Good day, everyone and welcome to Kosmos Energy’s Fourth Quarter 2021 Conference Call. At this time, let me turn the call over to Jamie Buckland, Vice President, Investor Relations at Kosmos Energy. Thank you, sir. You may begin.

Thank you, operator and thanks to everyone for joining us today. This morning, we issued our fourth 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 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 fourth quarter results call. I’d like to start today’s presentation looking at the company’s strategy and the defining characteristics which differentiate Kosmos and position us very well in a rapidly changing oil and gas sector. I will then talk about the operational momentum we saw in 2021 before handing over to Neal, who will walk you through our financials. I will then outline our plans for 2022 and the key investments we are making to deliver significant shareholder value in the next 12 to 24 months. We will then open the call up for Q&A. Starting on Slide 2, looking back, 2020 was a year of survival for the sector, in which Kosmos took the opportunity to high-grade its investment options to create a stronger company for the future. 2021 was a year of resuming operational delivery and strengthening the balance sheet, both of which were significantly enhanced by the Oxy Ghana and Tortue FPSO transactions. 2022 is the year in which Kosmos can really start to thrive. We have the right portfolio for the future and the boxes on the left of the slide highlight the key characteristics that define our portfolio. First, we have low cost, high-quality assets. The company is underpinned by world-class fields that have a longevity to deliver sustainable, high-margin cash flow. That gives us the ability to invest in our existing assets to materially grow production and free cash flow while simultaneously reducing debt. The right-hand chart shows the company’s production is forecast to grow by around 50% between 2022 and 2024 as we bring our planned developments on stream. Second, as the chart also shows we are increasing our exposure to gas and LNG. The Tortue Phase 1 comes online in the second half of next year. We also have a deep hopper of world-class gas opportunities in Mauritania and Senegal that we expect will provide further growth well into the future. Third, we have a robust balance sheet, which we expect to strengthen further in 2022 with a year-end leverage target of around 1.5x at current prices. Fourth is planned CapEx flows and free cash flow growth; there is potential for meaningful shareholder returns once leveraged sustainably below our target. And finally, we have strong ESG credentials driven by a portfolio shift towards lower carbon natural gas and a commitment to our host countries in Africa to support a just energy transition. Kosmos has emerged from the last 2 years with a strong team, excited about the future and hungry to deliver the significant value we see in the portfolio for our investors. Turning to Slide 3, one of the key areas of differentiation for Kosmos is a long reserve life of our portfolio, which underpins the growth we are planning. At year end 2021, Kosmos 1P and 2P reserves were both at record levels. The top chart on the slide shows the oil-gas split of our 1P and 2P reserves. On a 1P basis, oil makes up around 60% of our reserve base, whereas on a 2P basis, gas is over 55% of the portfolio, reflecting the longer-term direction of the company, a bias for oil in the near term and gas in the longer term. The bottom chart shows the diversification of the portfolio on a 2P basis. Ghana and Mauritania and Senegal each make up around 40% of the portfolio with Equatorial Guinea in the Gulf of Mexico, making up about 20% between them. This diversification is important as it means we are not dependent on a single field or a single geography to deliver our future plans. In 2021, our 1P reserves more than doubled to approximately 300 million barrels of oil equivalent with the booking of Tortue Phase 1 and the Oxy Ghana acquisition. Our 2P reserves are approximately 580 million barrels of oil equivalent, which gives us a 2P reserve to production ratio of over 20 years. Even excluding the Oxy Ghana acquisition, our reserves replacement ratio was strong with 114% of the total of our 2P reserves demonstrating the underlying quality of our asset base. Turning now to Slide 4, as you are well aware, for the last 18 months, we have been focused on deleveraging and have made good progress. With a portfolio of highly cash-generative assets, we expect leverage to continue to fall sharply this year. As guided, we ended 2021 at around 2.5x, a significant year-on-year reduction. We remain on track to end this year below pre-COVID levels. Our year-end target for 2022 is around 1.5x at strip pricing. We expect to achieve the deleveraging through a combination of rising EBITDAX and absolute debt reduction. EBITDAX is expected to increase materially year-on-year through several drivers, including higher production and stronger oil prices, which we have been able to hedge at much higher levels than in 2021. In addition, with greater production from Jubilee, we expect our unit costs to decrease as well. We also plan to reduce absolute debt by up to $500 million this year, which will further drive the leverage multiple lower. This absolute debt reduction is driven by the free cash flow we generate, but could be enhanced with the potential for contingent payments from Shell, the Oxy Ghana preemption proceeds and the NOC loan refinancing. I will provide an update on the preemption process shortly. On the NOC loan, we had initially aimed to get that done by year-end 2021 and received several term sheets for the transaction. We continue to progress those discussions. However, we want to ensure any deal done is in Kosmos’ best long-term interest and are taking the time to get it right. Our liquidity position is strong and could get stronger with potential proceeds from Ghana preemption and the shale exploration bonus. Therefore, we continue to pursue the NOC loan refinancing; the timing is less pressing. Turning to Slide 5, I talked about the embedded growth we expect to see over the next two years, which is driven by Tortue Phase 1, Jubilee Southeast and Winterfell, delivering an expected production increase of around 50%. As these developments start up, our capital commitments are expected to fall by more than 30%. With production up and CapEx down, we expect free cash flow to more than triple from the levels we expect in 2022 at $75 Brent. This cash generation is sustainable and underpinned by our 20-year 2P reserve life, putting us in a position to deliver material shareholder returns. Turning to Slide 6 and our commitment to sustainability, as I have noted on the previous slides, we have a long-dated portfolio of high-quality assets. Our goal is to help our host nations develop their hydrocarbons in a responsible way and expand access to affordable, reliable energy. Through creating economic benefits, we help to drive sustainable developments in our host countries. On the environment, two years ago, Kosmos set out a policy to achieve carbon neutrality for our Scope 1 and 2 operated emissions by 2030, and we are working to accelerate that timeline. We will give further updates