Kosmos Energy Ltd. (NYSE:KOS) Q3 2023 Earnings Call Transcript

Kosmos Energy Ltd. (NYSE:KOS) Q3 2023 Earnings Call Transcript November 6, 2023

Kosmos Energy Ltd. misses on earnings expectations. Reported EPS is $0.1771 EPS, expectations were $0.21.

Operator: Good day, everyone. Welcome to Kosmos Energy’s Third Quarter 2023 Conference Call. As 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. You may begin.

Jamie Buckland: Thank you, operator, and thanks to everyone for joining us today. This morning we issued our third 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 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 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.

Andrew Inglis: Thanks, Jamie. And good morning and afternoon to everyone. Thank you for joining us today for our third quarter results call. Since our last call, we continue to make good progress on our strategic objectives with several important recent developments. I’ll talk about these in more detail in today’s material, as well as giving an update on the quarter. I’ll then hand over the call to Neal to take you through the financials before wrapping up the presentation and opening the call for Q&A. Turning to slide three, at Kosmos, we’re pursuing a clear and consistent strategy to provide the world with the energy it needs today, while working hard to bring down the carbon intensity of our portfolio and providing the world with the cleaner energy it needs for the future.

To achieve this, we’re executing a differentiated set of projects that are focused on advantaged, low-cost, lower-carbon oil and advantaged, low-cost, lower-carbon gas. This slide shows the progress we are making. First, on production growth, we set a target to grow our production in the second half of 2022 by around 50% to the second half of 2024 from three core development projects, Jubilee Southeast, Tortue Phase 1, and Winterfell. In the third quarter, we brought the first of the development projects, Jubilee Southeast, online, which increased Jubilee gross production to around 100,000 barrels of oil a day, up almost 50% from the production levels seen in the first half of the year. I’ll talk more about Jubilee in the following slides, but we’re pleased with the progress being made.

We have more expected in the coming months. Second, our two remaining developments continue to progress. On Winterfell, the partnership recently completed the first production well, an important milestone for the project. At Tortue, the hub terminal was completed and handed over to operations, and we have re-contracted the subsea work scope, which was previously on the critical path. Third, in recent weeks, we have deepened our portfolio of high-quality, advantaged, oil and gas investment opportunities. In October, we announced a discovery with the Tiberius well in the Gulf of Mexico, and today we announced that we had assumed operatorship and increased our working interest in the world-scale, Yakaar Teranga Fields in Senegal, subject to customary government approvals.

We’re excited by both these projects, as we expect them to create the next leg of value growth for KOSMOS beyond 2024. More on both of these later in the presentation. The chart on the right of the slide is one we’ve shown before, which has been updated for these developments. It shows the progress we’re making against our longer-term strategic objectives. The first meaningful step up in production was in 3Q, with production rising 17% from the second quarter, with further upside potential from Jubilee, and then the planned start-up of Tortue Phase 1 and Winterfell in 2024. We expect this growth to drive a material step-up in pre-cash flow as these projects are delivered, enabling the Company to further de-lever and ultimately to fund shareholder returns when leverage falls below our target level.

Looking beyond that, we have a deep hopper of high-quality operated and non-operated growth options across both short-cycle oil and long-dated gas that will continue to differentiate KOSMOS from our peers over the coming years. We plan to balance the pace and working interests of these future projects to ensure we can manage our growth and generate material pre-cash flow. Turning to slide 4, which looks at the quarter’s operational highlights in more detail. Net production around 68,000 barrels of oil equivalent per day was in-line with guidance, and an increase of approximately 17% versus the previous quarter due to the Jubilee South East start-up. Jubilee produced an average of around 96,000 barrels of oil per day gross during the quarter, an increase of over 30% versus the previous quarter, with three producer wells coming online across Jubilee South East and the main field.

While we’ve been successful in production wells, there were some delays in providing the necessary water injection, which has had a knock-on impact on near-term production, which I’ll talk about in more detail. On TEN, production in the quarter of around 15,000 barrels of oil per day was in-line with expectations and lower than the previous quarter due to a planned two-week shutdown. While working on the maintenance of the FPSO, we modified the gas train, and the rerouted gas is now being re-injected into the Entome field to support reservoir pressure and maintain production levels. This has resulted in around a 75% reduction in flaring, a major step towards our goal to eliminate routine flaring by 2026. The amended TEN plan of development and combined TEN and Jubilee gas sales agreement has been submitted to the Ministry of Energy for approval.

