the second one.
The third one, if you can elaborate on what regulatory scenario is included in the guidance, namely, if any impact of clawback in Spain is included in the EBITDA guidance, the EUR 3.8 billion-EUR 3.9 billion for ordinary EBITDA. Thank you very much.
Thank you, Jorge. I think that actually, what's currently happening with the energy scenario, I would say that it reinforces our de-risking, because I understand that people now see that, JKM prices or TTF prices, and they say that right now with a bit of an open position, you might make a lot of money, but it could be the other way around. I think that, again, when we decided two years ago that we wanted to become a boring company, this actually reinforces our idea that we want to be a boring company.
We don't want to go to the market the tenth of November and having to give a guidance that is, you know, in a range of 3.8-3.9.
We would feel much more comfortable, we would be able to go already in January and give you a guidance that would be to the spots for the end of the year. I think that actually it has reinforced our idea of what we want to do, is we're going to keep on moving with the de-risking. We want to de-risk as much as possible, and we want to keep on being a company that delivers a cash flow visibility as stable and as long-term as possible. With the second part, CGE, I would say all of the capital gains are already all in the September results. We should not be expecting any further capital gains regarding CGE.
As for which regulatory impacts have we included in our EBITDA guidance, sorry, but that's something that I cannot disclose because, to some extent, it would give some signal to the government to what we think that might happen or we might not happen. I think that I'm not going to be able to be more open about that.
Next question, please.
The next question comes from Fernando García at RBC. Fernando, your line is open.
Hi. Good morning, everybody. I have three questions as well. First one is, I wanted to know how is your total position of gas contract versus customers after all the gas contract renegotiation and termination of the Maghreb Pipeline. The second is as well regarding the Maghreb Pipeline, I wanted to know what are the implied change in cost for you for this change, so moving the gas by LNG instead of pipeline, if that implies higher cost for you.
The third one as well regarding this pipeline in that scenario, the Maghreb Pipeline is used to export gas from Spain to Morocco. In that scenario, would you benefit from these revenues, or they will need to have a new concession, or what? How this will be negotiated?
Thank you.
Thank you, Fernando. I will try to answer the first two questions jointly. In July 2018, we already said that we were counting on the EMPL concession to expire. That means that was already factored in that our gas contracts were going to be enough to supply our end customers, and that also took into account the evolution of the gas prices. In that sense, for us, I understand that is something that this past few months has taken a greater visibility in the media, but for us, it's something that we've taken into account for these past two years. For us, it comes as no surprise.
For our customers, for this winter and for further years, we do have enough gas supply contracts in order to supply our end customers. As far as the gas cost, the gas procurement cost is concerned, it's something that we've already been factoring for the past two years. For us, it's something that is our baseline scenario. Having said that, we are working with Morocco and Algeria, or Algeria and Morocco. I don't care about which order you put it on because both of them are equally important to see whether we are able to extend the concession.
Because I think that it was something that would be sensible for all of the parts, and I think that is something that could create value for all of the parts involved.
If we do not reach a satisfactory agreement, that's our base case scenario. Be it in as far as volumes is concerned and also as far as gas procurement cost is concerned. Having said that, I mean, I think that some people think that our Algerian gas is cheaper than the rest of our procurement costs. I would not take it for granted saying that the Algerian gas is our cheapest or our most expensive. It's just another gas and something that we have to take it there. Whether the Medgaz, the EMPL pipeline can be used to export gas to Morocco, I mean, that's of course technically a possibility.
Whether that happens or not, I think that's something that at the current time being, it does not concern us. The way we see the pipeline and the gas is something that is there. It's not something that currently we're working on. Next question, please.
The next question comes from Manuel Palomo at Exane BNP Paribas. Manuel, your line is open.
Hello. Good morning, everyone. Thanks for taking my questions. I've got a couple. First one is on the CapEx. CapEx is at EUR 890 million in nine months. Could you please put it in the context of your currency hedging, which you expected significant boost in coming years, thanks to renewable capacity additions? Specifically asking about renewables and what's your updated installation expectation for the year 2021 and also the Latin networks. Secondly, I wanted to ask you a bit more in detail on the renewables and what is your hedging policy on renewable installation costs?