in this year’s sustainability report, which we will publish in the first half of this year to give investors access to the 2021 data sooner. We also plan to provide additional disclosure on our equity emissions. On social performance, we care deeply about the people who work for Kosmos and those who work with Kosmos. In our host countries, we employ 100% local nationals, and our U.S. offices in Dallas and Houston are consistently named in the top places to work. In our host countries, we aim to be trusted partners and good corporate citizens. We work with a range of stakeholders and our communities to facilitate sustainable development. We worked in this manner for nearly 20 years, going back to when the company was founded. Each year, we fund important social investment programs in Ghana, Equatorial Guinea, Senegal, and Mauritania that are aimed at creating economic opportunity, advancing social progress, and improving standards of living. The success of the Kosmos Innovation Center is a prime example. This initiative in Ghana, Mauritania, and Senegal invests in young entrepreneurs and small businesses outside the oil and gas industry. We train and empower young people to turn their ideas into viable businesses. And we work alongside promising startups to help them scale and reach their full potential. And finally, governance. Governance has always been a key pillar of our business and cascades down from our experienced and diverse Board of Directors through the executive leadership team to our employees. We have always taken an industry-leading position on transparency, publishing all of our material petroleum contracts online. In summary, our consistent commitment to sustainability is a core value and supports our ability to deliver long-term value to our shareholders and stakeholders. Turning to Slide 8, looking back at 2021, a year that saw an acceleration of our strategic progress with operational momentum across all areas of the portfolio. On production, we hit our year-end production target of 75,000 barrels of oil equivalent per day, boosting fourth-quarter cash flow and reducing leverage at year-end to approximately 2.5x. Our LNG development made significant progress during the year with Tortue Phase 1 around 70% complete at year-end. We enhanced our reserve base and now have a 2P reserve life of over 20 years with a growing gas weighting. We executed a highly accretive transaction in Ghana, acquiring a stake in the Jubilee and TEN fields from Oxy, which has helped us transform the balance sheet and increased free cash flow generation. And finally, we continue to advance our ESG agenda, supporting a just energy transition in Africa. On the following slides, we will briefly look at the progress we have made in each of our core geographies. Turning to Slide 9 and starting Ghana. 2021 was a pivotal year for Kosmos in Ghana, where we got back to drilling after a pause in 2020. Kosmos had net production of around 39,000 barrels of oil per day across Jubilee and TEN in the fourth quarter. The increased drilling activity in 2021 was promising, particularly at Jubilee, where the partnership drilled three wells, and Kosmos has a much greater interest. The challenge shows Jubilee production for midyear, where new wells started to come online. And you can see production rising from around 70,000 barrels of oil per day in July to over 90,000 barrels a day by year-end, which is where the field is producing today. On TEN, the partnership drilled one gas injector, which is helping to support existing producers. However, this has not been enough to fully stem production decline. Turning to Slide 10. In October, we announced and completed the acquisition of additional interest in Jubilee and TEN from Oxy for a total cash consideration of around $460 million. At the time, we talked about the attractive economics of the deal in a $65 world, which is highly accretive on all metrics and an expected payback of around three years. With the ongoing strong operational performance of the assets and the recent strength in oil prices, we believe payback will be reduced to under two years with significant future upside as we continue the infill program. Once again, I’d like to thank our equity and bondholders for their strong support. I am pleased to see the benefit of this transaction delivering so quickly. On preemption, both partners exercised their preemption rights in November. The impact of preemption on Kosmos is a small reduction in our Jubilee stake from around 42% to around 38%. In TEN, the reduction is more meaningful with our stake reducing from around 28% to around 20%. Assuming preemption is completed, we would expect to receive a bit more than $100 million of closing which we would use to pay down debt. The impact on Kosmos production will be about 5,000 barrels of oil per day. We are working with the partners on the transaction, and the preemption remains subject to the approval by the Government of Ghana. Turning to Slide 11, in Equatorial Guinea, fourth quarter gross production was in line with the full year at around 30,000 barrels of oil per day. Similar to Ghana, we saw increased activity in 2021 with the first wells drilled on the asset since 2015. The partnership drilled two jack-up wells, both of which came online in the fourth quarter. We have been pleased with initial performance, and the combined impact on gross production can be seen on the chart with Ceiba and Okume collectively producing at levels not seen for over 18 months. In the Gulf of Mexico, turning to Slide 12, fourth quarter production was 21,000 barrels of oil equivalent per day, slightly above full year production of 20,000 barrels of oil equivalent per day, on drilling the successful Tornado Dump Flood, which boosted output in the second half of the year as the chart shows. The highlight in the Gulf of Mexico last year was the Winterfell discovery and the successful appraisal well. With around 100 million barrels of gross resource potential in the Central Winterfell area and proximity to several nearby host platforms with OH, we are excited about the future potential of this asset. Turning to Slide 13, the Tortue project saw a ramp-up in activity in 2021 with all key work streams making significant progress. At year-end, Phase 1 of the project was around 70% complete. Looking at each of the work streams, on the FPSO, the final four process modules were lifted onto the deck in December. Mechanical completion of the process subsystems is now underway. In images of the FPSO on the slide show the high level of completion. On the hub terminal, we completed construction of the 21st and final caisson, and piling installation for the jetty has commenced ahead of the hub terminal facilities delivery. But the subsea activity is ramping up. The pipeline vessel has recently completed its nautical trials in the North Sea and should be ready for the offshore installation campaign in the second quarter. And on the floating LNG vessel, the four mixed refrigerant compressors have been lifted on board, and the pipe rack installation operations have commenced. So, 2021 was a busy year for us. And with the operational momentum we have built, we are well-placed to take delivery this year. With that, I will hand over to Neal to take you through the financials.

