Good day, everyone, welcome to Kosmos Energy's Fourth Quarter and Full-Year 2022 Conference Call. As a reminder, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] 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 fourth quarter and full-year 2022 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 material, 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 U.K. and SEC filings. Please refer to our annual report, stock exchange announcement, and SEC filings for more details. These documents are available on our website. At this time, I will turn the call over to Andy.

Thanks, Jamie, and good morning and afternoon to everyone. Thank you for joining us today for our fourth quarter and full-year 2022 results call. As I normally do with our full-year results, I'll start today's presentation by taking a step back to talk about our strategy and how the solid progress we've made in 2022 has supported the delivery of that strategy. We'll then focus on 2023 an important year of inflection for the company. Turning to slide three, which looks at Kosmos' role in helping address the world's energy challenges. The world is grappling with a need for affordable, secure, and cleaner energy with a balanced approach require to address the three dimensions of this energy trilemma. Kosmos has the right strategy and portfolio at the right time to be part of the solution. We have an oil-weighted portfolio that could supply more of the energy the world needs today. We're investing in growing oil supply in each of our core production hubs with an emphasis on high-graded projects that yield low cost, lower carbon barrels that are highly cash generative. At the same time, we're working with our partners to bring new sources of natural gas into production. These projects address affordability and increase energy security by supplying more gas to global energy markets, as well as into domestic markets in Africa. This assists our host countries in two ways. First, the revenues from the export of LNG can be invested in critical infrastructure to promote economic development. And second, providing base load domestic gas supply will help expand access to electricity, a key goal in each of the countries where we work in Africa. Over the next year, we're targeting an increase in production of around 50% as we optimize current production and bring new projects online.…

Thanks, Andy, Turning to slide 11. As Andy said, 2022 was a record year for Kosmos with the financial highlights noted on this slide. We posted record revenue and EBITDAX for the year, helped by, oil prices, but also by the highly accretive acquisition of the Oxy Ghana assets in late 2021. Free cash flow was strong with around $350 million for the year, which enabled us to pay down over $400 million of debt during the year and we exited the year below our year-end net debt target of 1.5 times. We expect further progress on debt pay down in 2023 at current oil prices with our free cash flow back end loaded, due to the timing of CapEx and production increases. Turning to slide 12, which looks at the fourth quarter in more detail. 4Q numbers came in largely as expected, CapEx in the quarter was slightly higher than guidance due to the timing of accrued CapEx on Tortue, which we flagged as a possibility when we reported last quarter. Depreciation was lower than guidance due to an increase of reserves at Jubilee booked at year-end. And as you have seen in today's press release, we have booked an impairment on TEN, as now we forecast a more conservative activity set, which is deferred in time, based on last year's well results. The reduction to 2P reserves is fairly small at around 3.5%, however, the bulk of the impairment related to the timing and mix of reserves between oil and gas. We still believe TEN has significant potential, but it does carry more risk and therefore any future activity must compete for capital with other opportunities across our portfolio, which we'll touch on a bit later when we talk about the year ahead. With that, I'll hand it back to Andy.

Thanks, Neal. Looking forward to 2023, we expect this year to be a major inflection point for Kosmos, as we strive to bring new developments online with multiple catalysts expected across the portfolio. Starting in Ghana on slide 14. In late 2021, we materially enhanced our stake in Jubilee to almost 40% through the acquisition of Oxy's interest, because we believe in the upside in the field. In 2021, the field produced 75,000 barrels of oil per day and we expect it to increase by around 25% from that level to 95,000 barrels of oil per day this year, due to the startup of the Jubilee Southeast project, which is on track to come online at the end of next quarter. Jubilee is a big field, which continues to get bigger. From first production back in 2010, the total oil in place is more than doubled to around 2 billion barrels as the partnership has drilled more wells to given more productive horizons and proved up more resource. We're now working closely with our partners to drive a higher recovery factor, which combined with more oil in place could increase gross recoverable reserves to over 1 billion barrels of oil equivalent with less than 40% of that produced to-date. The partnership has identified more than 30 additional drilling locations, which should enable the production plateau at these higher levels for several years to come. Recent drilling programs have been excellent with three Jubilee Southeast wells drilled, all of which have come in ahead of expectations. The results have been encouraging from two dimensions. Firstly, the wells are located reserves in more oil horizons than expected, and secondly, the primary horizons have indicated connectivity to the main Jubilee field. We look forward to providing further updates on this important project over…

