Tullow Oil plc (TLW) Earnings Call Transcript & Summary

Well, good morning, everyone, and Richard and I are delighted to present our 2022 results to you guys. I wanted to reflect back. So when I joined Tullow in 2020, I think some of you may recall, things looked pretty bleak then. But we had the conviction that in the quality of the asset base and the belief that with real focus and discipline, we'd be able to turn the business around and unlock its underlying value. And I think you'll agree that conviction has been validated by our strong operating and financial performance this year. We're now creating value. We're generating free cash flow. The balance sheet is strong with significant liquidity headroom and leverage of less than 1.5x. On the operating front, we've had a second successive year of really top quartile safety performance. And that really speaks to also the real focus we have on operational excellence, and I'll talk more about that in my section later on. The implementation of our investment plan is delivering real value, economic prosperity to our host nations. What's also exciting is today, we've got a really strong and diverse leadership team at Tullow, there's -- the organization is highly energized. I think what I like particularly is a deep commitment to delivering on our business plan and a willingness to go beyond the call of duty and delivering excellence. That's a really, really powerful thing. And that's evidenced, if you look, we had -- last year, it was marked by a successful preemption on part of the Oxy-Kosmos deal. We had a successful transition of the operation and maintenance of the Jubilee FPSO and we had top quartile drilling performance. So we're building on that in '23, I think it's going to be an exciting year because you'll start to see the results of the strategy. They become a lot more visible, a lot more tangible. One of the big things is we're going to achieve over 100,000 barrels a day of gross production from Jubilee. This is going to be in the second half when the Jubilee Southeast infrastructure is installed. I'll talk more about that. But just to remember, Jubilee was at about 70,000 barrels a day at the end of 2020. So for a kind of mid-life asset, that's a remarkable achievement. I think Richard will share this step-up in production that will drive very material free cash flow generation from the second half. And that kind of then results in equity value accretion as we repay the debt. It's a key part of the story. But on top of that, we've got several catalysts that will drive further value. And some of these include we're working on long-term gas sales in Ghana. There is a revised plan of development for TEN that's underway. We've made good progress on FDP approval. And then also we're working on the strategic farm-out in Kenya. And there's a lot of work going on in terms of monetizing the very large kind of prospective resource base. So really kind of fighting on all different cylinders. But the key thing I wanted to just say before I hand over to Richard, is that we've been working really hard to create what we believe is a very unique platform for growth within our sector. And it is gratifying to see that strategy play out very successfully. So that's just a quick overview. Let me hand over now to Richard, and I'll come back on kind of operations and strategy.

Thank you, Rahul, and good morning. I'll now take you through a strong set of financial results for 2022. Our exceptional operational performance through excellent uptime and a focused investment in our high-quality producing asset base has underpinned our financial performance. On a like-for-like basis, excluding the impact of the assets we disposed last year, production is up 6% despite the planned shutdown in the first half of the year. Operational performance, combined with higher oil prices, drove close to a 40% increase in revenue despite a $390 million payout under our hedge program. We have continued to focus on cost discipline, which has enabled us to keep OpEx flat and further reduce G&A despite an inflationary environment. We have continued to invest in our asset base, increasing CapEx by close to $100 million to $354 million. And our capital allocation continues to be focused on the high volume of short payback and high-return opportunities we have in our portfolio with close to 90% of our CapEx allocated to our producing assets. We've also invested $126 million in the Ghana preemption, which paid for itself back within 9 months. And following this sustained period of investment, we're now starting to see the cash flow potential from our assets. We delivered $267 million of free cash flow, which did include the impacts of the legacy Norway arbitration payment and the Ghana preemption purchase price. This means over the last 2 years, since we reset the business, we've delivered over $500 million of cash flow whilst investing nearly $750 million in organic and inorganic opportunities. This has enabled us to accelerate our deleveraging hitting our gearing target of below 1.5x 3 years ahead of our original plan. Our guidance for 2023 remains unchanged from the January trading update, with $400 million invested in our asset base, delivering $200 million of free cash flow at $100 a barrel. This will enable us to get to 1x gearing by the year-end or by the end of '24, if oil prices remain around $80 a barrel. However, as projects don't run to calendar years, this only partly tells the story, which I'll highlight on the next slide. The Jubilee Southeast project, which Rahul will describe shortly, transforms the cash flow generation capacity of the business, which the graph on the left demonstrates. This plots group production, CapEx and decommissioning by quarter over 2023. In the first half of '23, we'll spend $100 million -- over $100 million commissioning the Jubilee Southeast project. And following first oil, which will be around midyear, we'll see a material uplift in production as we move into the second half. At the same time, we'll see the completion of our decommissioning activities in Mauritania, which will significantly reduce our ongoing decommissioning expenditure. These factors combined to result in a material uplift in free cash flow from mid this year, which will sustain into 2024. And as you can see from the graph on the right, as our production ramps up, our hedge program begins to roll off with 60% unhedged in the second half of 2023. This provides us with significant exposure to a rising oil price environment. Now if we move on to costs. Over the last 5 years, we've transformed our cost base. We've seen a 30% reduction in OpEx and delivered a 60% reduction in G&A. Our continued focus on OpEx, which was supported by the O&M transformation project has enabled us to reduce unit OpEx in Ghana to $9 a barrel in 2023. In terms of G&A, we're forecasting a fourth consecutive year of reductions. This is driven by our emphasis on continuous improvement with a focus on how we can do things even more effectively and efficiently. Since we set ourselves a G&A reduction target in mid-2020, we have delivered over $300 million in cash savings. These actions across both OpEx and G&A are incredibly important given the inflationary pressures we're seeing. So if we move on to the next slide. So this covers our medium-term outlook. If you look at our core 2P opportunity set, we'll see $1.1 billion invested in our business over the next 3 years. This will generate $800 million of free cash flow at $80 a barrel, and it could increase to almost $1.5 billion at $100 a barrel. This is all on a 2P basis and excludes the highly value accretive impacts of our key catalysts, which Rahul will describe. In addition to the base plan, and as a reminder, we have material upside from contingent payments linked to previous divestments. The Uganda payment with first oil target in 2025 and plateau production of 230 KBD will deliver a significant additional income stream, which we've not included in any guidance. The group is also potentially due to receive $40 million in contingent consideration from the EG and Dussafu disposals. So what does this all mean for our refinancing plans. At the end of last year, we had a 2P NPV of $3.9 billion. Our net debt was down to $1.9 billion, and we had $1.1 billion of liquidity. Our net debt maturity is now until March 2025. And ahead of this, as you can see from the graph, we're going to deliver material free cash flow and at which point we'll also be 1x geared. Therefore, our conclusion is we have time. We have an ever-improving financial position and a number of options to address our debt maturities on an opportunistic basis. So in summary, Tullow continues to deliver both operationally and financially, with like-for-like production, revenue, EBITDAX and profits up year-on-year. We have maintained our disciplined approach to capital allocation and cost management, which creates a clear pathway for Tullow to deliver significant free cash flow from mid this year. With the ongoing investment in our assets, delivery of the key catalysts, I'm confident that we'll maintain and even enhance our gross asset value, which together with material deleveraging and refinancing of our debt will provide material equity accretion for shareholders. And with that, I'll hand back to Rahul.

