Eni S.p.A. (ENI) Earnings Call Transcript & Summary

Good afternoon, ladies and gentlemen, and welcome to the conference call covering today's announcement of Eni's purchase of Neptune Energy, hosted by Mr. Claudio Descalzi, Chief Executive Officer. [Operator Instructions] I am now handing you over to your host to begin today's conference call.

Thank you. Good afternoon, and welcome to our conference call to discuss today's announcement concerning the agreement of Eni and Vår to acquire Neptune Energy. I'm sure you will have had a chance by now to read our press release published this morning and see related information published by Vår Energi. Together, we have agreed to purchase Neptune Energy with Vår acquiring the Norwegian asset and Eni acquiring the remaining portfolio with the exception of German operation. Between us, we are paying $4.9 billion to acquire Neptune, including debt, with Eni paying $2.6 billion for the international business. That equates to an attractive 2P acquisition price of $10.1 per barrel for a business expected to produce around 130,000 barrels per day in 2023. On Eni portfolio basis, therefore, including our 63% stake in Vår, Neptune will contribute over 100,000 barrels per day on average over 2024-'26. The deal with an effective date January 1, 2023, is subject to customer condition and approvals and is anticipated to close in the first quarter of 2024. The transaction represents a unique fit for Eni. We are acquiring a portfolio of high-quality, low emission resources with a significant geographic overlap that both reduce risk and announces the value opportunities. We are already an important producer in each of Neptune's country of operations with the exception of Netherlands, which even so is still aligned with our broader net North Sea footprint and of course, our European midstream activities. Indeed, that contest, that acquired portfolio, carbon supply around 4 Bcm of gas to Europe where Eni is arguably the leading integrated player in delivering these important source of low cargo energy to customers. It is also worth saying that the share united at Snovhit and production through Bontang in Indonesia feed through into our global LNG system. Focusing now a little further on the portfolio. In Norway, the addition of around 65,000 barrels of production with 3 operated field reinforces Vår as the second largest and fastest growing dependent E&P in the country, active across the full value chain. Vår's role in this transaction further validate Eni's creation of the upstream satellite structure. In the U.K., Eni will add around 25,000 barrels per day to the current 44,000 barrels per day, continue to have important presence in both production and also importantly in CCUS, where Eni is 1 of the only 2 Track One projects and where we are continuing to advance these projects on the North Sea Coast. Of course, the addition of further gas production in Nigeria consolidate our leadership position in the country and supports our continued action to boost gas export where Nigeria playing a critical role in supply to Europe in the aftermath of the invasion of Ukraine. Neptune is partners in many operated assets in Indonesia, while in addition, there is a considerable potential upside in align with the proposed Neptune trail development in the Bonaparte Basin, offshore Australia with our existing Blacktip asset. Neptune is also progressing a number of CCUS projects with the Dutch L10 project, the most advanced among them. This transaction will increase the stake of our equity contribution to GDP sales by 4%, up to 33% of the overall sale of our midstream business. And furthermore, Neptune's gas [ waiting ] not only adds to the integrated midstream financial proposition, it also helps advance -- advances us towards our decarbonization objectives by adding low operating emissions production and supporting our target to shift the share of gas production to 60% by 2030. In the Upstream, Neptune brings high-quality production and low operational emissions, and this offers potential for industrial upside. This intrinsic quality, the competitive price, plus the available G&A and industrial synergies drives the attractive accretion, which in turn support our distribution commitment. We estimate synergies delivering in effects of $500 million of value over the operating period. Furthermore, there is scope for additional costs, synergies and exploration and development opportunities, including more CCUS, which we added to financial and midstream upside, could double the value. Importantly, this is all consistent with our stated full year plan set out in February in terms of net portfolio activity, production growth, CapEx and financial returns. To summarize, this is a compelling deal, a strong operating and strategic fit for Eni transacted at a competitive price. It aligns with both our E&P and GDP operations and will reinforce our -- reinforces our position in Norway, highlighting the bio satellite structure. By virtue of its strong underlying cost performance and expected synergies, it delivers immediate value and earnings and cash flow accretion, which further underpins our shareholder distribution commitment. It complements our organic oriented strategy for growth and is consistent with all the financial framework of the 2023-2026 plan, including the expectation that we will generate a positive EUR 1 billion from M&A activity over the 4-year plan. And finally, the additional gas production into our portfolio and the low emissions profile and the assets themselves at around 6 kilogram of CO2 per barrel is consistent with advancing our mission objectives as part of us addressing the energy trilemma in the way we discussed in February. We are very proud to bring into any of these high-performing business, which will contribute to our cash flow growth, our lower emission profile and our shareholder value delivery, and we look forward to closing the transaction. That concludes my comments. And together any top management team, I'd be pleased to take your questions. Thank you.

