Good afternoon, ladies and gentlemen, welcome to the conference call covering today's announcement of Eni's purchase of Neptune Energy, hosted by Mr. Claudio Descalzi, Chief Executive Officer. For the duration of the call, you will be in a listen-only mode. However, at the end of the call, you will have the opportunity to ask questions by pressing star and one on your telephone. I am now handing you over to your host to begin today's conference call. Thank you.
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 assets 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 two-tier acquisition price of $10.1 per barrel for a business expected to produce around 130,000 barrels per day in 2023.
On any profiled basis, therefore, including our 62% stake in Vår, Neptune will contribute over 100,000 barrels per day on average over 2024, 2026. The deal, with an effective date, first January 2023, is subject to customary conditions and approvals and is anticipated to close in the first quarter of 2024. The transaction represents a unique feat for Eni. We are acquiring a portfolio of high quality, low emission resources with significant geographical overlap that both reduce risk and enhances the value opportunity. We are already an important producer in each of Neptune's countries of operation, with the exception of Netherlands, which even so, still align with our broad, broader Med, North Sea footprint and, of course, our European midstream activities.
That context, that acquire portfolio currently supply around 4 BCM of gas to Europe, where Eni is arguably the leading integrated player in delivering this important source of low-carbon energy to customers. The share in Albatross at Snøhvit, and production to Bontang in Indonesia, feed the key 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 a 3 operating field reinforces Vår as the second largest and fastest growing independent E&P in the country, actually across the full value chain. Vår's role in this transaction further validates 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, continuing to have important presence in both production and also importantly, in CCS, where Eni's HyNet is one of the only two Track One projects, and where we are continuing to advance the huge project on the North Sea coast. The addition of further gas production in Algeria consolidates our leadership position in the country and supports our continuing action to boost gas export, with Algeria playing a critical role in supply to Europe in the aftermath of the invasion of Ukraine. Neptune's partners in Eni-related assets in Indonesia, while in addition, there is a considerable potential upside in aligning the proposed Neptune future development in the Bonaparte Basin offshore Australia with our existing active asset.
Neptune is also progressing a number of CCS projects, with the Dutch L10-CCS project the most advanced among them. This transaction will increase the stake of our equity contribution to GGP by 4%, up to 32% of the overall say of our midstream business. Furthermore, Neptune's gas will not only add to the integrated midstream financial proposition, it also helps advances us toward our decarbonization objectives by adding low operating emission 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 it offers potential for industrial upside. This intrinsic quality, the competitive price, plus the available GNA and industrial synergies, drives the attractive acquisition, which in turn supports our distribution commitment.
We estimate synergies delivering in excess of $500 million of value over the operating period. Furthermore, there is scope for additional cost synergies and restoration and redevelopment opportunities, including more CCS, which we added to financial and upstream upside, could double the value. Importantly, this is all consistent with our stated four-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 GGP operations, reinforces our position in Norway, highlighting the biorationalized 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, is consistent with all the financial framework of the 2023, 2026 plan, including the expectation that we will generate a positive EUR 1 billion in, from M&A activity over the 4-year plan. Finally, the additional gas production into our portfolio and the lower emissions profile and the assets themselves, at around 6 kilograms of CO2 per barrel, is consistent with advancing our emission objectives as part of us addressing the energy dilemma in the way we discussed in February. We are very proud to bring into Eni, this 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, together, Eni 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. As a reminder, star one for questions. The first question comes from Alessandro Pozzi of Mediobanca.
Hi there, thank you for taking my questions and our congratulations to the for the acquisitions, thank you to give the graphical sake also for the GGP. 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. If you can talk about gas agreement that Neptune has, and how they can be, let's say, migrated into the GGP, that would be very useful. That's the first question. The second question, I think there's quite a lot of exploration, appraisal upside of EUR 200 million.
There is another 500 million of contingent resources. I was wondering if you can give us maybe just thoughts on how fast the appraisal and contingent resources can be moved into the. Thank you.