In the interim, we’ve extended the Jubilee gas sales agreement through the end of November at a price of $2.90 per MMBtu. Next to all Guinea, gross production averaged around 25,400 barrels per day during the quarter, in-line with expectations. The infill drain campaign is expected to start this quarter with a rig now in country. Ahead of the three planned infill wells, the rig is planning to carry out two work-overs on the Sabre field, which should boost the year-end production rate before the new wells start coming online around the end of the first quarter. The operator expects the work-over and infill campaign to add around 10,000 barrels of oil a day to gross production. Post our infill campaign, the Akeng Deep infrastructure-led exploration well is on track to spud early in the second quarter of 2024.

In the Gulf of Mexico, net production was approximately 15,700 barrels of oil equivalent per day, ahead of guidance due to lower-than-anticipated storm activity. At all jobs, the subsea pump project continues to make good progress and is expected online in 2024. Kodiak production continues to perform in-line with expectations and will be supported by the work-over scheduled for mid-2024. On Winterfell, the partnership continues to make good progress. The rig arrives in the third quarter and we have successfully completed the first of the three wells, an important milestone for the project. First oil is on track for the end of the first quarter of 2024. Post-quarter end, we announced the discovery of the Tiberius well in Keighley Canyon, which I’ll talk about in more detail later in the presentation.

Turning to slide five, the start-up of the Jubilee Southeast development has driven a material uplift in production at Jubilee. Three producers were brought online during the quarter, taking gross production up to around 100,000 barrels of oil per day, a level not seen for several years. As I mentioned earlier, water injection rates in 3Q were lower than planned. This is partly due to lower uptime on the water injection pumps and partly due to the delay in bringing two water injection wells online, which were originally planned to start in 3Q. Post-quarter end, we did bring these two water injection wells online and are now ramping up water injections to support the elevated levels of production. The partnership had previously assumed we would farm out the drilling rig in Ghana in the fourth quarter.

This was to allow time to assess our initial three wells in Jubilee and high-grade the next set of wells. However, given the success in our well selection and drilling execution, we are now planning to accelerate an additional producer and water injector into the fourth quarter from 2024. This should allow for continued Jubilee production growth into 2024, with both wells expected online early in the new-year. The acceleration of this activity results in an increase in 2023 CapEx of around $30 million net to Kosmos. However, the expected returns are very high with quick payback. As a result of the lower water injection rates, the operator is now forecasting that Jubilee will produce around 85,000 barrels of oil per day gross for 2023, down from its previous estimate of 90,000.

This decrease is driving our lower production guidance for the year and is expected to result in one less 2023 cargo from Jubilee than previously forecast. It is just a timing issue, and our view of 2024 production is unchanged, with a shortfall in 2023 expected to be made up in 2024. While there are always challenges in bringing a new project online and optimising overall field performance, we are excited about the future potential of Jubilee and are continuing to work well with the operator to maximise cash flow from the field. Turning to slide 6, this is a slide we have used over the years to provide a status update on the key work-streams on the Tortue LNG project. On the hub terminal, construction is finished and handover to operations has been completed.

Within the quarter, we also made important progress on the subsea work scope, which was previously on the critical path to first gas. Following the performance issues with the previous pipeline vessel, the subsea work has been re-contracted. All seas and Saipem have now been brought in to finish the deepwater pipeline and the infill flow lines, with work expected to start in early December and finish in the first quarter of 2024. On the FLNG, sail away of the vessel is expected later this quarter, with arrival expected early next year. The partnership is currently working with Golar to identify ways to advance commissioning of the vessel. The critical path to first gas on phase 1 of the Tortue project is now through the arrival, hook-up and commissioning of the FPSO.

The delivery of gas in the first quarter of 2024, as signalled by BP, the operator, in its third quarter results last week, depends on the execution of this workstream, which has the potential to slip into the second quarter of 2024. Turning to Slide 7, beyond these key projects, we have been focused on defining the next set of growth projects for the Company, targeting high-quality, advantaged oil and gas investment opportunities with operating control. Today, KOSMOS announced that it increased its interest in assumed operatorship of the Yakaar Teranga field in Senegal, subject to customary government approvals. Yakaar Teranga is a world-scale gas resource, with approximately 25 trillion cubic feet of gas in place, and was the largest discovery in the world in 2017.

