Good day, everyone. Welcome to Kosmos Energy's second quarter 2021 conference call. Just a reminder, today's call is being recorded. At this time, let me turn the call over to Jamie Buckland, Vice President of Investor Relations at Kosmos Energy. Thank you, operator, and thanks to everyone for joining us today. This morning, we issued our second quarter earnings release. The release and the slide presentation to accompany today's call are available on the investors page of our website. Joining me on the call today to go through the materials are Andy Inglis, Chairman and CEO, and Neal Shah, CFO. During today's presentation, we will make forward-looking statements that refer to our estimates, plans, and expectations. Actual results and outcomes could differ materially due to factors that we note in this presentation and in our U.K. and SEC filings. Please refer to our annual report, stock exchange announcement, and SEC filings for more details. These documents are available on our website. At this time, I will turn the call over to Andy. Thanks, Jamie, good morning and afternoon to everyone. Thank you for joining us today for our second quarter results call. I'll run through the highlights for the quarter before handing over to Neal to take you through the financials and guidance for the remainder of the year. Starting on slide two. Kosmos continued to successfully execute our plans in the second quarter, delivering on the three key priorities outlined on the slide. First, we posted strong cash performance in 2Q, with free cash flow of $150 million in the quarter. We expect this strong performance to continue in the second half of the year as production increases with new wells coming online. As previously communicated, we target a year-end exit rate of around 60,000 barrels of oil equivalent per day and are making good progress towards that target. We expect leverage to fall significantly by year-end and continue to reduce through 2022 at current prices. Second, we continue to strengthen our financial position in the quarter. We announced today the completion of the FPSO sale and leaseback transaction for the Greater Tortue Ahmeyim project, an important step in funding our remaining capital to first gas. The transaction will fund our outstanding capital requirements on the project through 2021 and partially into 2022, with additional savings from the transfer of future FPSO milestone payments to BP. In May this year, we successfully completed an amendment and extension of our reserve-based lending facility, which pushed out any material near-term debt maturities to 2024 and beyond. Third, we remain on track with our operational delivery for the year. 2021 has been an active year so far for Kosmos, with momentum building across all areas of the portfolio. We plan to drill nine infill wells this year and are starting to see new wells come online, which is having a positive impact on production levels. One example is the first Jubilee producer well that came online in July and has added around 10,000 barrels per day of incremental gross oil production. We look forward to more wells coming online in the third quarter, which should further drive production levels towards our targeted year-end exit rate. In Mauritania and Senegal, all key work streams on the GTA project have made good progress, with first gas expected in the third quarter of 2023. In the Gulf of Mexico, we expect to drill a Winterfell appraisal well later this quarter. Turning to slide three. As mentioned on the previous slide, Kosmos delivered strong cash performance this second quarter, with around $115 million of free cash flow for the company. Free cash flow generated from the base business for the first half of the year was around $125 million. That excludes CapEx related to Mauritania and Senegal and includes a slight working capital benefit. This second quarter cash generation allowed us to reduce net debt by around $100 million by quarter end. As shown on the top chart on this slide, our leverage ratio has fallen sharply since year-end 2020 should continue to do so going forward. Higher oil prices are driving higher EBITDAX, with 2Q 2021 EBITDAX over 3x higher than the same quarter last year. This, along with our growing production and absolute debt reduction, are positively impacting our leverage ratio, and we look forward to further progress through year-end and into 2022. As I previously mentioned, we're pleased to have completed the Greater Tortue Ahmeyim FPSO sale and leaseback transaction, which is expected to fund our remaining GTA capital through 2021, with additional savings coming in 2022. At the beginning of the year, we talked about 2021 capital expenditures for Mauritania and Senegal net to Kosmos of around $350 million. The FPSO financing is now expected to cover around $160 million. This is slightly less than previously expected given the short delay in closing the FPSO transaction, but we expect to see additional savings in 2022 as a result. An additional $100 million benefit in 2021 is expected from the NOC loan refinancing that we aim to complete in the fourth quarter of the