Okay. Thanks, Richard. That's brilliant. So I really wanted to talk about our real sort of purpose. And we're focused on building a better future through responsible oil and gas development, it is something we're really proud of. We're working actively. We're investing in social programs across our host nations. And really, the idea is to make a meaningful impact, which is working within the communities that we operate. So one example of this is we've supported over 6,000 students across the host nations with STEM scholarships with educational support. We focus a lot also on local content because that's quite fundamental to the success of our business. And last year, for example, we spent nearly $175 million with local suppliers. Over a 5-year period, total is about $1.2 billion. So it's quite tangible. We also obviously deliver direct value to our host nations. And last year, if you think about tax and royalties from Tullow itself is over nearly $0.5 billion, $150 million to our host nations. So that's kind of on the social side. I think from a climate perspective, we're committed to being net zero on Scope 1, Scope 2. This is with respect to our net equity emissions by 2030. And really, there are 2 big drivers for this effort. So one is we're working hard in terms of increasing gas handling capacity at Jubilee. There is process modifications. We're doing at TEN, and that's going to enable us to eliminate routine flaring in Ghana. That's going to be by the end of 2025. That's a big component of the kind of net zero pathway. At the same time, we're really working hard and making good progress on a nature-based carbon offset project in Ghana. We signed a letter of intent with the Ghana Forestry Commission late last year, and we're planning for FID for this year. If I move on to reserves. Really, when you look at the combined kind of 2P/2C reserve and resource base, that's over 830 million barrels. And that underpins the future growth of our business. And we actively manage the hopper, so you go from resource to reserves and production, that's fairly actively managed. When you look at the 2P reserves, so last year, a relatively steady around 230 million barrels of oil equivalent compared to 2021. And the reserve replacement was driven by a variety of things. So we had the preemption of the Oxy-Kosmos deal. We had adds in Jubilee, we had adds in Gabon and some new projects in TEN, particularly Tweneboa and Ntomme infill, which offset some reductions, which had due to field performance in TEN and also one of the Riser Base area wells. So overall, quite a good performance from reserve replacement. But I look at the 2C resource, that's quite substantial, again, over 600 million barrels of oil equivalent. And that also remains steady. And that really provides kind of meaningful replenishment potential for our reserve base. Now there is a number of opportunities to organically increase the reserve and resources in the near term. These come from the gas commercialization in Ghana. We had some good well results in the Jubilee Southeast program, so which look promising because we have identified some producing -- producible hydrocarbons at lower levels. And then we are working on development plans for discovery in Gabon, Wamba, which is currently a long-term test. So quite a few organic reserve replacement opportunities. When you look at production, it was up 5% in '22 relative to '21. And as Richard talked about, and we'll talk about it some more. This coming year, Jubilee is really set to increase beyond 100,000 barrels a day in the second half. And that is going to drive a material step change in production, which more than offsets the expected decline in TEN and in the non-op portfolio. So that sets up us for a pretty strong second half '23 and then beyond. Now I want to talk about kind of Tullow as it's kind of new target, right? We're really an operations-led company. So the focus on safety becomes really integral to how we work. And we're really proud of our track record. In recent years, we've managed through some pretty notable risks such as COVID-19. There's a very elevated activity levels we've had with the step up in CapEx to deliver a truly kind of safe place to work for our workforce. In '22, I'm pleased to say we had no injuries in our business and we had top quartile safety performance. Now these things don't just happen. They're underpinned by actions that we're taking and a very strong safety culture. And the way the operating teams work and this is with support from me and then the senior leadership team as well, they developed some detailed improvement plans on a regular basis. We learned from every incident and every near miss no matter how small, there is a very strong reporting culture. We complement this with a fit-for-purpose assurance program and also that helps us kind of provide the right checks and balances. So what the result of all this is a continuous learning culture and where every accident is preventable. Every day, it represents an opportunity to improve from the day before. And that's quite fundamental to how you build a strong operating business. And I think that foundation really also underpins the whole focus we have on operational excellence. Let me talk about that for a minute now. What you've seen over the last 3 years is really a steady improvement in uptime in Jubilee. I'm just taking that as a kind of metric, but it captures kind of a wider focus on operational excellence. But that illustrates that journey that we have. Now the team is -- continues to do a fantastic job of kind of delivering high production efficiency and maximizing production. And that's really demonstrating this whole mindset that we have at Tullow where every barrel matters. And last year, again, as a kind of part of that whole strategic transition, we transferred the