It is advantaged gas with negative CO2, located approximately 75 kilometres from the Dakar Peninsula, enabling a low-cost development. KOSMOS’s working interest in Yakaar Teranga will increase to 90%, with Petrosen holding the remaining 10%. Our aim is for Petrosen to participate as an equal partner in the full value chain with a greater working interest. KOSMOS is working with Petrosen and the Government of Senegal on an innovative development solution, prioritising cost-competitive gas to Senegal’s rapidly growing domestic market, combined with a floating LNG facility, targeting exports into international markets. Petrosen’s Director-General stated in today’s press release that Yakaar Teranga is a strategic project and supports the Plan Senegal et Merchant, which aims to provide affordable, abundant and cleaner energy for the country.

KOSMOS and Petrosen plan to evaluate partnership strategies with the objective of creating an aligned partnership, possessing the necessary upstream and midstream expertise, coupled with access to cost-effective financing and access to international LNG markets. Turning to slide 8, last month KOSMOS announced a successful discovery of the Tiberius infrastructure-led exploration well in the Gulf of Mexico, where KOSMOS is operator and has a 33.34% interest alongside Oxy and Equinor. Tiberius is a four-way structural trap in the outboard Wilcox trend, which was drilled using the partnership’s ocean bottom node seismic. This modern seismic technology generates an enhanced image of the prospect, which helps refine the location of the exploration well and de-risk the future development program.

The image on the slide shows the Tiberius exploration well, which was drilled on the crest of the structure in the central fog block, with additional upside potential in the neighbouring fog blocks. Technology improvements like OBN seismic are a game changer for the industry and allow us to have a much better understanding of the subsurface pre-drill. The well-discovered net oil column of around 250 feet, we were able to conduct an extensive logging program, recovering multiple fluid samples and sidewall cores. Initial analysis suggests a fluid quality similar to other nearby discoveries in the Wilcox trend. The fluid samples and cores have been sent to the lab for analysis that will enable us to better understand permeability and viscosity, which are key to confirming well flow rates in a future development.

We are now working with our partners on the planning of a phased development scheme, which targets first production in around two years. The preferred host platform would be the oxy-operated Lucius facility, located six miles to the northwest of the discovery, with key commercial terms of the production handling agreement agreed pre-drill. Success at Tiberius validates our proven base and infrastructure-led exploration strategy, targeting low-cost, lower-carbon, short-cycle oil opportunities to complement our deep hopper of long-dated, lower-carbon gas opportunities in West Africa. I’ll now hand over to Neal to take you through the financials.

Neal Shah: Thanks, Andy. Turning to Slide 9, production for the quarter was in-line with guidance. Gulf of Mexico was slightly ahead of expectations, offsetting the lower-than-anticipated production from Jubilee that Andy talked about earlier. OpEx was in-line with guidance and higher quarter-on-quarter as a result of the 110 cargo that we have in the year falling in the third quarter. As a reminder, TEN OpEx, which is higher than the rest of the assets in the portfolio is recognized when we have the listing. The guidance slide in the appendix shows OpEx falling down to normalized levels in the fourth quarter. CapEx is at the higher-end of our range that did include the extensive success case evaluation program associated with Tiberius that Andy mentioned on the previous slide.

Turning to Slide 10, during the third quarter, we saw a continued improvement in our financial position with leverage lower as a result of both increased EBITDAX and reduced net debt. We repaid the Gulf of Mexico loan within the quarter an important step towards simplifying the capital structure. Following the pay-down of the GoM term loan and the RBL amendment in October, Kosmos has no scheduled debt maturities until 2025. We’ve talked about reaching a cash flow inflection point as production rises and capital falls as our growth products are delivered. Our near-term priority with any cash generated is debt pay-down to bring leverage towards our long-term target of less than 1.5 times at mid-cycle oil price. With our floating debt more — now more expensive than our fixed debt, we are prioritizing the RBL, which allows us to maintain and grow available liquidity over time.

We anticipate that we still have a couple of quarters of higher CapEx ahead of us completing Tortue and Winterfell, after which, we expect debt reduction to accelerate as free cash flow ramps up meaningfully in the second half of next year. We continue to make good progress on our hedging targets for next year. In-line with previous practice, we are looking to hedge around 50% of the following year’s production, which allows us to fund the capital plan for the year. Using collar structures, we currently have around one-third of next year’s production hedged at an average floor of $69 per barrel with an average ceiling of around $94 per barrel. Looking forward at our 4Q guidance, which is included in the appendix, there are a few points I wanted to flag.