Thanks, Andy. I would like to start on Slide 14 by talking about the financial delivery we saw in 2021. We accomplished a lot to have positioned the company well to prosper over the coming years. First, we successfully refinanced the reserve-based lending facility, which now has a total facility size of $1.25 billion, with $1 billion drawn at year-end. In August, we announced the completion of the Tortue FPSO sale and leaseback transaction, which funds around $375 million of our CapEx on the project and with key parts of the financing path we laid out in November 2020. Our producing assets generated strong free cash flow of around $175 million during the year, excluding working capital, in line with our guidance. The combination of these, along with the bond transactions we executed, have deferred all of our near-term debt maturities and helped increase our liquidity to over $750 million available at year-end. Through strong operational performance in the Oxy Ghana transaction, we materially reduced leverage during the year, ending at around 2.5x as planned. And finally, we have taken advantage of higher commodity prices to put in hedges at significantly higher floors and ceilings than we had in 2021. Around 55% of our production is hedged with an average ceiling of around $80 per barrel with the rest exposed to current prices. All in all, it was a good year for Kosmos. While there is still more work to do in 2022, we start the year in a strong position. Turning to Slide 15. Kosmos delivered a record quarter in 4Q with our highest-ever sales volumes and EBITDAX. Net production of approximately 70,000 barrels of oil equivalent in the quarter was in line with our expectations. Sales volumes of 82,000 barrels of oil equivalent were higher than guidance as a result of an additional Jubilee cargo in Ghana loading in late December. The realized price of around $65 per barrel, which includes the impact of hedging, was materially higher than the previous quarter, a trend we expect to continue in 2022. In the first quarter of this year, we anticipate a realized price net of hedging of over $80 per barrel. Costs were all in line or slightly below previous guidance, which helped to drive today’s positive 4Q results. Turning to Slide 16. As I mentioned in my opening remarks, we made a lot of progress with the balance sheet in 2021. And the chart on the left of this slide shows that liquidity remains at a healthy level. This quarter, we expect to complete the refinancing of the RCF, pushing that maturity to late 2024. The chart on the right shows that we expect to have no material debt maturities until late 2024 at the latest, although we do plan to utilize our flexibility to prepay some of our existing debt well before that. With that, I’ll hand back to Andy to take you through the year ahead.