operations and maintenance of the FPSO at Jubilee, which is our most prized asset from an external contractor to our operating team. And the results have been immediate. We've seen safety, reliability performance has remained very strong, and the operating cost, running costs have come down. Richard talked about that a little bit in his section as well. We've also seen -- so that's the kind of output piece, but we've also seen some improvement in key operational inputs. You look at things like maintenance backlog, you look at the contract counts, you look at local participation and contracting. So all of this kind of makes the uptime and the cost enhancements much more sustainable in the long term. This O&M transformation, as we call it, is a major step in supporting our vision of becoming really a leading low-cost operator. But what I find very energizing is really the change that we see in the morale, the attitude, the ownership of the operating team, and that's really translated into some visible improvements in the control of work and the housekeeping at the FPSO, the orderliness and also just the kind of overall general positivity on the facility. And of course, all of that sort of comes to kind of the impact on production. So again, staying with Jubilee, we're targeting in excess of 100,000 barrels a day in the second half of this year. If I look back, since 2021, we brought on stream 7 Jubilee wells and they've increased gross production from 75,000 barrels a day in '21, I think it was closer to 70,000 barrels at the back end of 2020 and to an expected average of 95,000 barrels a day in 2023. So quite a major kind of increase in production and quite an achievement. I think just talking about the Jubilee Southeast project. So this year, we're targeting the completion of the subsea infrastructure that's in the Eastern part of Jubilee. So think about Jubilee, the Eastern part has been historically undeveloped. We're looking to install production and water injection manifolds and related pipelines and along with a total plan of about 11 wells. So this project we sanctioned in late 2020. The cost was about $1.1 billion. That's gross. I'm pleased to say that despite inflationary pressures, we're still pretty much in line with those cost estimates. So 4 of those 11 wells will be completed this year, and we've got another 7 that are in plan. So we have from Jubilee Southeast point of view, again, kind of fairly deep inventory to help sustain production beyond '23. So the project, like I said, is progressing well. I think we've managed inflationary pressures reasonably well. I think this is another example that kind of highlights our project management strengths, its ability to integrate deliverables across kind of global multidisciplinary team. And the first oil from this, again, for us is a major milestone. So that's on Jubilee. Let me talk about TEN as well because there, we're looking to draw a line under the decline and then looking to prepare for a new future in terms of kind of new planer development. So the focus last year in TEN was on reservoir management. And I think that's paid off. So we've been able to reduce the annual decline rates to less than half, which this was in '22 compared to 2021. In '23, we have no new wells planned, but the focus will remain on active reservoir management. We're going to just, again, looking to sustain strong operational uptime and improving the gas handling on the FPSO this year. So we're looking to a planned maintenance shutdown that's scheduled for the second half of the year, and that will help again with allowing us to improve gas handling facilities. The increase in the gas handling facilities will also facilitate a very significant reduction in flaring and also increased gas injection to help support our production. So that's the focus. There's a very large undeveloped resource base across the various accumulations in TEN, and we're looking to monetize these resources through a variety of things. Infill drilling, there's phase development of new areas near the existing infrastructure. There is development of significant gas resources and also drilling of prospective resources. So we're working on a comprehensive plan of development, that will capture all of these opportunities, and that's going to be submitted to the government of Ghana later this year. So -- and like I said, in this kind of -- hopefully, this comes through is there's a continuing quest for value across Tullow. And I think in the case of TEN, in addition to the subsurface, we're also evaluating a potential restructuring of the FPSO cost base, so that will allow us to drive sustained cost efficiency. So let me then move on to Gabon and Cote d'Ivoire. This is really is -- I like the portfolio, it's capital efficient. So if you look at Simba for example -- sorry, in Gabon, just where the whole story has been around capital efficiency and around infrastructure debt exploration. So the Simba development, that's probably best highlights the opportunity set. So if you go back in times of Simba-2 appraisal wells, we drilled that kind of late 2018 and that was put on stream in January 2019. So within, I think, about 4 months. And the investments are paid off pretty rapidly. We've then since drilled, I think it was the late 2021. We drilled Simba-3, and that was part of the expansion project for the field. And that well was brought on stream in January '22. And again, that had a rapid payback. The production has declined as expected, but now we've showed a number of new prospects in the area with a targeted drilling at the end of 2023. So that's a good story around capital efficient sort of projects, rapid connection and quick paybacks. We've also identified a number of other opportunities in Gabon, particularly around the Tchatamba infrastructure where we invested