Energean plc (ENOG) Earnings Call Transcript & Summary

Good morning and happy new year to everyone. Great to be back speaking to you about the latest developments of Energean. I would like to start flipping to Page 3 of the presentation that we have uploaded, giving you a snapshot of what Energean looks like today. And I think this is extremely important because we have been transitioning throughout last year to reach today 9 countries of operation, more than 1 billion barrels of oil equivalent in terms of 2P and 2C reserving resources. 200,000 barrels of oil is our new medium-term production target, a production target that is more than 70% gas weighted, and this is what characterizes us, gas focused in the Mediterranean with a material production and resource base. A couple of comments on our targets on ESG, which I think are extremely important and have been consistently a top priority. We were the first to commit to net zero, the first E&P to commit to net zero, and we are taking actions to achieve our goals. And this has been rewarded by the market and by the rating agencies with a number of awards and the ratings that we'll talk about later. So a big transformation of our business. Going to Page 5 in 2020, focusing on operational performance. We have seen an 80% year-on-year increase in 2P reserves to 956 million barrels of oil equivalent. A production that reached 48,000 barrels of oil equivalent a day, 74% of which was gas. And that obviously reflects the acquisition of Edison that we closed towards the end of the year. Our development, our flagship development of Karish is progressing well despite a very challenging year with COVID and all the problems that the planet has faced from the pandemic. We managed to continue to operate on all our sites and reach an 87% completion rate as of the end of the year. Beyond that and looking to the future, we focus on organic growth, we took FID on 2 very important projects on Karish North and NEA/NI in Egypt. And that will fuel the growth of the business over the next years. On the commercial front, we promised and we delivered the closing of Edison. Despite the challenges, despite the huge drop that we saw in the oil price, we renegotiated the deal. We closed it at what we believe is a very favorable price and expanded our operational footprint to the 9 countries that I mentioned earlier. Beyond that, towards the end of the year, we agreed to buy Kerogen's 30% holding in Energean in Israel, and these are probably the best barrels that one can buy. In my mind, buying your own barrels is the best M&A you can do. On the commercial side also, we have nearly filled the FPSO with 7.4 Bcm a year of GSPAs that have been now signed and executed, bringing us very close to our target, which is to fill up the boat. And the big challenge we have now is to continue the further growth of our business in other areas. On the capital side, on the capital structure side, we've said many times before that capital discipline is a key characteristic of this management team. And during 2020, we reduced our CapEx by $440 million compared to the original guidance, reflecting changes in the market but also reflecting the delays that we've seen in closing of Edison and the other projects. We were sitting at the end of the year at $1.2 billion of cash and undrawn facilities, showing the strong liquidity that we have underpinning this business, and this, for an E&P company, is extremely important. I mentioned about our net zero strategy. And we've achieved a 67% year-on-year reduction of our carbon intensity to 22 kilograms of CO2 per barrel of oil equivalent, continuing our path, and I'll come back to that later, to become the first E&P company that will reach actually net zero. We rolled out green electricity at Prinos in Greece, and we will continue to do that in our efforts to improve our carbon footprint and improve our environmental impacts on the planet. Moving to Page 6. I think this slide shows what Energean looks like today. Compared to the top 5 EMPs by scale, Energean, in terms of working interest 2P reserves, is at the top. We have reached 1 billion barrels being a very material resource base today. And I remind everyone that this is a result of not only the acquisitions, but also reserves and resources that came through the drill bit. So we always combined commercial and technical success. The same in production. Today, we are -- last year, we closed at around 48,000 barrels a day. And our target is to reach 200,000, making us one of the top 5 players in production in Europe. I'll hand over to Panos to walk you through the actual guidance for 2021 and our medium-term targets.

