Good day, and welcome to the BW Energy Q2 2022 presentation. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star followed by the number 1 on your telephone keypad. If you would like to withdraw your question, press the star 1 again. For operator assistance throughout the call, please press star 0. Finally, I would like to advise all participants that this call is being recorded. Thank you. I'd now like to welcome Carl Arnet to begin the presentation. Good morning or good afternoon, as the case may be. It's a pleasure to welcome you to this BW Energy Q2, first half 2022 presentation. The presentation will be hosted by Lin Espey, our COO, Knut Sætre, our CFO, and myself, Carl Arnet. Please note our disclaimer. The highlights we will go through in this presentation is our acquisition of the Golfinho and Camarupim clusters, including the FPSO, that would add significantly to our production from 2023. More details on that will follow later in the presentation. We also, as we also showed in the first picture on the first slide, we have gotten a BW MaBoMo, which is the new name of Hibiscus, on its way to first oil in Gabon, and we will cover that in more detail as well. We have also signed an inaugural RBL facility for up to $300 million to finance our planned growth, and that will also be covered in more detail. The first half of 2022 gave us an EBITDA of $71 million and a net profit of $19.2 million. We had strong operational cash flow through the first half of 2022, which gave us a cash position of $123 million at the end of the Q2. The Q2 gave us an EBITDA of $5.5 million, with a net loss of $16.5 million, as there were no liftings in the quarter. The Q2 gross production was 975,000 barrels, and we will also, of course, cover that in some more detail later on. On people and environment, we still have some effects of the COVID-19 affecting work predominantly FPSO-related. We have some modifications that are affected, but it should be under control. We had no recorded LTIs in the Q2. We are very pleased that we managed to perform the full conversion of the MaBoMo facility, totaling 1.9 million man-hours without any LTIs. The security risk at Dussafu remains low. We are in a quiet corner of the Gulf of Guinea, so that's good. We had no environmental incidents. Our production outlook is shown on the current slide. We have net production estimates showing you the development to 2023, 2024 and 2025 when we are expecting to get Hibiscus Ruche phase one and two online, as well as Maromba phase one and two. This is not showing the yet-to-be closed transaction on Golfinho and Camarupim cluster, but it shows the current expected production profile with the projects that we are undertaking. On to Dussafu. Production at Dussafu in the Q2 was 975,000 barrels gross, which equals to 10,700 barrels per day. Our OPEX was at $35 per barrel, and that's including the additional COVID costs that we are still carrying. We, as we have related before, we need additional gas lift capacity to reach full potential on the wells we have drilled. We are awaiting eagerly, of course, the installation of the new gas lift module on Adolo, which is progressing but not as quickly as we would have liked to. We are carrying out some periodic tests with nitrogen for intermittent supplement to the gas lift. We have periods where we do achieve higher production. The long-term recovery rate from Tortue remains unchanged, so this is, again, as I mentioned before, deferred production. The Dussafu production forecast for 2022 is 4 million barrels. We will get the additional gas lift capacity at Hibiscus Ruche up in Q1 of 2023, which will then increase production significantly. The drill program is six wells, and of course, we will add production as we add wells. For the OPEX, we expect $35 per barrel for the full year as well as we had for the Q2. We had no liftings in the Q2 as was planned. You can see that from the lifting schedule in the bottom right-hand corner. We have completed our lifting for August, and we will complete one further lifting in the Q4. We are extremely pleased with the development of the BW MaBoMo facility. Here you can see the unit loaded on the heavy-lift vessel following the conversion at Lamprell. The yard and our team did an excellent job, and the unit is leaving with very, very minimal residual work. The work that is left is basically work that is associated with the work that we are doing with pipelines and tying it into the field infrastructure. We had an exceptionally strong HSE performance. Again, very pleased with the performance of the yard and our team, 1.9 million man-hours without any LTIs. The unit is scheduled to arrive in Gabon end September. As you can see from the calendar, we have plenty of time to undertake the remaining installation work and tie-in in time for drilling to commence. We are on track for first oil and Q1 from the Hibiscus Ruche development. This will, when the drilling is completed, add up to 30,000 barrels of oil production, which of course will be a significant increase to our production as a company. We are expecting a somewhat later start to the drilling activities than previously planned as we expect the company that is using the rig currently