in a new MOPU. And these include -- I talked earlier about the Wamba discovery that's on a long-term production test and which is going to help define the development potential in the area. In Cote d'Ivoire, a slightly different story. We're super excited about there is a strategic position that we've built in the Tano Basin. So the Tano Basin, to remember is across Jubilee, TEN and Ghana and then it covers into Cote d'Ivoire. So we've now got 2 blocks, and you can see on the map, CI-524 and 803. And these are exactly sort of adjacent to TEN and Jubilee. They've got significant prospectivity within these cretaceous turbidite plays. They're very similar to the plays they're producing in the adjacent TEN and Jubilee fields. And the first drillable opportunities in CI-524, we're maturing that and potentially an exploration well being drilled or being planned for next year. The other part of CDI is Espoir where remediation work is going on, on the FPSO. That will continue through 2023 and then the operator, which is CNR, they're also considering plans for significant investment for the development drilling campaigns. So that's a little bit about the operation. Let me talk about strategy. And again, what excites us is that there are very material catalysts to unlock potential value in the near term. Each one of these is quite significant. So let me just walk you through these. In Kenya, last week, we submitted the field development plan for approval to the government. We're expecting the FDP approval process, including ratification by the parliament to conclude later this year. In parallel, we're continuing to progress a farm down to a strategic partner that's in a joint process with our partners. The other thing we're working on is to secure a long-term supply of indigenous gas. This is a real priority in Ghana because it will enhance energy security for the nation, but also facilitate industrial development. I think from our perspective, it's going to unlock value from a very substantial gas resource space. I touched on exploration strategy in the context of CI, but when you look at it, it's very much now the strategy is focused around our producing assets in West Africa. This is where we have a deep understanding of the geoscience. And as explained in the context of Gabon, we've got access to infrastructure that enables a pretty rapid development of the discoveries. So that focus, I think, will remain, and you'll continue to see us unlock opportunities from there. But don't forget, we also have some very material legacy positions in the big emerging basins in Guyana and Argentina, where we're continuing to seek opportunities to unlock value. So I think when you look overall, there's a platform of assets, but also equally, there's a set of capabilities that are quite unique within our sector. And I think as we delever, Richard talked about the whole cash flow generation, I think as we delever, we'll create financial flexibility that enables us then to consider additional opportunities for growth. So when you look at these critical actions that I've just described in these catalysts, the action plans for each one of these are very well defined. And also importantly, the delivery of each one of these catalysts is embedded in our KPIs. So there's a clear, clear focus on delivery for these. So when I look at all of these together, I think there is where we stand today, we see a very compelling value proposition. So 2022 has been a year, as hopefully, you've seen now is a strong financial operating and drilling performance. And there's been -- along with that, there's been significant progress on a number of fronts, including the most notably on the Jubilee Southeast project. So overall, when we look at it, our delivery is well ahead of the plans we set out in late 2020 and '22 kind of built on '21. And all of this performance, it underscores what we've talked about continuously, the deep potential in the asset base. And also, it's not possible without the strong commitment of the team to deliver value from that. I think as Richard shared at the end of last year, we had liquidity was over $1 billion. Gearing was at 1.3x. This year, we'll deliver further tangible results. There's a material step-up in free cash flow delivery in the second half, and that will accelerate deleveraging. I think then as you delever, there is material equity value accretion. And what I would submit to you is that, that accretion process is now derisked. And when we look at the business, we see like it's undervalued on all metrics. And it's largely, we believe, due to a perceived debt overhang. Now as you look at the hedges rolling off that Richard talked about, we've got very significant oil price upside. So when you look at a strong balance sheet, you've got visible and accelerated deleveraging. Our conviction is this is the year people stop worrying about the [ data telc ]. And I think that's going to be a major game changer from a value perspective. Beyond all of this stuff, there is the impact of all the catalysts that I talked about in the previous slide. So you can see kind of why when we look at this, we're excited about very compelling. I think it's a unique proposition that Tullow offers today. So that's kind of story, but I just want to pause here to kind of thank our team. I think people have worked extremely exceptionally hard last year, the commitment is incredible. I think there is a strong focus on delivering the business plan. I really want to thank the team for their commitment and delivery. But also, we're very grateful to our host nations and communities. We work very closely with all of them for their continued support and to all of you, shareholders, debt investors for your confidence in us. So thank you, and Richard and I here, who can answer any questions. So over to you, guys.