year. This leaves around $90 million of 2021 Mauritania and Senegal CapEx for Kosmos to fund in 2021, which occurred in the first half of the year. In May, we completed an amendment extension of the reserve-based lending facility, and I'd like to thank our banking group for their continued support. The facility, which is a total size of $1.25 billion, was $1 billion drawn at the end of the second quarter. Importantly, the extension pushed out maturities by another two years, meaning that we have no material maturities until 2024 and beyond. Turning now to slide four. At the first quarter results in May, I talked about momentum returning to the business with activity starting to ramp up across the portfolio. I'm pleased to say this momentum has continued to build through the second quarter. We remain on track to achieve our objectives. We've seen drilling across our three production hubs and continued progress with our GTA project in Mauritania and Senegal. Taking each hub in turn. In Ghana, as I mentioned, we're starting to see positive results from this year's drilling campaign with the Jubilee J56 producer now online. Production at Jubilee is now around 80,000 barrels of oil per day, up from around 70,000 barrels in the first half of the year. The second well, a Jubilee water injector, should come online shortly and further enhance production. The rig will move to drill a gas injector on TEN, which is expected online in the fourth quarter. The partnership plans to drill a second Jubilee producer that is expected online around the end of the year, with further production increases expected as we move into 2022. In Equatorial Guinea at the Ceiba field, a major infrastructure integrity project has been completed, which is expected to improve reliability and allow greater flexibility for gas lift to additional wells. The Okume upgrade project is expected to be completed in the fourth quarter, adding additional power, water injection, and gas lift capacity necessary for further facilities debottlenecking and additional electrical submersible pumps or ESPs. In April 2021, one ESP conversion was completed, with further ESPs expected post-completion of the upgrade project. The first of three infill wells spudded in June with positive initial results. The rig will now move to the second well location, and hookup has commenced for the first well. All three wells to be drilled in the Okume complex are expected to be online in the fourth quarter of 2021. In the Gulf of Mexico, the Tornado 5 producer well was drilled in the second quarter and came online in July, and is currently producing at the top end of the operator's 8,000-10,000 barrels of oil equivalent per day guidance. Later this quarter, we're planning to drill the Winterfell appraisal well. In Mauritania and Senegal, the partnership continued to make progress across all the major work streams during the quarter. As we noted in the release, the nearshore terminal has started to take shape, with three concrete caissons now installed and several more in transit. The critical path to delivery of first gas now sits with the FPSO, which is being built by Technip Energies at the COSCO yard in China. We're working diligently with BP to ensure that the revised timeline to first gas is delivered. I'll now hand over to Neal to take you through the financials. Thanks, Andy. Turning to slide five. As Andy said, the second quarter posted a strong cash performance on the back of higher sales volumes, which saw a reversal of the underlift position in the first quarter, together with improving realized oil price. I don't plan to focus on every line on this slide, but instead walk through a handful of key items. While Ghana continued to deliver solid performance, net entitlement production fell slightly quarter on quarter, mainly due to lower than expected production in the EG and the Gulf of Mexico. Both areas were affected by more downtime than expected, as we indicated in our July operational update, with EG also impacted by higher prices, reducing our entitlement production under our PSC. Realized price per barrel post-hedges was around 20% higher quarter-on-quarter, reflecting higher oil prices and some hedges rolling off during 2Q, which will continue during the third and fourth quarters. OpEx per barrel rose due to slightly lower production and also due to production mix with the TEN cargo sold in the second quarter, which has a higher OpEx per barrel, largely responsible for the quarter-on-quarter move. Net interest was $39 million, up $39 million was higher than the first quarter. As indicated in May, 2Q includes $15 million of one-time costs associated with the extinguishment of debt when we completed the RBL amendment and extension. Lastly, base business CapEx increased quarter-on-quarter as we began our drilling activity in Ghana and Equatorial Guinea in the second quarter. Turning to slide six. This slide looks at our guidance for the third quarter and for the full year. Full year production guidance remains unchanged, with production expected to trend higher through the second half as new wells come online in Ghana, EG, and