Good morning from me as well. We expect that '20 -- as Matthaios mentioned, we expect 2021 to be a key transition year for us, paving the way to achieve our medium-term targets, that consistently we have communicated in the past. So our 2020 guidance regarding production from our existing producing assets will be around 35,000 to 40,000 barrels a day. Cost of production before trying to implement our cost optimization initiatives, we expect it to be steady at around 200 million. And our development and asset integrity, capital expenditure will be at around $500 million to $590 million, increased from last year, mainly because of our NEA/NI FID that we have taken. In terms of exploration expenditure, we expect to reduce the amounts, mainly driven by our exploration commitments in the U.K. with Isabella and Glengorm exploration wells and the first long lead items leading into our 2022 Israel exploration campaign. The commissioning expenditure, we expect to be around $25 million, $30 million. Again, our guidance would be towards the lower end of that range we give. Our consolidated net debt is expected to hit its peak of where we expect it to be, just before or around the first gas in Israel of just over $2 billion. As you will see from the medium-term targets and the ones that are following our recent presentations, these are improved and are improved on the basis of a higher liquid sales expected from our Karish field as well as the additional gas sales agreements, the contracts we have signed in Israel. That will get us at around 200,000 barrels a day, revenues of more than $2 billion and will -- should get us to single-digit numbers on our cost of production per barrel. Our target is to keep G&A under control at around $30 million, EBITDAX of around or close to $1.5 billion and of course, our consistent effort regarding strong balance sheets to stabilize our net debt position below 2x our EBITDA. On the next page, we have, as Matthaios mentioned, consistently increased our asset base, reserve base that now stands at around 1 billion barrels. We expect that asset base to deliver more than 200,000 barrels a day of production in the next few years. And that is driven by our key growth assets and development assets in Israel and Karish and our infill drilling in Abu Qir and the NEA/NI satellite development we just mentioned. For the avoidance of any doubt, when we refer as a management team to our medium-term target, this is not an aspiration or wishful thinking but a very firm realistic aim we have set as a company to deliver in the next 18 months. And we do have the confidence to be a little bit more specific, more specific, I would say, this time around of how we achieved that. And you will see that towards, I would say, second half of 2022 on an annualized basis, we are getting to that $2 billion revenue target, which we expect to exceed in the following months and years. The split is very -- reflects our targets and what we have been saying. That 55%, close to 60% of that revenue is protected by fixed or floor price gas sales contracts with the rest being liquids as well as gas prices linked -- European gas prices. In Page 11 of our presentation. I think our discipline and focus on managing the cost base, as effectively and efficiently, should get us down, as I mentioned before, to single digits, of course, of production. These are initiatives that are already taking place in Greece, as we have communicated in the past. And we expect this type of logic and initiatives to be implemented very soon in our expanding portfolio post the Edison acquisition. As we're entering the final [ stage ] of our large development in Israel, you won't be surprised that our capital allocation strategy is shifting from greenfield to brownfield type of development expenditure. And on top of that, we expect the absolute amount committed to development expenditure to reduce as we are trying to hit the right balance between growth and sustainable and reliable dividend policy. That is well reflected in the charts we have put forward that shows the split on how we will prioritize our development CapEx in the next couple of years. And since we're talking about capital allocation, we're trying to be a bit more specific again and put everything into perspective what we mean by capital allocation and how we prioritize the use of our cash and capital. We will try to hit the right balance between sustainable dividend, which we aim to be able to deliver in 2022; organic growth from the many opportunities we have in our portfolio and driven by very strict and high-return criteria; a healthy and robust balance sheet and capital structure, which will be reflected from a rapid reduction of our debt cost at absolute and as a percentage amount of debt post 2022; and of course, a very selective and disciplined acquisition strategy as we have clearly demonstrated in the last year with a focused regional and asset mix, meeting our very focused regional and asset mix strategy. I'd like to close with what Matthaios mentioned as well and the main reason why we're exiting a very challenging. And sometimes the word challenging for 2020 seems like an understatement. At a strong position, and it was always our liquidity and the fact that it allowed us to not only continue our existing projects but pursue what we consider to be fantastic acquisition opportunities and deliver on those. And of course, we'll fill and meet all our commitments on our existing portfolio. We enter 2021 in an even stronger position because we do find this year to be a transitional year. I would like to go through, for avoidance of any doubt, what is the available facilities we have. In Israel, we have recently not only increased the amount to close to $1.5 billion, as communicated earlier in 2020, but we now have extended the maturity to reflect the delays that we had in the delivery of the FPSO. We have announced the term loan of $700 million to cover the acquisition of the 30% of Karish, Tanin from Kerogen as well as allow us to accelerate the FID in Karish North as well as plan for our 2022 drilling campaign. In Egypt and Greece, you won't see any changes to what we had before. All I can say is that both facilities are sitting in very healthy levels in terms of borrowing base redeterminations, and we expect the Greek RBL to continue being amortized in 2021 with no -- absolutely no issue. At this point, obviously, we would like to thank all the banks and financial institutions that continued funding us as well as standing beside us in what was an extremely challenging year for our sector. And I think their commitment to not only continue funding us but increasing their commitments reflects the robustness of our asset base and our plans.

Thank you, Panos. I'll move now to go through the key projects. I will go to Page 16. And I want to focus on the key issue that a lot of you may be concerned or worried about, what is happening with the project in Israel, when will the FDSO be delivered. As you can see, the FPSO is 93% complete. I repeat, 93% complete -- completion of the FPSO. We are very close to the completion of the project. And the only reason why we are mentioning that there could be a delay, and I repeat the word could be at the moment, first, gas is still targeted to be December 2021. And this will depend entirely on the ability to move more people into the yard. I'm sure everybody understands that in the middle of a pandemic, there are restrictions that are [indiscernible] businesses. We all experience that. We can't go to our offices. We can't go to our places of work. And that is limiting the productivity of the yard. But I repeat, this does not have a material impact on the project. In a project of 20, 30 years with long-term gas contracts, I do not consider a month or 2 of delay if this happens to be material in terms of financial impact. We will go through our contracts and Nick Witney, our Commercial Director, will tell you exactly where we stand. We do not have any material risk of any contracts being canceled. We do not have any issues with our customers in Israel who are not only supporting but actually are waiting for us to start given the actual dynamics of this market. So I repeat, we still target first gas in 2021, but being prudent as always and being conservative. We want to make sure that we guide people properly if things don't work in 2021 as we want them to. In 2020, they worked better than expected despite the pandemic, despite the shutdown of the yard, despite limitations on travel in Israel and neighboring countries. We managed to execute a subsea project, the onshore project, which is nearly complete and continued, obviously, with the drilling operation, which we completed successfully. So we have managers and management team to overcome any difficulty that we saw -- and we will do exactly the same in 2021. I will move to Page 17 to talk a little bit about Karish North because that has been a major discovery that we made last year. 2P reserves of 240 million barrels, 84% gas, of course, which we are developing with a CapEx of $150 million at a cost of $0.6 per barrel of oil equivalent. These are costs that you can only see in onshore developments in mature fields. And we're managing to bring development costs down because of our strategy to build our own infrastructure, the FPSO and the pipeline in the area. The well we drilled was tested and has a fantastic deliverability. We estimate 300 million scfs a day. These are world-class wells that we will be delivering. Operating costs for this project is minimal -- incremental cost is minimal. And the economics, obviously, are fantastic with an IRR of 40%. I will focus now on the very exciting story of the liquids in our business in Israel, which we hadn't talked about a lot and we hadn't focused on. Through the wells we drilled, we have discovered 100 million barrels of 2P certified by PMM. I repeat, 100 million barrels. This was never a part of the business plan. We knew and we expected that there would be liquid production, but 100 million barrels is a huge result, which we still haven't appraised fully. So we expect that we will be producing close to 28,000 barrels of oil in addition to the 7.4 or 8 Bcm of gas that we will be producing from the field. And we are targeting to appraise further this resource to find potentially more of the oil rim that sits under our gas field. Our choice to develop the field with an FPSO was absolutely the correct one, and this is proven by the fact that we only need to install the second oil train. This is going to be designed and built outside of Far East. It's going to happen in Europe from Technip. And we're installing now a second riser to be able to get to the 8 Bcm that we need to get to. This is a total CapEx of $100 million, which is fully funded by a new term loan. We expect all this to become operational in 2022. Now the FPSO has 800,000 barrels of storage capacity. So for no further CapEx, we can increase our production to about 10 million barrels a year, and you can do the math, depending on the price deck that everybody uses, what that means in terms of our cash flow. In addition to that, these are low carbon barrels which we add to the portfolio. We expect carbon intensity to be around 4.5 kilos of CO2 per barrel produced, which is in line with our strategy to reduce our carbon footprint. So this is a fantastic addition to what we already have in Israel. Moving to Page 19. I think this shows you the strategy. The initial development of Karish is costing us about $6 per barrel of oil equivalent. And the satellite fields that we have Karish North, Block 12, Tanin as we further away from the FPSO, Karish North, total development cost at a cost of $1.5 per barrel; at Block 12, less than $4; Tanin, around $5. Obviously, the closer we discover gas and oil to the FPSO, the lower that CapEx is going to be. That is exactly why we're targeting an additional well in Karish North. That is exactly why we're targeting an additional well in Block 12, which, if it's successful, we'll come to that in a minute, will not only give us additional resource but will push Tanin further to the future. And I remind you that on Block 12, we have no royalties to the original owners of the fields. So the incremental economics of this block are much more favorable compared to Tanin. I'll hand over to Nick to walk you through our commercial success in 2020 and where we stand with respect to our buyers on all our contracts.