Full year ’23 production guidance is now expected to be approximately 63,000 barrels of oil equivalent per day due to the delayed start-up of Jubilee Southeast and reduced water injection levels. We raised full year GoM production guidance due to the back of storms, however, 4Q GoM production is lower than the third quarter due to both planned and unplanned downtime, which is expected to be largely complete this month. We also now expect total CapEx for the year to be around $800 million, reflecting the accelerated drilling in Jubilee in the fourth quarter and the increased activity at Tiberius following the successful well result. We still expect a step down in CapEx into ’24, particularly in the second half as we finish our capital spend of our three key projects.

With that, I’ll now hand it back to Andy to close today’s presentation.

Andrew Inglis: Thanks, Neal. Turning to Slide 11 to conclude today’s presentation. I started today’s presentation talking about the importance of having a clear and consistent strategy. So far in 2023, Kosmos has achieved multiple important milestones in the delivery of that strategy, which centers up well for further delivery in 2024. Whilst I don’t intend to dwell on all of the bullets on the slide, I want to focus on some key themes. Kosmos has a differentiated growth story, which we’ve started to deliver with the start-up of the Jubilee Southeast project in Ghana with more growth expected to come in 2024. We continue to progress our other development projects at Tortue and Winterfell, which are expected to drive another material production uplift in 2024 with Tortue providing further portfolio diversification both geographically and by adding a new multi-decade LNG revenue stream once online.

We are also expanding our medium- to long-term growth hopper with high-quality operated investment opportunities across both advantaged oil and gas through Tiberius and Yakaar Teranga. And finally, as we deliver increased free cash flow, we will prioritize debt pay-down until we reach our target leverage level, which is when we plan to look at shareholder returns. The Kosmos management team is excited by the future opportunity set in front of us and energized lever growth in value for our shareholders. Thank you. I’d now like to turn the call over to the operator to open the session for questions.

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Q&A Session

Operator: Thank you. [Operator Instructions] Our first question comes from Matthew Smith with Bank of America. Please proceed with your question.

Matthew Smith: Hi there, guys. Thanks very much. A few questions from me, if I could. The first one would be on Tortue CapEx. I think at the last earnings call, we noted that there is an element of uncertainty over the phasing and also I guess, the amount of additional CapEx to be incurred from the new subsea contractor. I think if I heard correctly, you didn’t sort of note that as a reason for the increased 2023 guidance. So should I take it that there might be some deferred CapEx from this change to 2024? That would be the first question. And the second one, if I could, on Tiberius, I appreciate there’s further analysis to be done here, but you’re able to just remind us of the pre-drill resource estimate that you had there, and where you feel like may have come out versus that, if you’re willing to comment.

And then lastly, squeeze a third on, if that’s okay, that’s just whether you can add anything on Tortue Phase two at this point. And I suppose the question that some investors would ask is, is there anything that we should read across from BP and their exit from Senegal in terms of their enthusiasm on the expansion at Tortue? Please.

Andrew Inglis: Yes. Thanks, Matt. Why don’t we split-up with three questions. I’ll let Neal talk about the Tortue CapEx. I’ll pick up Tiberius and then talk about Phase Tortue.

Neal Shah: Yes. So Matt, just on Tortue CapEx, yes. We mentioned last quarter, there would be a rephasing due to the subsea our overall view for ’23 hasn’t changed. Some of the CapEx is basically related to the subsea that was supposed to be in sort of the second quarter and third quarter as rephased the fourth quarter, and then ultimately, some of that slipped into ’24. And so ’23 is roughly the same. There is an additional amount of capital versus what we originally planned probably in the order of around $100 million net for Tortue in the ’24 time period.

Andrew Inglis: Okay. On Tiberius, Matt, we’re really encouraged by the initial exploration well. As we talked about in the material, we targeted the central fault block, and we believe that we probably in that central fold block de-risked around about a third of the potential that we had pre-drill. In terms of its development, we’ve did a pretty extensive logging program, which was part of the additional CapEx that we spent in ’23. So I think we’ve got a really good set of sidewalk cores, fluid samples, which gives us encouragement around being able to move ahead quickly with the development. We’ve obviously get all that analysis back from the labs. In the interim, we’ve already kicked off actually the planning of the tieback to Lucius.