Thanks, Andy. Turning now to slide 20. With a busy year of activity, we remain committed to disciplined capital allocation. In 2023, we are targeting capital spend of between $700 million and $750 million, which is in line with 2022 levels as we continue to progress our three key developments. Approximately $250 million to $300 million is for maintenance activities across Ghana, EG and the Gulf of Mexico, which primarily includes our infill drilling programs and the subsea pump project in the Gulf of Mexico. $350 million to $400 million is related to our three key development projects, Jubilee Southeast, Tortue Phase 1 and Winterfell. Between $50 million and $100 million is planned for our ILX activities in the GoM and EG, as well as the appraisal of our greater gas resources in Mauritania and Senegal. We also remain committed to continued debt paydown. At current oil prices, we expect to generate around $100 million to $200 million of free cash flow this year before working capital, which is back-end loaded as we reach the anticipated inflection point of lower CapEx and higher production. All excess cash flow this year will be prioritized to debt repayment. We remain focused on debt paydown until we get leverage to below 1.5 times in a normalized oil price environment, which should come from both increased EBITDAX from higher oil production and continued reduction of absolute debt. When we reach that level, we have the potential for shareholder returns, which is an active conversation with our Board. But in the near-term, we see debt pay down as the best use of cash flow to ensure we continue to strengthen the financial resilience of the company. Turning to slide 21. Having outlined the capital plan for 2023 this slide shows the multiple catalysts we expect from that investment throughout the year. I don't plan to touch on every catalyst on the slide. But as you can see, there is a consistent stream of important milestones across each part of our portfolio. Already in the first two months of the year, we have finished drilling the Jubilee Southeast wells, which are expected online at the end of next quarter. On Tortue, the FPSO has left the shipyard in China. The wells have all been drilled and completed, and we've announced further progress on Phase 1. We'll be reporting on the rest of these catalysts as we move throughout the year. And as I mentioned on the prior slide, we expect to see a major inflection point in the second half of this year as CapEx ramps down and production ramps up in Ghana. It's going to be a busy and exciting year across all of our geographies. With that, I'll hand it back to Andy to wrap up today's presentation.

Thanks, Neal. Turning to Slide 22 to conclude today's presentation. Kosmos has a differentiated strategy that we pursued countercyclically over the last five years. This has built a high-quality, diverse portfolio of low-cost, lower carbon oil assets, low-cost, lower carbon gas assets, which have longevity, a 2P reserve life of over 20-years. We plan to deliver around 50% growth in production between 2022 and 2024, and these assets have the potential to generate significant free cash flow with a major inflection point expected midyear as production grows and CapEx starts to fall. A key differentiator of our portfolio is our deep hopper of future gas and LNG opportunities, which have exposure to premium international pricing. And finally, we have a management team focused on creating value for our investors with a clear strategy and rigorous capital discipline. Thank you. And I'd now like to turn the call over to the Operator to open the session for questions.

Thank you. We will now be conducting a question-and-answer session. [Operator Instructions] Our first questions come from the line of Charles Meade with Johnson Rice. Please proceed with your question.

Good morning, Andy, Neal and to the rest of the Kosmos team there.

Good morning, Charles.

Good morning, Charles.

I wonder if you could talk us through, I guess, the process of selecting the gravity-based structure for Phase 2 of Tortue. And I'm not as familiar with those as a solution. So I'm curious why the departure from the design of Phase 1 being FLNG and what are the relative advantages of this gravity-based design concept? And what perhaps are some of the compromises that go along with those advantages?