[Operator Instructions] Our first question is from Chris Wheaton at Stifel.

Rahul, thanks very much indeed for the presentation and for outlining what's been the end of the moment of the year of transformation for Tullow. So very well done indeed. Let me start with a couple of questions. Firstly, on TEN, could you help me understand what the gas reinjection profile might look like or might do to the production? Is it a case of holding production flat for a couple of years? Or are we still going to see decline, but more like, say, 10% a year decline in the gas reinjection rather than the 20% or so we've been seeing. If you could help me understand that and also the CapEx associated with that now beyond 2023, that would be really helpful. Also, I would have thought if you're stabilizing production, you need to start to be thinking about where the resource development comes from. So you would be thinking about exploration spending on TEN in '24 included in your sort of your -- i.e., on the -- but on the Cote d'Ivoire orders. Is that included in what we've talked about on production -- sorry, on the CapEx guidance. That would be a great place to start.

Okay. So I think what we would expect as we're seeing this year is that the gas injections will help mitigate the decline. It will not eliminate it. So I think that's the first thing. I think from a -- so you would expect it to -- I think the goal then Chris is to, on an NFA basis, to try and hold ourselves to the kind of low double digits or high single digits. So to give you a sense, I think this year, if you look at our kind of guidance, I think we're down about 12%, I think, from last year. But if you take out the shutdown, which is about 4%, so you're at about 8% to 9%, I think, decline, and that's largely as a consequence of increased water injection and gas injections. So I think it wouldn't eliminate it, but it would certainly mitigate it. If we're not drilling any new wells, then there isn't much CapEx associated with it. The CapEx is going to go into kind of -- so we're not drilling any new gas injectors and things like that. There will be some costs which are associated with the shutdown, which are captured in the CapEx for this year. So if you take from an NFA point of view, you've got a mitigated decline with not a lot of CapEx. If you look at the future potential in TEN, Chris, it's -- there are probably 4 big things. You've got infill wells. You've got additional -- so things like Tweneboa oil, which is adjacent to infrastructure. You've got a gas resource, which is contingent on securing a gas sales agreement and then you have what we call prospective resources. So that's kind of prospects that are within license and adjacent to it. We haven't put a time frame to the drilling program for TEN because the idea, Chris, is to get the plan of development approved and then look at how the capital allocation, so Richard is going to kind of balance out how we look at debt repayment and how we look at capital allocation in Jubilee and TEN. So what we haven't done is we haven't given -- or we haven't defined specifically when we start drilling in TEN. But what I want to be able to do, Chris, is by the end of this year to be able to say to you guys, look, this is the plan of development for TEN. It draws a line under all of the disappointments you have in the past, and this is what it looks like going forward. So that's -- yes, I'll stop there. And you asked about -- you asked about CDI. So CDI we're looking to target kind of an exploration well for next year.

The next question is from Matt Cooper at Peel Hunt.

So 3 from me. Firstly, could you talk a little bit about the potential scale of upside in restructuring the TEN cost base? Could this potentially be similar to the 20% reduction you've achieved at Jubilee? Second question is all the deeper reserves that were discovered by the Jubilee wells last year included in your year-end 2022 2P reserves? And then finally, you mentioned in January about the possibility of buying back some of your debt. If you could update on your latest thinking here, that would be great.

Okay. On the first one, Matt, we haven't done the work yet in terms of defining what the price would be. But I think the mandate to the team is to not be constrained. So I would be lying to you if I gave you any guidance on that. I think let us do the work and we'll come back to you on that. On the deeper horizon reserves, I don't think they were included in the year-end stuff because that well was drilled after TRACS would have done their work. So, TRACS, I think completed the work I'm looking at Matt, are met is at end of October. So I think we'll double check it, but I don't think it's included, Matt. And on the buyback, I'll turn to Richard.

Yes, sure. So I mean, where we're sitting today, and I think as I outlined, we've got $1.1 billion of liquidity. We're generating a lot of cash, and we've got time to our next debt maturity. So there are lots of options we've got available to us to address our sort of debt maturities. And so the key for us is to be opportunistic and do things on sort of our terms at the right time for the company. So we're sort of not guiding to any specific type of outcome or the timing of those.

Okay. But buying back debt in the open market is kind of still on the table?

It's one of the many options that we've got available to us.

Okay. And sorry, just finally a follow-up on -- so those deeper volumes, can you just remind me the size of those net to you in Jubilee?

We haven't given Matt sort of guidance on that. Yes, that's -- yes. But it's just -- I think -- but just to kind of frame it for you, it's one horizon in one well. So it's not going to be like hundreds of millions of barrels, but it's -- the way we look at it it's even incremental volumes. I mean the incremental cost of that on a gross basis, I think from memory, Matt, was like less than $5 million, and the value of that would run into some very significant numbers for us and the production contribution is material.

Okay. Yes, I look forward to getting more of an update on that in the coming months.

Our next question is from Mark Wilson at Jefferies.

Big year ahead, excellent to what we expect from Jubilee in the second half. What I'd like to ask is, firstly, the CapEx in the last couple of years, $300 million this year in Ghana, $270 million last year. Could I ask how much of that is on the infrastructure? And how much of that is on drilling? And then the second part of that question is your current drilling rig in Ghana. Just how long do you have that on contract for, please?

Let me hand over to Richard.

Yes. So from a CapEx perspective, over -- so certainly, the first half of this year, I think, as I said, we're spending over $100 million commissioning the project, which basically entails most of the infrastructure spend. We spent a very similar amount last year as well. So the sort of -- I suppose that if you take the $300 million that we're spending in Ghana this year, $100 million of that relates to infrastructure. There's some small bits and pieces of other elements, but the bulk of that, the rest of the remaining $200 million is drilling costs.

And in terms of rig, we had contacted it for 4 years starting in April 2021, Mark.