Ladies and gentlemen, we will now begin the question-and-answer session. [Operator Instructions] The first question comes from Alessandro Pozzi of Mediobanca.

Congratulations for the acquisitions. That is a good geographical fit also for the GGP. And talking about the division, I was wondering if you can maybe give us a bit more color on how you can extract synergies for the midstream out of the Neptune Energy. And if you can talk about gas sales agreement that Neptune has and how they can be, let's say, migrated into the GGP, that will be very useful. That's the first question. And the second question, I think there's quite a lot of exploration appraisal upside of $200 million. There is another $500 million of contingent resources. And I was wondering if you can give us maybe your thoughts on how fast the appraisal in contingent resources can be moved into reserves?

Thank you for the questions. Before giving the floor to Cristian Signoretto I just want to say that clearly, the gas that the additional gas gives more flexibility to GDP. That is already one of the first player in Europe. Clearly, the gas is not just Europe, but we have more flexibility, not just through pipes. That is a very important point. But also, we increased the flexibility through LNG because we have access for the first time to Norway, and we doubled our capacity in terms of supply to Bontang. And then we are going to increase and we are going to start production or we start production in Algeria by the end of this year with a very important rate. And Algeria is critically critical for our supply for Italy, but also for Europe. So overall, that is the critical and fundamental point. Then you talk about they already, the commitment that Neptune has in the Europe, that clearly remains. But that, in any case, in terms of volume, create more flexibility. So I don't want to know if Cristian wants to add something about that.

Yes. So thanks for the question. In terms of gas portfolio contracts, apart from a few exceptions, Neptune Energy has a contract which is expiring in the next, let's say, 12 months. So we will be able to step in, in those contracts and increase the materiality of the flows for GGP out of this transaction, especially in Europe. On top of that, the field of production are located in areas in which we have already our commercial presence. We have our, let's say, customer areas in the country in which Neptune operate. And then clearly, another actual element of interesting presence for us is also Indonesia, where we as Claudio was saying, we will complement the supply to the Bontang terminal, and we expect to be able to take more LNG out of that terminal in order for us to bring it to the high-value market in Asia.

Thank you, Cristian. Now Guido, if you can comment on possible upside in our upstream acquisition.

Yes. Our preliminary evaluation of the exploration portfolio can be valued between $50 million and $150 million and is mainly located in Australia. But we do also have prospectivity in Indonesia and in the Netherlands. We also know that there are synergies in Norway, where there is a significant potential on the Vår assets. Equally, around the field of Algeria, that field, there are interesting opportunity to exploit once we have taken the operatorship of the field.

Just on GGP. Could you -- maybe is it too early to quantify the potential synergies that could be additive to the EBIT of GGP from this deal? Would it be fair to assume maybe a few hundred millions in the long run?

Alessandro, just to clarify, GGP upside were not included in our evaluation. I would like just to give you this reference. So far, we have included around 500 million. This 500 million take into account of the potential that we mentioned before, the one related to potential exploration results and industrial synergies in the main asset that we were, let's say, speaking about, so particularly related to Algeria, Indonesia and few more in U.K. Where we have a potential upside, as we said, it is GGP not yet accounted for additional potential upside to better performance and exploration results in excess of what we are figuring out. Clearly, also the typical synergies that you can see in the asset. And this will -- we estimate this amount of all that activity could double the $500 million that we have so far accounted for. So the potential is up to 1 billion. And once we speak about this, 1 billion is NPV and limited to our Eni portfolio. So limited to the $2.6 billion of investment that is related to the other geography out of Norway.