Yes. Thanks, Charles. What don't I sort of start at the top. Clearly, BP as well communicated the decision around the Phase 2 concept decision. And I would say that all the partners, the governments, the NOCs, BP, Kosmos are aligned around building a West African Energy Hub. And ultimately, it's about alignment of strategy of developing resilient hydrocarbons for the energy transition. And Phase 2 is an important next step on that journey. I'm sure we'll get questions across many callers around the concept. So why don't I sort of address sort of three big questions, why the concept, the timing and the cost. I think when you look at the concept, we did a lot of work with the government, as I discussed, I think three months ago around ensuring that we had properly evaluated the concept and primarily as we look to the changing market conditions, what was the right next step in the development of the significant gas resource. So the decision around the gravity-based structure for Phase 2 is primarily sort of three primary considerations. One is the fundamental cost efficiency of the concept versus alternatives I think the second issue, which is unique around the GBS is you have the opportunity to upscale the storage, and that actually creates operational efficiencies as we integrate Phase 1 and Phase 2. And I think the third element that contributed to the decision was flexibility around financing if we choose to go down that path and then ultimately, the cost of that financing. So those are the 3 things that sort of drove the selection of the GBS for the midstream, but it's sort of worth, I think, reiterating that we have a Phase 2 concept, which is going to leverage heavily the infrastructure from Phase 1…

Yes. It is. Thank for your comments, Andy. It's an exciting prospect and when we're going to be able to follow for a while here. My follow-up, Jubilee Southeast, you made a couple of comments in your prepared remarks about and I think you also had some in the press release that not only did you establish pressure connectivity with the main field pays in Jubilee proper, but that you found -- it seems like you found maybe some new sand, some new reservoirs.

Yes.

And that is a -- that's a near-term upside for you guys, it seems like. So I wonder if you could perhaps elaborate a bit on your prepared remarks there.

You know, look you know. I think those three wells that we've drilled now in Jubilee Southeast were important. We're obviously testing an expansion of the field. From the slide that we included with our presentation you can see the step out of the field to the Southeast. And so important that those wells actually delivered the subsurface results that we were hoping for. And actually, it was more than we'd hope for. We -- as you say, there were a couple of things that were important. We believe that we have the indication of connectivity to the main field, which clearly sort of says that there was additional resource sort of inboard of the wells that we drilled. And then we found some deeper horizons. So I think if you step back from the detail Charles, you're absolutely right. Jubilee, as we said, is a big field gets bigger. We're continuing to see upside from the development of the field. And from a near-term perspective, having sort of derisk the subsurface now for Jubilee Southeast, at least for the initial phase of the field, we think there's additional follow-on potential. There were 30 development locations that we found, which gives you an indication, I think, of the longevity of the plateau that we can build.

Great. Thank you for your comments, Andy.

Great. Thanks, Charles. Appreciate it.

Thank you. Our next questions come from the line of Alex Smith with Investec. Please proceed with your questions.

Hi, guys there. Thanks for the call today. Just a question on TEN for me, please, today, just given the impairment. It looks like a decision has been taken on the back of the two strategic wells and the Greater [Indiscernible] area back in 2022. So it would be good to hear your views on the medium-term prospects for that asset? And any opportunities you feel there could be to kind of get things back on track and grow the area, especially maybe the opportunity for gas for TEN as opposed to oil in terms of growth, given that gas agreements are being signed with the government. So any kind of clear views on TEN would be great. Thank you.

Thanks, Alex. Good question. Look, when you step back from it from a reserves perspective, it was roughly more 3.5%. So there was some reduction in oil offset by some additions of gas. So sort of on a reserve basis, a relatively small impact across that trigger then the assessment against the ceiling test. I think when we look at the investment in TEN, we actually see less capital going in, therefore, a more conservative development case. So there is future development in the field, but we are going to target lower risk areas where we have good well control. And fundamentally, for Kosmos, it's about how would that development therefore compete with other opportunities that we have in our portfolio. Clearly, in the material today, we talked about the deep hopper of opportunities that we have in Mauritania and Senegal, opportunities that are opening up in the Gulf of Mexico and in Equitorial Guinea. So I think ultimately, this is about quality through choice and therefore, where TEN would rank in our future opportunities. So we do see future potential. It will be a combination in TEN of both oil and gas. But clearly, it's smaller than we'd anticipated, and therefore, the decision as we look at the capital allocation to take the impairment.

Both, very clear. Thank you.

Thanks, Alex.

Thank you. Our next questions come from the line of Neil Mehta with Goldman Sachs. Please proceed with your question.