All right. Excellent. Okay. So I got that for a good while yet. Second question, just get an update on where we are in gas offtake from the Jubilee FPSO. Your CMD a few years ago, you talked about that getting to 130 million SCFs a day around this time, but growing potentially to 200 million. So just check where that stands in terms of offtake and whether -- and what the capacity of the FPSO? I think you said that would expected to be 190 SCFs a day by now with possibly increasing.

So 2 different things, Mark, let me -- so there is what we call kind of gas handling capacity on the FPSO. And in essence, kind of that allows us to deal with the associated gas that comes out of the oil production and the gas handling capacity can be a constraint because as you increase oil production, you produce more gas. So one of the things we've been doing consistently over the past 2 or 3 years has been increasing the gas handling capacity. And I think this year, again, we're going to look to increase the gas handling capacity further to about, I think, 230 million, 240 million SCFs a day. So that's kind of one side of it. The other part of it, which is the gas export capacity. And between sort of -- so Jubilee, we could comfortably export 150 million SCFs a day. The constraint -- so typically what has happened in the last 2, 2.5 years, Mark, is that we've been consistently been able to ship over 100 million SCFs a day of gas. And the limiting condition there is not our capacity. It's typically the ability of the GNGC plant, the Ghana gas plant to offtake the gas. So we're not constrained from our side. When you look at Jubilee and TEN together, we can comfortably supply 200 million SCFs of gas a day. But to make that happen will require incremental midstream processing capacity to increase on the Ghana side, so whether it's GNGC or another plant. So simplistically, I'm saying we're not constrained. We have the ability -- we'll have the ability from a kind of capacity point of view to supply, let's say, 200 million SCFs pretty comfortably.

Got it. Okay. And the point [Technical difficulty] you still expected to have a lower [Technical difficulty] you're not going to run into [Technical difficulty] I'm saying the -- just to confirm, the Jubilee Southeast wells, which increased oil, but they would have a lower gas oil ratios you expect to run into?

Yes. So I think -- I mean, the idea generally is that the wells as you start producing them, newer wells have lower GOR than older wells. I mean, that's kind of the simplistic thing. So I think what's happened if you look back over the years, last 2 or 3 years, as we've invested in new wells, you're typically getting lower GOR wells, and they're phasing out the older kind of higher GOR wells. So that has -- within a constrained gas processing capacity, you can increase oil production.

Okay. And if I may, just one last question. You say you submitted the -- an updated FDP for Kenya. Could I just ask where that stands for approval and how that affects the license term. So where is the expiry of that license now you've submitted an FDP, please?

Yes. So good question, Mark. So the requirement for the license extension we had secured back in 2020 was that we would submit an FDP, which we did in December of 2021, right? So that was certainly kind of that protects the license. The next stages for the FDP to be approved. And there has been a lot of pre-work done through last year and the beginning of this year. And remember, we had a change of government in Kenya. So you've got a new leadership team at the ministry. So we work with them to finalize the FDP, which is -- which we kind of did, and then that got submitted last week. The process now, Mark, is that they will go through EPRA, which is a regulator will go through a review of that FDP before recommending it to the minister, the CS for approval, and then they will take it to Parliament.

Okay. And in terms of the license term, where does that stand right now?

So what happens then is once the FDP gets approved, then we're working on a concept to say, like happened in Uganda to say, look, then you have -- the next step is FID. And once you do that, then your production period starts. So I think in a simple sense, where we are now is that the license is protected. The next stage is the kind of FDP approval, which sets you up for FID, and that's when the production period will start.

Next question is from James Thompson at JPMorgan.

A couple of questions for me. Just in terms of your 2023 outlook, I mean, obviously, a little bit more 2H weighted than we'd be usual. Just in terms of what you laid out there at the start. I mean, can we assume, therefore, that net debt will probably be up a little bit at the midyear point in 2023? And then secondly, in terms of the kind of medium-term cash flow outlook, you've kind of given us the guide at $180 million. Could you maybe talk a little bit about where you see sort of the cash breakeven over that period? And obviously, you've not included some of the potential upsides there in terms of Uganda royalties, et cetera. Obviously, the tax disputes are ongoing, and they're not included either. So maybe you could just give us an update on potential risk there in terms of the tax disputes and risk to that sort of free cash flow profile that would be great.

Okay. Well, Richard, this is all your stuff.

So in terms of the cash flow profile for this year, yes, it is very second half weighted. And that's the transformation point for us, point forward with the infrastructure spend coming off, decommissioning spend coming off and production ramping up. So yes, we -- when you then layer on some of the fact that we've got some pretty weighty tax payments in the first half of the year related to 2022 and Gabon that we pay annually. The first half of this year will be negative with a material uplift into next year. In terms of the breakeven on the cash flow, look, we don't tend to look at it like that. There's $1.1 billion of CapEx in that period. If oil prices were to start falling away from where they are now, we would reassess that capital allocation. So it becomes quite a circular assessment. I mean the things that you can look at, look, we've got OpEx down in Ghana to $9 a barrel, and we're working hard on both sort of looking to increase production that helps with that figure, but also the optimization of the OpEx position on TEN that will further reduce our breakeven. And sorry, I missed the final question was on tax.

Also Uganda royalties.

Yes, just an update really in terms of the processes there would be great? Because that's potentially a risk for your free cash flow guidance.