Thanks, Neal. Across our business, this is an important year for the company. We’re investing in our key assets to drive the increase in production and cash flow that we discussed earlier. Turning to Slide 18. In Ghana, we have a world-class field in Jubilee that has the potential to produce at elevated levels for the next several years as we deliver on our plans. In 2022, we’re investing capital in three infill wells, one producer and two injectors that support the base production. With these new wells, combined with the benefits of the wells we drilled last year, we expect to deliver year-on-year growth at Jubilee of around 10%, which includes the impact of the two-week shutdown planned for the second quarter. Around the end of the year, the partnership plans to start drilling the first Jubilee Southeast wells. Jubilee Southeast is an untapped area of the reservoir, where we will be drilling lower GOR wells. Once online, in mid-2023, these wells should push gross production in Jubilee to around 100,000 barrels of oil per day. On TEN, as the operator guided previously, production is expected to trend lower until we see the benefits of the wells that are being drilled later this year. The partnership plans to invest in two infill wells this year, one producer and one injector, which should help stem decline in 2022. We’re also drilling two riser-based wells, which are targeting an undeveloped extension of the NTM reservoir closer to the FPSO, allowing us to take advantage of existing infrastructure. These riser-based wells are expected online in 2023 and should help to increase production. As the operator recently communicated, the longer-term plan with TEN is to double current production levels by increasing the activity at TEN with a second rig in Ghana. And finally, we’re aligned with the operator and the Government of Ghana to eliminate routine flaring by 2025. As a first step, we plan to modify the gas handling system on the Jubilee FPSO during the shutdown in the second quarter of this year, which is expected to allow us to inject and export more gas volumes. Turning to Slide 19. In Equatorial Guinea, production year-to-date has continued to be strong as a result of the wells drilled late last year. In 2022, investment will be focused on facility maintenance, well work and a second ESP program with the aim of keeping production around these levels through the year. There is a lot of untapped upside at Equatorial Guinea, and we have several high-grade ILX opportunities, particularly in the untested deep. In the Gulf of Mexico, we’re planning to sidetrack the Kodiak well in the first half of the year, funded by insurance proceeds, with the well expected to contribute in the second half. That, in addition to some production optimization projects, should support existing production levels. On Winterfell, we’re working with partners on a low-cost, lower-carbon development, targeting sanction for the initial two-well development scheme in mid-2022. First oil is expected around 18 months from sanction. In addition, we continue to mature multiple prospects for future ILX drilling in 2023 and beyond. Turning to Slide 20. As I said last year, we continue to make strong progress on Tortue Phase 1, with all the major work streams advanced as evidenced by the images on the slide. In 2022, we expect to hit several important milestones, ahead of first gas planned for the third quarter of next year. We plan to begin drilling the initial four wells next quarter, with offshore installation of the subsea infrastructure expected to commence in the second quarter as well. On the hub terminal, we expect to commence facilities hookup in the third quarter of this year. On the FPSO, sail away from the yard in China is due in the third quarter with the vessel expected to arrive on site around the end of the year. And on the floating LNG vessel, we will be testing the steam turbines later in the year and they have been commissioning of the vessel power management system with sale anticipated early in 2023. Turning to Slide 21. Beyond Phase 1 of Tortue, we also have a significant amount of low-cost gas across our assets in Mauritania and Senegal that we are working to commercialize. Given the ever-tightening supply-demand backdrop of global LNG, we believe our discovered resource has significant value upside to Kosmos. For the second phase of Tortue, we’re working with BP in the NOCs to optimize the upstream facilities to deliver another 2.5 million tons of capacity at an upstream cost of less than $1 billion of gross CapEx we have previously communicated. We expect to make a development decision related to the projects around the middle of this year. This would kick off the FID work to fully support the detailed contracting costing required for formal FID. At BirAllah, we expect to complete the seismic reprocessing and rest of our modeling which should allow development concept to be selected. And in Yakaar-Teranga, the partnership plans to advance studies and the met ocean and geophysical surveys while also progressing domestic gas sales discussions. Turning to Slide 22, which looks at our high-level guidance and capital plan for 2022. There is a more detailed guidance slide included in the appendix. We expect company production for the year to be in the range of 67,000 to 71,000 barrels of oil equivalent per day, which at the midpoint would be a year-on-year increase of over 20%. CapEx of around $700 million is broken out in the chart on the bottom right. We plan to spend between $250 million to $300 million of maintenance CapEx on the producing assets, which is development drilling and integrity spend in Ghana, Equatorial Guinea, and the Gulf of Mexico. We also plan to spend between $100 million to $150 million of growth CapEx on the base business for production growth in 2023 and beyond. This includes Jubilee Southeast, the TEN riser-based wells, Winterfell as well as long lead items ahead of our 2023 drilling program in Equatorial Guinea. On Tortue Phase 1, we expect to spend around $250 million during the year, which reflects the timing of accrued CapEx based on the approved budget from the operator. We also expect to spend a further $50 million in Mauritania and Senegal on Tortue Phase 2 and increased activity on BirAllah, Yakaar-Teranga to support progress on those developments. At $75 Brent, we would expect to generate around $200 million of free cash flow, which we plan to use to reduce debt. As I mentioned in the opening slide of today’s presentation, we could see absolute debt reduced by up to $500 million this year through a combination of organic free cash flow, contingent payments from Shell as they are successful with their drilling campaign this year, Ghana preemption proceeds and the NOC loan refinancing. So turning to Slide 23 to wrap up today’s presentation. Kosmos has a differentiated portfolio and exciting outlook. We have low-cost, high-quality assets with significant embedded growth. We are investing in world-class gas projects that will help facilitate the energy transition to provide the company with long-term sustainable cash flow. We have a robust balance sheet that continues to get stronger as we deleverage this year and beyond. As our leverage improves, we anticipate our efforts will generate significant amounts of cash flow which will enable meaningful shareholder returns, especially at current commodity prices. And finally, we have strong ESG credentials that give us a license to operate in our host countries and a portfolio that is fit for the future. Thank you. And I’d now like to turn the call over to the operator to open the session for questions.