I think within a week actually after the discovery was announced, the team had already put out the bid documents to build the subsea layout. So I’m actually quite pleased around the pace at which we’re moving and the fact that we have with that initial fault block a significant increment to production for Kosmos. And we’d anticipate that coming on within a couple of years. So again, sort of good progress. And I think the subsea architects will be laid out. There will be a single flow line initially. But with the addition of maybe two, maybe three additional wells from the additional fall blocks that we showed in the material. On Tortue Phase 2, I think sort of step back and actually sort of think about how it links into Yakaar Teranga, I’m sure there’ll be more questions around Yakaar Teranga.

But we have a very distinctive growth portfolio in Kosmos of advantaged low-cost gas adjacent to Europe. And our objective now is to phase the development of that in a way where we can not only grow but return capital to our shareholders. The first step of that is the completion of Tortue Phase 1 obviously, we’ve given you the forward time line for that. With control now of Yakaar Teranga, I think we can then position that as the next building block in that sequence. And I would imagine that Tortue Phase two could sit behind that. So we have a phase set of developments now where you’re building out around, I don’t know, 2.5 million tonnes of LNG, but doing it in a way where there’s control now with an operated project and doing it in a way where you’re limiting the capital outlay so that you have a credible and manageable capital profile.

So we’re pleased what the future looks like now, and we believe this is an important source of value growth for shareholders.

Operator: Our next question comes from Charles Meade with Johnson Rice. Please proceed with your question.

Charles Meade: Good morning, Andy and Neal and the rest of the Kosmos team there. Andy, I wonder if I could just pick up maybe just about where you left off. You said you’re sure there’d be more questions about Yakaar Teranga, and that’s what I’d like to ask about. I guess there’s two parts to this. One, can you just give us the bigger context of where Yakaar Teranga, how you chose to develop Tortue over Yakaar Teranga first. And where Yakaar Teranga kind of sits in the, I guess, in the — in your mind as far as the — is it number 2 after Tortue? And then also as part of that, I recognize that different companies that have different priorities and have different viewpoints. But how would you make the case for the value of Yakaar Teranga to Kosmos for people looking at BP and saying, well, if BP just walked away from this, why is it valuable?

Andrew Inglis: Yes. Thanks, Charles. As you say, all good questions. And maybe I’ll start at the end and sort of work back. Yakaar Teranga, is a distinctive gas resource. It has low CO2 content. It is close to shore, 75 kilometers of the Dakar Peninsula. And from both a domestic and an LNG perspective, it has a strong market pull. There’s a need to replace heavy fuel oil as a source of power in Senegal. And clearly, the Senegal is one of the closest sources, new sources of LNG to Europe. So you then sort of say, well, okay, how does that fit with various companies strategies? And I think to me, the — we’re at a point now in the life cycle of the energy transition where different companies are placing different bets. And I suppose nothing was clearer on that than the two big announcements over the last couple of weeks here in the U.S. And I think that strategic context actually influences the way that people look at various investment opportunities.

As I said, I think Kosmos believes that this gas is distinctive and is well described. Well described, what do I mean by that? I mean that in Tortue, we drilled four exploration and appraisal wells and a DST that enabled us to calibrate the seismic that led to four successful development wells. It’s a huge amount of subsurface data that directly correlates to Yakaar Teranga, where we have three exploration and appraisal wells. So we believe we have a well-described subsurface and are confident in its ability to deliver a very commercial project. We also believe that’s a low-cost solution to development, given the geographic situation close to the Dakar Peninsula. Now I would say that BP doesn’t have the same view. And I think it’s not ultimately I think have influenced.

It is ultimately heavily influenced by the strategic context of where they are allocating capital and their ability to envisage a commercial development. So I think this is a great opportunity for the company. We’ve inherited our share. We started at 90%. Our objective is for Petrosen to build their share so that they are an equal partner with ourselves and whoever comes in. We’d anticipate, therefore, 25% to maybe 33% shares. We’ve got work to do now on fully describing the concept that we laid out in the material, and we’ve got work to do to bring in a partner and underpin the financing. But with all of that done, this is an incredibly commercial opportunity, but it has to be done in a low-cost way that fully leverages all of the subsurface knowledge.

