Good day, everyone. Welcome to Kosmos Energy's second quarter 2022 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. This 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 and 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 we note in this presentation and in our UK 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, and good morning and afternoon to everyone. Thank you for joining us today for our second quarter results call. I'd like to start today's presentation looking at the operational delivery in the quarter. I'll then hand over to Neil to talk through the financials before I wrap up today's presentation. We'll then open up the call for Q&A. Turning to slide three. 2Q was another quarter of strong execution for Kosmos, as highlighted by the boxes on this slide. Our production assets are performing well, with production for the quarter at the upper end of guidance. Our three development projects, Tortue phase I, Jubilee South East, and Winterfell, are continuing to make good progress and are expected to deliver production growth of around 50% by 2024. We continue to optimize our world-class gas portfolio in Mauritania and Senegal, working closely with partners and the governments to accelerate and deliver value from our significant discovered resource. Today, Kosmos announced its plan to utilize existing contractual rights in the sales agreement for GTA phase I volumes to divert cargos to prospective buyers in order to benefit from the current market environment. More on that in a moment. Finally, the balance sheet continues to improve as the portfolio generates cash and drives down leverage, all while supporting our differentiated growth. We'll dig into each of these themes later in today's presentation. Turning to slide four, which looks at our producing assets, which are performing well with 2Q production coming in at the upper end of guidance. In Ghana, the Jubilee field continues to deliver. Gross production for the quarter, excluding the impact of the shutdown, was around 92,000 bpd. Including this impact, gross production was around 74,000 bpd. In May, the partnership completed the planned two-week shutdown, achieving our key objectives, which included important maintenance and the tie-ins for the risers for the Jubilee South East development. Following the shutdown, gross production has averaged over 90,000 bpd, benefiting from the producer well and the injector well completed and tied in during the quarter. As the operator recently communicated, the Ghana drilling performance has been excellent, with the wells coming in ahead of schedule and under budget. The partnership will now focus on managing the performance and reliability of the field until the Jubilee South East wells come online, which is scheduled for mid-next year. These wells should drive the next step-up in production towards a 100,000 bpd field target. At 10, gross production of around 24,000 bpd was in line with expectations. One producer well is currently being drilled at Enyenra, with production for that well expected in the fourth quarter. As the operator highlighted in its recent trading update, the partnership has been performing a review of the 10 resource development opportunity. We believe there remains a significant amount of undeveloped oil and gas, and we are evaluating the optimal path to bring these resources online over the coming years. As part of that optimization plan, we had two riser-based wells planned at 10 this year to support the delineation of the Ntomme resource. In July, the partnership drilled the first of the two riser-based wells. The NT10 well was drilled to test two separate reservoir objectives, with the reservoir quality and thickness better than expectations, but the well encountered water. The well was drilled in a structural low to test the boundary conditions for the end zone resource modeling. The second riser-based well, NT11, is planned for late 2022, targeting a different fairway in a structurally higher setting. The results of the two wells should allow us to high-grade and optimize the future drilling plans for the TEN enhancement project. In Equatorial Guinea, gross production of around 31,300 bpd was in line with expectations, but sequentially lower quarter-over-quarter due to higher facility downtime and certain wells being offline for workover activity. We have two ESP installations planned this year, with the first completed during the quarter. As we flagged in May, the partnership extended licenses of both Ceiba and Okume to 2040, extending our 2P reserves base by around six million barrels, which creates an incremental NPV10 of around $100 million at a $75 per barrel oil price. With the extension, the partnership has committed to drill a package of four infill and ILX wells. A rig has been selected, and we expect to begin that work in the second half of 2023. In the Gulf of Mexico, net production of 20,600 barrels of oil equivalent per day was above expectations and around 10% higher than the previous quarter due to less downtime of third-party facilities in the second quarter. The HP-1 vessel, which processed production from the Tornado field, had been scheduled for a routine dry dock in late 2Q. This has now been deferred to the third quarter, so we expect there will be downtime of around 45 days related to Tornado in 3Q. Full year production