Thank you, Matthaios. I hope everyone can hear me clearly. 2020 was an excellent year for us in terms of gas sales in Israel, built largely on the success of Karish North exploration and appraisals, which went extremely well, as Matthaios just catched on, provided us with an excellent low-cost resource to which we compete the supplier market, which continues to show high demand for our product. As I said, the low-cost base and significant resource of Karish North enabled us to continue to compete assertively in the market, which was going through a period where there was still substantial demand coming primarily from the continued privatization of the IEC gas-fired [ powered ] fleet and some growth in desalination tenders and exchanges of assets amongst major gas consumers in Asia. We signed 2 major agreements or about 2 deals. One was split up into smaller agreements for a total of 1.8 Bcm a year. And I think one of the important things to say about these deals is that these are repeat customers. So in all of these deals, either -- at least one of the parties was an existing customer of Energean in Israel. And I think this shows the continued confidence of the market in us. These contracts were largely negotiated during the restrictions of COVID-19. So we have a very strong working relationship with our customers, you can imagine, to negotiate these deals remotely and at a time when there was a degree of uncertainty in the global industry and the global economy. As a result of these new contracts we've signed, we can expect, as Matthaios has highlighted, to increase our production to 7.4 Bcm a year when we reach plateau in 2025. We have a ramp-up as contracts come on. Not all contracts start with first gas from Karish North and some have Karish North, and some have an ability to increase their contracts as their business grows. So we now have 19 contracts with the largest power producers, the largest industries and other blue-chip customers in Israel. And the 20th contract will come on stream later in 2025 when one of our buyers is able to transfer a part of their contract from another supplier. So we will be reaching that plateau level. We've effectively sold our current inventory of 2P resource. So we have a small amount of capacity left in the FPSO, up to 0.6 Bcm a year absent any further debottlenecking. And with the continued drilling that will be talked about later, we potentially have a little bit more gas to sell into the market. And we have some quite a lot of confidence in gaining share. Thank you.

Thank you, Nick. I would like to ask Steve to talk about our future drilling program, which we are very excited about, the next wells that we're planning to drill in Israel.

Good morning. Okay. Can you hear me? So we're looking to drill up to 5 wells in 2022. This is one development well at Karish North, one appraisal well, which, as Matthaios says, we'll go and examine the oil rim that we believe exists in the northern part of Karish Main and 3 exploration wells. The 3 exploration wells will target Tamar A, B, and C and D sand deposits. So the horizons, which are similar to our existing discoveries, Leviathan, Tamar, et cetera, so it's a proven play. And in the case of Hercules, we'll actually go to deeper horizons that have not been drilled offshore in Israel, which we believe would be more liquid-rich than a typical Tamar Sand well. So we will start the campaign at Athena. Athena is very critical because it helps de-risk the whole of Block 12. If we have a discovery at Athena, we've obviously got Tanin sitting at the other end of this large structure. You have to view the Block 12 and Tanin as one structure really. Then we effectively de-risk everything between. We've selected Athena over Zeus because although Athena and Zeus at the A and the B sand level are the same size, we have a big structure at the deeper horizon at Athena that we can drill for no additional cost. So we go for Athena instead. That doesn't really show in the volumes because the risk of that deeper structure is higher, and therefore, it isn't really captured in the figures that you see. We then move through the appraisal well, then the development well and we finish the campaign off by going to the southern part of our northern blocks. Hermes is really a gas prospect. It's very similar to Tamar, to [ Dali ], to Tanin. We expect dry gas. Around about 97% of the volume that's quoted here would be gas and could lead to, in that area, up to 4, 4.5 Tcf of gas in the structures that we map in this area. And then the final well, hopefully will be Hercules. Hercules, we see very clear gas indications into Tanin A and B. So we're almost certain to find some gas. Could be tied back to Karish as a satellite in parallel with Tanin and Block 12. But the exciting part of Hercules is the deeper play in the Cretaceous and the Jurassic. And the liquids that we found in Karish really encourages us that if there aren't liquids or we know there are liquids being developed from deep horizons, if they're going to accumulate anywhere, they're going to accumulate in Hercules. And actually, we map a string of other prospects in Block 23 that can be targeted post the discovery at Hercules. So Hercules hasn't been audited by the D&M at the moment. We will give it to them next year to have a look at. We have set around -- the potential for up to 400 million, 500 million barrels in Hercules barrels oil equivalent, about 50% gas and 50% liquids. I think -- is that a nice -- Matthaios, I hope [indiscernible]