So that’s the essence of maybe of the difference. But I see is a huge opportunity for the company. And look, as you know, it’s not without precedent. So you’re very familiar with the Gulf of Mexico. You go back to something like Shenandoah. I think two large companies gave it up. a smaller company now has it and is now executing a very competitive scale project now. So those things many presidents in the industry of that. And I think the energy transition has simply made those differences more acute, and therefore, the opportunity is greater.

Charles Meade: That’s helpful elaboration, Andy. And if I could go back to your prepared comments, you talked about the two additional wells you’re going to drill at Jubilee and Jubilee Southeast, I just — I want to make sure I understood. So you guys were going to farm out the rig, but then you decided you’ve got these two wells. One is in Jubilee, if I understand right, one is in Jubilee, one is in Jubilee Southeast, does this lead to a higher plateau or it’s just — or were these wells just kind of more reduce the volatility around that plateau in case you have some more of these water injection. Can you kind of frame it up for us what the…

Andrew Inglis: Yes. It’s simply really around accelerated activity out of ’24 into ’23, which allows us to actually build towards the facility limit faster. So that additional water injection well is important because it allows us to address some of the water injection issues that we’ve been experiencing. And then the second well is a producer, which would come on in ’24. And then we have an ongoing drilling program on Jubilee that would build with additional producers. So ultimately now, it’s about building to the facilities limit in terms of well capacity, probably building slightly beyond the facility is limits. So we have degree of well capacity in reserve and then holding the field at that level. So we’ve accelerated some capital out of ’24 into ’23 to allow us to build towards that facility limit faster.

Operator: Our next question is from Bob Brackett with Bernstein Research. Please proceed with your question.

Bob Brackett: Good morning. Acknowledging that you don’t yet have the ground truth of the sidewall core data for Tiberius. So the wire-line porosities in-line with what you expected pre-drill? And the follow-up related is, how do I think about the capital cost of developing Tiberius given that the host is some cost and given that potentially the wellbore just on cost.

Andrew Inglis: Yes. Bob, always good questions. The porosity was absolutely in-line with expectations yes. So is, as you’re well aware, the next step then is to do the labor to actually confirm permeability rather than it be a read across in porosity and then to finalize the fluid data with viscosity arm all of that, we can then optimize the completion design. So yes, everything is in-line with what we expected. It’s in-line with analogs that are from adjacent fields. So sort of so far so good. And as I said, to — we’re moving ahead with a really cost-effective development plan with the tie back to Lucius. Neal just pick-up on the capital of that.

Neal Shah: Yes. Just Bob, yes, you’re right. In terms of — yes, there’s minimal infrastructure to be laid and therefore, it should be very cost-effective tieback program. And we didn’t vision we developed it similar to how we’ve done Winterfell and other projects in terms of the staged phase development to where we have a single well EPS, where we install a full line of the facility and then grow the development over time with more information from the well in the reservoir over time. So I think we’ve talked about the past of sort of S&D in sort of $10 to $15 range generically. Yes, I think that’s — this would squarely fall in that range.

Operator: Our next question is from Neil Mehta with Goldman Sachs. Please proceed with your question

Neil Mehta: Good morning, team. Thanks for the update today. The first question I had was just around capital spending.. Can you bridge us from your previous CapEx guide to the current one? And how much of that was project related versus inflation. And as you think about 2024, recognizing you don’t have the full numbers, but how should we think about the fair way that we — to the extent you’re able to provide that?

Andrew Inglis: Yes. Great. I’ll have Neal pick that up. Neal?

Neal Shah: So yes, on ’23, I think the two biggest pieces were really around the Tortue acceleration that Andy talked about with that being $30 million and about $20 million of it was sort of the additional drilling sort of additional two wells or 1.5 wells in Ghana at Jubilee. There’s $30 million on that and then the $20 million was really additional drilling at Tiberius post the success and the extensive sort of logging campaigns. So that sort of took us from sort of — we were trending towards the high end of the range, and that basically moved us from 750 to 800. So that’s kind of the acceleration of that sort of what we call value-adding activity into ’23. If I look sort of going forward, I think we’ve talked about sort of a normalized CapEx, right, post our three big projects of, call it, 300 to 350 of maintenance and 200 to 250 of growth, which sort of gets you around 550 of steady-state CapEx for the company.