guidance remains unchanged. The Kodiak sidetrack has now been drilled with completion activities ongoing. Drilling results of the well are in line with our expectations, and initial production is expected later this quarter. Also on Kodiak, we completed the preemption transaction in June to acquire an additional 6% interest, taking our total interest to around 35%. The new sidetrack well, combined with our larger working interest, should increase our net production in the Gulf of Mexico by approximately 3,000 barrels of oil equivalent per day after the Kodiak sidetrack comes online. Finally, at the end of the second quarter, we sanctioned a new subsea pump project at the Odd Job field, which should both accelerate production and also increase recoverable reserves by extending the economic life of the field. A great investment which we expect to have a very short payback, particularly in a higher price oil environment. Turning now to slide five. We've talked in previous presentations of growing production by around 50% by 2024. This slide has a status update of the three key developments that we expect will drive that growth. First, Tortue phase I, our LNG project in Mauritania and Senegal. All work streams continue to make good progress with the project over 80% complete at the end of the second quarter. On the hub terminal, all 21 concrete caissons have now been installed, an important milestone for the project. Piling installation is on schedule and nearing completion, with the construction of the living quarters platform complete and in transit to the site. On the floating LNG vessel, which is being constructed in Singapore, construction mechanical completion activities continue and commissioning works have commenced. On the FPSO, which is being constructed at the COSCO yard in Qidong in China, mechanical completion loop checking activities continue and were approximately 50% complete at the end of the second quarter. BP's working hard to mitigate the impact of the April lockdown at the COSCO yard and the ongoing COVID disruptions in China, while ensuring the FPSO leaves the yard with a targeted high level of completion. However, the operator has not been able to fully mitigate these impacts, and we now expect the FPSO sail away to slip from end September into the fourth quarter. Despite this later sail away date, the partnership is working to maintain the overall project timeline to first gas by optimizing the sequencing of the hookup activities. On the subsea, the installation of the subsea pipeline began the second quarter, with a second pipeline vessel expected to arrive later this year to begin the deep water portion of the pipe lay. There have been quality issues with the fabrication of some of the subsea equipment, which will require repair. We don't currently anticipate this to impact the overall project timeline. Finally, on drilling, we've successfully drilled two of the four wells required for first gas. The third well is in progress. Even with the supply chain challenges, we continue to make good progress quarterly and are still targeting first gas in the third quarter of 2023, with the first LNG cargo targeted for year-end 2023. On Jubilee South East, the project's approximately 40% complete, with long lead items ordered and the drilling on track to commence in the fourth quarter. As I mentioned earlier in the presentation, work was done during the Jubilee FPSO shutdown to allow the tie-in of these wells. Initial production is targeted for the middle of 2023, with the new wells expected to increase total Jubilee field production to over 100,000 bpd. At Winterfell, the field development plan has been submitted to the partnership, and formal FID is expected by the end of the third quarter. Based on the additional technical work we completed on the initial wells, we now believe the total resource is significantly larger than previous estimates, with up to 200 million barrels of gross recoverable resource. I'll talk more about the development plan on slide six. As we've described in the past, we plan to develop Winterfell as a phased subsea tieback project. The first phase, which can be seen on the right side of the slide, is expected to include five wells, three drilled before first oil, targeting around 100 million barrels of gross recoverable resource. Based on the pressure work from the discovery wells, we now believe the total resource could be around double the original 100 million barrel estimate, which we expect to prove up as we drill and produce the phase I wells. Winterfell is already well advanced, with long lead items ordered and a rig selected to drill and complete the first wells next year. The partners have received the field development plan from the operator, and we expect FID approval by the end of the third quarter. This low cost, lower carbon oil development is expected to have strong economics. Development costs are expected to be around $10 per barrel, with operating costs around $12.50 per barrel, delivering a break-even of less than $25 per barrel. First oil is expected around 18 months from FID approval. Turning to slide seven. Over the last two slides, I've discussed the development projects in the portfolio that we expect to drive production growth around 50% over the next two years. This slide looks at the deep hopper of opportunities in Mauritania and