Well, good morning, everyone. Richard and I are delighted to present our 2022 results to you guys. I wanted to reflect back. When I joined Tullow in 2020, I think some of you may recall, things looked pretty bleak then. You know, 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. 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. That really speaks to also the real focus we have on operational excellence, and I'll talk more about that in, you know, in my section later on. The implementation of our investment plans 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, the organization is highly energized. I think what I like particularly is there's a deep commitment to delivering on our business plan and a willingness to go beyond the call of duty in delivering excellence. That's a really powerful thing.
That's evidenced if you look, we had last year, it was marked by a successful preemption on part of the Oxy-K osmos deal. We had a successful transition of the operation and maintenance of the Jubilee FPSO, we had top quartile drilling performance. We're building on that in 2023, I think it's gonna be an exciting year 'cause 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 gonna achieve over 100,000 barrels a day of gross production from Jubilee. This is gonna be in the second half, when the Jubilee Southeast infrastructure is installed. I'll talk more about that. Just to remember, Jubilee was at about 70,000 barrels a day at the end of 2020.
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. 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's a revised plan of development for TEN that's underway. We've made good progress on FDP approval. Also we're working on a strategic farm-out in Kenya. There's a lot of work going on in terms of monetizing the very large kind of prospective resource base. Really kind of fighting on all different cylinders.
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. It is gratifying to see that kind of strategy play out very successfully. 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. Good morning. I'll now take you through a strong set of financial results for 2022. Our exceptional operation 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've continued to focus on cost discipline, which has enabled us to keep OpEx flat and further reduce G&A despite an inflationary environment. We've continued to invest in our asset base, increasing CapEx by close to $100 million- $354 million.
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 have also invested $126 million in the Ghana pre-emption, which paid for itself back within nine months. 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 pre-emption purchase price. This means over the last two 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 , three 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 2024 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 2023, we'll spend $100 million, over $100 million commissioning the Jubilee Southeast project. Following first oil, which will be around mid-year, 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 combine to result in a material uplift in free cash flow from mid this year, which will sustain into 2024. 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.
If we move on to costs. Over the last five 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 ever 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. If we move on to the next slide.
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 three 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, as a reminder, we have material upside from contingent payments linked to previous divestments. The Uganda payment, with first oil targets 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 continuing consideration from the EG and Dussafu disposals. 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 next debt maturity is not until March 2025, and ahead of this, as you can see from the graph, we're gonna deliver material free cash flow, and at which point we'll also be 1x geared. 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.
In summary, Tullow continues to deliver both operationally and financially with like-for-like production, revenue, EBITDAX, and profits up year-over-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. With that, I'll hand back to Rahul.
Okay, thanks, Richard. That's brilliant. I really wanted to talk about our real sort of purpose and, you know, we're focused on building a better future through responsible oil and gas development. This 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. One example of this is we've supported over 6,000 students across the host nations with STEM scholarships, with education support. We focus a lot also on local content because that's quite fundamental to the success of our business. Last year, for example, we spent nearly $175 million with local suppliers. Over a five-year period, total is about $1.2 billion.
It's quite tangible. We also obviously deliver direct value to our host nations. Last year, if you think about tax and royalties from Tullow itself, is over nearly $500 million , upon $50 million, to our host nations. 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. Really there are two big drivers for this effort. One is we're working hard in terms of increasing gas handling capacity. At Jubilee, there is process modifications. We're doing a TEN, and that's gonna enable us to routine to eliminate routine flaring. In Ghana, that's gonna be by the end of 2025.
That's a big component of the kinda 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 kinda 2P, 2C reserve and resource base, that's about 830 million barrels. That underpins the future growth of our business. 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, last year, it was relatively steady around 230 million barrels of oil equivalent, compared to 2021. The reserve replacement was driven by a variety of things. We had the pre-emption of the Oxy-K osmos 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. Overall, quite a good performance from reserve replacement. I look at the 2C resource, that's quite substantial. Again, over 600 million barrels of oil equivalent, and that also remains steady.