will declare options, which will lead to us getting the rig a bit later than anticipated. We have a program of a total of four + four firm and four options. We are planning to drill six Gamba wells, two in Ruche and four in Hibiscus. Then we have an additional two potential slots for exploration wells, and we are currently working on these exploration targets. The pipeline will be installed by Technip upon the arrival of the unit in late September. We expect, as I said, to have the infrastructure all in place and ready to go as soon as we get the wells up and ready. The CapEx, I'm very pleased to announce, is holding. We did see some price creep through towards the end of the project, mainly related to increased fuel costs and some expediting we had to undertake to maintain project schedule. We are still very much below the original FID budget of $490 million, so we are extremely pleased with the financial outcome of this project. On to Maromba. Maromba will unlock material production increase as well when we expect first oil in 2025 and, of course, based on a significant increase in our 2P reserves of 105 million barrels. We are working diligently on our development plan and the approval of same. Right now we are working full steam on the completion of the project financing activities. We have, in the meantime, put the FPSO Polvo in layup pending yard selection and pending completion of these project financing activities. On to Kudu. We are continuing the work on our gas-to-power project based on the already discovered and proven resources in the Kudu Main structures. We have progressed extremely well in negotiations with power off-takers, and we are progressing on signing up MOUs. That will allow us to go back and start work on the financing activities. Recent oil and gas discoveries made by TotalEnergies and Shell in Namibia has of course put a lot of new focus on Kudu as well. We have acquired additional 2D seismic to evaluate the subsurface potential. Kudu is up dip of the very significant discoveries of Venus and Graff. That is, of course, making the structures that we see in the vast Kudu North province extremely interesting. We see both oil-bearing potential in the Kudu North as well as additional gas from gas horizons in the same region. We are putting a lot of activity into this at the moment with the information we can glean from public sources today as more and more is known about the discoveries made by Total and Shell. On to Golfinho. I'm sorry for this somewhat busy slide, but we are summing up the transaction that we have agreed with Petrobras here on this first slide. We have agreed to acquire 100% working interest in Golfinho and Camarupim clusters, as well as 65% in Brigadeiro. Current production and the production we expect is about 9,000 barrels when we take over in Q1 of 2023. That's from an estimated 38 million recoverable resource. We also see gas potential in this cluster, and we see 0.7 TCF with further potential. The total consideration for the field is $75 million that we expect to pay. That's including contingent payments linked to oil price production and future successful developments. With respect to abandonment liabilities, Petrobras takes responsibility for all existing hardware that we're not going to use. We take responsibility for the hardware that we are going to use, as well as any new hardware that we decide to put in, is basically the scheme. We have also agreed to acquire the FPSO Cidade de Vitória from Saipem for a total consideration of $73 million. The takeover of the Golfinho and Camurupim operations will allow us to build a solid relationship with the government ahead of the Maromba, the significant Maromba development, and we see this as excellent synergies. The transaction will be covered through existing liquidity and cash flow from operations. Golfinho is today producing from six wells, and we have in our pre-work leading up to this agreement identified two infill well opportunities that will add significantly to production. The acquisition also includes a gas export pipeline to an onshore gas processing facility, and we see Brazil as a very interesting market for gas in the future. It's a growing market. The reservoirs are, with a broad brush, classified as good quality sandstone reservoirs, so we see a very good potential and very minimal risk to further development. If we sum up what this is doing to BW Energy, we have made a kind of before and after. If we look at production, we will, with the acquisition, more or less double the production of the company. We will increase the 2P reserves by 22%, and we will increase the 2C, the potential reserves by almost 200%. We consider this to be a very accretive acquisition for the company. The planned production from the Golfinho cluster is depicted here in this slide. Resource base current 38 with a potential of 116 to add 116 from nearby opportunities at infill wells. We see we are estimating a CapEx for infill opportunities of approximately $200 million with a significant add to production with gas and oil in 2026. Some details on the payment structure. The field transaction, we expect to pay $75 million, as I previously said. We have paid $3 million at signing. There