Thank you for the questions. Before giving the floor to Christian and Guido, I just want to say that clearly, the additional gas gives more flexibility to GGP. 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 increase the flexibility through LNG because we have access for the first time to Norway, and we double our capacity in terms of supply to Bontang, Indonesia .
We are going to increase, and we are going to start production or restart 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. Overall, that is the critical and fundamental point. You talk about the already the commitment that Neptune Energy has in Europe, that clearly remains, but that remaining case in term of volume, create more flexibility. You know, if Christian want to add something about that.
Yes. Thanks for the question. In terms of gas portfolio contracts, apart from few exceptions, Neptune Energy has a contract which is expiring in the next, let's say, 12 months. We will be able to step in those contracts and, you know, increase the materiality of the flows for GCP out of this, 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.
Clearly, another actual element of interesting presence for us is also Indonesia, where, you know, we, as Carlo was saying, we complement the supply to the Bontang terminal, and we expect to be able to offtake more LNG out of that terminal, in order for us to bring it to the our value marketing area.
Thank you, Cristian. Now, Guido, if you can comment on your possible upside in your now upstream acquisition.
Yeah. Our preliminary evaluation of the exploration portfolio can be valued between $50 million and $150 million, and is mainly located in Australia. 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, the two field, there are interesting opportunity to exploit once we have taken the operatorship of the field.
Thank you. On the GIP, could you maybe, is it fair to quantify the potential synergies that could be additive to the detail of our GGP from the PA? Would it be fair to assume maybe a few hundred million EUR for, 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. Far, we have included around EUR 500 million. This EUR 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 are speaking about. In particular, related to Algeria, Indonesia, and the few more in UK. Where we have a potential upside, as we said, it is GGP not yet accounted for. Additional potential upside related 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. The potential is up to $1 billion, and once you think about this, $1 billion is MPV and limited to our Eni portfolio. Limited to the $2.6 billion of investment that is related to the other geography out of Norway.
Okay. We're here. I come back. Thank you very much.
The next question is from Oswald Clint of Bernstein.
Yes, thank you very much. Just on the topic of attractive accretion, I'd just on the earnings per share accretion, I mean, I'm getting 3%-4%, and I wanted to see if that sounded reasonable. Perhaps you could say that the $500 million of synergy you just discussed, what's the time period that you expect to capture that opportunity? Then, secondly, the Touat field in Algeria, I think that's the largest volume piece here. I think it is Neptune's first in the region, there have been those issues. I mean, have you had a good look under the hood to 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? Thank you.
Yes. About the growth related to earning 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 EUR 900 million of additional cash flow from operation. And in term of EBIT, it is something in the range of EUR 1 billion at our scenario, which is a scenario with an $80 barrel per Brent, and EUR 50 per MW hour. If you discount this value to EUR 60 per MW hour, you have, let's say, a reduction in the range of EUR 200 versus this number.
The EBIT will be probably $800, and the cash flow operation will be $700. It is still quite material, and it proves the capability and the resilience of this, of this asset, that has also the benefit of being light in term of CapEx. 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 term of distribution of that synergy, that $500 clearly is split in along the plan. There are also some additional benefit just after the, after the plan, in particular related to potential synergies in Australia, but all the rest are within Algeria, et cetera, are within the four-year plan, therefore, is a short-term opportunity.
Um, uh,
Just 1 point that is only related to the financial. We have to consider that the key or the cash neutrality to this asset is well below $60, so it's really very resilient. We, I think that the price at this point in time is not really.
... an issue, and the synergies are the big upside that we are now in. As far as concern, 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.
Fantastic. Thank you very much, everyone.
The next question is from Irene Himona of Societe Generale.
Thank you. Good afternoon, and congratulations. 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-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-4 billion of assets to be disposed? 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? Thank you.
Okay. Yes, correctly, Irene, you have recapped what is our policy or our, let's say, plan related to portfolio. This is really just one of the elements of a broader portfolio activity that is, let's say, considered both acquisition and sale, and at the end is resulting in a positive EUR 1 billion over the quarter plan. In terms of which kind of asset will be targeted for the disposal, these are substantially a different kind of asset, the opportunity to valorize our business related to the transition, particularly as we know that Plenitude there is the most advanced one from this point of view. In the future, we are also thinking on something similar to sustainable mobility.