The next question is from Oswald Clint of Bernstein.

Yes. Just on the topic of attractive accretion, just on the earnings per share accretion. I mean, I'm getting 3% to 4%. And I wanted to see if that sounded reasonable. And perhaps you could say the 500 million of synergy you just discussed. What's the time period that you expect to capture that opportunity? And secondly, the Touat field in Algeria, I think that's the largest volume piece here. I think is Neptune's first in the region. There have been those issues. Have you had -- I mean have you had a good look under the hood comfortable getting this up to the 70,000 barrel per day gross? Is it as simple as the mercury removal unit, and that's really what we should be expecting towards the end of this year?

Yes, about the growth related to earnings per share and the distribution along the years. About the performance, this is an accretive deal, as we said, is a deal that we estimate in the range of 900 million of additional cash flow from operation. And in terms EBIT, it is something in the range of 1 billion at our scenario, which is a scenario with an $80 barrel per brand, EUR 50 per megawatt hour. If you discount this value to 60, something in the range of EUR 35, EUR 40 per megawatt hour, you have, let's say, a reduction in the range of 200 versus this number. So the EBIT will be probably 800 million and the cash flow from the ratio will be 700 million. So it is still quite material and improve the capability and the resilience of these assets that have also the benefit of being light in terms of CapEx. So this is a portfolio that doesn't require a high level of CapEx, something in the range of $200 million, $250 million per year. In terms of distribution of that synergy, that 500 million clearly are split in along the plan. There are also some additional benefit just after the plan, in particular, related to potential synergy in Australia. But all the rest are within Algeria, et cetera, are within the 4-year plan and therefore, is a short-term opportunity.

One point that is only related to the financial. We have to consider that the breakeven of the cash neutrality of these assets is well below $50. So it's really very resilient. So they -- I think that the price at this point in time is not really an issue and the synergies are the big upside that we have in our end.

As far as concerned, the Algerian asset, the issue of the Mercury has been addressed. The solution is being implemented, and we expect a restart by the end of the year.

Next question is from Irene Himona of Societe Generale.

First question, you maintain your longer-term guidance for EUR 1 billion of net disposal process over the plan. Given today's deal, it implies perhaps EUR 3 billion to EUR 4 billion of asset disposals. I just wonder what would be the key, your key strategic themes or criteria that would drive the choice of EUR 3 billion to EUR 4 billion of assets to be disposed? And then the second question, the deal is effective 1st of January this year. It will close a year later. So you're receiving a full year of Neptune cash. By the time the deal closes, what price do you expect to pay? And what happens to gearing before any future disposals?

Okay. Yes. Currently, Irene, you have recapped the -- what is our policy or our, say, plan related to portfolio. This is clearly just one of the element of a broader portfolio activity that is, let's say, consider both acquisition and sale and at the end is resulting in a positive 1 billion over the 4-year plan. In terms of which kind of assets are, let's say, will be targeted for the disposal, these are substantially different kind of assets are, let's say, the opportunity to arise our business related to the transition, particularly as we know that the plant is the most advanced one from this point of view. But in the future, we are also thinking on something similar to sustainable mobility. So that is one of the model, one of the typical asset will be partially, let's say, diluted in particularly for allowing to cash in more cash and reinforcing the transition of Eni and our strategy execution. On the other side, we also continue to improve our upstream portfolio by selling down and diluting our position until assets mature areas where we think other operator could have more interest why we will focus on different geographies or different assets. In terms of what will be the impact. As you have seen, the value is $2.6 billion, and this is including enterprise value is around 0.5 billion of net debt. So the equity value, it is $2.1 billion. We expect that after 1 year, we will able to cash in around $500 million, that is the estimate of free cash flow of this year from the asset of Neptune. So therefore, the cash out will be $1.6 billion, something the range of $1.6 billion. And then clearly, the net debt impact will include also the $0.5 billion that is what is inside the current Neptune balance sheet. The overall impact, therefore, it is in the range of $2 billion in terms of growth of net debt. At the time of the closing, we would expect to have additional, let's say, cash in. And therefore, I will say that the impact in terms of leverage is something between 1% to 2%.