I wonder whether, given the current inflation cost, is it fair to assume lower IRR WACC spreads than initially expected as a result of this price inflation for the already awarded projects? I think that's about it from my side. Thank you.
Thank you, Manuel. I think that in CapEx, I would differentiate between two different evolutions. On the one side, we see what's happening in Latam, and depreciation is not only affecting our results, it also affects our CapEx. In local currency, the evolution is different than the one that we're currently seeing in euros. In renewables, I think that what we've seen in the delay of investment that Steven talked about is basically due to the increase in the cost that we're seeing in some of the components or most of the components for the renewables.
That has led us to delay some of the projects, because for the time being, what we do not want to do is sacrifice the IRR levels. In this sense, we think that it makes more sense to delay the projects and see whether in some cases. Because I think that what we're doing is reviewing some of the projects. Some of the projects we've been able to improve the design of the projects or improve some of the conditions on the underlying PPAs that have allowed us to keep on with the original schedule and factor in the increase of the CapEx without any negative impact on the IRR.
In some other projects where the FID has not been taken, or we have not been able to successfully review the PPA, what we've decided is to delay the FID of the project or delay the construction of the project to see whether the component prices are going to reduce. Because in this sense, I would say that this is the outlook that we have, and it's not only the outlook that we have, but also what we see in the sector is that the current increase in the prices is something transitory.
In this sense, it makes sense that if you're not able to somehow change your project to maintain the IRR, what you should do is just wait to build the project.
Another thing is if the time goes by and we see that this price increase is not transitory and it becomes structural, then of course we'll have to go back to our drawing board and decide what we have to do. Next question, please.
The next question comes from José Ruiz at Barclays. José, your line is open.
Yeah. Good morning, everyone, and thanks for taking my questions. Three quick ones. First one, on the Cheniere contract, if you can confirm us that you're in the money, considering the high, Henry Hub prices, and when will we see an impact on your accounts from that? Secondly, there was news flow this morning, in Spanish press about, Algeria increasing gas prices, for the contract. Is this a regular revision or it's extraordinary?
If you can say something about that. And finally, can you confirm that the restructuring costs are not going to increase in the fourth quarter, they're going to stay around EUR 433 million? Thank you.
Starting with the Cheniere, for good or for bad, Cheniere gas costs are fully public and fully transparent. Seeing whether a spot cargo of Cheniere is on the money or out of the money ought to be pretty straightforward. The thing is, these past few years, what we've been doing is we've been de-risking the positions, and that means that we've locked in the margins according to the forward prices that we've been seeing these past few years. Currently, for example, our closed position in the LNG business is 92% for this year, and it's over 70% for last year.
This is something that doesn't allow us to capture the upsides, but also protects us from the downsides if when they also come in the market. Because right now we're in the middle of this huge commodity price boom, but we forget that we are coming from a period where we were talking about the LNG glut that was supposed to last until the end of times.
I think that it's not looking at the public information and trying to see whether we are in the money or on the money, that does not give a good idea of how our results linked to the Cheniere volumes are going to evolve, because we have been hedging them and we will keep on hedging them. Do not expect to see huge upsets.
There might be some upsides because we were not able to lock in 100% of the volumes, but most of the volumes have been locked in in the past. Moving to the second question, I don't know exactly what the newspaper was talking about the Algerian price. As far as we are concerned, the ordinary price review with Algeria starts January 1, 2022, and that's as much as we know, regarding the current contractual situation of the Algerian volumes.
Moving to the third question, I can say that all of the restructuring costs that are linked to personnel costs, there will be no further increases in the fourth quarter, as all of them have been already registered in September.
Thank you very much.
Another reminder to press star followed by one on your telephone keypad to ask a question. The next question comes from Alberto Gandolfi at Goldman Sachs. Alberto, your line is open.