the Gulf of Mexico. From a sales perspective, we expect to lift one cargo in Ghana during the third quarter and half a cargo in EG, which will lead to an underlift in the quarter similar to the first quarter, which should reverse in the fourth quarter as it did in the second quarter. OPEX guidance for the third quarter is expected to be between $15 and $17 per barrel. We are increasing our OPEX guidance for the year by around $1 per barrel due to some higher costs we've seen across the portfolio so far this year. Base business CapEx remains the same, but as Andy flagged in his earlier remarks, we now expect around $90 million of capital for GTA to be funded in 2021. That concludes today's presentation. I'd now like to turn the call over to the operator to open the session for any questions. Thank you. Our first question comes from the line of Nick Stefanou with RenCap. Please proceed with your question. Hi gentlemen, it's Nick Stefanou from RenCap. Thank you for taking my questions. I've got two to ask, if I may. Andy, the first one I think is for you. The LNG market has bounded back strongly in the past few months. I was just wondering, are you maybe considering maybe a farm down, maybe like resurrect, like a farm down in any part of the Mauritania, Senegal assets there? Is this something that will make sense? The second question is for Neal. It's on the hedging policy. These three-way collers, the good thing about them is that they're pretty much free because they don't pay much premium. They don't really protect if there is way too much volatility. They don't give you much of the upside. They only protect when there's sort of downside. If you think about it, the reason we're doing the schedules will be to protect against volatility. Are you thinking of maybe changing the way you do the schedules going forward? Thank you. Thanks, Nick. Why don't I take your first question? I think we're pleased with the progress on GTA. I think the step that we announced today on getting the FPSO financing has been an important step forward. Clearly the next thing for us to work on is the NOC financing. We can see a direct path now to get to first gas. I think as you look at the scale of the resource that we have in Mauritania and Senegal, more than 100 TCF of gas in place across the whole of the trend through Mauritania into Senegal. There's clearly more there than Kosmos can ever develop at its working interest today. I think the focus is on GTA and ensuring that we deliver the project on time, on budget, that we deliver the cash flow from the project. Actually, the important part about phase two is that it's currently not priced. I think the opportunity to FID that project and get the benefit from a much stronger LNG environment is part of the overall plan. I think you're going to see us in terms of lightening the opportunity in Mauritania and Senegal. It is about how do we look at some of the more longer-dated opportunities and advance the cash flow from there. I think that's our real push in Mauritania and Senegal, is how do we bring forward the cash flows from the portfolio we have there? I think that will focus therefore on the things where the development plans are less well developed, and we can't see a direct line to the cash flow. I think that's going to be our focus, and I think it's no different from the strategy that we outlined to you in the past. I think if I hand over to Neal now and he can talk about the hedging strategy. Hey. Good morning, Nick. Yeah, as your question on hedging, I think for us, we have used a variety of structures within the hedging portfolio, and I think we'll continue to do that going forward because I agree, I think a portfolio of 100% three-way collars doesn't provide sort of both the equity, debt, and the business sufficient downside protection. We have looked at balancing what's the right balance to manage the downside protection, but also the cost and retaining as much upside potential as possible. There's a couple of things that we're trying to balance. Again, clearly we can get a higher floor with the lower cost with the three ways, but the two ways provide sort of absolute protection. When you look at the portfolio today, particularly in 2022, it's about sort of a 50/50 mix between those two structures. I think that general shape is something we're comfortable where we can manage the cost of the overall hedging portfolio, but at the same time put in protection mostly around the area where it's needed between that sort of $60-$40 range. Okay. Thank you. Thank you. Our next question comes from the line of James Carmichael with Berenberg. Please proceed with your question. Hi, a couple from me. First, on the deleveraging chart on slide three, obviously, it says that current oil prices are moving around a fair bit at the minute. I just wondered if you could be specific about the assumptions in that chart and perhaps provide some sensitivities. A couple on the U.S., I guess first on Kodiak should be helpful. Just to get a bit of color around issues in that well, and perhaps any early indications on the timeline to finding a solution. On