Thank you. Thank you, Steve. I think that demonstrates not only the great project we have in Karish, the great growth opportunities we have in Karish North, but also the future prospectivity in all our blocks, completing a fantastic picture for our acreage in Israel. I would now like to move to the other project that we sanctioned, NEA/NI in Egypt on Page 23. The first thing we did immediately after we closed Edison at the end of the year was to sanction a project that had been sitting there for quite a while, sleeping without Edison and its previous shareholder EDF wanting to invest any further money in Egypt and in the E&P business. That sort of created the drop in production that you see between 2020 and 2021 because this project is critical to not only stop the decline but stabilize and increase the production from the Abu Qir field in Egypt. As you can see from the page, this is a subsea development tied back to the main Abu Qir facilities. Very similar story with what we're doing in Israel. We're using existing infrastructure to develop satellite fields through subsea tiebacks at a very low capital cost and a very low incremental operating cost per barrel. A project that has a 30% IRR, the gas price on NEA/NI is significantly higher than the main gas price of Abu Qir. We're at about $4.2 contracted to the Egyptian state. So no commercial risk and a long-term gas price, which is very helpful for this project. This is a project that should have been sanctioned earlier by Edison. This is the first thing we did, and we would bring it on stream as soon as we can. We've already awarded the contract to Technip to develop the asset for us. The other big deal that we did in 2020 was the acquisition of Kerogen. Panos will give you the details of the deal, which I think is probably one of the best deals we've done so far.

Yes. As explained and hopefully reflected in our RNS, the agreement to acquire Kerogen is [ further ] 30% in our subsidiary, Energean Israel Limited, where we currently hold 70%. That acquisition will take us to 100% and fully control that subsidiary as well. As a result, we expect to have full control of the capital structure of this very important subsidiary of ours. In terms of technical, trying not to repeat what you have already in our RNS, it adds 220 million barrels of 2P reserves. I think from all the metrics we are outlining here, the key for us is the payback period for this incremental acquisition, which we expect it to be less than 3 years based on the contracts and the projections we outlined before. A bit more details about how we have structured this deal, which is heavily on deferred payments, again, to reflect the dates and the timing around first gas and peak production. $175 million paid upfront at closing and $125 million to $150 million deferred cash consideration post practical completion. The range here just reflects the agreement, the commercial agreement that if we choose to prepay that $150 million, the discount could be up to $25 million. There is a deferred consideration of $30 million end of 2022 and another $50 million in the form of convertible notes, which mature in end of 2023 with a 0 coupon. In terms of the milestones remaining, you have seen the financing that we closed that includes in the use of funds the $175 million. We are already in discussions and we have submitted to the Israeli Petroleum Commissioner the necessary paperwork for approval, which we expect to get in early February, first or second week. At the same time, we expect the publication of the circular and towards the end of the month, February, we expect the final CP, which is the shareholder votes to be in with the closing to take place last week, February, early March, the latest.

Thank you, Panos. I would now like to zoom into our ESG business, which, in my mind, is one of the top priorities for us. As I said earlier, we have set a target to reach net zero by 2050. And on Page 29, you can see the actual steps we have taken to reduce our carbon footprint by more than 85% until 2023, which is a key target for us. We're not just talking about long-term targets. We're actually taking specific actions in the short and medium term to comply with the SDGs of the United Nations. So we have a target to reach less than 9 kilos of CO2 per barrel. We've been very transparent. We are focusing on disclosing all our carbon footprint according to CDP and TCFD, and we will be obviously continuing the effort to reduce our carbon footprint. We have linked executive compensation to ESG to make sure that everybody stays focused and understands the importance this part of our business to -- not only to Energean, but to the rest of the E&P business. We believe that as a leader in this business, this has been rewarded by a number of -- awarded by a number of achievements we've got this year. We have been rated A by MSCI. We have a gold medal by Maala in Israel, and that reflects our leadership position on ESG. Following on this, I'm going to talk today a bit about Greece, which we have forgotten the last few months. We have a unique opportunity in the Prinos field in Greece, which has become less important, obviously, to our business because of the size of the rest of the portfolio as we have identified a great opportunity convert it into the first carbon capture and storage project in the East Mediterranean. Being focused on the East Mediterranean and identifying our strengths, we have a country in Greece that emits close to 36 million tonnes of CO2 a year. And Prinos is the only place where this can be the only field that can be used for a CCS project. We are in detailed discussions with the Greek state and we are in a unique situation where there's a lot of funding available, not only because of the focus on Europe on green projects, but also on the back of funding that has become available to the country because of the pandemic. So we're looking to -- we're evaluating the opportunity. We believe this could be a great addition to our portfolio and a great project for our future business in Europe, especially in the Prinos field. Now closing today's presentation and before we open to Q&A, I would like to sum it all up. I think the operational performance that we've demonstrated is fantastic in 2020. We plan to deliver first gas at Karish and develop the Karish North in the next year and '22 and '23 for Karish North. We will develop NEA/NI in Egypt. Already, contracts have been awarded on the same logic, turnkey contract to major contractors. And we will deliver 5 wells that Steve described earlier that will provide the future growth for our business. On the commercial side, we plan to close Kerogen in the first quarter of 2021. We will continue to sign GSPAs until we fill the remaining space in the Karish FPSO, and we are continuously looking for opportunities to export gas from Israel. I remind everyone that we've signed 20% of the capacity to EastMed Gas Pipeline that is being developed to connect Israel with Greece. And we have planned to sign an offtake agreement for the Karish liquids in 2021, a substantial part of the business coming out of Israel. We'll continuously optimize our capital structure. We are planning to refinance the debt on Energean Israel in 2021. We will define our dividend policy. And as a shareholder, I remind everyone that this is a unique situation where management team is totally aligned with shareholders with a very big holding of the management team in the shareholding of the company. We are totally focused on paying a stable and sustainable dividend over the next years. That will become a top priority for us, and we will be guiding the market as the year unfolds. Our medium-term debt-to-EBITDA will continuously stay below 2, as Panos mentioned, and that is also another key focus for me business because we do not want to be overleveraged. This is not where E&P companies should be. Closing on our net zero strategy, very important for us. We will align with TCFD recommendations. We will roll out more green electricity to reduce our carbon footprint, and we will evaluate moving the Greek business and using effectively any assets that we have in a smarter way, aligned with what the market wants year-to-date. So I will close by repeating what I said before. Our target is to deliver first gas from Israel in 2021. We are working very closely with Technip, our contractor to overcome any difficulties and increase the manpower in Israel. That is something that we would be focusing on over the next months. But in the big scheme of things, I think the reality is that this is a great project for us that doesn't get impacted, especially because of the gas contracts that we have in place. So thank you for listening today. And I would like to open the floor to any questions.

