Naturgy Energy Group, S.A. (NTGY) Earnings Call Transcript & Summary

Good morning, everyone. We hope you're well, and thank you for joining our results call for the first 9 months of the year. Next to me is our Head of Financial Markets, Steven Fernandez; 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. So with that said, I'm handing it over to Steven to go over the presentation.

Thank you, Abel, and good morning, everyone. As usually, we're going to start off with Slide 4, an update on the energy scenario where we're seeing a continued recovery in the regions wherein the regions where we operate. As you can see, electricity and gas demand in Spain averaged 3% above the first 9 months of 2020. And 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 9 months of the year. If we move on to the evolution of energy markets in Slide 5, you'll find a comparison between the average of the key commodity prices during the first 9 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 months 2020, while gas prices on the major gas hubs, for example, Henry and NBP, have also increased on average by 62% and above 300%, respectively, during the first 9 months of the year. The Spanish pool for its part has multiplied by around 2.5x on average versus the first 9 months of 2021. The 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 currencies 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. So 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 results, if we turn on 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 business for the remainder of the year, and 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 $3 billion in the period, up versus the previous year but still below pre-pandemic levels. And 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, nonordinary impact amounted to around EUR 430 million, corresponding mostly to restructuring costs incurred during the period. And you may remember, we announced an employee voluntary departure plan that was completed by the company in Spain, and you have details of the specific one-offs in the appendix of the presentation. In terms of the main business units, I'm going to skip through this part simply because Jon Ganuza is going to 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 about during the quarter and following the strategic plan presented last July, the rating agencies have consolidated our corporate credit rating of BBB with a stable outlook. And with that, I think I hand over to Jon.

Okay. Thanks, Steven, and good morning, everyone. So moving on to Page 10. You will find a comparison of our results for the period from 2019 to 2021. As still anticipated, results remain below pre-pandemic levels. In particular, in energy management and networks, network to Spain delivered growth, supported by higher volumes and 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 continued 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 2 effects. First, the CMB 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 access 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 21-year average of the 12-month forward outlook for the pool prices. This price has been lower in 2021 than 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 half. In summary, the third quarter involved some transitory impacts in energy management amid the volatile scenario, which should not be extrapolated for the remainder of the year.

So if we move -- 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. And as a result of that, ordinary net income reached 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 spot of CGE Chile and the agreement to resolve the joint venture in ESG. 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. And 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 12 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 Chile Electricity Networks subsidiary CGE, in addition to the cash payments resulting from the agreement to asset UFG. If we shift over to CapEx, it amounted to around EUR 890 million in net period, that's up 8% versus the same period of last year. And the increase is mainly explained by greater investments in renewable developments in Australia, Spain and U.S.A. 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 renewal plans. So for the balance of the year, it's unlikely that we're going to be able to reach the EUR 1 billion of CapEx target that we have envision for renewables. So 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 9 months amounted to almost EUR 3 billion, mainly supported by the gradual recovery of energy demand and the transitory impact from open positions in energy markets that Jon described. The performance in energy market -- in 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. And that also explains the guidance in the range of EUR 3.8 to EUR 3.9 billion at the ordinary EBITDA level for the balance of the year. Finally, the Board of Directors have 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 15th of November, and it is in line with the commitment of paying EUR 1.2 per share against 2021 results. And with that, we conclude our presentation, and we are obviously happy to take any questions that you guys may have.

[Operator Instructions] Our first question comes from Javier Suarez at Mediobanca.

Three questions on the -- I guess, the big picture is on the current scenario of very high electricity prices. What is Naturgy's contribution to the debate, what do you believe that it should be done to reduce electricity prices? And 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 customers and industrial tariff to the cost of renewals? And if you can -- if you have any comment on that proposal and 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 supplies to Spain. so any update on that would be extremely helpful. And the third is on the numbers. I think that during the presentation, management has made reference several times to 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. So 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.