The next question is from Henri Patricot of UBS.

Two questions, please. The first one, just following up on your comments just now on the CapEx is like around $400 million for the year. How is that looking over the next few years? And then secondly, given you've not changed the production guidance and the CapEx guidance. Is the accommodation of these new assets just done through disposals? Or are you looking to slow down investments in some of your existing projects?

First of all, we said that the average CapEx in the range of $200 million, $250 million per year. And this is already included because this deal was assumed in the 4-year plan. So the CapEx figures that you have seen in our start of the presentation had already, implicity included this CapEx contribution and also clearly also the other disposal impact that in the fore plan as impacting the investment.

The next question is from Alastair Syme of Citi.

Claudio, a couple of questions on the sort of the upstream part of this transaction, I think, from a strategy standpoint. The first is do you see this deal as being accretive or dilutive to the company's upstream reserve or resource life? Could you just sort of frame that? And then secondly, I think back on the last couple of years, you cut CapEx very heavily in 2020 and 2021. I think in the upstream more than any other European IOC. Now it feels as though there's sort of a lot of recovery, and that's been probably more than anybody else in Europe. Can you just sort of provide some thoughts on your ambitions in the upstream versus how you think the rest of the industry is acting?

Okay. I mean, we see in terms of reserves very accretive for a number of reasons. We have -- we are expanding on high-quality reserves, which are mainly gas, which is absolutely aligned with our strategy. I'd just like to remind that 75% of the reserves we are acquiring are gas reserves. And so we see it very accretive for the nature of the resources, for the geographical location of the resources, which fits with our footprint, operational footprint, where I mean, we've elaborated a lot today on the synergies we can leverage, the proximity on our -- of our facilities. And I would say this is absolutely in line with our strategy, where we see the gas as a long-term hydrocarbon destination.

Thank you. Thank you, Guido. See, just to complete clearly is very accretive for what Guido said. As you said, the breakeven is very low. The technical breakeven is really very low. And there are a lot of synergies and exploration potential and 2C reserves. So I think that increase the value of our overall package. I don't think that we are spending more, as you said, CapEx. Clearly, we increased because after the shock of the reduction of the last couple of years because of COVID, we had to reactivate all our machine in our system. But I think that our average investment absolutely in the range of what we have to invest to fight our depletion and assure our growth, but with very, very, very efficient because we only range -- we still range in the average of $50 of cash neutrality. That means that we are always in the same area that can assure a good margin. And when we talk about increased CapEx, we are -- through our satellite model, we are able to invest in the transition. So in the transformation of our industry, our business of our energy, but also in increasing what we need now, that is gas. Because the demand is gas is increasing, and we have scarcity due to the Russia war, but this scarcity also because of very low investment in the past. And the demand is always there. So clearly, through our model, we are able to invest in the right way for both without sacrificing one investment with respect to the other. We want to grow on both line, on the 2 lines, clearly, with profit being efficient from a balance sheet point of view. But we are growing in circular economies, CCUS, renewables via biochemical, but we are growing now. And you see in gas and that is our main target and what we are doing clearly in the most efficient way to assure everybody, the company, but clearly, our shareholders.

The next question comes from James Hosie of Barclays.

Just a quick 1 following up on Algeria. 20% of the reserve base you're acquiring. Now you mentioned earlier, it should be produced by year-end. But just wondering, are there particular milestones ahead of that to get to production, which you're looking for? And also when do you expect it to be at plateau?

Well, as I said, the issue is being addressed. The solution is -- it's been implemented at the moment. We expect the restart by the end of the year and the plateau in quarter 1 of 2024. The plateau is around 70,000 barrels of oil equivalent per day.

Just a second question. Just on the German portfolio, I'm just wondering why you didn't want that part [indiscernible] particular factors it just meant it didn't fit with Eni?

When we started to have the discussion with the seller, the German portfolio was already subject to a potential transaction. So we focused all our activity and due diligence on the remaining part.

The next question is from Matt Lofting of JPMorgan.