Senegal that we expect can deliver significant additional value and contribute to a growing gas weighting across the portfolio. First, Tortue phase I. To optimize the commercial value of sales for the gas production from Tortue, Kosmos plans to utilize existing contractual rights under our phase I LNG agreement to divert cargos to prospective buyers in order to benefit from the current market environment. In the gas sales agreement for phase I, we have a deliver or pay contractual right, which allows us to take advantage of elevated global LNG prices for a portion of our phase 1 volumes. By exercising this right and diverting cargos, Kosmos could retain significantly more upside to global gas prices, especially with current gas prices severely dissociated from oil prices. Second, Tortue phase II. As we said last quarter, given the structural changes to the global gas markets we have seen in recent months, we are working with the operator and the government to ensure we have the right development concept for phase II with regard to scope and scale. We are therefore working closely with our partners to optimize the development scheme to best utilize the existing phase I infrastructure to maximize cash flow and returns to the partnership. We also want to manage cost exposure in line with the supply chain constraints and inflationary pressures we are seeing across the industry. A development decision is now planned for the end of the third quarter. Third, on BirAllah, with the expiration of the C-8 license in 2Q, the partnership has agreed the substantial terms and conditions of a new PSC, and the license is awaiting government approval. The new PSC, which retains the area surrounding our successful BirAllah and Orca discoveries, would grant the partnership two years to submit a development plan. As we discussed in the past, the area has future development potential of around 10 million tons of LNG per annum, and we would also plan to develop these resources in phases. As we would have a new PSC carved out from the existing C-8 license, we were required to write off our historical E&A costs from an accounting perspective, although they are still tax-deductible and cost recoverable against our Tortue development. Lastly, at Yakaar-Teranga, the partnership continues to progress the initial phase of the gas development with the government, which centers on a domestic gas solution to provide low-cost gas to support the country's energy needs to drive its rapidly growing economy. I recently visited Senegal and Mauritania to meet with their respective energy ministers and President Sall of Senegal to discuss the future gas opportunities in the region. With both countries, there's an aligned view around what the future could hold for their gas resource development. There is a significant lower carbon advantage gas resource available offshore that could help provide more energy security for the world and Europe in particular. Equally important, given the characteristics of the gas and its lower carbon intensity, this resource could play a significant part in bridging the energy transition and in providing the affordable energy that Mauritania and Senegal rightly demand for their own development, the very embodiment of a just transition. Both governments recognize that we are living in a volatile world as the pandemic and the events in Ukraine have shown, and I believe both countries have the vision to see through this volatility and become important players on the world energy stage in the coming years. As we refine the next phases of our LNG projects, I believe the futures for Mauritania and Senegal are bright. With that, I'll turn the call over to Neil to take you through the financials for the quarter. Thanks, Andy. Turning to slide eight. The second quarter saw continued progress as we further enhanced our financial position. We are taking advantage of higher oil prices to rapidly strengthen our balance sheet with net debt approximately down $400 million in the first half of this year to $2.1 billion. EBITDAX in 2Q was around $385 million, which resulted in free cash flow of around $70 million dollars in the quarter and around $290 million for the first half of the year. Excluding capital expenditures in Mauritania, Senegal, base business free cash flow in the first half of the year was around $450 million, demonstrating the strong cash generation ability of our business before our development projects come online. The solid cash performance and continued net debt reduction helped to drive leverage down to 1.6 times. Liquidity, which has grown consistently over the last year, was over $1 billion at the end of the second quarter, which is the highest it's been since 2018. As we look forward, with expectations that the business continues to generate strong levels of free cash, we plan to continue to prioritize debt paydown, aiming to get beyond our leverage target of less than 1.5 times at year-end and net debt below $2 billion. Turning to slide nine. As Andy mentioned, net production of over 62,000 barrels of oil equivalent per day was at the upper end of guidance, helped in particular by strong performance at Jubilee and less downtime in the Gulf of Mexico. We realized a price of $86 per BOE, including the impact of hedging. Excluding hedging, the realized price was around $109 per BOE. Operating costs were