[Operator Instructions] And our first question comes from the line of Nathan Piper from Investec.

I've got 2 questions for me, please. First of all, on the timing of Karish. I just wanted to understand how this fits in with the force majeure you've already declared and indeed how discussions have gone with the off-takers from the Karish project. So I wonder if you just clarify one last time how force majeure, the date that you need to deliver gas and all that comes together alongside any potential for liquidated damages if there is any disputes?

Nathan, the answer is very simple. There isn't a force majeure. There's a potential force majeure that has been declared by Technip, and we have passed this on obviously to all our buyers. This is something we are covered from the gas contracts we have in place. Our contract with Technip provides for liquidated damages to be paid for delays of the project, which are obviously not related to the pandemic. So there is an ongoing discussion with Technip about how much of the delay -- or the original delay I'm talking about has been caused because of the pandemic, to be able to be fair and adjust the liquidated damages to reflect only real delays in the project. The same happens with our buyers. And I think the most important issue for me is the commercial reality in Israel. We have seen a major change. We've seen Chevron coming to the market. And the first move they did was to be aggressive with buyers. And I think that was reflected by the news we've all read in the markets. And the buyers have all covered their positions with short-term agreements from existing suppliers and are waiting for us to come on stream. I think what Nick said is very important. The contracts we signed were towards the end of the year, the last contract, demonstrating, again, the confidence the market has in us and not only the contracts, but also the fact that we are continuously offering the lowest gas prices in the market. We competed hard for the Ramat Hovav power station. That is a big amount of gas that we'll be selling. And I want to highlight that we have not lost on any single big contract that we completed. And the market is there. Market is covering us or Supporting us, and I don't see any issue with any of our buyers. With respect to timing, I said it before, I will say it again, we have 1,000 people working on the shipyard at the moment. And I think everybody understands what the pandemic brings, and the pandemic does not allow people to work very close to each other. And that is the only issue that we're faced with in Singapore. So as the country sorts out its issues -- and Singapore has dealt with this issue extremely well. As the country gets vaccinated, like every other country, and as we get out of the problems, I am very confident that we will see a ramp-up, and that ramp-up will be reflected in an increased productivity of the yard that will allow us to deliver the FPSO out of the yard as soon as we can. But these are issues that are outside our control. These are issues that we cannot do anything about. I don't think anyone can force a government to change COVID-related restrictions. And I repeat, there are 1,000 people working today. I wish there were more, and we will be trying to get more. But this is not something that anybody of us can control. As a management team, what we can do is do our best to overcome any problems to shorten the time of transit to Israel, to shorten the time of commissioning to make sure that we get a project started as soon as we can. I do not foresee any major risk of delay for the project because even if we stay at existing levels, there's no further increase of resources. We have guided today that there could be a 2- to 3-month delay if we are as -- if we stay as we are today. So let's call this the worst-case scenario and from there, we will improve. So that's where we are at the moment. We like to be conservative. We like to be prudent. And although we could just state that we remain confident about first gas in 2021, we want to be prudent and confident and guide the market properly.

That's very clear. And my second question really was around what the opportunity or what you think the opportunity might be to debottleneck the FPSO? So once you've got it on street, given you're doing all this exploration drilling and everything else, what can you do or what do you think the potential might be with the existing facility once you've got the extra oil train or the extra riser to perhaps increase the capacity of the vessel even further?

Nathan, the big problem is not the vessel. The problem -- the issue is going to be the pipeline. The pipeline has a [ fixed ] capacity, and there's nothing you can do to debottleneck a pipeline unless you lay a second pipeline. Now what we can do and what we are looking at is other evacuation routes. We're looking at floating LNG options. We're looking at pipelines to Cyprus. We're looking at the pipeline that will connect to Europe. So all these are projects that are under discussion. We do not have, at the moment, anything specific because there's still the design phase. The great prospectivity that we see in the other blocks could lead to more discoveries. If we reach that point, we will be looking at options to increase the capacity not only of the FPSO but also the evacuation routes. So the issue is not the FPSO. The issue is going to be the evacuation routes. I think if you go back when we started this project, the scenario was that we would produce 4 Bcm a year and 7,000 barrels of oil a day. That's the basis on which investors bought our shares at IPO. And today, we are talking about close to 8 Bcm of gas and 28,000 barrels of oil a day with a potential because we will have the capacity through the debottlenecking of the oil train to go all the way up to 40. So as we find more resource, we find the solutions. And that is -- that's what we will continue doing. But I cannot be more specific today.

Our next question comes from the line of Chris Wheaton from Stifel.

Could you perhaps talk a bit more firstly about the dividend? As you reiterated, you want to pay a dividend in 2022. How do you see the factors driving that, so the requirement to continue to invest in the business, particularly in the acquired assets, but also the substantial free cash generation you're going to be making from Israel? And secondly, you talked again today about the potential for filling the boat with additional contracts. You do have that additional capacity. You sound very confident on that. Is that something now that we're likely to see before first gas? Or is that something that is likely to be probably after first gas, particularly as you said, given the market change or market disruption we've seen with the entry of Chevron into the market or the acquisition of Noble?