Hey, good morning, Andy, Neil and team. Thank you. So congratulations to you guys on getting the FPSO moving towards West Africa. I just would love your perspective on what are the gating items that we should be thinking about, about getting to first gas by the end of the year at Tortue Phase 1?

Yes. Thanks, Neil. We've achieved a lot on the project. And as you say, it's not done yet, but we continue to make progress quarter-on-quarter. The FPSO is an important delivery in the first quarter, and we anticipate it being in location in the field in the second quarter, so that's clearly a milestone for you to track. The FLNG vessel is targeted to leave Singapore in the second quarter getting there in the third quarter. So that's again an important milestone for you to track. In terms of the drilling of the wells sort of all complete, done, the completions flowed back and we're very positive about the well results. As we said in our remarks, we've achieved very significantly higher supplies for Phase 1 liquefaction so we feel good about the Southeast. We also feel very good about the hub terminal. I think we included some pictures in the deck, which show that the construction is complete, commissioning underway. And the last terminal will be ready to receive the FLNG vessel when it arrives in the third quarter. So really now, it's about the completion of the subsea installation. The Amazon vessel is on location in the field now. We'll complete the lay of the deepwater pipeline and then we start to install the structures. So I think as you sort of think about it, you're really into the completion of construction of the subsea through the third quarter, beginning of the fourth quarter, mechanically complete, which then enables first gas in the fourth quarter. So the big things to look at are, obviously, the arrival of the FPSO and its anchoring in position, the arrival of the FLNG vessel and it's looking at connection to the hub terminal, the completion of the installation of the deepwater pipeline and then the mechanical completion of the subsea equipment with the installation of the subsea equipment. Those are the big things. And as BP indicated in their results, I think the closer we get to it, the more confident we get around the delivery of gas by the end of the year.

This is the -- the follow-up question is a tricky one because maybe not all the moving pieces are there, so feel free to pass on it. But you gave a 2023 free cash flow number of $100 million to $200 million at current prices. I think for a lot of investors, what they're really planning for is 2024 because at that point, you've got Phase 1 coming online to get that big inflection. Is there any parameters that you can provide around what the free cash flow could look like ex Phase 2 where we haven't gotten to FID yet?

I'm going to give Neal a minute to think about the answer to that question, Neil. But I think it's a great question because what we're talking about is the inflection point that is occurring in ‘23 for Kosmos. And mid-2023 middle of this year, we're going to start to see first product from Jubilee Southeast, which is a significant contribution to the growth in production. We obviously see an end of the capital going into that project. We then go through the back end of the year, and we see a continuing decline in CapEx as Tortue Phase 1 is complete. And then we go into the beginning of F ’24 we’ll start-up of production at the back end of ‘23 on Tortue and then the startup of production in Winterfell at the end of the first quarter. So I think the most important thing is you're going to see a progressive increase in our free cash flow quarter-on-quarter as we go through the second half of this year into the first half of next year. And then once we're we have Winterfell on then you're starting to get to a sort of plateau number. Yes, so that inflection is really close. We're not far away now. The forecasting of free cash flow in ‘23 is going to be dependent on the exact timing of those projects. Could you move to ‘24, Neal?

Yes. So without giving new numbers, Neil I’d say all the things Andy said structurally are still sort of in play, which is sort of operating cash flow increases to the sort of maintenance or the CapEx required for the business to maintain that production certainly comes down quite a bit. I think the key piece that will continue to progress on top of that, we'll be we've got some choices then to make around sort of where do we redirect that incremental free cash flow. And I think we feel good and as we've said in the past around being able to direct cash flow towards future growth, high graded on to the projects that we want, continued debt paydown to get the balance sheet into a stronger, more resilient place and then an additional piece on top of that for shareholder returns. And so I think we should be unique in that ability to do all three, given the quality of the portfolio and kind of where we are, and that's certainly where we're taking it.

Thank you both.

Thank you. Our next questions come from the line of Subash Chandra with The Benchmark. Please proceed with your questions.

Yes, hi thank you. A couple of questions, follow-ups, I guess, on the gravity base. First is, how do you compare cycle times post FID for that versus floating? And what do you think about sort of the novelty of gravity base, at least for this purpose? Do you think it's -- it actually increases the risk or the operational risk or decrease is it?