Good morning, and thanks for taking my question. The first one I wanted to ask is on renewables. Could you tell us a little bit more about what, you know, how many months of delays are we seeing, and what percentage is really supply chain versus your own decision, as you said, John, to protect the IRR? Perhaps it would be great to know how much you have currently under construction or ready to build, i.e., with, you know, all approvals done and just you're just waiting for taking FID, but maybe you've already won an auction or you have an agreement in principle on PPAs.
The second question is, I'm wondering if you're beginning to see any benefit from widening spark spreads at all, and if you can maybe describe a bit what you are seeing on spreads in terms of margins from the CCGTs. The last question, I appreciate that the weather can create quite a lot of volatility because of such high prices on commodities for Q4. If we look at 2022, and if we assume a normal weather, should you benefit or not from the current commodity environment in LNG and supply? Can you maybe quantify at all if anything can be quantified from that perspective? Thank you.
Thank you, Alberto. I'm going to start with the bad news. You know that we do not give any guidance, explicit or explicit, besides the one that we've already given in the presentation. I will not be able to quantify anything regarding 2022. With the renewables delay, I think that we have to differentiate by geography.
As we are fully aware, it's not exactly the same situation, the one that we're seeing, for example, in the U.S., to the one that we're seeing in Spain or the ones that we would be seeing in Australia, because there are also other trade slash political situations that do impact not only the prices but also the supply chain issues.
I would not say that there is a magic number that gives you an idea of how big the delay is. Again, the delay is not only supply chain related, in some cases is due to a decision taken by the company. If we are not able to improve the condition of the park that somehow is able to offset the component increase, then we decide to delay the project. I would not be able to say X months lag or Y months lag because we would have to go on a park by park basis. Right now, top of my mind, I cannot give you the figure exactly of how many megawatts we are currently under construction.
Maybe later, the people from capital markets can give you a more precise figure regarding that. Moving to the second question, the spark spread of the CCGTs in Spain. I think there's one thing that we have to bear in mind, because I think that the question that you've posed can be a bit tricky, and it has to do with implicitly, you are asking me about what's the gas price of the CCGTs. I have to tell you that the way we see it is that the CCGTs in Spain are interruptible supplies. They cannot guarantee which level of demand they are going to have on a yearly basis.
Actually, we've seen huge levels of variation from the utilization rate that we've seen in the past and the one of the current year.
When you see that kind of behavior, actually, that implies that it means you have to go to suppose that that's basically market. That means that the gas supply, the gas price of our CCGTs is hub-based. That means basically that the spark spread that we're seeing in our CCGTs is really low because all the pool prices right now, they are really high because gas prices are high. That means also that the level, the room that you have in order to have spark spread is really limited, especially if the gas supply of your CCGTs is hub-based.
I would say that the spark spread of some of our CCGTs is more or less independent of the pool price levels that we see because it's a pass-through of the fact that our gas prices for the CCGTs is hub-based. I would say it's, you know, PVB-based. If the question implicitly was, are we seeing any windfall gas price profits? No. In the CCGTs, there is no windfall for the gas prices we are having. Our CCGTs are supplied with gas price on a hub basis.
The third question is the ones that I said at the beginning. I'm sorry, but we don't give any guidance of the impact that is going to have. We have to bear in mind that the de-risking strategy of Naturgy has been in place from 2018.
That means that we do have a substantial part of our positions for the winter of 2022 that are closed, not all of them. With the current prices scenarios, we're seeing gas prices and electricity prices that are 5 times, 6 times the normal historical levels. That means that even a slight open position or that you have a gas cargo, LNG cargo that fails or that's something that might have an impact in the results and therefore introduces a level of uncertainty that is really high, even taking into account the level of closed positions that we have. Was that the final question?
We don't have any further questions on the line, so I'll hand it back to you for any closing remarks.
Thanks. Thank you very much. Just thank you for joining and you know we'll remain available for any further questions you may have over the next days. And thank you everyone for joining. Have a good day. Thanks.