So I mean -- thank you, Javier. Regarding the electricity scenario, I think that there was many questions in one. But 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 that 6 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 our commitment to the society. And that's what we think is really important and we believe in the ESG and the S part, the society part. And that's why we've decided that we're going to be more active in the way that our intermarginal energy is being sold to our customers. And we're going to self-impose a cap of EUR 65 megawatt hour in the intermarginal 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's the strategy that has been implicitly defined for the last few years by all of the utilities in Spain that -- in the [ ruralized ] market, we've always been favoring long-term fixed-price contracts. Actually, it was the CMC with -- in the past said that they did not want to have this kind of contract. That they rather have that the PVPC, what links to index contract to the pool price. So I think that trying to move as many -- as much more of the volume as possible to long-term fixed contracts is a movement that is welcome because we think that is something that reduces the volatility in the end customers, is 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 I think that the best thing is to wait and see what the final measures that the government are and then maybe it would be better to give you 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 case of scenario, the EMPL was not going to continue. In fact, we said that in July 2017 in London. So of our balance and as far as supply and demand is concerned in Spain for our end customers, do not rely -- to not rely on some of the Algerian volumes. Actually, what we're doing is we are working with Algeria to put a compressor station in Medgaz inflation as soon as possible. And we are also in talks with Algeria, Morocco in order to see whether we can extend the concession with the EMPL. But again, we do not meet those volumes currently to -- for this winter because we knew in advance that those volumes were not going to be there. A complete different question is you think on Spain basis, on a European basis. But as far as our customer 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 an agreement with Algeria that it would be at most an upside. And regarding to why the results cannot be further extrapolated. So I think that when Steven was describing the currently energy scenario, the smart thing, if you look on a yearly basis, on 9 months, maybe the results do not -- the commodity price evolution does not fully reflect what currently happens if it will look on a monthly basis. So if we look at November or October, some of the commodity prices are 5 to 6x 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. So that's why we don't think -- I would say that it's more out of caution that saying that there's something that we definitely know that is 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. So to give an example, in the previous years, if one LNG cargo would have come 2 -- 1 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 price scenario, that's something that can have a material impact on our P&L results. So I think that, that's the kind of things that we -- right now, we see that might happen in this next 2 months. And despite of the fact that most of our commodity positions are closed and therefore -- and that our normal energy price scenario volatility that should be -- or uncertainty that should be expected would be really, really low with these current price scenarios. Even a slight open position, be positive or negative, can substantially impact the results. And that's why we don't feel comfortable giving a more precise or a more exact energy scenario. But it's not something that precisely we foresee what's going to go wrong or what's going to go right.

The next question comes from Jorge Guimaraes at JB Capital.

I have 3 questions, if I may. Firstly, regarding the LNG, would you -- in past presentations you entered the market that you were running down the -- or derisking this area going forward? Has the current price scenario, made you change your mind on that? The second one is the detail about CGE. Is all the capital the gain of CGE already included in the 9 months result or will still -- some come until year-end? This would be the second one. And the third one, if you can elaborate on what the regulatory scenario is included in the guidance? Namely, if any impact of [ COVID ] in Spain is included in the guidance -- EBITDA guidance, the EUR 3.8 billion, EUR 3.9 billion for ordinary EBIT.

Thanks, Jorge. I think that actually what's currently happening with the current energy scenario, I would say, that it reinforces our 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. So I think that, again, when we decided 3 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 at the tenth of November and having to give a guidance that is in a range of 3.8% and 3.9%. We will feel much more comfortable. We would be able to go already in January and give you a guidance that would be to the spot for the end of the year. So I think that actually, it has reinforced our idea of what we're going to do is we're going to keep on moving with the derisking. And we want to derisk 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 will say all of the capital gains are already all in the September results, so we should not be expecting any further capital gains in -- regarding this CGE. And as for which regulatory impacts have we included in our EBITDA guidance, sorry, but there is something that I cannot disclose because some extent, it would give us some signal to the government to what we think that might happen or might not happen. So 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 Garcia at RBC.

I have 3 questions as well. First one is I wanted to know how is your total position of last contract versus customers after all the gas contract renegotiation and the 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 gas by LNG instead of pipeline if that implies a higher cost for you? And the third one as well regarding this pipeline. In a scenario of the Maghreb pipeline used to export gas from Spain to Morocco. In that scenario, will you benefit from this revenues or they will need to have a new concession or what -- how this will be negotiated?

Thank you, Fernando. I will try to answer the first 2 questions jointly. So in July 2018, we already said that we were counting on the NPL concession to expire. So that means that, 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. So in that sense, for us, I understand that it's something that these 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 3 years. So for us, it comes as no surprise. So for our customers for this winter and for further years, we do have enough gas supply contracts in order to supply our end customers. And as far as the gas cost -- gas procurement cost is concerned, it's something that we've already been factor in for the past few years. So 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 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. But we do not reach a satisfactory agreement. That's our best case scenario. So bid in -- as far as volumes is concerned and also as far as gas procurement cost is concerned. And having said that, I mean, I think that there is some place -- people -- some people think that our Algerian gas is cheaper than the rest of our procurement costs. And something that I would not take it for granted as saying that the Algerian gas is our cheaper or our most expensive. It's just another gas and something that we have to take it there. And the NPL pipeline can be used to export gas to Morocco. I mean that's of course, is technically is a possibility, but 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 BNP Paribas.

I've got a couple. First one is on the CapEx. CapEx is at EUR 890 million in 9 months. Could you please put it in the context of your currency and being which you expect a significant boost in coming years, thanks to renewable capacity addition? I'm specifically asking about renewals and what's your updated installation expectations for the year 2021 and also the LatAm networks. And secondly, I wanted to ask you a bit more in detail on the renewables, and what is your hedging policy on renewable inflation costs? And I wonder whether the current inflation cost is after the -- or given the current inflation costs, is it fair to assume lower IRR WACC spreads than initially expected as a result of this price inflation for the already awarded projects? And I think that's it from my side.