All right. Let me take the first one. So I think to be more precise, the dividend policy will become much more granular and specific, I expect, towards the end of this year. But there will be 2 events, I would say, that will drive that policy. One is what we have said is our efforts to refinance a number of our outstanding facilities, with a long-term facility structure that will allow us to draw that reliable and credible dividend policy for the next years. We are focused to achieve that in 2021, and I'm very confident we will do that. That is the first one, and that is the key. The second one, obviously, is what Matthaios said, our continuous effort to hit first gas as soon as possible. We expect as we're ramping up all our gas contracts from first gas onwards 2022 to deliver a big chunk of that annualized cash flows that we are predicting. We are relying on healthy oil prices. I'll remind you that only 6, 9 months back, we really had to run scenarios at oil prices with [ FX ] margins when it hit even negative prices. But when I mean healthy oil prices and commodity prices, I don't mean 70 or 80 or anything like that. But if oil prices stay at around where they are today and we ramp up as expected in early 2022, I believe we are very confident we will be able to be much more specific on both the timing and the amount of dividend in 2022. And of course, that to be followed by even more long-term strategy around this issue. So these are 2 key factors. And I hope and trust we will be meeting both those in 2021.

Yes. And one more comment from me on this. Energean will not become a continuously or a never-ending investment story without returning money to shareholders. And as I said earlier, we are in a unique situation where this management team is heavily invested. So we're very focused on turning the great success that we've seen to date into meaningful shareholder returns, and that is going to happen. And we will combine that with growth because we will continue to grow. So I think the way to look at our business is that this is a stable dividend-paying story going forward but with growth potential only in opportunities like the ones we've seen today, low-cost developments and very low-cost acquisitions like we've done with Edison, like we've done with the business we did with Kerogen right now. So when we see opportunities, we grab them, when we have developments that are as exciting and lucrative as the ones that I mentioned today, Karish North, NEA/NI projects with 30% and 40% IRR, are unique in our business, those are the types of opportunities we will invest in. But always keeping in mind, keeping our debt low, keeping liquidity and keeping a stable dividend policy for the future.

Great. And my question on gas contracts.

Nick, do you want to take the question?

Yes, I do. I do. So the picture that we have at the moment, we have -- as I said, we've effectively sold our existing 2P inventory. So the short-term limiting factor on us at the moment is resource. It's not capacity. We still have capacity, as we pointed out, in the FPSO. We have capacity in our well stock. So we have an exploration campaign, as you heard from Stephen, in 2022. So as we've done with Karish North, we can move very, very quickly from exploration discovery to commercialization. So we have customers who are -- we are still talking to, who have an eye on the new projects, on new tenders, on new privatization, which should enable us to fill that incremental capacity in the FPSO.

Our next question comes from the line of David Farrell from Crédit Suisse.

Sorry, we can't hear the question. I don't know if it's only us.

Hello?

David, can you state your question, please?

Hello?

Yes, we can hear you now.

All right. Sorry. My apologies there. Can I just ask a couple of questions? So could you just speak kind of more broadly around kind of Israeli gas demand, how that's been effective in 2020 and how you kind of see that shaping out up over the next few years? And then my second question, I just wanted to touch on the status of the U.K. appraisal wells, where we were in terms of the timing of appraisal wells on Glengorm and Isabella and your thinking about kind of monetization of those assets?

Nick, do you want to take the gas demand in Israel? I will take the second one.

Sure, sure. The -- so the gas demand in Israel has not been significantly affected by the events of the pandemic. As you would understand that a lot of the demand in Israel is driven by electricity and then for gas. And during the homeworking period, there's been plenty of demand. I think we actually -- they've actually experienced the peaks in gas and electricity demand that they've had historically, driven largely by increased consumption of air conditioning. In the medium to longer term, the government has released a number of forward-looking plans, including targets for renewables. However, the -- in all of those scenarios, there is continued growth in gas demand. So we see -- certainly are in line with our maturity of our resource base with the opportunities to increase, as Matthaios said, our gas processing and the evacuation capacity and the competitive positioning in Israel as -- with the price of oil increasing. We've seen a restriction on some of our competitors' export contracts lifted. And we would expect to see more gas being exported from Israel to neighboring countries such as Jordan and particularly to Egypt. So in terms of, as I say, our positioning, we intend to be and have shown to be and will remain -- should we say the lowest on the cost curve, which will mean that we will be in a position to take advantage of any of the expected incremental medium-term growth in the Israeli gas market. And we still see Israel as a strong creditworthy and promising market for our gas production.

On your second question about the U.K., obviously, I cannot comment on the well, which is being drilled at the moment. [indiscernible] of the operator should be commenting on progress. On our long-term strategy in the U.K., I think I've made it clear in previous communications that the U.K. is not part of our core area of business. We believe that Glengorm and Isabella are fantastic assets. So the strategy, as we've said before, is to continue to obviously drill the wells or the well that is being drilled at the moment, the appraisal well. And then we would look for an opportunity to monetize our position.

Our next question comes from the line of Rachel Fletcher from Morgan Stanley.

Just one question [ lastly ] on production, please. Excluding your contributions from Israel in 2021, you said that production is expected to decline year-on-year. I was just hoping you could talk around the reasons for that decline, please.

I will cover the high level. And if you need more details, Steve can obviously give you more. The reason for the decline is that we have a gas field in Egypt, which, like every other gas field, is naturally declining and need investment. Now Edison and EDF, their shareholders, had not invested in either infill wells in Abu Qir or the NEA/NI development that is critical, as I mentioned earlier, to stop the decline and actually see the production come back to the original levels. So any gas field like Abu Qir needs further investment. And the first thing we did, as soon as we closed Edison [ world ] to sanction, not only the NEA/NI development, but also the infill drilling on Abu Qir. So that is the main driver for the reduced production in 2021, which will be reversed as soon as NEA/NI comes on stream and as soon as the infill wells on the Egyptian assets become operational. The same happens with the other developments we have in the portfolio because we have later the gas field in Italy, Cassiopeia, that [ PNI ] is operating, which is also in development, but that comes at a later date, and our other assets increase as well. But the main reason for 2021 is the decline of Abu Qir.

Can I just jump in, Matthaios, and just add one more thing. I mean it's also worth stating that the decline in Abu Qir is exactly as we expected it to be. So it's not it's declining any faster than expected. It's declining completely in line with our expectations. As Matthaios said, gas fields decline. The other thing to note is that the oil fields in Italy are performing very well. So they're declining at a slower rate than we expected. So I think, overall, the performance last year and the projected performance this year are in line or slightly better than when we acquired the Edison assets.