Yes. Look, I mean from a tax perspective, look, the -- we've got the 3 processes now within arbitration. We filed for the BPRT arbitration back in '21. And that hearing is in October of this year with the likely decision in the first half of next year. So look, these processes take time. We're very confident of our position. And look, we'll -- I think as we've said in the statement, that we'll look to sort of continue to engage to sort of to address these points over the near term. And then the question on Uganda, we -- the magnitude of that, there's 2 thresholds. So $62 a barrel is when it kicks in and then it steps up above $70 a barrel. So when you're looking, say, higher oil price environment, $100 a barrel, it's close to $50 million a year into perpetuity. So it's a big income stream for the group, but I don't think is included in anyone's value equations.

Thanks, Richard. That's very helpful. Rahul, maybe one for you. I mean this year, obviously, the reserve replacement was dominated by the preemption. You've kind of laid out some opportunities for 2023. I was just wondering if you could sort of maybe scale some of those organic reserve growth opportunity. I mean, notwithstanding Kenya, which really as it gets done, will be quite transformational for 2P, but just sort of the scale in terms of just the organic opportunities for 2023 would be quite helpful.

So the -- I think, again, just to go back to 2022, James, so the -- you had -- you had sort of 3 -- 3 bits of organic stuff. So you had Jubilee reserve adds. You had reserve adds in Gabon and then on TEN. You had Ntomme. Now you had Tweneboa oil and some additional infill stuff. So those 3 were actually the same order of magnitude almost as the preemption. And then we had a reduction in TEN partly because of the Riser Base well, one of the Riser Base wells and some performance. So it wasn't all driven by the preemption. And the reason I wanted to highlight that is because that order of magnitude, certainly, we see good potential from some of the things that we're working on. So I think Matt asked earlier about potentially deserved from the deeper horizon. I think that's going to be a helpful reserve add. When you look at something like gas, obviously, that's going to be -- if we get a gas sales agreement, I think that's going to be quite positive from a reserve adds as well. Things like Wamba, for example, again, if we have a development plan around that, that would be -- so again, I think what you end up with is we get good visibility around organic opportunities. The gas obviously, would be more significant than each of these individually.

The next question is from Rachel Fletcher at Morgan Stanley.

Apologies if these have already been answered. I've had some technical issues over the course of this call. But my first one is just to come back to the debt. You mentioned that Tullow will be a low debt business by 2025. You've given some gearing guidance for '23 and '24 at 1x net debt to EBITDA. But I was wondering what the right level of gearing for Tullow is in your opinion from 2025 onwards and into the kind of medium to longer term? So that's my first question. And then on the second question, just any guidance you can give on contingent payments that you're expecting this year and next year, please?

Yes. That's Richard.

Yes. So look, in terms of what's sustainable for the company going forward, I mean I think when we're below 1x geared, I think that's a real game changer for us in terms of having financial flexibility going forward. I think the important thing to add on that, I mean, I think that's 1x geared in a low oil price as well. Obviously, we've done very well. We've hit our targets well ahead of schedule, but oil prices have also been very supportive. So we need to get that gearing to a position where it's below 1x at a sustainable position, which is a rule and I have mentioned, we're back very much in the plan from a '25 perspective. In terms of, look, the contingent payments it's very difficult. We don't have access to all of the data that we used to have when we own these assets in terms of production profile, some plan drilling. We sort of see sort of externally as much as you guys will in terms of progress on projects and drilling campaigns. So we haven't included any of those payments in any of our guidance figures sort of as and when they crystallize, that will be upside to the positions that we've disclosed. I mean the Uganda first oil, I think, is being sort of disclosed around '25. So the way the mechanism works, the first payment would likely be in 2026.

And I think Rachel missed because she didn't hear your order of magnitude numbers from that.

Yes. So I mean, the trigger price is $62 a barrel and it steps up materially above $70. So if you're looking, say, a high oil price environment, $100 a barrel, it's up to $50 million a year.

And then the other ones, which is for the other disposals is about $40 million?

$40 million in total. It's capped to $5 million per year. That's for [ Equatorial Guinea ] and Gabon.

We've got a large number of questions in the queue. So I don't think we'll be able to get through all of them. But we'll see if we can get one or at least maybe 2 in. So James Hosie, you're next.

Yes. I was just wondering, Rahul, if you could just maybe elaborate a bit on the time frame for submission and approval of the new TEN plan of development and just how dependent that plan is on agreeing a long-term gas offtake agreement.

Sorry, you said time frame for POD approval? And what was the second question?

Yes, for the time frame for the submission and approval of this new TEN plan of development, I mean just how dependent that time frame is on the gas sales agreement being arranged.

Okay. So I think, firstly, the plan of development and the gas sales agreement are tied together because part of -- I think, as I said, James, is the plan of development includes development of the gas resource. So the 2 are -- they're separate agreements, but they're sort of linked to each other. I can't give you a specific time frame, but what I will say to you is that there is a real impetus from the government to get both of these done quickly because, again, energy security is a big thing in Ghana as in most countries. I think given what's been happening in Europe, in particular, you've seen a radical shift in LNG flows away from Africa. So there is a real focus from the government to try and get these done. James, you've been around long enough as I have, I wouldn't forecast a time frame on that. But what I am encouraged by is the very active engagement from the government in progressing this. So I would just simply say kind of watch this space. But yes, but it's something we're working on pretty hard.