Winterfell appraisal, perhaps you could remind us of any sort of key risks around that deeper M4 reservoir you're testing and put the well in context in terms of that de-risking the sort of 100 million barrel potential you talked about in the area. Thanks. All right. Thanks, James. I'll pick up the U.S. questions. Neal, do you just want to cover the deleveraging? Just on the chart, just to answer your question, James, the charts have been generated based on sort of a $65-$70 deck, which again, I think is still pretty down the fairway in terms of current oil prices. There is clearly some movement in there, and there's a number of assumptions within that, which is why we've sort of faded the chart. I think the reality is anywhere sort of in the ballpark, regardless of say, sort of negative movement in the oil price, the business generates a lot of cash. Clearly, we're hedged, particularly in the short, more so in 2021. The price movement in the prompt has less an impact on that deleveraging profile. We got more access to that upside in 2022, whereas higher prices will help de-lever the business faster. Thanks, Neal. James, in terms of the U.S., we've clearly seen stronger production from Tornado than we anticipated. So we're pleased with that well. Kodiak has not performed where we had anticipated. And we're currently reviewing ways in which we can intervene on the well. If I would sort of give you our best view of that, I think it's probably going to be around year-end into next year before we can secure the equipment that we need to actually do that. So I think as you look at the Gulf of Mexico, the good news is that the strong performance from Tornado is more than offsetting the Kodiak well. So there isn't a net negative from that. And we clearly would see in 2022 the upside from getting the Kodiak well back online. On Winterfell, we're testing the adjacent fault block to the north. We're testing a similar horizon that was successful on the discovery well, and we're also deepening it. The deepening would be an upside from the well. The real test is to demonstrate the adjacent fault block in the same reservoir. It's got the same horizon. It's got the same seismic signature. That actually creates the sufficient volume, I think, for an initial development. I think we now need to see the results of that appraisal well to decide, is that the basis on which we move forward with incremental appraisal thereafter to do a phase development? Is there another step in the appraisal program, and if results were encouraging, whereby you had a larger initial starting development. I think it's all positive, and I think there's lots of optionality on Winterfell to phase the development and also increase its scale. We'll be obviously interested to see the results of that well, and then the discussions that would ensue with partners. Okay. Thanks. Okay. Okay. Thanks. Thank you. Our next question comes from the line of Mark Wilson with Jefferies. Please proceed with your question. Hi. Good morning, gentlemen. A few housekeeping points first. On the sale and lease back of the GTA FPSO, congratulations for getting that done, firstly. Can I check the overall financing inflow you should expect for that across 2021 and 2022, please? Second point is, in terms of a go-forward OpEx level for the group, let's say, producing at a 60,000 level through 2022, what should we be looking at there? Finally, GTA once on stream, what sort of OpEx should we be factoring in there to include the FPSO lease back as well? Those are the three housekeeping points. Thanks. Okay. Neal, do you want to Yeah. So just on those questions, and good morning, Mark. On the first question, just in terms of the FPSO transaction, I think what you'll see is basically through the rest of this year, post August, we will show no more sort of CapEx related to Mauritania Senegal until sort of the past costs are recovered. Basically, on day one, we record a receivable from BP for the inception to date cost. We'll also record sort of the corresponding liability to deliver the FPSO to BP after construction. The CapEx for Tortue gets offset against that receivable until it's exhausted. Nothing shows up on the cash flow statement until the first half of 2022. Beyond that, you'll see the CapEx related to Tortue. That excludes the portion related to the FPSO start back to flow through to the income statement. We'd expect around a benefit of around $200 million in terms of overall savings in the 2022 timeframe, in addition to the $160 in 2021. Does that make sense? No, that's exactly what I was looking for. That's great, Neal. Yeah, thanks. The second two points was, OpEx has ticked up. What would we expect that to be if we could maintain a 60,000 level and then the Tortue OpEx once on stream? Yeah. We've raised the midpoint of the guidance to around $1,650 per barrel. I think we do have the ability to bring that down $1, $2 per barrel as we manage the costs within the portfolio. Actually, the production is higher by, call it 5% or 10%. You will see that sort of rationalize back towards the mid-teen as you have both those specs coming