Our next question comes from the line of Nick Linnane from Sefton Place.

I'm just trying to understand a little bit the dynamics for the refinancing. How much debt is secured against the Israeli assets? Would the JPMorgan, Morgan Stanley just -- to take out? Or is it expected that a refinancing would also take out that JPMorgan, Morgan Stanley facility? And if so, can you talk a bit about what you think is a logical capital structure for Israel? I mean, would you expect to have secured debt with some unsecured as well? Or do you think you can refinance the 2 facilities just with secured debt against Israel?

Look, I can't get into too many details because everything is work in progress, and we're talking to a number of institutional banks about the best possible capital structure. Everything is related and it depends on the pricing you can achieve as well as the debt quantum. Our target is to have a long-term solution, long-term debt solution for the full Israeli-related expenditure. And obviously, that includes the $700 million plus the $1.4 billion we have right now. I want to emphasize, these are commitments. We haven't drawn on anything on those. Our absolute drawing right now is just over $1 billion. If you're asking me what is a sustainable quantum that I would feel very comfortable, I feel that a number around [ 2 to 2.5 ] is extremely possible even with senior strict credit metrics. A business that delivers in excess of $1.41 billion EBITDA for something like 5, 6 years and very credible forecasted type of revenues with long-term gas contracts. This is the type of quantum you would see. Are we going to adopt this? Not necessarily. And everything will be structured around the combination, as I said before, of our target dividend policy. Again, not to leave anything unanswered. Yes, our target would be something secured in Israel when it comes to amounts related to that asset. We will avoid unsecured or corporate debt to the extent we can to effectively facilitate the maximum flexibility on how we use group treasury funds. And for the [ avoidance, when in doubt ], the amount I mentioned is gross debt, right, not net debt. We talk about gross debt always. Our net debt position will reach its peak, just over $2 billion, in end of this year, and we expect this to drop afterwards post first gas of our Israeli.

Our next question comes from the line of Al Stanton from RBC.

Yes. Can I just ask about the oil at Karish, please? I mean you presented as icing on the cake, but as an oil rim, it's going to be slightly more complicated than that. So I'm wondering, to maximize the recovery factor, whether you need additional wells that we haven't really talked about yet, whether perhaps you have to pull Karish North harder so that you can take it easier on duration. And would that then result in perhaps pressure on having to tie back other discoveries to -- in the medium term to maximize the oil production? And then finally, what does that all mean for Tanin? Can Tanin sit on the shelf as long as you want? Or is there an obligation to deliver first gas by a specific date to retain the license?

I will cover the last, and then I will hand over to Steve to give you the technical details of the well. There is no obligation to deliver first gas by specific date. Obviously, we can't sit on an asset forever. But we need to develop the asset sequentially. So obviously, we're in very close communication with the Israeli government to maximize the recovery depending on the existing infrastructure and the gas contract. So our maximum capacity today is 8 Bcm, and we will give priority, as I said, to Block 12, which is closer, has a lower development cost and has no royalties associated with it. So there has fantastic incremental economics compared to Tanin. Depending on demand, depending on ability to access more gas contracts and infrastructure, we may decide to accelerate Tanin, but only if that is underpinned by additional gas contracts. For the time being, we will focus on the lowest cost developments. Steve, do you want to cover issue of...

Yes, no problem. I think the first thing to say is just to make it clear that we don't believe -- or indeed, we know that there isn't an oil rim under most of Karish Main. So at least 75% to 80% of the field by area and reserves doesn't have an oil rim. So the area is drained by Karish Main 1 and Karish Main 2. We've drilled through the contacts. There is no oil rim. What we're talking about is an area in the northern part of Karish Main, south of Karish North. So we call it Karish Central, where there is good evidence that we have a very rich fluid. So this fluid is 7 to 8x richer than the fluids we found in the main part of Karish Main, showing that this area is disconnected from the KM1 and the KM2 areas. This is drained through the KM3 well. The work that we've done to date shows there's a base case scenario. It's a rich gas oil with no rim. But if we model it in an alternative way, we can model it with a rim. And that rim could be very significant. It could be 100 meters thick. It could have 200 million to 300 million barrels of oil reserves in it. And it stretches into a compartment that has yet to be drilled. So the KM4 well will actually kill a number of things off at the same time. It actually is drilled so that we target this undrilled block, which could contain more gas and more oil. It also targets 2 shallower prospects which have been yet to be drilled and a deeper prospect that hasn't been drilled, and it goes through the location where the rim is. We will keep that well and it potentially will become a production well for the oil in the oil rim. So at the moment, at least 80% of the volume of Karish Main isn't impacted at all by the liquids, 20% is. But in the base case, we can produce that well at the expected rates just producing larger amounts of liquid, and it's that reason we have to increase the liquid handling capacity. Karish North itself contains 3x as much liquid per scf of gas than Karish Main. And we'll use actually the 3 different -- the richnesses of liquids or gas to blend to make sure that we can achieve the maximum liquid capacity and the maximum gas capacity for as many years as possible before the liquids come off plateau and then eventually, the gas will come off plateau. So it doesn't cause us any concern, just gets us excited because there's lots of upside. If we find this significant oil rim almost certainly to exploit it effectively, we will have to probably put a second facility there. But -- okay, that's good. I mean it is a nice problem to have if you suddenly stumble across 200 million, 300 million barrels of more liquids. Actually, that answers the question, yes?

Yes, it does. It's kind of opened up one last question, if I may. I mean you highlighted Karish North, Karish Central and Karish Main. I mean in terms of the seismic anomalies that you see, how does that look when you look further west to [ a thinner ] -- and actually, right across the portfolio, I mean, in terms of probability of success?