is a further $12 million to pay at closing, and then we have conditional payments of $60 million contingent upon project development and production, and production duration and the Brent oil price. We fully expect to pay that in the current oil price environment. The FPSO transaction is $73 million total, $25 million at closing, $13 million at takeover, and $35 million in installments over a period of 18 months from takeover. In total, we expect to pay $148 million for the Camarupim or the Golfinho and Camarupim cluster and the infrastructure on the main production unit. I will leave you to Knut, who will take you through the Q2 financials. Thank you. Yes, I'll take you through a few slides on our Q2 financials. Just to add, we have also issued the half-year results today in a more formalized report where you can find all details on income statement, balance sheet, cash flows, and also the notes on our website. We also have supporting files with earnings tables. If you would like to see more details, you can go in there. Going to the income statement, we issued a trading update early July, so these numbers shouldn't come as a surprise to you. We have very low operating revenues due to the fact that we didn't have any liftings. We had one lifting in... A big lifting of 950,000 barrels in March. The government had their lifting in June this year. There were no liftings for BW Energy in the Q2. We had one in August, as Carl just mentioned, and we will have another one in the Q4. This quarter is very low on revenues and also operating expenses due to the fact that we didn't have any liftings. To add here, we had the hedges that we explained in detail in the previous quarter. We had another $4 million in losses on those hedges, bringing EBITDA down to $5.5 million in the Q2. The depreciations are following sales volume, so they're much lower. The other depreciations on right of use assets follow production, so they are more in line, giving us a operating loss of $3.45 million in the quarter. On the financial items, we've just mentioned a slight increase in the lease liability interest expenses due to the fact that we bought Polvo in the previous quarter. That is accounted in the income statement as a lease expense. There was an increase there. Bringing the loss before tax to $5.5 million. The tax expense is again following production, giving us a net loss for the quarter of $16.5 million. To the balance sheet, as just mentioned, the Polvo purchase comes into the right of use assets. On the E&P tangible assets we are adding because of our investments in Ruche Phase 1 mainly. In the tangible assets, we have also some increases that is explained here. We had a very high increase in inventories since we didn't have any liftings, so we had an underlift position. On the trade receivables, we had a very high decrease because of the March lifting that was in trade receivables. Now that has turned into cash. On the other side of the balance sheet, we have the long-term lease liabilities increasing due to the Polvo purchase, some settlements on trade payables, and then also some transactions leading to changes on the derivatives, with the realized losses on hedges and also some unrealized losses in Q2. We are very pleased with the developments on cash flows. Starting with the quarter, we had a cash position of $110.8 million and a very good operating cash flow of $72.4 million, mainly the payment then of the March lifting offset by the investments of $52 million, as you can see here, bringing our cash position to $123.3 million. We also had a high activity on the financing side in the Q2, where we finally in August signed an international reserve-based lending facility of up to $300 million. The funds will initially be used to finance further development of Ruche phase one and two in the Dussafu license. We have an initial commitment from banks of $200 million, which can be expanded then up to an additional $100 million with an accordion facility. We are currently working with banks to see if we can get the full commitments up to another $100 million. This secured long-term debt facility is provided by a syndicate of five international banks and has a tenor of six years. We come to the summary. To our strategic priorities and imperatives on the production and exploration side, it's to optimize the Dussafu output, including the new gas lift capacity, the compressor that we have under construction that we will be transported to Gabon and installed on the BW Adolo. We will continue to evaluate the Dussafu exploration targets in the time to come. On the development side, of course, bringing Hibiscus Ruche to first oil at the end of Q1 2023 is very important to us and a very high focus. In addition, we're working hard on Maromba to get to FID and to finalize the project financing. We are currently working with a set of banks in the Middle East and hope to give you some updates there in the coming quarters. Maturing new right-sized Kudu gas to power project with a new, let's say, lower CapEx and improved timeline. On the corporate side, we're very pleased to have maintained a very strong balance sheet, and the liquidity is now further supported by the RBL. Now that we also have