lower than guidance during the quarter, reflecting production coming in at the upper end of guidance and some deferred maintenance activity in Equatorial Guinea. CapEx in the quarter was slightly higher than forecast, primarily a result of higher accrued capital related to activity in Mauritania and Senegal. As many companies in our industry have reported, we are seeing the impact of some inflationary pressures, particularly at the Tortue project in Mauritania and Senegal as we get closer to the finish line. As a result, we are increasing our full-year CapEx guidance by approximately 5% to around $700 million. Although we are seeing some higher costs, we have maintained our free cash flow guidance for 2022 of approximately $420 million, assuming current oil prices offsetting the inflationary cost impacts. To conclude the financial section of today's presentation, it was another good performance in the quarter with continued progress across all key areas. We delivered a strong cash flow performance with rising liquidity, material debt pay down, and a meaningful reduction to leverage. I'll now hand back to Andy to close today's presentation. Thanks, Neal. Turning to slide 10 to wrap up today's results presentation. While the macro environment continues to be volatile, Kosmos has had another solid quarter of operational and financial delivery. Our production assets continue to perform well, coming in at the upper end of guidance. Our three development projects continue to make good progress to drive the 50% growth in production we expect from current levels by 2024. We're working closely with our partners to optimize the value of our gas portfolio that we expect will deliver growth beyond 2024. Our financial position continues to improve with continued strong free cash flow generation. This has enabled liquidity to rise to multi-year highs with leverage falling sharply, well on track to exceed our year-end targets. Finally, we have the right portfolio at the right time, providing the energy the world needs today and supporting a just transition that addresses the trilemma of energy security, energy affordability, and climate change. Thank you. I'd now like to turn the call over to the operator to open the session for questions. Thank you. Ladies and gentlemen, at this time, we will conduct our question-and-answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment, please, while we pull for questions. Our first question comes from Austin Aucoin with Johnson Rice. Please state your question. Good morning, Andy, Neil, and Jamie. Thank you for taking the questions this morning. Yeah. Hey, good morning, Austin. On Tortue phase I, could you help me understand the mechanics of the spot pricing opportunity? Also, does this increase the potential value to Kosmos over the first year or two of the contract? Yeah, sure, Austin. You know, we think there's a differential value in Kosmos versus peers because of the material and growing exposure to international gas. You know, the structural changes in the global gas market on the back of the Ukraine war mean that gas prices are likely to stay higher for longer and, you know, remain dislocated from oil. Now, clearly, we've talked about in the past, our phase I volumes are priced against a Brent slope, so the price we receive is driven by oil prices. However, there is a deliver or pay clause that would allow us to utilize and take advantage of current gas prices in instances where pricing allows us to pay for it by an agreed non-delivery penalty to our current buyer. This is a typical provision in an LNG sales agreement. You know, we can't share with you the exact details of the contract, but of contracts of this era, the penalty is typically in the range of 20%-30% of the contractual price, the price that's linked to the Brent slope. If you take those inputs and you look at an average gas price, let's say, for 2024 and 2025 of around $20 and an oil price of, let's say, $100 per barrel, the opportunity could be around $200 million of additional revenue net to Kosmos, you know, in total over those two years. You know, if you look out at the forward strip and you look to where that's sitting today, you know, TTF is closer to an average of 25 over the 2024/2025 time period. You know, with those assumptions, the revenue benefit to Kosmos in aggregate over the two years would be around $350 million. It's a significant opportunity for us and, you know, we believe it's important to start engagement with prospective buyers now because the opportunity is clearly there. Well, I appreciate the color on that. As a follow-up, you provided a positive update on your Winterfell project with FID approval expected later this quarter and doubling the expected gross recoverable resources. Did the recent technical work from the initial two wells cause any modifications to your development plan/timeline of this project? No, it hasn't, Austin. I think, you know, we're targeting FID at the end of this quarter. That, you know, we see first oil, you know, 18 months afterwards. Clearly, it's the technical work from the first two wells, which we believe has indicated a significantly larger resource. The first phase is a five-well development, as I said in my remarks. That's targeting development of the initial 100 million barrel opportunity. But we think with production data from those