Yes. No, good questions, thanks, Subash. The -- in terms of the cycle time, we would see the cycle time being very competitive with floating. I think simply because you've got a broader access to construction yards, shipyards relatively full at the moment. So I think you have a broader contracting base to draw upon. So we see no disbenefit from a contract cycle time. In terms of the novelty of it, it's a proven development approach, it's been used elsewhere. There are proven designs that have both a concrete base and a steel base, so we don't see any increased complexity associated with the approach. In some respects, it's a very straightforward piece of design and engineering that's been proven. And as a base structure, it obviously gives you a very simple architecture then for putting the FLNG trains on a very simple sort of top side. So we think it has a lot of benefit in terms of both the contracting strategy, the access to different providers and ultimately, the architecture that you create. So when you look at all of those combined, we think that it's the right approach. As I say, we looked at it from a capital efficiency perspective, which I've talked about, which is both cost and time. We looked at it from the ability to sort of create incremental operational efficiencies from fine-tuning the storage capacity and then greater flexibility to do that. And then if we chose from a financing perspective, we could create greater flexibility there. So I think we don't see any increased technical risk, in fact, probably nothing there what we feel we're taking there's any disbenefit to it. And I think in cycle times, it's absolutely competitive.

Hey, got it. Makes sense. A follow-up. The Kodiak workover, what do you think that could do for Gulf volumes? How do you think of if everything worked out, exit Gulf volumes in ‘23?

Yes. Well, I think we're -- great just to go back, obviously, the sidetrack well, we've had some skin issues. We've done an investigation, partners involved. We believe we have an effective way to intervene on the well work over the well and anticipate that it's going to execute in the, sort of, back-end of the third quarter around the third quarter. So we'll have in the production impact in the fourth quarter. I think in terms of the volumes probably coming from the well, we could probably around what Neal, double...

1 to 2,000 barrels a day.

Yes, a couple of thousand barrels a day net increase Subash. I think that's sort of -- it could be greater than that, but that's sort of what we're targeting.

Okay. Thank you very much.

Great. Thank you.

Thank you. Our next questions come from the line of James Hosie with Barclays. Please proceed with your questions.

Hi, there. Thanks for the presentation. So it's encouraging to see all the updates on Tortue. I'm just wondering if you want or need LNG offtake contracts before you sanction Phase 2? And then also there's any update on the possibility of redirecting some of your Phase 1 cargoes to realize some of the upside to your contracted price?

Yes, good question, James. Fundamentally, Phase 2 is different from Phase 1. The capital that's involved is significantly lower. And therefore, we believe we absolutely will not require a full sale of the contracts before we sanction. I think that with the announcement now of Phase 2 in terms of the concept and the scale and the timing of the project, we intend to engage in the market in this year to look at options that we have around flexibility on sales. And without wanting to preempt that process, I would say there will be an element of fixed to it. We'll have to review what indexes we choose and how we manifest. And I believe that we will have an element of spot in it as well to be able to fully capture upside. So we will not have to have sold all of the gas at FID. And so the FID is sort of separating from that, whereas when we're at Phase 1, it was very much linked. On Phase 1 with the cargo opportunities, we continue to make progress on that. We have engaged now with a sort of high-graded list of potential buyers. We're working with those buyers on a contract structure, which we believe will give us the best opportunity to capture the upside. And we anticipate that we would be in a position to sort of select the high-graded buyer and the contract structure probably in the first half of this year. With regard to BP Gas Marketing, we've continued to debate, discuss with them the contract structure. There's clearly a difference of opinion between us in terms of how it would actually operate, so when you have a disagreement amongst friends, we've gone to a third-party. So we have agreed to go to arbitration and have the contract interpreted for us. And this is actually a good thing. It's a positive outcome, because it allows us to get everything clear before we would start to reuse those cargo optimization options, which comes at the end of the commissioning period, which is sort of around the middle of ‘24. So getting everything lined out and sorted out in terms of how it would actually work is an important step forward. And we'd have all of that sorted out, I think, within a year as we go through that process. So those are the key updates. But going to the market now with Phase 2 at the same time as we're discussing Phase 1 allows us to get a really good understanding of the sort of fixed nature of the future contracts and the spot nature and then optimizing that between Phase 1 and Phase 2.