Golfinho coming up, we are working hard to get that closed in about five-six months. Both the increase in production from the Dussafu license and Golfinho will then give us very good operational cash flows to also fund new projects and shareholder returns. Our intention is still to pay the dividends of up to 50% of net profit when we have Dussafu and Maromba in full operation. We've also added a graph on the right-hand side where you can see what this is doing to our production and also then cash flows in the time to come. We will more than double our production with the startup of the Hibiscus Ruche wells and Golfinho. During 2023, we will even further increase production as we go along. To sum it all up, we expect to create significant value for our stakeholders going forward. In the shorter term, the focus is obviously bringing Hibiscus Ruche to first oil and closing the asset transactions in Brazil. These are milestones that will really change the company from 2023 and onwards. This will then further support our cash flow. At current oil price levels, it looks extremely good. Also Giving us a very solid capital base with the RBL and additional funding for a new accretive projects. We are ready to go into Q&A, and then I'll leave it back to the operator for questions, and then we can also see if there are any questions from the web. Over to you, operator. Thank you all speakers for the presentation. At this time, I would like to remind everyone, in order to ask a question, press star then the number one on your telephone keypad, and we'll pause for just a moment to compile the Q&A roster. Your first question comes from the line of Teodor Nilsen from GCC Market. Your line is open. Good afternoon, Carl and Knut. Thanks. Take my questions. Three questions from me, if I may. I just want on the size of the August lifting, if that's something that you can disclose. Second question is on general CapEx. You say that the Hibiscus and Ruche CapEx, if any change respectively is possible. I just wonder what you see your general cost inflation industry and do you see any more cost inflation in some parts of the industry than others? The last question is on Maromba and your current stake on 95%. Any thoughts around that, will consider to farm down closer to first oil or maybe after first oil. That's all. Thanks. Okay. This is Carl. I can take your questions one by one. The size of the August lifting, I think it's around 680 and some barrels. That's correct. 680,000. Cost inflation. Here I have to give a little bit more qualitative answer because, as I'm sure you appreciate, a lot of the contracts were signed ahead of, let's say, this last turn of rapid inflation that we've seen. My guess is that what we have seen or what we will see is a cost inflation in the range of 10%-20%, depending on what you're talking about. You know, labor rates have not gone up dramatically, but equipment have. I would say 10%-20% would be a kind of range of the cost inflation that we're seeing. We do not see the same cost pressures now, so we expect this to be holding for, let's say, if we were to start a project today, we would estimate that. Farm down, we're always open to have discussions, meaningful discussions, but of course, we are very aware of our own capabilities, and we are very aware of the value of our assets. We're not going to make any fire sale just to get some money in the door. That's. We have absolutely the capability to finance Maromba. Yes, in the future, we will of course always look at our portfolio and be entertaining discussions as long as they are meaningful with respect to valuation. Okay. Thank you. As a reminder, if you would like to ask a question, please press star one on your telephone keypad, and we'll pause for a moment for any further questions on the phone. There are no further questions from the phone lines. I'll turn the call back over to Knut for the questions from the webcast platform. Thank you. We have several questions, and I'm trying to structure them together. There is one question. That's the first one. With regards to BW Energy's low valuation, is there a danger that BW Energy will be bought out by a larger player? The answer to that is that we normally not comment on any mergers or acquisitions initiatives either way. But what I could add to it is when you look at the shareholder structure of the company, you would have to agree with someone at least before that could be done. Then we have some questions to Golfinho. I don't know whether, Lin, I know you had issues with your line, if you're on, but I- Yeah. I'm here if you can hear me well enough. Yeah. Loud and clear. Thank you. There are a few questions on Golfinho. First one is, it is normal for oil acquisition to have an effective date some time prior to completion with a working capital adjustment to the price. Your deal only has an effective date when you complete. Why was it structured this way? Well, this was the protocol that we had to go through with Petrobras. They have a very regimented formula for their transactions, and we had to adhere to that. That's the short of it. Yeah. I think we can add that, for the time being, the field is shut down due to some remedial work that Petrobras is doing. In