That is one of the model, one of the typical asset that will be partially, let's say, diluted, in particular for allowing to cash in more and more cash and reinforcing the transition of Eni and our strategy as a whole. The other side, we also continue to improve our upstream portfolio by selling down and diluting our position in tail assets, mature areas, where we think other operator could have more interest, while we focus on different geographies or different assets. In terms of what will be the impact, the, as you have seen, the value is EUR 2.6, and this is including enterprise value, is around EUR 0.5 billion of net debt, so the equity value, it is EUR 2.1.
We expect that after one year, we will be able to cash in around EUR 500 million, which is the estimate of free cash flow of this year, from the asset of Neptune. Therefore, the cash out will be EUR 1.6 billion, something in the range of EUR 1.6 billion, and then clearly the net debt impact will include also EUR 0.5 billion, that is what is inside the current Neptune balance sheet. The overall impact, therefore, it is the range of EUR 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. Therefore, I will say that the impact in terms of leverage is something between 1%-2%.
Thank you very much.
Yes.
The next question is from Henri Patricot of UBS.
Yes, hi, everyone. Thanks for the presentation. Two questions for you. The first one is following up on your comment just now on the, among the in the CapEx is of, like, around EUR 400 million for the year. Obviously, looking over the next few years. Secondly, given you've not changed the production, guidance and the CapEx guidance, is the accommodation of these new assets just gone through disposals, or are you looking to slow down investments in some of your existing projects? Thank you.
First of all, we said that the average CapEx is in the range of $200 million-$250 million per year. This is already included because this deal was assumed in the quarter plan. The CapEx figures that you have seen in our started presentation had already implicitly included this CapEx contribution. Also clearly also the other disposal impact that in the forward plan, as impact in the investment.
The next question is from Alastair Syme, of Citi.
Thank you. Claudio, a couple of questions on the sort of the upstream part of this transaction, I think from a, from a strategy standpoint. You know, the first is, do you see this deal as being accretive or dilutive to the company's upstream reserve or resource life? If you could just sort of frame that. Secondly, you know, as I think back over the last couple of years, you know, you cut CapEx very heavily in 2020 and 2021, I think in the upstream, more than any other European IOC. You know, there's a sort of a lot of recovery in that spending, probably more than anybody else in Europe.
You know, 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? Thank you.
We see in terms of reserves, very, very accretive for a number of reason. We are expanding on high quality reserves, which are mainly gas, which is absolutely aligned with our, with our strategy. I'd just like to remind that 75% of the reserves we are acquiring are gas reserves. We, 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. I would say, this is absolutely in line with our strategy, where we see the gas as a, as a long-term hydrocarbon, destination.
Thank you. Thank you, Luigi. Just to complete, clearly, very accretive, from what Luigi said. I said, the breaking is low, the technical breaking is really very low. A lot of synergies and exploration location, and to see the sales. I think that increases the value of our overall package. I don't think that we are spending more. As you said, CapEx, I feel really increased, because after the shock of the reduction of the last couple of years, because of COVID, we had to reactivate all our machinery system. I think that our annual investment are absolutely in the range of what we had to invest to fight our position and ensure our growth.
With the very, very efficient, because we only range, we still range in an average of $50 cash neutrality. That means that we are always in the same area that can ensure a good margin. When we talk about increased CapEx, we are in, 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. The demand is gas is increasing, we have scarcity due to the Russia war, scarcity also because of very, very low investment in the past, and the demand is always there.
clearly, through our model, we are able to invest in the right way for both, without sacrificing one investment respect to the other. We want to grow on both line, on the two lines, clearly with profit, with being efficient from a balance sheet point of view. We are growing in circular economy, CCS, renewables, biochemistry, but we are growing now, and you see, in gas, and that is our main target in what we are doing, clearly in the most efficient way to assure everybody, the company, but clearly our shareholders.
Okay. Thank you very much.