Okay. I guess, a follow-up for me just if I just wonder a little bit about the future project you've got both in Senegal and Mauritania. I guess we've seen some press reports that, I guess, naturally indicate the country is very eager for you to get on and develop them. Is there increasing pressure on yourselves in BP to commit to Yakaar-Teranga or is it just noise?

No. Look, I think it's actually a positive, James. I wouldn't see it as a negative. As I sort of step back, I think yes, real alignment amongst the government, the NSCs, BP, Kosmos around the development of our resources. And again, from a BP perspective, they view it as a key part of their strategy for the development of Brazilian hydrocarbons. So I think we're moving forward on both of Yakaar-Teranga and BirAllah. Yakaar-Teranga will have a domestic element to it. Clearly, the project is aimed at displacing heavy fuel -- expensive heavy fuel on for power generation in Senegal and enables us to start the project in that way with a competitive domestic gas project with the option then of LNG export. In Mauritania, the -- there is a difference, because you're looking primarily at an LNG scheme there. And again, we're looking at a way in which we can get an efficient phased approach that uses some existing infrastructure in a port in Mauritania. So for us, it is about how do we continue to progress those projects and that absolute alignment between BP and Kosmos to do that, do it in a way where we come up with really competitive schemes that compete. And yes, ultimately, there may be a choice within Kosmos around, which ones we invest in and which ones we bring in partners. But I think that's ultimately a great problem for us to have going forward. So I don't feel any pressure. I think it's great. I think we have a resource the world needs and we're addressing energy security in Europe. We're creating affordable power in Africa and ultimately contributing to a lower carbon fusion. If we can do all of that, I think we're only -- we will only create value for Kosmos' shareholders. So I'm excited about it in Phase 1 moving forward is just a signal, I think, of the progress that we're making.

Good. That’s great answer. Thank you very much.

Great. Thanks, James.

Thank you. Our next questions come from the line of Mark Wilson with Jefferies. Please proceed with your questions.

Alright. Thank you, I got two questions, one on the GBS concept and one on exploration, please. On the GBS, you've talked before about the floating concept for Phase 2 being approximately $1 billion CapEx. Now that was a few years ago. We've had inflation and it appears to be a bigger scale. But I'm just wondering if you can give any sort of parameters to help us on what you think CapEx of that concept select could be, maybe as a percentage of Tortue Phase 1 as one example. Also on the GBS one thing -- I was going say one thing that strikes me -- yes, one thing that strikes me is you built all these concrete caissons for Tortue Phase 1, so there's a big knowledge of using concrete to build large things in Senegal. So is that part of the concept like as well, local content and possibly building it there? Thank you.

Yes. All right, Mark. Yes, we'll do that one first. Just I think just sort of when we talked about costs in the past, and we talked about the $1 billion. It was clearly around at the time the upstream component on the basis of the sort of the lease midstream. Yes, so I think those were early costs, and I think that we'll do a lot better than that on the upstream now as we've done further work to delineate what's actually going to be required to debottleneck the infrastructure that we have in place today to take in another gas flow of around 400 million, 450 million standard cubic feet a day that you need to provide for 2.5 million to 3 million tons of LNG liquefaction. So I think that's the first point, yes. So I think in terms of that $1 billion number, the actual upstream cost, I think, is going to be below that now that we've done the work. Then you come to the midstream. And clearly, we've got options to release finance, which we obviously, that would -- the capital will not be on our books or do we capitalize and that's a decision that we have yet to make. But clearly, when we look at the GBS as an option, we believe whether it's a capital or whether it's leased, it is more cost effective than going down the FLNG route. Does that make sense?

It does, yes, definitely. And then on that local content point, given, as I say, the Phase 1 [Indiscernible] work that's gone on in Senegal?

No, yes, absolutely, Mark. And again, what we're looking to do is build that local content as we look at Phase 2. What I don't want to do is sort of preempt the work that we'll do with the market as there are various ways of doing it. We can clearly do it with a concrete base. You can do it with a steel base and what we need to do is go out, work it with the market to come up with the most cost-effective way of doing it, and one that is aligned with the local content. So that -- I think what you're unpicking is we have some real optionality now of how we create the most capital-efficient -- most capitally efficient way of doing it and leveraging some of the knowledge that we've built from the past. So we see this as we say, it is absolutely the most cost-effective way to move forward. And it gives us the most flexibility on storage size and financing.