through in terms of higher production and lower costs. As for Tortue, we haven't given explicit OpEx guidance post the FPSO. I'd like to come back to you on that a bit later, if that's okay. Okay. No, that's fine then. Neal, working capital is quite a moving feast this year. Been very positive in the second quarter, you had a very strong quarter for sales productions. Q3, certainly from your cargo, looked to be quite a low sales quarter. Should we see or expect a negative working capital effect in association with that in Q3? Yeah, Mark. That's a very good question. The biggest driver around our working capital timings is ultimately cargoes, which again, is just a function of the lifting schedules that are in each of the contracts. We did get a benefit in 2Q as a result of the increased cargo liftings. That reverses in 3Q, so you will see a draw on working capital. You'll likely see a draw in the third quarter, which reverses in the fourth quarter. There is sort of the unfortunate lumpiness due to the oil price and the cargo sizing. It does even out over the year. Okay. One last point, this is more a broader one that just struck me as we were thinking about this. I was just wondering why it is the FPSO is fit for this sale and lease back scenario and an FLNG vessel may not be, or maybe it is. What's the difference there? Actually, it'll be treated similar to the FLNG. The FLNG, we just started as a lease project. Golar is the operator, and they lease it to the JV. This had started as a piece of equipment within the partnership that we're switching to a lease arrangement. Now it'll be accounted for similar, basically the same as the FLNG will be as sort of OpEx in the future. Now you mention it makes complete sense. Okay, thank you very much. I'll hand it over. Great. Thanks, Mark. Thank you. Ladies and gentlemen, as a reminder, if you'd like to join the question queue, please press star one on your telephone keypad. Our next question comes from line of Neil Mehta with Goldman Sachs. Please proceed with your question. Hi. Good morning. This is Carly on for Neil Mehta. Thanks for taking the questions. Just wanted to start on the cost side. I know you mentioned the higher OpEx guide. Can you just talk about the drivers there? Is that inflation driven or are there other factors at play? I guess, what are you looking at to potentially manage costs going forward? Yeah. Carly, maybe I'll talk about that, and then Neal can also chime in. I think the quarter was a little unusual because you get variability in the costs because of the nature of where the liftings have occurred. There was a TEN cargo in 2Q, so it actually comes with a higher OpEx per barrel. There's a lease cost associated with the FPSO there, so it's naturally higher. We have that variation in the quarter. We also had sort of strong production in Tornado. Tornado's PPHA actually has a price factor associated with it. We obviously got the benefit of the higher prices, but we also saw a slight rise in the PPHA. Obviously, if prices persist at the current levels, that would continue. I think underlying, I'd say, there's a small sort of what I would call underlying structural element to it. That's ultimately just about the challenges of getting things done in the COVID world. We have continuation of some of the COVID measures now as a result of Delta. I think we're getting much smarter about how we manage those and how we reduce the cost by using more sophisticated protocols. I'm less worried about that. I think the thing that you should sort of look at is just the quarter had a couple of one-offs associated with it, which in particular, the TEN cargo. Great. That's really helpful. Thanks. The follow-up is just on Tortue financing. The release mentioned you guys expect to complete the refinancing of the NOC loans later this year. Could you just talk a little about what's left outstanding in that process, and if there are any milestones that we should be watching for? Yeah. Why don't I'll have Neal pick that up, Carly? Hi, Carly. The main thing that we're waiting on for the NOC financing was really the completion of the FPSO, because obviously, it sort of shapes the cash flows of the project. We've had some initial conversations with the banks, and we'll push that now. We have sort of defined structure around the FPSO. Our best view on sort of timing is to get that done in the fourth quarter, which gives us plenty of time to go execute it. Yes, I'd say, Carly, we're just sort of moving. We're executing on what we said we would do. The most important step was to get the FPSO financing done. We've done that. We've got the NOCs on board with that, so we have alignment with all of the parties. With that in place, we can then move to the next item, which is the refinancing of the NOC loan. I think everything's going along as we anticipated. Great. Appreciate that color. Great. Thanks. Thank you. Ladies and gentlemen, since there are no further questions at this time, I would like to bring the call to a close. Thank you to everyone joining today. You may disconnect your lines at this time. Thank you for your participation.