Our first question comes from Charles Meade with Johnson Rice. You may proceed with your question.

Good morning, Andy and Neal, and to the rest of the team there. Andy, I want to go back to your prepared comments and specifically the timeline that you laid out for Phase 2. Did I hear that you’re going to have a front-end engineering process sometime around midyear that precedes FID, or can you just go back to that and kind of set the timeline for us?

Yes, Charles, it’s Andy. Yes, the timeline is to get to the concept select decision by mid-year. And we’re working hard with BP to ensure that we fully optimize that. And as I said in the remarks, I think we believe there is real opportunity to lower the cost below the $1 billion growth for the upstream that we talked about. So that’s the process going through to the middle of the year. And then the second point with the concept selected and the way forward defined, we will do the engineering to go through the formal process of FID. For FID, obviously, the government approvals we need, the final engineering costs and we need the contracts in place. So that’s sort of the real work will kick off in the middle of the year.

Got it. So FID would be sometime in the back half of the year at the earliest?

It’s – and again, it’s really important, I think, in the current environment, to do quality engineering to ensure that we have the right basis of the capital and the right contracts in place. So I think that we want to ensure that the quality of this is a really good project. And we’re quite – we see a lot of opportunity actually to remove costs upfront. And we want to make sure that we do that.

Got it, thank you. And then a quick question about the Gulf of Mexico, the two-well Winterfell development. Just to get kind of an order of magnitude here, should we be thinking about gross rates from that development in the range of 5,000 to 10,000 barrels a day?

Yes. I think, Charles, gross rates for the two-well development will be around 20,000 barrels a day or maybe a little less than that, but basically flow on.

Got it. Thank you, Neal. Appreciate it.

Alright, thanks, Charles.

Our next question comes from the line of Neil Mehta with Goldman Sachs. You may proceed with your question.

Good morning. Andy, the first question is just around your marketing strategy. Obviously, with everything going on in Europe right now, the value of Tortue and the barrels continues to move higher potentially. As you think about cargoes for either Phase 1 or Phase 2, can you ultimately market some of those cargoes into Europe and talk about how you see this asset fitting in the broader natural gas macro?

Yes. Thanks, Neil. I think that if you sort of go back and sort of starting where we are today on Phase 1, we have the 2.5 million tons being marketed by BP. As you’re aware, it’s a 9.5% low to Brent. The real upside, of course, therefore, comes from Phase 2, where those cargoes are not sold today. And we believe there is a real opportunity for us to take greater benefit, I think, from strengthening prices for LNG globally. And I think as you look at the world today and obviously, one of the consequences of the sad situation in Ukraine is that Europe needs to look at how it can ensure energy security and look for new sources of gas. And I think in Mauritania and Senegal, we have a resource that is low cost. The gas is low carbon. It has no CO2 in it, and it’s proximate to Europe. So I think we believe, and I believe deeply that this is an important resource for the world. Our job is to support the energy transition as a company, bring forward new sources of supply that help support energy security. I think we can do that with the gas supplied from Mauritania and Senegal. I think the Phase 1 will come on at an important time. And as we discussed with Charles, we’re moving forward with Phase 2, which I think, again, will come on at an important time to continue to support a growing gas demand and hopefully create another source of energy security for the world. Gas is part of the energy transition. So I think it’s becoming more widely recognized that it plays a role. And we believe that Mauritania and Senegal is therefore a part of that. So I think when you look at the big macro and a lot has changed actually since we started the journey with Tortue. I think there is a lot to look forward to. And in particular, around your initial question about Tortue Phase 2, I think there is a lot of optionality on the gas pricing for that.

Thanks, Andy. And as a follow-up, is just around hedging strategy. Obviously, in ‘21, there were a lot of those barrels that were sold at a discount relative to spot price. As you roll into ‘22, remind us what percentage unhedged you are? And as you think about that remaining unhedged portion, is the intention to leave it open to give yourself that sort of exposure to potential stronger commodity price realizations?

Yes. Sure, Neil. I’ll take that. Yes. So we’re about 55% hedged on ‘22 oil volumes, which means we have 45% unhedged. We plan to keep that exposure through the rest of this year. And I think the interesting part that we’re working through now is on ‘23. So we are less than 10% hedged today with upside to $95 on those couple of million barrels that we have hedged. And we are looking at structures that give us more downside protection and more access to the upside. So that’s the main focus for us for the next few quarters is really to get ‘23 in a place where the downside is protected well, and we’ve kept as much access to the upside as possible.

Thanks, Neal.

Our next question comes from the line of Nick Stefanou with Renaissance Capital. You may proceed with your question.

Hi, guys. It’s Nick from RenCap. Thank you for taking my questions. I have three to ask, please. Going to ask two and then ask a follow-up. So Andy, in the past, the idea about Tortue Phase 2 has been that this would be a funded development from the cash flow that Phase 1 will generate. But if it is sanctioned this year, then it’s a very kind of like possible scenario for – but for maybe 6 to 5 months going to have to pay for both Phase I and Phase 2 CapEx. So can you give me kind of like some comment around how you think about or is this something you might play back towards the venture of the project? And then the second one is on the sensitivities. I don’t back to sensitivities because it looks like they reduced from last quarter to $50 million from $100 million to $5. I’m not sure if this is – is this like purely because of the additional hedges you have done quarter-over-quarter because it doesn’t seem to be that many? And then I’ve got a follow-up. Thank you.