initial wells, we would see that being the indicator of a larger resource. Clearly, the infrastructure that we're putting in would enable us then to build and expand to fully access that. I think the work we've been doing over the quarter to get to FID is around that phase I, three initial wells pre first oil, followed by two follow-up wells. You know, we're anticipating a larger resource, and therefore the ability to expand from there. I appreciate the color. That's all from me. Great. Thanks, Austin. Our next question comes from Neil Mehta with Goldman Sachs. Please state your question. Hey, good morning. This is Carly on for Neil. Thanks for taking the time. Wanted to just start on Tortue. As we think about the potential for phase II, could you talk a little bit about what are the outstanding gating factors as we should be keeping in mind to get that project to FID? Are there any changes to the timeline to expected first gas there? Yeah. Hi, Carly. No, I think that, you know, we've taken the time to make sure that we've got the right project for phase II, both in terms of the sort of scale and scope of the project. You know, a lot's happened in the last six months with regard to the LNG market, in particular the European market. It's important that we've got, you know, the right project that enables us to, you know, fully access that opportunity. We also need to make sure that from a contracting perspective at a time of real inflationary pressures, we've got the right approach to the market. The development concept that we pursue is clearly an important part of that. That's been the work that we're doing at the moment. The objective is to come to a decision on that concept by the end of the third quarter. That will then enable us to do the detail work, the feed work to get to the cost in Mauritania and Senegal to get formal approval of, which is, you know, FID. We have to go to the governments with the, you know, the full contractual position, the full cost, et cetera. The anticipation would be that we will do that in 2023. You know, that leads you to a, you know, a first gas date in the sort of end-2026, 2027 timeframe. No fundamental change to that. I think it's ultimately about have we got the concept which allows us to best take advantage of the current market conditions and allows us to, you know, ensure that we've got the optimum scope from managing the inflationary pressures which are clearly in the market today. Got it. That's helpful. The follow-up was just kind of on your last point on inflation. As you're pursuing these different development projects across the portfolio, can you just flesh out a little bit kind of what you're seeing from an inflation perspective and what steps that you're taking to mitigate those pressures? It's clear that we're seeing in the deep water now, you know, supply chain challenges really across all dimensions, you know, whether it's sort of drilling rigs being sort of at a high level of utilization, subsea equipment, installation vessels, et cetera. I think the mitigations are around doing the work up front to ensure that you've got a concept and an approach to the contracting strategy, which allows us to get to the, you know, the most cost-effective approach. I think that's a clear, you know, part of the work that we've been doing on Winterfell. You know, again, as an example on Winterfell, without, you know, getting ahead of our skis, you know, we have been, you know, ordering the long lead items. We've moved ahead to select a rig. We've done that, you know, for the program in Equatorial Guinea. You know, access to the right equipment is clearly important. I think these are all tried and tested techniques, you know, that the industry has used. I think for us it's about being rigorous now about the management of this, you know, literally on a day-by-day basis. You know, no increase in scope. Don't allow the projects to have any gold plating. It's about the rigor of execution, right approaches to the market, access to the best equipment, et cetera. I think that is the other challenge the industry has today. It's not only an equipment issue, but it's also a human issue. You know, getting access to, you know, the A teams. I think those are all of the areas we're focused on. From a Kosmos perspective, you know, we have three projects. We're clear where we stand on each of those projects, and now it's the rigor and discipline of managing them through to first production. Great. Thanks for that color. Our next question comes from Matt Smith with Bank of America. Please go ahead. Hey, thanks, guys. First couple of questions are just around the LNG pricing, if I could. Could I just double-check on the phase I volumes, does that contractual right apply to 100% of your entitlement of the phase I volumes? And then the second question on the same topic was really around sort of phase II and the contracting opportunity there. You know, I guess each time we talk about this, the gas keeps moving higher and higher. Is it fair to characterize that you're more likely to look for gas exposure for the phase II volumes? And if so, is that likely to be through pure spot pricing, or do you think there's perhaps a happy medium in between? Yeah. Thanks, Matt. Yeah, actually the LNG contract is public, actually. If you look through that contract, Matt, what you'll find is that