’24 is a bit of a transition year because we still have the completion of Tortue and Winterfell the residual CapEx related to those as well as the sort of steady-state CapEx. So again, we haven’t given it ’24 guidance yet. We’ll do that in February. But I expect that ’24 will fall in between the 2, where we are sort of this year and then sort of the steady-state level as we finish those two key projects.

Neil Mehta: The follow-up is just around Phase I and maybe you can get us a little bit more clarity around the work stream that you highlighted, which has the potential to slip into the second quarter. But as of now, you’re still on track for first gas in the first quarter can you get us into the field and give us more granularity, so we understand what specifically you’re talking about?

Andrew Inglis: Yes, no, sure, Neal. Yes, if you sort of go through the key work streams. We’ve talked about the hub terminals sort of being finished, handed over to operations. That was a big milestone in the quarter. You then look at the FLNG vessel, which will obviously be more in the hub terminal. That leaves Singapore around the — in this quarter, and it will get to site at the beginning of next year. So sort of not sitting on the critical path. The big breakthrough in the quarter was around getting all the subsea architecture finished, re-contracting with dual-seas and side-pen. That work starts early next month and with a clear program to complete in the first quarter. So I feel good about that. The piece that — the issue we’re asking with at the moment is just around the FPSO.

It’s actually an issue that’s sort of external to the vessel. The vessel has fair leads on it. The fairly are used in the permanent anchoring of the vessel on location. They have a sea fastening and in the voyage across to the East Coast of Africa. Those sea fastenings castings were damaged. The boats are currently sitting offshore at Durbin at the moment, and we’re looking to get access to the port in Durbin so that work to address the issue with the fair leads can be conducted. So that’s the thing where there’s a little bit of sort of uncertainty in the timing. So not a big issue, but it’s sort of — it is a very singular issue that we’re working. All that said is there’s work ongoing on the FPSO itself and all the top side, so we can get on with work to do with the pre-commissioning.

So when it does arrive on site, that work stream is shortened. So look, like with all big projects, it is about the integration of the pieces we’re clearly getting close, and I actually felt good about the progress we made in 3Q. And we’ve got significant milestones now to hit in the remainder of this quarter and into the first quarter of next year. And the one that we’re obviously intensely focus on with the operator is to make sure that we get the FPSO on location so that we can deliver first gas. So that’s the color as we’re behind the update.

Operator: Our next question is from Mark Wilson with Jefferies. Please proceed with your question

Mark Wilson: Okay. Thanks, gents. And thanks for the color on the FPSO there. I was going to ask about that. So that’s clear. So, yeah, let’s go to Yakar Taranga. You’ve actually outlined a very specific development concept in the press release today, 550 million cubic feet a day with piped gas, domestic and export via FLNG. And I think, Andy, you mentioned an FLNG vessel of a similar size to Tortue, that’s what I want to check is what would be the split of that gas? How much does Senegal required domestically and therefore, how much would be left to export. And you mentioned bringing in a partner. So I guess that is a definitive requirement to move forward? And what sort of final percentage stake would you envisage taking in such a development?

Andrew Inglis: Okay. Yes, right. Good questions, Mark. Yes. So I think sort of covered it earlier, but just sort of I think that it is a well-described development scheme. I think I hope you get a sense from that, that we’ve been — obviously been working closely with Petrosen in the development of that and a scheme that clearly is competitive, commercially attractive, but meets the country’s own development goals, which were around the domestic gas supply, and the ability then to create additional revenue through LNG export. If you look at the split, it’s around 130 million standard cubic feet a day into the domestic gas, I think with that, initially, probably there won’t be the full power capacity to take that, but that will grow through time.

The — and again, a steady state, we would be looking at an LNG scheme, which is about 2.5 million to three million tonnes, yes, which sort of takes you to a gas supply of 400 million to 500 million standard cubic feet, yes. So that gives you an idea of the scheme and therefore, the number of wells that will be required, the well potential is very similar to GTA. And I think in sort of the efforts sort of linking back to the question, the sort of why is deeply not involved. This is a scheme that we developed in collaboration with Petrosen. And then ultimately, the decision by BP not to participate has allowed us to move forward with that. So as they step back, they’re going to focus on getting Phase 1 of GTA finished. And that creates the opportunity to work this.