one sense, that's good. In two senses that is good because first of all, they do the remedial work. Secondly, they're not producing at the moment, leaving barrels in the ground for us. Yep. That's a good point. There is another question, which is, at what price or linked to what index would you expect to sell gas from Golfinho in Brazil? If I heard the question, what's the gas price we hope to achieve? That's correct. Well, right now the gas market is very robust in Brazil. I don't think it's quite on par with what Europe is seeing, but it's higher than what's happening in North America. With that in mind, it's part of the interest and excitement that we got into Golfinho because as Carl mentioned in the presentation, there is a large gas potential upside close to 0.7 TCF of gas. Our intention is to commercialize that and bring that to bear. As for a specific gas price, well, I gave you a range there about what they're seeing right now. Okay. What is the main timing constraint? That means it will be three years before you expect production from the three infill wells that you expect to do. I believe it's. So- two infill wells. Correct, two infilled, one infilled oil well that we're very excited about, and one infilled gas well we're very excited about. These wells are in the Golfinho license, and they're already part of the existing Petrobras development plan. That's part of the plan wells. Now, I think we're being very conservative on the timing. I think we've got a stretch target to bring that forward, but this is our first time operating in Brazil, so I think we're taking a measured approach and we will bring these wells on. At the same time, once we become operator, we'll be advancing the concepts to commercialize the gas accumulations in Camurupim and potentially Brigadeiro as well. Okay. There is a question, how is the taxation on the Golfinho production? That is a standardized tax regime in Brazil where there is a royalty part to it and then there is corporate income taxes. Royalty is currently 10%. There might be a reduction there for our future production due to the fact that this is a mature and smaller field. It might come down to 5% for new production. But then 34% corporate tax. The final question for Golfinho is on the FPSO. Yes, the gas from Camurupim will then be tied back to the existing FPSO on the field, so there's no need for a new FPSO. The timing of that is in early 2026. I believe that covered the Golfinho questions, and then we might jump over to Kudu. There was a question about seismic that we had acquired seismic, and the question was whether we had analyzed any of that new 2D seismic, and if we could give the audience some flair about that outcome. Well, I. Maybe you, Lin, take that one. Okay. Yes, we have acquired additional 2D seismic lines. These were already existing lines in the region. We've acquired them. Yes, we are doing our interpretation of them. Other than, I will just highlight, reiterate what Carl mentioned earlier, we like the region that we're in. It's exciting that Shell and TotalEnergies have made these discoveries outboard of us and we are evaluating the potential of what that means, that shallower oil play Campanian means for the Kudu block. It's all very interesting at this stage. Then a follow-up question to Kudu, do you have a rough estimate of what a development of Kudu will cost? Do you expect to do the development alone or together with a partner, for example, in a major nearby field? I presume that is related to the gas to power project that we are currently discussing with stakeholders in Namibia. It's a little bit. It depends what you include in the project and how you put together the ownership structure. You have basically a field development site, which is three wells. You have a main production asset, which we have already acquired, a semi-submersible unit for a very reasonable price that we intend to use for that purpose. You have the pipeline to the beach, and then you have the power station. All in, everything is, let's say, of the order of $1.5 billion. The ownership structure of each of these elements is, of course, something we are currently looking at and where we are obviously see great potential to take partners is in something like the power station where there is an established, let's say, system and established players that are keen to own power stations and operate power stations in this part of the world. It's a bit tricky to say, you know, exactly how we will end up putting this together because that's really what we are looking at and discussing with potential partners and the government right now. As a follow-up, final question to Kudu, whether we can say anything about the gas pricing, which I assume is more the price of electricity. Yes. That is the case. We will be able to deliver electricity at a, let's say, a competitive price point to Namibia. It will be very competitive compared to new power for the region. It will be okay for existing power, coal-based existing power. We fully expect Namibia to be thinking about the future and the environmental footprint of their power provision. We believe we have a very competitive power price. Good. Then we have a, let's say, more technical