we have to maintain every second year 50% of the ACQ. That means sort of, you know, year one, you can divert, you know, 50%. Year two, you can divert 100%. Year three, you can divert 50%. You know, year four, you can divert 100% while still meeting all of your obligations under the contract with the penalty for the diverted cargoes. What it means is, you know, to do the math, you're paying a penalty on the diverted cargo, and you can divert up to, on average, 75% of the cargoes with it, sort of, in a modeling sense, 50%, 100%, 50%, 100%. Let's say typically, you know, I can't share with you the actual penalty, but contracts of that era had a penalty of around, you know, somewhere between 20% and 30% of the price to the buyer. phase II. Yeah, sorry. Yeah, on phase II. Look, I think the step on phase I is an indication of where we intend to go on phase II. You know, we would want to sort of build, you know, a relationship with customers that could take those volumes in that, you know, 2024, 2025, 2026, 2027 timeline. You know, phase II volumes would be following absolutely, you know, after, you know, in that time period. We would look to overlay it with contracts that gave us real exposure to the gas exposure, as you said. Look, I think genuinely it is gonna be a mix. The big difference for phase II versus phase I was that we don't anticipate any financing requirements for phase II. We put the infrastructure in place for phase I, and therefore the incremental build-out in terms of additional capital is very modest. You know, we've talked of a number of less than $1 billion in the past. As you start to think about the flexibility that gives us, it's significant. That's really, you know, the excitement that we have now around the exposures to the international gas price. As I said in my answer to Austin's question, I think we're quite unique amongst our peers in having this exposure to not only that sort of high margin, low carbon oil, but actually high margin, low carbon gas. You know, as you start to look at now where the forward curve is going for gas, you know, due to the unfortunate extension of the war in Ukraine, we believe there's a fundamental opportunity for us to access. In terms of bringing that forward, we can do it with the phase I volumes, as we've described with the diversions, and then clearly back that up then with the phase II volumes and become a very sort of credible seller into the market. Perfect. Thanks, Andy, really appreciate the detail. Perhaps if I could just sneak one more in. It was just around the sort of NOC cost carry that you have at Tortue. It sort of sounds as though you're sort of no longer prioritizing the refinancing of that, you know, given that you don't have necessarily balance sheet constraints anymore. Just wondering if you could remind us sort of on the default mechanism of how you will recoup that cost and perhaps even if you're able to give any color on how quickly you might recoup that'd be much appreciated? But that's all from me. Yeah. I'll ask Neal just to pick that up, Matt. Yeah, Matt, the mechanism is meant for sort of the phase I revenue to the NOCs to repay sort of the NOC loan. There is some flexibility built in in terms of the duration of that repayment. But you know, clearly the more that they generate from the phase I volumes means the faster we can potentially get our proceeds from the loan back. Alternatively, you know, you know, as you noted, sort of while the immediate pressure is still off from getting the NOC loan off of our books, it's still something we wanna pursue. I think just from a timing perspective, you know, that naturally will make sense around sort of the phase II project sanction to bring back into the fold. It's still something on the agenda. All right. Okay, thanks both. I'll pass over. Cheers. Great. Thanks, Matt. Our next question comes from Alex Smith with Investec. Please go ahead. Hi, guys. Thanks for the call. Just two quick ones from me. First one, just you're rapidly approaching your gearing target and producing healthy levels of cash flows. Just when could we begin to see maybe a decision on dividends or buybacks, and would there be a preference for either? Just on Ghana, can you just comment on the cost of the wells that you have been drilling? You mentioned that they've come in slightly under expectations, and the plans for a decision of the second rig. Given the current oil and price environment, is there an opportunity to accelerate this decision given how well the drilling program has gone to date? Thank you. Yeah. Hey, Alex. Let me just. I'll talk about Ghana first, and then, you know, Neal can pick up the financial framework. I think in terms of the decision around the second rig, you know, we're, you know, as I commented in my remarks, we are, you know, drilling well in Ghana at the moment. You know, the wells are ahead of schedule, you know, under cost. And actually, the opportunity therefore is to deliver the volume increase that we intended across the asset, but actually do it through a high-graded, you know, one rig program. That's the focus for today. We don't anticipate bringing a second rig in currently. We're gonna continue to evaluate that opportunity. I think it's all around this mantra of capital discipline today. You know, as you start to deal with the inflationary pressures, you know, the