Okay. Why don’t we let Neal take the second question first, and then I will come back to the Tortue Phase 2 timing.

Yes. Nick, so just on your question, yes, most of it is just a function of where we are in the oil price now. So again, I think what we’ve said, which is still accurate on hedge base, it’s a $5 move is around $100 million change in an annual sort of free cash flow sense. And so what guidance we gave is around sort of $50 million for ‘22. Basically, 55% of our production, like I said, is hedged and therefore, that sort of the upside. And again, the average ceiling on our hedge is around 80%. So we’re right around that pinpoint. So, it’s maybe a little higher than that from 75% to 80% and then a little lower than that from – just given the staggering sort of ceilings that we have through the hedge book.

Okay. Got it. So it’s just linear for where we are now was very much, much lower plus, not anymore?

Correct, yes.

And then on Phase 2, Nick. It sort of goes back to Charles’ point. I think that we will start to incorporate CapEx for Phase 2 from sort of midyear, which will be the sort of the fee spending that’s incorporated in our current budget. I wouldn’t anticipate any significant spend on Phase 2 to commence until 2023. And therefore, the overlap with Phase 1 is almost exact, not quite, but almost exact. Yes, I think the second thing that I think is important to recognize is that as we have said we think there is real opportunity to drive down the upstream costs for the project significantly. And therefore, the net outlay to Kosmos is getting less and less. So, I think I feel good about the ability to actually self-fund it, and the enjoyment, if any, is very small. So we are well placed here. I think we have got a follow-on project which is really exemplary. It will fully utilize all of the built-in infrastructure we have from Phase 1. Therefore, the capital costs are coming down, and we are finding those savings as we speak. So, I think the overlap between Phase 1 and Phase 2 is going to be relatively small.

Okay. Fair enough. And my other question is on that G13 discovery you made in could give me a few years back. So, last year was more about fleet drilling of those wells, which did deliver results. So, I was expecting this year to be kind of like a fresh logo was going to be in EG. And it doesn’t seem to be – seem to be much activity or must kind of like talk about what is covering more. So, just wondering how you think about it? And what are the next steps for EG?

Yes. Nick, I am happy to take that. I think where some sort of our S5 sits is ultimately continues to sit in the appraisal camp. We do have additional plans for drilling in EG. And the question for us is how do we maximize the value of the existing discovered resource that we have across the portfolio. So clearly, we have opportunities in Mauritania and Senegal. Ghana, EG, and the Gulf of Mexico that we are moving forward. We can move them all together at the same time. And so we are phasing out the development projects. And if we can find more resource in EG, which we talked about potentially a ‘23 additional drilling campaign, we could make a new development more attractive from a risk-reward basis going forward and then would be in a position to allocate more capital to it. So, I think that’s kind of – yes, it’s there, we will continue to move it forward, but we would like to continue to de-risk it and make the economics better.

Okay. Excellent. Thank you.

Our next question comes from the line of Mark Wilson with Jefferies. You may proceed with your question.

Thank you. Good morning, good afternoon gentlemen. First question is on the 100,000 barrel a day target for 2024. Just to get some of the bigger moving parts in that. I’m hoping to say that expectation that TEN could double from here. It sounds like one of them and the other would be that Jubilee is over 100,000. Would those be those main moving parts? And also, would you expect both Ghana and Equatorial Guinea to be higher than they have produced in the past year?

Yes. Hi Mark, it’s Andy. I will take that. So, if you think about the buildup from where we are today to 100,000 barrels a day, clearly, in ‘24, Tortue is on stream net on a BOE equivalent. That’s about 18,000 barrels of oil equivalent per day. So – and then the next increment is Jubilee. We are talking about growing that to 100,000 barrels a day with the - at our current working interest, that adds an additional 8,000 barrels a day. And then Winterfell would add about 4,000 barrels. So, if you sort of do the quick math on that, you sort of get to the 100,000 barrels. Underlying that, you then got additional contribution from TEN. We have a lower working interest. And you have the Gulf of Mexico. And you have Equatorial Guinea benefiting from an infill program in ‘23. So, I think if you take those contributions against the underlying decline, you can see your way to a healthy 100,000 barrels a day. So, the big contributor is Tortue, the growth in Jubilee and TEN, Jubilee being the most significant part, the addition of Winterfell and then the underlying activity sets in Equatorial Guinea.

Got it. Okay. Thank you for that. And then also, you gave guidance towards where the $700 million guided for this year, how that tapers down towards ‘24? But just thinking about next year with Jubilee Southeast, with Winterfell, I suppose, theoretically in there. But before we get to a Tortue Phase 2 and post-Tortue Phase 1, we’d expect to come down into ‘23 overall?