accounting question to revenues. We did not have any liftings, but we're still showing revenues. As we've said in the past, we have the domestic market obligations where we sell, we buy and sell oil. We sold oil for $3.6 million in the Q2 that we bought for $3.8 million. That comes at a small loss on our domestic market obligation. We have the state profit oil that also comes in as both on revenue line and taxes. We have $10 million of that. We had some adjustments because of hedges that also goes into the revenue line. The $4 million loss reduces revenues, and there are some other smaller items as well. We can go to Gabon and Dussafu. There's a question here, when roughly would you expect to start drilling on Hibiscus Ruche Phase Two? I'll take that. As you saw, we had sail away for the production facility, and that's gonna arrive end of next month. Shortly thereafter we'll do the pipeline tie-in to the FPSO and to the new production facility, new name, BW MaBoMo. We'll be ready for the rig to drill the wells. Now the rig that we have contracted is being used by offset operator, and when they finish it, we'll take over. Right now, that's scheduled takeover at the year-end. We'll need a couple of months to drill the well and tie it up. It looks like March, mid-March-ish or so, give or take, for first oil. We're all very excited about it. Good. Then there is a question, so are you looking at assets on the Norwegian Continental Shelf? What we could say is that that's not exactly in our expertise or in our strategy. I'm leaving it there. We're not speculating in M&A activities. Then there are more Golfinho questions coming, but let's see if I can. Yeah. There is one question about the RBL, whether that comes with hedging requirements, and if so, what are they? Yes, they are. All RBLs come with hedging requirements, and our requirements are 40% for year one production and 25% for year two on the production forecast in the banking case, which is a somewhat more conservative forecast than what we have ourselves. I think we are at a Maromba question. When do you expect to secure a drilling rig for Maromba? How sensitive is the project economics to higher rig rates? I think we're a little ways out before we secure the drilling rig. Costs have gone up for drilling services and drilling rigs. As we previously said, though, the Maromba project is very attractive at $50 oil price. That's when we originally bought it and scoped it out. Now we are, as Carl mentioned, seeing some inflation. The 10%-20% we probably expect to see that on the drilling rig services at least. Yet we've also experienced quite a bit of inflation on the oil price as well. It's always gonna be important for us to, when we embark on these new developments, that they are robust at these lower oil price scenarios, and we're gonna continue to do that as well. Excellent. If we're coming to the final questions, there are a couple more on Golfinho, as I said. When do you expect Golfinho reserves to depleted or decommissioned? What is the production timeline and associated decline rate? I think we saw that in the presentation, the graphs on the, let's say, existing production. It's losing about 1,000 barrels per year in the shorter term. In the longer term, maybe you could comment, Carl or Lin. Yeah, I can comment on that. Existing reserves between existing and planned reserves, I believe it's between 30 and 40 million barrels. That's gonna take us out, you know, five to 10 years or so timeframe. You know, that's excluding the gas developments. Once we get the gas developments that come online, that's gonna push it on, beyond that. Then on top of that, we think it's a very oily and gassy area. We like the region. It's a huge amount of acreage. If you add the gas and other further development, you know, it's gonna exceed this beyond 20 years, hopefully. Thanks, Lin. We have the final question. Can you give a bit more color on the remediation work that is being done on Golfinho? Are there risks around this getting done properly? Current remediation work, I take it, that the field is shut in. Is that correct, you think? Yes. Is that the nature of the question, Kenneth? Yeah. I guess so. Okay. Well, we have a high confidence that Petrobras will be conducting this work in a professional manner. You know, we have a interface team. We have a steering committee working together. We have our folks periodically inspecting the activities on the rig. The nature of the work that's being conducted, I don't think we're at all concerned about. We have a lot of skill sets in the organization that have a lot of FPSO experience. The nature of the work, we're quite confident that it's gonna be done properly. Yeah. It's readily inspectable. It's above the waterline. Correct. Absolutely. Very good. That concludes the questions on the web. I'll leave it for you, Carl, to close. Well, I think, thank you for all the good questions. It's always nice that people pay attention, and please keep questions coming. We will obviously answer questions offline as well if you have further questions. I thank everybody for listening in and participating in this presentation. Thank you. This concludes today's conference call. You may now disconnect.