So I think the scheme is sort of clear. In terms of working percentages, we typically have 25% to 33% in our current projects, I’ve envisioned the same. The objective is for Petrosen to step up to an equivalent share to other parties that would come in. if it’s two, it’s maybe we are 25% and they’re at 25%. If it’s just one party coming, maybe we’re at a third, a third, a third. So it’s that sort of shape. And to get there, we’ve got work to do now to bring in the partnership that is a gating item for both ourselves and Petrosen and secure the necessary financing to enable Petrosen to move forward. So lots to do on it, but it is a project which I believe has the full support of the government has a very clear development concept and a very cost competitive proposal.

Now there’s work to do to bring all of that to fruition.

Mark Wilson: Okay. And on that development concept, can we just push a little bit harder on it. So Tortue, for instance, there’s a very large breakwater being built and a lot of the Phase I was sized with a view to a follow-on Phase 2 FLNG being added. Could you explain what’s different in terms of Yakaar Teranga, maybe in terms of its location offshore that might make it an easier or quicker in international phase?

Andrew Inglis: Yes. No, again, good piece of color, Mark. Yes. We — I suppose the way to describe it is we don’t envisage building a break water. We believe that there is a design to enable an FLNG vessel to be located on location there, different metocean conditions so that you don’t have the significant cost of building a breakwater. So I think that it is about being innovative around the demand solution that we’ve talked about, and we believe that we’ve done significant work. We have done significant work to enable us to be able to progress our concept.

Mark Wilson: Okay. That’s great. And sorry, I’ve just got one more. I just want to confirm. So in Jubilee now additional producer-injector pair before year-end, but it’s still a plan for that rig to continue in 2024 with a three to four well annual program, I think that’s been talked about before by the operator.

Andrew Inglis: Yes. No, no, you’re right, Mark, in concept, that’s the proposal. About half a rig year, I would say, on Jubilee in ’24. And again, I think it was Charles’ question around the objective is to build the well capacity so that we’ve got the sort of reserve capacity beyond the facilities limit. And together with reliable water injunction, you then have the ability to sort of hold the plateau at that level. And then clearly, you then follow up with additional wells as that well capacity becomes tested. But so we’re on a good track now to sort of continue to move forward with Jubilee as we add those wells and fundamentally underpin the new wells with reliable water injection. So the increase in Jubilee is well described in terms of the forward activity set.

Operator: [Operator Instructions] Our next question comes from Stella Cridge with Barclays. Please proceed with your question.

Stella Cridge: Hi there. Afternoon all. Many thanks for all the updates. I want to ask on three things, please. The first, just a tidying up question on Yakaar Teranga. Do you actually have to pay any consideration to BP for the additional stick, that would be the first one. The second on the TEN gas development. I did see a figure in the press about potential cost of this. I just wondered if you would be able to comment directly about, what CapEx you see there, and how you would fund the Cosmos share? And then finally, do you have any updates on the Ghana tax situation? That would be three things.

Andrew Inglis: All right. I’ll sort of go back those in reverse order. As regards to Kosmos, we have no ongoing dialogue with the GRA, which is the Ghanaian Tax Authority regarding any tax issues. On TEN, the — I think the newspaper article talked about a $1.3 billion development, which would cover the full development of the next phase of the TEN POD. We would — our share would be 20% of that. And clearly, that spend would be forward spend through potentially ’24, ’25, et cetera. So — but we’re still waiting for progress with the Government of Ghana in terms of that spend. So we don’t yet have any firm timing for that. And then on the Yakaar Terganga, there was no consideration paid to BP.

Stella Cridge: That’s great. And so you mentioned you don’t have any ongoing dialogue with the government. Do you mean there is no tax claim anymore or the tax claim is still there, but there’s just been no discussion about it?

Andrew Inglis: We have no tax plan.

Stella Cridge: Right, okay. Was there any particular reason that was dropped, so…

Andrew Inglis: I don’t think there’s — no — with regard to our sales versus other parties, there was never a tax claim against…

Neal Shah: Never a dispute.

Andrew Inglis: Never a dispute.

Neal Shah: Every partnership is different. We’ve never had any formal dispute with the GRA. We obviously have ongoing discussions with them, but we don’t have any claims that we’re working through.

Operator: There are no further questions at this time. I’d like to bring the call to a close. Thanks to everyone joining today. You may disconnect your lines at this time, and thank you for your participation.