Okay. And then does the gas sales agreement for TEN, does that need commitments from elsewhere and expanding the midstream capacity in Ghana as well? Or can you -- could you do a TEN gas sales agreement, but with the existing constraints or the midstream as they are?

So I think the idea -- if you look at it from a kind of Ghana energy security point of view, what they -- what makes sense from their perspective is to say, look, we want line of sight on security of supply of ex Mcf per day, right? Whether it comes from Jubilee or TEN in a way, it's -- that's not their concern. So one of the things that we've demonstrated to them is our ability to deliver, like I said, a couple of hundred million SCFs of gas per day and you mix and match sort of where that comes from. So that's kind of #1. So it's not -- it's not specific. We don't think it should be specific to particular assets. It's certainly not from their perspective. I think the second thing is that it's -- as I said earlier, there is existing midstream capacity up to about 150 million SCFs per day and the GNGC plant. To go beyond that is going to require additional investment by GNGC. There is a couple of plants that are being worked on right now, one by GNGC, one by another company. So we're pretty comfortable. I think that one of those things will come through over the next couple of years.

The next question is from Dmitry Ivanov from Jefferies.

Richard, I guess like 3 quick questions from me. So if we go to Slide 8, with this free cash flow expectations for the next 3 years. As you mentioned, you expect like up to $1.5 billion of free cash flows based like on $100 Brent price. I guess we're talking about just below $1 billion free cash flows, assuming $80 Brent price. Just want to be sure that I understand this number correctly, is like free cash flow before you expected like lease [ payments ] and mandatory amortization of 26 bonds. So it's approximately $200 million in lease payments and $100 million amortization. I just wanted to make sure that this like free cash flows before this amortization and the lease payments. So the first question. The second question on your cash flows -- cash flow position. So I guess you mentioned that available cash is $550 million around this on restricted cash position. So I would like to understand what's your comfortable minimum cash position? And what's your kind of strategy with regards to allocation of cash. So how much of this is now allocated outside of Ghana and the other operations? And what's your kind of target for the allocation of cash? And third question on this tax claim from Ghana Revenue Authority. I know like they recently kind of sent a new kind of tax claim on the taxation of the insurance proceeds. I'm kind of curious to understand what was the justification from Ghana Revenue Authority when they kind of send this like claim was not like kind of just what was the justification of this presented by GRA? And any color would be also helpful to understand kind of the position free cash flow. So these are 3 questions from me.

Yes. Sure. So in terms of the first question, in terms of lease payments and amortization, so lease payments are included in the operating cash flow number, so they are deducted from the operating cash flow number, but this is a free cash flow number. So it is what the business generates. That cash flow will then be used to repay debt, which is through amortization. So this is pre the amortizations, but it's post all of our, sort of, I suppose, costs of operation. In terms of the cash position at year-end, so we're sitting on a very healthy cash position. And in terms of what we believe that we need from a liquidity perspective to run the group, I think it's significantly, particularly given where we are from an operational perspective and a risk perspective. That number continues to decrease. It's certainly significantly lower than the $550 million that we got at the moment, probably sort of closer to the $200 million mark. In terms of capital allocation, I think as I mentioned, look, we're continuing to focus our capital allocate. Look, we've got a lot of really short payback, high-return opportunities, both within Ghana and our Gabonese assets. We've obviously got the big Jubilee Southeast project that contributes a fair chunk to CapEx this year. But that 90% of our CapEx is allocated to those producing assets. That discipline is something that we're going to continue in through the sort of near and medium term focus on those opportunities that we've got that provide those super short-cycle returns and high IRRs. Look, we're really focused on delivering the cash flow that we've set out to delever and just continue to accrete equity value. And then I think the final point on tax. Look, we've got a corporate business interruption policy. It was taken out by Tullow Oil plc and the -- I suppose, the event that happened that triggered the insurance that paid out under it happened in Ghana. And I think the sort of the position from the GRA is that -- because that insurance event happened in Ghana, it's taxable in Ghana, whereas look, it's a PLC policy. It was taken out in PLC. All the premiums have been paid within the U.K. It was assessed for tax within our U.K. tax returns. So it's very much a corporate tax -- corporate insurance policy. And cash in terms of where we hold it. It's all held -- the majority of it is all held in offshore bank accounts. So yes, so very little held in country.

And apologies, everyone, in the queue still with questions, we'll endeavor to get back to you over the course of the day. But I think we'll have to draw it to a close there. So I'll hand back to Rahul to finish proceedings.

Okay. Well, look, thanks again, everybody, for your attention. I think hopefully, you get a sense of the tremendous progress that we've made. I think we've talked about our plans for some time. I do see that we're at a very important inflection point where the delivery of those plans is derisked. I think we're a very important inflection point where the cash generation of the business kind of steps up in the second half. So no longer -- I think some of you has talked about in the past on this jam tomorrow. I think that is no longer the case. And I think as you see with the delivery of the business, the strong balance sheet that we have, the imminence of the step change in cash generation, I think we put the debt concerns behind us and look to unlock further value from the number of kind of super exciting opportunities we have. So look, it's been -- it's a transformational journey, I think, but it feels like we're at arriving. So thank you again for your time, and we'll look to engage with a lot of you in the coming days.