Yes. I mean this is why the portfolio is so exciting. I don't know if you know much about Israel. But the first 7 wells drilled on this play were by Noble or with Discovery. So we give them positives of 75% to 80%. But in reality, every well drilled in the Tamar Sands on a structure that has an amplitude support [ some ] gas to date. Every structure that we have in the northern part of Tanin and the whole of Block 12, all has identical amplitude support at the A and the B sands. They have flat spots. They have a dimming across the whole structure. And the dimming coincides exactly with the skill point of these structures. So they're very, very low risk. As I said earlier on, we have to consider Tanin and Block 12 as one large structure broken into multiple fault blocks. And what we're drilling up really is the fault blocks that haven't yet been drilled. Now we also have deeper plays in all of those, which you can't see. They don't have amplitude support. We know that works at Karish North because we've actually discovered a different pressure regime, increased north in the D sand. It didn't work in the original Tanin well. But one of the reasons to go to Athena is to test that deeper play out and unrisk it. Same at Hermes, we have amplitude support at Hermes, but not as strong. So it's -- we don't have the flat spots, but we have the dimming. Hercules is almost a slam dunk in the Tamar A and B and the C sand. We have flat spots. We have exactly the same amplitude support as Karish and Tanin. But it's really -- the big prize in Hercules is the deeper structure where you won't see any amplitude support. So there is -- I don't know whether you are aware, but they have found oil offshore in Israel, closer to the shore in the Cretaceous and the Jurassic, just offshore Tel Aviv, but it was in noncommercial quantities because of small structural sizes. So Hercules is a very significant structure at the deeper zones. It's a carbonate buildup very much like Zohr in Egypt in the deeper zones. And that's why we're so excited about Hercules. So we have good amplitude support everywhere in the portfolio, and that amplitude is tested with multiple wells. And indeed, there's been no negative results when drilled on that amplitude so far in the basin, including Cyprus. So Aphrodite was drilled on exactly the same amplitude signature.

And our last question comes from the line of Michael Alsford from Citi.

A couple of questions for me remaining. I think Steve touched on it a little bit, but could you elaborate a little bit more. Now you have the keys to the Edison E&P assets. What you've seen positively relative to your expectations, but also negatively since you've taken over the ownership? Secondly, just on Egypt receivables. You received some money in 2020, but it's about $150 million remaining. So could you maybe talk a little bit about the timing of when you expect to see the remaining receivables paid? And then finally, just on Greece, you clearly are prioritizing other larger assets in the portfolio. I'm just wondering if there's a risk that we see further impairments on Prinos at full year results?

Michael, on Edison, we haven't seen anything that surprised us following closing and we have been very closely monitoring all the assets throughout the last 1.5 years that it took from agreeing to buy the deal and closings. So nothing that surprised us. As I said earlier, the only issue with Edison is the fact that there hadn't been any investment over the assets over the last year. So we are fixing that. We are seeing a workforce which is extremely keen to be part of a fast-moving and growing E&P story rather than one that was exiting the E&P business. So we have strengthened significantly the technical team with the people based in Milan and Cairo and the other areas. And the assets themselves, Italy is performing as planned. Egypt, as Steve said, is performing as we expected, but it needs the investment that we're making. I'll let Panos talk about the receivable and how it has evolved. I can only tell you that we have a totally different approach when it comes to receivables and the government of Egypt. We have a very close relationship with the government as proven by the fact that we got all the approvals from them in record time. And we are in constant communication with EGPC, with EGAS, with the Ministry of Petroleum to support with a more stable and faster receivable reduction. I think we have reached the lowest point since we bought -- or we closed the deal of receivables that Edison had ever seen. The country manager in Egypt is amazed by how attitude has changed. And as you can imagine, this comes together with the investment we're making. So the Egyptians want to see commitment and once they see commitment, they return it back by an acceleration of payment. So the sentiment will change. I think it's going to be much more favorable compared to the past because they see a committed operator that has Egypt as a priority.

Yes. Just following up on what Matthaios said and because this question has come up about the production guidance. I remind you all that we're getting an asset -- a portfolio of assets that only had $10 million invested in them, and we talk about a big gas field in Egypt that only got 10 million the full year of 2020. Just to put things into perspective and just emphasizing what Steve said about the PDP profile is pretty robust and pretty credible. And shifting that focus now to do the very basic in free drilling in Abu Qir as well as commissioning the satellite development of NEA/NI is key for that part of our portfolio. Of the receivables, as we have said many times, Michael, it is something that we, as finance department, we can only take very conservative assumptions and drive our liquidity assumptions and forecasts accordingly. We have seen the surprise acceleration of those, and that is what drove and made us very confident to accelerate that FID in the early year. As a concept, generally, both from a financial and business perspective, we believe in Egypt, we like what we see. We feel it's a matter of managing liquidity accordingly. Do we expect to get back to 30-day payment terms in 2021? No. Do we expect to get back to 360, 400 days of receivables? Again, no. So we are hoping to accelerate and have a reliable and credible turnaround of around, I would say, 120 days, 100 to 120 days that we feel is very, very, very sustainable and a reasonable expectation given the investments that we will be putting in the country.

On your question on Greece, Prinos is an asset that is producing at a stable rate at the moment of around 1,800 barrels a day. We are, as we've announced previously in discussions with the Greek government for a financial package that will become available from them given the effect of the pandemic, and I repeat what I said before, we have a unique situation where a lot of money becomes available to support businesses affected by this. So the absolute development will be sanctioned as soon as -- or continue as soon as we finalize the discussion with the government. This will not require any additional shareholder funds. So if you look at Prinos, we have a stable production at the moment. We have the Epsilon field that will be developed. And as I said earlier, the future of Prinos will come through its conversion into a CCS project that will also have the additional benefit of an EOR project that will increase recovery factors and give a lot more oil out of the producing asset. You're right to say that it's not material in the big scheme of things, but it's still an asset that sits in a country with very favorable tax terms. It sits - it's a legacy asset that we feel very comfortable with. And it's an asset that can turn into a huge success for us because Europe and the E&P business are now totally focused on CCS projects with funding available from the European Union with support from the Greek state. I think this can become a new driver for our business going forward, in line with our targets to reduce emissions to net zero.

We have no further questions at this time. Please go ahead.

Okay. If there are any -- if there are no further questions, I would like to thank everyone for participating today. We remain committed to our goals, as we always do. And we will be updating you for any news coming out of all the various fronts of our projects. Thank you very much for participating today.