Two, if I could, please. First, just coming back to intended divestments and the strategy around there. It seems that the sort of the disposal approach is quite important as a second order in terms of further high grading the value of the transaction given the sort of the reference you made earlier to looking to divest to the more tail-related assets against it. Could you just expand on the confidence that you have as a company on being able to execute on tail asset type disposals, particularly in the upstream under prevailing macro conditions and the potential duration over which that program is carried out to get back to the sort of the net EUR 1 billion of M&A under your 4-year plan? And then secondly, on the cash flows. I think you mentioned $900 million CFFO and $1 billion EBIT at your scenario assumptions earlier. Could you just clarify, is that inclusive or excluding additional dividends that would come to Eni from Vår given that Vår's associate accounted in your numbers?

I'll take the first question and then Francesco the second one. So in A&P, when we do talk about Francesco, mature assets or tail asset, we have different opportunities. And I can say that a couple of that are very mature and very close to what we -- our expectation is to close in the next 10 months and maybe also this year. Then we have the other opportunity on which we are working that we spread out in the 4-year plan. But real is not just an assumption, but it's something that is mature and close to be finalized. About the figures that I described, this does not include any contribution from the Vår Norwegian asset. And therefore, this will be an additional upside that will come through this deal.

The next question is from Massimo Bonisoli of Equita.

And congrats for the deal. I have just 1 clarification left. In its first quarter results presentation, Neptune Energy guided for a net cash tax payable for $2 billion. If I got correctly, you were referring before of $0.5 billion free cash flow for 2023. So just to put everything into perspective, just to understand the tax position of Neptune Energy in 2023.

But clearly, Neptune has probably provided the overall picture. The overall picture clearly taken into account of Germany. And once we speak about the cash position and the tax position, you should include also some tax, let's say, legacy that have to pay in Norway related to last year's results. So the net debt that we described, clearly, the net position. There is also working capital or a fiscal position that brings, let's say, the value close to the level that you are referring to.

The next question is from Paul Redman of BNP Paribas.

I just had 2 quick questions. One, just on Australia. My thoughts were that I think previously around 2021, you are potentially things were selling out of Australia. I kind of wanted to ask what's kind of change seemingly you have picked up some more assets in that region? And secondly, just when we talk about oil at $60 per barrel, what gas price you're implying there?

About the $60, I'm referring to, once we speak about 700 to a value of 4 million BTU of around the 11.7 is $12 per million BTU. So something in the range, as we said before, EUR 35, EUR 40 per megawatt hour. About Australia, I think that -- okay, so if you want to come. I can complete, yes. It was clearly -- remember that once we launched that potential sale, it was at the end of 2020. So we said that after the end of 2020, a lot of things have changed. The offer that we received, we consider at the time not in line with our expectations. So we kept -- and now clearly, Australia is a component of a larger deal. We think this is an opportunity in this deal. But clearly, it is not the main driver because we are doing this deal. This is an upside that will benefit on. But clearly, all the values mainly related to the other assets, our strategies on opportunity to implement it to increase even the value of our portfolio there.

The last question is from Kim Fustier of HSBC.

Two, please. Firstly, could you give an indication of how much of Neptune's gas production is exposed to hub or LNG prices versus how much are domestic gas prices? And then secondly, are you able to quantify the uplift to your LNG production and LNG sales or offtake from this acquisition?

Well, the gas portfolio in Europe is completely exposed to the uprise. And instead, the portfolio of Neptune in the, let's say, producing countries is mostly exposed to Brent pricing. When it comes to the LNG production, as we said, I mean, acquiring especially the position of Neptune in Indonesia, given that the one in Norway will be acquired by Vår, will increase our feed gas to the plant, to the Bontang plant from which we are already exporting LNG and we sell it into the Asian market. Clearly, with this -- with the increase of the feed gas position into the Bontang plant, we'll be able to, let's say, negotiate better terms with the stakeholders involved into the plant and have an opportunity to take even more LNG from our portfolio going forward. Clearly, this also will be linked to the new project, which will be available in due time. So I'm talking about the new development in the East Kalimantan basin, but this is going to happen already in the 4-year plan.

Mr. Descalzi, that was the final question, sir.

So thank you. Thank you very much for attending the call.

Thank you for participating in the Eni conference call. You may now disconnect your telephones.