Well, clearly not giving any guidance yet, so it’s a little early. But I think you have talked about the moving parts, okay. So, there is a moving part in Tortue Phase 1, where we are moving from the sort of ‘22 is a big year of spend. We drop the fabrication activities going on. We move to a different phase in ‘23. So, clearly a lot lighter. We have that coming down, yes. We have the sustaining spending in Jubilee Southeast. We have an additional spend in Winterfell. So, I think we are sort of – we are on a blind path which sort of when we have shown ‘22 and ‘24 is the chance, but we are on a glide path of decreasing CapEx. We are on a glide path of increasing production, which ultimately will create incremental free cash flow growth in ‘23 over ‘22 and then a growth in ‘24 over ‘23. So, I think I feel good about the shape we are building now going forward. ‘22 will be a full year of delivery followed by ‘23 and ‘24. But we are clear about the things that we need to do. And as Neal said, we are being very conscious about the capital inputs. Some is about ensuring that we don’t put capital into things, which we think you are going to make a material difference on the – we need to be sure that we are putting the capital into the highest quality opportunities. That was clear with Tortue Phase 1 and 2 with Winterfell and the Jubilee Southeast. So, we are very clear about the activity set. We are clear about the capital and the contribution that it will make in growing cash flow through ‘23 and into ‘24.

Got it. Okay. That’s very helpful. And just one last one, if I may. The Shell exploration payments, what are the steps and certification hurdles to be done from here to get any money in from that? What would be – what should we be looking for?

Yes. Well, look, again, Mark, what we understand is that Shell had a successful initial well. I think what’s interesting is that they decided to drill a well and back-to-back and have a second well ongoing as we speak. And I think that we would see that as a positive sign. In terms of the steps forward, the payment comes when they submit an appraisal plan. So, the current well, I suspect will – was probably a couple of months away from a result appraisal plan and then we get to a payment. So, those are the steps. I think they clearly chose not to submit an appraisal plan at this stage because it would have slowed down the ability to move ahead to drill the next well back-to-back.

Okay. Thank you. I will turn it over.

Great. Thanks, Mark.

Our next question comes from the line of Matthew Smith with Bank of America. You may proceed with your question.

Yes. Hi there. Thanks very much. I just wanted to ask around the future opportunities in Mauritania and Senegal. So, I mean quite rightly, we are still sort of talking about the long-term potential of Bir Allah and Yakaar Teranga. I just wondered whether equally, the optionality for a Phase 3 or a further expansion of the Tortue project is still on the cards as the potential next step rather than going into one of the other two projects? And then linked to that, just on Bir Allah and Yakaar Teranga, I just wanted to ask whether you thought there would be any potential or any appetite for you to down interest in those projects at this early stage, or would it be fair to assume that, that value crystallization point would be closer to a development concept?

Yes. Thanks, Matt. Yes, good questions. I think that our focus on the Tortue at the moment is to sort of maximize the value from the infrastructure that we have laid in. And I think as we have discussed on prior calls, hitting the 5 million tons is sort of fully utilizing all the existing infrastructure in terms of the full capacity of the FPSO, the pipeline issue, etcetera. So, I think the focus is to – I think the focus is, therefore, to ensure that we get that. We get it underway. And I think when that has been achieved and we have some production history from the reservoir we will be in a better position, I think, to fully describe what Phase 3 would look like. Yes. So, I think that it’s absolutely remains an objective to increase beyond the 5 million tons. But I think we have some work to do and some production history to gain before we fall in a position to make that next step. And I think being disciplined around the capital that we put into that is critical. Then I think it’s about how we progress the other given resource, which is significant. The BirAllah and Yakaar Teranga developments are different. But BirAllah, there isn’t as large a need for domestic gas in Mauritania. There isn’t even as large as there is in Senegal, but that ultimately would be an export project. We are working hard now with BP to define a development concept. And again, as we discussed in one of the prior questions, it has to sort of compete against gaps from the U.S., but there is a growing need for it in Europe and how we can put together a phase scheme that enables us to start in the right way. So, it’s low cost, it benefits from being low carbon CO2. So, I think that’s the goal of Mauritania and for BirAllah to increase their exposure, I think to the European market. Actually, it’s good for buyers that you are buying it from a diverse defined source. It’s a different production facility. Therefore, it has a more – it becomes a more diversified source of gas. Yes. So, I think there is a good rationale for looking at that in parallel with or potentially ahead of a Phase 3. When you look at Yakaar Teranga, differently, ultimately Yakaar Teranga will be part of Senegal’s domestic gas growth. It is about – as they end they pursue their own energy transition targets moving to a lower carbon world, they are going to mix renewables with gas. So, that project is driven by that time line. So, it has a different purpose and therefore, would be a very – we have a very different purpose in Senegal work from the expansion of Tortue. So, I think those – that’s the way to see it. I think there are different roles that each of the projects can play. And we need to be very clear about ensuring that we quite allocate the capital in a very disciplined way again those objectives and move projects forward at the right pace. But I think that our objective at the moment is to ensure that we absolutely maximize the returns from Tortue. And then I think with confidence in that and the production history from that, yes, there will be another phase. But I believe that the Yakaar Teranga and BirAllah will serve in parallel a different investment action.