Got it. Okay, thank you. Just one quick follow-up on a couple of really quite punching exploration wells in the coming year at Tiberius Akeng Deep. On that -- on the Akeng Deep, could you remind us who your partners are in Block S, please?

So our partners in...

[Indiscernible] partners in blockchain [Tweneboa] (ph) and Trident.

And [indiscernible] yes.

Okay, very good. Thank you.

Yes, [Indiscernible] yes great question, Mark. Important about that is that, again, we see it as being highly prospective. This is an untested deeper objective. Clearly, between the source rock and the currently producing horizons in Ceiba and Okume with a very solid away structure. And the great thing about it is then the alignment around the partnership that enables us then to bring it back to the existing capacity that we have in Ceiba and Okume. So no, we're excited by it. I think it's a great exploration prospect. But actually, the CapEx again it's a very low-cost F&D because of the existing capacity in Ceiba and Akume and the fact that we have alignment amongst the partnership.

Got it. Appreciate the color. Thank you.

Great. Thanks, Mark.

Thank you. [Operator Instructions] Our next questions come from the line of Matt Smith with Bank of America. Please proceed with your questions.

Hi, there. Thanks very much. I just wondered if I come back to the free cash flow guidance for 2023, please. And I guess just in light of how that compares to the results in 2022, given the production, I guess, broadly flat. It's slightly up, CapEx broadly the same. Clearly, there's a macro element. But I think on -- due to the hedges in 2022, your post-hedge realized price wasn't too far from what we see on this group today. So I just want to make sure if I'm missing anything in terms of moving parts for free cash flow in 2023, please? And then I think a related follow-up would probably be just to check on shareholder returns. Am I interpreting the comments correctly that that's probably a story for 2024 if we're looking at further deleveraging across 2023, please?

Yes, sure, Matt. The -- yes, so when you sort of reconcile ‘23 versus ‘22, clearly, production is higher, and we're sort of forecasting a lower sort of oil price, which is the biggest sort of impact to that free cash flow number. As you noted, hedges aren't a headwind. We've put in the floors around in the 70s and have ceilings up to 110 on average. And so we've got much better access to higher oil prices as the year goes down -- as the year goes on. OpEx clearly is trending slightly higher, but it's lower on a per barrel basis given sort of the increased amount of production we're running through. Just from a free cash flow perspective, as you said, sort of CapEx is about the same. There is a bit higher interest cost, just given we do have some variable rate debt and then cash taxes are a bit higher, partially just reflecting timing. So easy taxes are paid sort of year arrears. And therefore, the benefit we got from last year will pay a little higher tax on that front this year. But on the whole, we generated about $400 million to $350 million of free cash flow last year at $100 oil. The sensitivity is still around $100 for every $5 in oil price, and we're assuming sort of oil price between sort of 80% and 85%. So that's the biggest portion of the difference…

Perfect. Thank you very much. And just on the shareholder distributions.

Sorry, can you repeat the question Matt.

Yes. Sure. Sorry, I just wanted to double check whether I was interpreting the comments correctly. I think you referenced that 100% of free cash flow in ‘23 will go to deviate the balance sheet. So therefore, are we thinking about shareholder returns B&A 2024 story?

Correct. Yes. I think that's the way to think about it. I think as we get towards through the sort of midyear inflection point, we'll be closer to the point to where we can provide sort of external guidance in terms of what that looks like in ‘24 and beyond. I think there are clearly a number of moving parts, both on the oil price and the project side that we are working through. And like I said, it is an active discussion with the Board in terms of what is the quantum and inform of those -- of that shareholder return policy. But it is a 24 plus given sort of oil prices backed off a bit from where they were six months ago.

Perfect. Well, thank very much, guys. Appreciate the color.

Great. Thanks, Matt.

Thank you. At this time, we have reached the end of our question-and-answer session. With that, I would like to bring the call to a close. Thanks to everyone for joining today. You may disconnect your lines at this time, and thank you for your participation.