opportunity ultimately is around operate more efficiently. That's how you mitigate the increase in the unit cost. You know, that's our focus today, and I feel confident that we can actually do that. We don't, you know, we're not making a decision today to bring in a second rig. We've got, you know, a clear program that enable us to start the drilling of the Jubilee South East wells this year. That, you know, enables us to deliver on that project where we anticipate startup once the subsea equipment is in place in the middle of the year. That, you know, in terms of driving 2023 volumes, that is the you know, the big driver. We have a follow-up of the TEN enhancement project that would follow in, you know, 2024, 2025. I think we're well placed today and we don't have to, you know, there is no economic benefit from bringing a second rig today. Neal, in terms of the gearing targets. Yeah. In terms of the gearing and as well as, you know, allocation of capital, our views really haven't changed overly too much, Alex. I think, you know, the goal is to fund, you know, the capital program, both the maintenance and the growth projects that we have. Within that, you know, while leverage is, you know, continue to sort of prioritize debt pay down until leverage is less than sort of 1.5 times. We've said we'll sort of get on track to get there before the end of this year, but we want that to be sustainable before we sort of look at sort of shareholder returns. It is sort of clearly next on the agenda, that we would look to. In terms of buybacks versus dividends, again, I think, yeah, that will be, you know, more to come on that in terms of which specific method. You know, will largely depend on where sort of both the share price looks like at that time period. You know, I'd say currently sort of more tilted towards the buybacks, but we'll look at that as we achieve our debt targets. Great. Thank you very much. Our next question comes from Bob Brackett with Bernstein Research. Please state your question. Yes, please. I saw that you drilled two of the four producers at Tortue phase I. Can you comment on did they come in at least based on the log analysis in line with pre-drill predictions? Yeah. Overall, you know, we're looking to build well capacity, Bob, where we've got the coverage and really from sort of 2/3 wells that will deliver the required, you know, plateau versus four. The first two wells have enabled to stay on track to do that. We're currently drilling the third well, and then the fourth well is actually a twin of one of the original exploration well. In terms of having the required well productivity with the appropriate level of insurance at first gas, we feel good about what we've seen so far. Great. Thanks for that. In terms of EG, you mentioned the four wells as part of a drilling program split between infills and ILX. How are you strategically deciding whether to go for a more sure infill versus a greater upside ILX? How, what's the logic there? Yeah. No. You know, great question, actually. We see two really good opportunity sets. Yeah. You know, you know the history of why we went into EG. We felt from two perspectives that it hadn't been fully developed from an infill perspective, and there was a sort of remaining exploration opportunity in the Río Muni. You know, we built a pretty good handful of infill opportunities, and we're gonna high grade the first three of those actually, Bob, in terms of the drilling program. Then the fourth well will be the ILX well, which is targeting a deeper untested Albian opportunity underneath the Ceiba and Okume infrastructure that looks really interesting. That's the balance. You know, clearly the ILX opportunity is significant and will be a significant game changer in terms of our position there in Ceiba and Okume, while the infill wells are really high quality, high rate of return, sure payback, you know, tieback to the existing infrastructure. We've got some, you know, both of those opportunities on the roster, and clearly gaining the license extension out to 2020, 2040 has made both of those opportunities even better, yeah. 'Cause clearly, you know, with the extension we have, if we were successful with the Albian, we've got significant amount of time then to drill out, you know, quite a large associated inventory. You know, the drilling program will start the back end of next year, and I think will be an interesting phase of the development of Ceiba and Okume. Great. Thanks for that. Super quick one, if I may. In terms of just to follow on exercising contractual rights on the Tortue phase I, I believe is BP both the counterparty of those as well as the operating partner, and is everything amicable between you all? No, I think it's you've got to be, you know, sort of quite important that BP is the upstream operator. Yeah. BP Gas Marketing is the purchaser. So there's actually Chinese wall between BP as the upstream operator and BP Gas Marketing as the buyer of the gas. Actually everything is amicable. Perfect. Thank you. Thanks. Our next question comes from James Hosie with Barclays. Please state your question. Yeah, hi there. A couple from me. I guess going back to your right to divert some of the Tortue phase I cargoes, how much notice do you need to give on this? I'm just wondering how far ahead you need to make a call on LNG spot prices. Yeah, you