Okay. Thank you, Manuel. I think that in CapEx, I would differentiate between 2 different evolutions. On the one side, we see what's happening in LatAm and depreciation is not -- FX depreciation is not only affecting our results, it also affects our CapEx. So in local currency, the evolution is different than the ones that we're currently seeing on euros. And in renewables, I think that what we've seen in the delay of investment that Steven talked about is basically induced to the increase on the cost that we're seeing in the -- in some of the components or most of the components that -- for the renewables. And 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. And in this sense, we think that it makes more sense to delay the projects and see what -- in some cases, because I think that what we're doing is we're renewing some of the projects, some of the projects we've been able to improve the design of the projects. So 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. But in some other projects where the FID has not been taken or we have not been able to successfully review the PPA, what we 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 be -- to reduce. Because in this sense, I would say that -- and this is the outlook that we have, and it's not only the outlook that we have, but also that what we see in the sector is that the current increase in the prices is something that is transitory. So in this sense, it makes sense that if you are 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 became structural, then of course, things will to -- we have to go back to our joint board and decide what we have to do.

Next question, please.

The next question comes from Jose Ruiz at Barclays.

Three quick ones. First one, on the Cheniere contract, if you can confirm us that you are in the money, considering the high -- higher prices? And when will we see an impact on your accounts from that? Secondly, there was news flow this morning in Spanish press about the Algeria increasing gas prices for the contract. Is this a regular revision? Or is 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?

Okay. So starting with Cheniere. For good or for bad, Cheniere gas costs are fully public and fully transparent, so seeing whether as both cargo Cheniere is on the money or out of the money ought to be pretty straightforward. But the things this past few years, what we've been doing is we've been derisking the positions, and that means that we've locked in the margins according to the forward prices that we've seen -- been seeing in this past few year. So currently, for example, our close position in the LNG business is for 92% for this year, and is over 70% for last year. This is something that doesn't allow us to capture the upside, but also protect us from the downside if there -- 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 that was supposed to last until the end of times. So I think that it's not looking at the public information and going to see whether we are in the money or not in the money. That does not give a good idea of how our results into the Cheniere volumes are going to go because we have been hedging them, and we will keep on hedging them, so do not expect to see huge upsides. 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 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 first January 2022. And that's as much as we know, take out in the indicative 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.

[Operator Instructions] The next question comes from Alberto Gandolfi at Goldman Sachs.

The first one I wanted to ask is on renewables. Could you tell us a little bit more about what -- how many months of delays are we seeing? And what percent is it really supply chain versus your own decision, as you said, Jon, to protect the IRR? And perhaps it would be great to know how much you have currently under construction or ready to build, i.e., with 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. And 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 spread in terms of margins on the CCGTs? And the last question, I appreciate that the weather can create quite a lot of volatility because of such high prices on commodities for Q4. But if we look at 2022 and if we assume normal weather, should you benefit or not from the current commodity environment in LNG and supply? And can you maybe quantify at all, if anything, can be quantified from that perspective?

Thank you, Alberto. I'm going to start with a 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, so I will not be able to quantify anything regarding the 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/political situations that do impact not only the prices, but also the supply chain issues. So I would not say that there is a magic number that gives you an idea of how big the delays. And again this delay is not only supply chain related. In some cases, it's due to a decision taken by the company. If we are not able to improve the condition of the part that somehow is able to offset the component increase then we decided to delay the project. So I would not be able to say x months lag or 1 month lag because we would have to go on a part-by-part basis. Right now, top of my mind, I cannot give you the figure exactly of how much -- how many megawatts we are currently under construction. So maybe later, the people from Capital Markets can give you the -- 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 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, which cannot -- they cannot guarantee which level of demand they are going to have on a yearly basis, and actually, we've seen huge levels of variation from the utilization rate that we've seen in the past and the world of the quantum of currency. And when you see that kind of behavior, actually, that implies that you have to go to support that, that's basically market. And that means that the gas supply -- the gas price of our CCGTs is half based. And that means basically that the spark spread that we're seeing in our CCGT is really low, because the pool prices right now, they are really high because gas prices are high. But 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 half based. So I would say that the spark spreads so far with CCGTs is more or less independent of the full price levels that we see because it's a pass-through of the fact that our gas prices for the CCGTs is half based. So I would say it is not BBB based. So if the question implicitly was, are we seeing any windfall gas price profits? No. In CCGTs, there is no windfall for the gas prices. We are having our CCGTs are supply with gas price on a half basis. And the third question is the one that I said at the beginning. So I'm sorry, but we don't give any guidance of the impact that is going to help. But again, we have to bear in mind that the derisking strategy of Naturgy has been in place from 2018. So that means that we do have a substantial part of our positions for the winter of 2022 that are closed, not all of them. And as I said before, with the current prices scenarios, we're seeing gas prices and electricity prices that are 5x, 6x than the normal historical levels. That means that even a slight open position or that you have 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.

We don't have any further questions on the line. So I'll hand it back to you for any closing remarks.

Thanks very much. Just thank you, thanking everyone for joining. And we remain available for any further questions you may have over the next days. And thanks, everyone, for joining. Have a good day. Thank you.