The next question comes from James Hosie of Barclays.
Hi, good afternoon. Just a quick one just following up on Algeria, with respect to active 20% reserve base you're acquiring. You mentioned earlier it should be producing by year-end, but just wondering are there particular milestones ahead of that to get to production which we'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 being implemented at the moment. We expect a restart by the end of the year and the plateau in quarter one of 2024. The plateau is around 70,000 barrel of oil equivalent per day.
Okay. Thank you. If I could just, a second question. Just in German portfolio, just wondering why you didn't want that part of Neptune , a particular factor that 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. We focused all our activity and due diligence on the remaining part.
Right. Clear. Thank you.
One moment for the next question, please. The next question is from Matt Lofting of JP Morgan.
Hi, gents. Thanks for taking the questions. Two, if I could please. First, just coming back to the intended divestments and the strategy around that, it seems that this is 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 $1 billion of M&A under your 4-year plan?
Secondly, on the cash flows, I think you mentioned EUR 900 million CFFO and EUR 1 billion EBIT at your scenario functions earlier. Could you just clarify, is that inclusive or excluding additional dividends that would come to Eni from Var, given that Var's associate accounted in your numbers? Thank you.
The first question then, and then Francesco, the second one. In the NP, when we did talk about Francesco, material assets or tail asset, we have different opportunities. I can say that a couple that are very mature and are very close, or Our expectation is to close in the next 10 months, and maybe also in this year. We have the other opportunity on which we are working, that we spread out in the, in the four-year plan. Are real, it's not just an assumption, that is something that is mature and close to being 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.
Super. Thank you very much.
The next question is from Massimo Bonisoli of Equita.
Good afternoon, congrats for the deal. I've just one 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 a $0.5 free cash flow for 2023. Just to put everything into perspective, just to understand the tax position of Neptune Energy in 2023.
Clearly, Neptune has probably provided the overall picture. The overall picture clearly take into account of Germany, and once we speak about the cash position and the tax position, we should include also some tax, let's say, legacy that have to pay in Norway related to last year's results. The net debt that we described clearly is a better position. There is also working capital or a fiscal position that brings, let's say, the value closer to the level that you are referring to.
Great. Very clear. Thank you.
The next question is from Paul Redman of BNP Paribas.
Hi, guys. Thank you very much for your time. I just had 2 quick questions. One just on Australia. My thoughts were that, I think previously, around 2021, you were potentially selling, thinking of selling out of Australia. I kind of wanted to ask, what's kind of changed, and you've picked up some more assets in that region? Secondly, just when we talk about oil at $60 a barrel, what gas price are you implying there? Thank you.
About the $60, I'm referring to once we speak about 700 to a value of EUR for million BTU of around 11.7, means $12 per million BTU. Something that ranges, we said before, EUR 35- EUR 40 for MW power. About Australia, I think that. If you want to completely, yes. It was clearly, remember that once we mentioned that potential sale, it was at the end of 2020. We said that after end of 2020, a lot of things have changed. The offer that we received, we considered at the time, not not in line with our expectations, so we kept. Now clearly Australia, yes, is a component of a larger deal.
We think this is an opportunity in this deal, but clearly is not the main driver because we are doing the deal. This is an upside that we'll benefit on, but clearly all the values mainly related to the other assets, Australia is an opportunity to implement it, to increase even the value of our portfolio there.
The last question is from Kim Fustier of HSBC.
Hi, good afternoon, and thank you for taking my questions. 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? Secondly, are you able to quantify the uplift to your LNG production and LNG sales or offtake from this acquisition? Thank you.
Well, the gas portfolio in Europe is completely exposed to the hub price . Instead, the portfolio of Neptune in the, let's say, producing countries, is mostly exposed to the Brent price. 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 Bar, 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 Indonesian market.
With this, with increase of the feed gas positioning to the, 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. This also will be linked to the new project, which will be available in due time. I'm talking about the new development in the East Kalimantan basin. This is going to happen already in the four-year plan.
Thank you.
Mr. Gattei, that was the final question, sir.
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.