know, I don't wanna get into too much of the detail, James, 'cause it is, you know. In terms of the ability, we have the right to, you know, divert, you know, cargo by cargo, and therefore we have the ability to build a program. You know, we can, you know, dictate the duration of the scale of the diversions. Then just on another topic, if you could give us some color on how the 2022 capital budget is shaping up. I'm just thinking that you're talking about Winterfell. It sounds like it's a billion-dollar project gross, and obviously inflationary pressure as well. Should we be assuming higher CapEx compared to the 2022 budget of $700 million? Yeah. Look, you know, we don't normally give CapEx guidance for the following year till we can match with our final year, you know, results. I think, you know, conceptually the way to think about it is, you know, the base business, as we talked about, it's a sort of sustained production there. We're spending around sort of $350 million on that in 2022. Looking forward with the rigs locked in, et cetera, you know, we feel sort of good about that number. You've really got the capital that goes into the growth projects, and you've got a couple of dynamics, yeah. You probably got a similar level of spend on Jubilee South East. You've got a reducing level of spend in Mauritania, significantly reducing, and then you've got an uptick in Winterfell as you described. You know, I think that's the way to think about it. At the margin, you've got discretionary capital around, you know, the ILX programs. I think that's the way to think about it. Clearly the timing around the relative ramp up and ramp down of those projects, you know, you've clearly got, you know, significant decrease in spend in Mauritania and Senegal, but you will have, as you say, an uptick in the Winterfell spend. Okay. Very good. Thank you. Thank you. Just a reminder, to ask a question, press star one on your telephone keypad. Our next question comes from Mark Wilson with Jefferies. Please state your question. Hi. Thanks for taking my questions. A few points here. It sounds like you're not bringing a second rig in or don't plan to do the Jubilee South East development drilling. That's the first clarification. Could we also just understand where we stand on those Shell exploration payments after success in Namibia? Lastly, we've seen the BirAllah PSC extension, some changed terms there. Do we expect something else like that on Yakaar-Teranga? Thanks a lot. Yeah, no, you know, as I said in answering a prior question on the second rig, I think it's actually a good news story. You know, at a time of real inflation, it's about driving efficiency into the business. I think on Jubilee, you know, we've seen the demonstration of that in terms of the drilling performance. You know, for us, it's about continuing down that path, you know, high-grading the well selections, you know, being able to deliver the volume increase that we've outlined in Jubilee and, you know, and deliver the benefit from that project. We don't, you know, we're not anticipating making a decision on a second rig currently. You know, clearly we'll continue to evaluate that, Mark. The answer is no second rig at the moment. In terms of Shell, they have success with two wells in Namibia, La Rona and Graff. Our understanding is that they intend to submit an appraisal plan at the beginning of the fourth quarter. With the submission of the appraisal plan, they would be obligated to pay the bonus from the contract that we have in place with them. That's what we anticipate. On BirAllah. Yeah. BirAllah is, you know, an important step forward in new PSC. You know, clearly we have to separate out in a development sense the discoveries that we had in Orca and the surrounding acreage. Better to do it now ahead of a sort of development proposal than do it later. You know, we spend the time now to do that. You know, in an accounting sense, there has been an impact, but actually in an economic sense, the costs that were associated with essentially was the Orca exploration well, we get the benefit of that both in cost recovery and tax on Tortue. There's no economic impact from this. What we do have, we have a new PSC, substantially the same terms. You have some small modifications around local content, et cetera. Ultimately, we now have the basis on which to move forward now with BirAllah on a very sort of, you know, clean, forward-looking perspective. As I said, I think, you know, for us it was important to do this now rather than sort of get to the development decision, then have to negotiate the new PSC as part of that development decision. I think, you know, we're on track now to move forward and do the concept work that's required to bring that forward as a real opportunity. You know, there's a big resource base there. You know, again, it's characterized, you know, by low cost, low carbon gas adjacent to the European market. Our objective, as I said in remarks, will be to tackle that with a phased approach very much in the same way as we've done on Tortue. Got it. Okay. No, thank you. turning it over. Great. Thanks, Mark. Appreciate it. Thank you. Since there are no further questions at this time, I would like to bring the call to a close. Thanks to everyone joining today. You may disconnect your lines at this time. Thank you for your participation.