Perfect. Thank you, Andy. And then one final question, if I could, would just be on the Shell sort of continued consideration, obviously, up to $100 million. Could I just clarify how you might get to that $100 million in 2022? So, presumably, we are hoping for $50 million in Namibia, if that’s right and then where the opportunity might come for the residual and to hit that cap?

Yes, there are – the drilling plans we believe for Shell will be when the rig finishes in midyear. It would then move to where it would drill the juck-up well, so that would be the next well in the program. And then beyond that, there are the wells issuing that. So, I think in Shell been very clear about there in fact the score we get on with our exploration program. And so I think we will see those wells being progressed after there is going to be second.

Our next question comes from the line of James Hosie with Barclays. You may proceed with your question.

Hi. Thank you. I have a couple of questions. Just firstly, does the 2024 production free cash flow outlook on Slide 5, does that incorporate the impact of the Ghana preemption process that we presumably have completed by then? And then just Mauritania and Senegal, just wondering if the work program you have now got for BirAllah and Yakaar Teranga, is that intended to get the assets to a point where you could look at monetizing them? And what sort of market do you see for those assets today?

Yes. So, just all the numbers in the presentation and all of our guidance don’t include preemption. And like we said, preemption has about a 5,000 barrel a day impact. Now clearly, we said it’s greater than 100,000 barrels a day. So, there is some flexibility around that. But it does everything throughout the presentation included the impact of preemption.

Okay. And then just on the second question. Look, I think the world is – the world of LNG continues to evolve. I think as a company, we have been strong on the underlying demand for LNG. And I think that picture remains unchanged. I think what’s sort of changing is that the supply challenges for new projects to set forward to meet that demand. I think there are various forecasts out there of shortfalls by the end of this decade. So I think there is going to be real opportunity to move projects forward that have the right characteristics, not just like I keep repeating myself, but it has to be low cost. It has to be low carbon gas so that it doesn’t have the disbenefit of CO2 to with it. And it has to address the market shortfalls in a geographic sense that are emerging. So I think we – our strategy sort of remains unchanged. We see real value in the undeveloped resource in Mauritania and Senegal, where we are excited about the optionality that a Phase 2 of Tortue brings because not only is it low cost leveraging from the prior investment in Phase 1, but we believe we can get greater access to the price upside because the gas is un-contracted. And that’s where we would want to go for instance, with BirAllah where we would be bringing that gas to market, and I think we have the ability to benefit from the optionality that the market would bring. So ultimately, would that provide an opportunity to monetize, it may. But I think what we have to do is demonstrate first the value in the assets. And I think we are doing that well. We will talk to you Phase 1. We are doing it well with Phase 2, and we need to do it with BirAllah. So I think the work that we will undertake this year will be an important part of that. And I think that the backdrop – the macro backdrop for LNG is only supporting the inherent value of those assets.

Great. Thank you.

Great. Thanks.

Our next question comes from the line of James Carmichael with Berenberg. You may proceed with your question.

Hi. Thanks guys. Just a couple of quick ones. I guess just press on Winterfell. In the release, it says targeting a lower carbon development that we develop. So, just sort of wondering what that really means lower than what I suppose? And how are you going to look to achieve that through the development? And then just a quick second one, apologies if I missed this earlier. And I appreciate it’s difficult to be precise, but is there anything that you can or have said on the timing of likely timing of preemption? Thanks.

Yes. I will do the preemption first, James. The first step in the process was to agree all the transaction documents with KEL, and we worked very closely with them since they announced that we are going to preempt. That documentation is now complete and will be submitted shortly to GMPC and the Government of Ghana for their approval. So, the timing will, therefore, depend on that process. But in terms of ourselves and Tullow, I think we have made a lot of progress and the pipe work is done and will be submitted shortly. On Winterfell, I think the point we are making is simply the Gulf of Mexico, as you know, has a very low carbon intensity for its oil production, why? Because the reservoirs are typically driven by natural aquifers, so they don’t have a huge amount of water injection. And secondly, gas is piped for sure. The third thing, of course, is that you are using the existing facility. So, your incremental use of energy on those facilities to bring onboard a tieback is well. So, Winterfell will be a buyback. We will start with a two-well development. There is existing infrastructure around the field. And therefore, the combination of drive, not flaring and the use of existing facilities where the incremental energy demand, all of those meant for a lower carbon oil project. And that’s why one of the things I believe the Gulf of Mexico has a role to play is that it has the infrastructure in place that enables you to develop at a lower carbon quote. So, that’s the prescription of Winterfell and why we feel it’s an important part of our portfolio going forward.

Great. Understood. Thank you.

Thanks James.

Since there are no further questions at this time, I would like to bring the call to a close. Thanks to everyone for joining us today. You may disconnect your lines at this time. Thank you for your participation. Enjoy the rest of your day.