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. Then, you know, we are working on development plans for discovery in Gabon, Wamba, which is currently on long-term test. Quite a few organic reserve replacement opportunities. When you look at production, it was up 5% in 2022 relative to 2021.
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. That is gonna drive a material step change in production, which more than offsets the expected decline in TEN and in the non-op portfolio. That sets up us for a pretty strong second half 2023 and then beyond. Now, I wanna talk about kinda Tullow as a kinda new Tullow, right? We're really an operations-led company. The focus on safety becomes really integral to how we work. 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 level we've had with the step-up in CapEx to deliver a truly kinda safe place to work for our workforce. In 2022, I'm pleased to say we had no injuries in our business, and we had top quartile safety performance. These things don't just happen. They're underpinned by actions that we're taking in a very strong safety culture. The way the operating teams work, and this is with support from me and then the senior leadership team as well, they develop some detailed improvement plans on a regular basis. We learn from every incident and every near miss, no matter how small. There's a very strong reporting culture. We complement this with a fit for purpose assurance program. You know, that helps us kinda provide the right checks and balances.
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. That's quite fundamental to how you build a strong operating business. 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 three years is really a steady improvement in uptime in Jubilee. I'm just taking that as a kinda metric, but it captures kind of a wider focus on operational excellence. That illustrates that journey that we have. Now, the team is continuous to do a fantastic job of kinda delivering high production of efficiency and maximizing production.
That's really demonstrating this whole mindset that we have at Tullow, where every barrel matters. 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. The results have been immediate. We've seen safety, reliability, performance has remained very strong, and the operating costs, running costs have come down. Richard talked about that a little bit in his section as well. We've also seen. That's the kinda 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.
All of this kinda 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. 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 a kind of overall general positivity on the facility. Of course, all of that sort of comes to kind of the impact on production. 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've brought on stream seven Jubilee wells, and they've increased gross production from 75,000 barrels a day in 2021, I think it was closer to 70 at the back end of 2020, and to an expected average of 95,000 barrels a day in 2023. Quite a major kind of increase in production and quite an achievement. I think just talking about the Jubilee Southeast project. This year we're targeting the completion of the subsea infrastructure that's in the eastern part of Jubilee. Think about Jubilee, the eastern part has been historically undeveloped. We're looking to install production and water injection manifolds and related pipelines. Along with a total plan of about 11 wells.
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 that with those cost estimates. Four of those 11 wells will be completed this year, and we've got another 7 that are in plan. We have, from a Jubilee Southeast point of view, again, kind of fairly deep inventory to help sustain production beyond 2023. The project, like I said, is progressing well. I think we've managed inflationary pressures reasonably well. I think this is another example that kinda highlights our project management strengths, its ability to integrate deliverables across a kind of global multidisciplinary team.
The first oil from this, again, for us, is a major milestone. 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 plan or development. The focus last year in TEN was on reservoir management, and I think that's paid off. We've been able to reduce the annual decline rates to less than half, which this was in 2022 compared to 2020. In 2023, we have no new wells planned, but the focus will remain on active reservoir management. We're gonna again, looking to sustain strong operational uptime, and improving the gas handling on the FPSO this year.
We're looking to a planned maintenance shutdown that's scheduled for the second half of the year, and that'll 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 increase gas injection to help support oil production. That's the focus. There's a large, very large undeveloped resource base across the various accumulations in TEN, and we're looking to monetize these resources through a variety of things. There's 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. We're working on a comprehensive plan of development that will capture all of these opportunities, and that's gonna be submitted to the Government of Ghana later this year.
Like I said, in this kind of... hopefully this comes through, is there's a continuing quest for value across Tullow. 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. Let me move on to Gabon and Cote d'Ivoire. This is really, I like the portfolio, it's capital efficient. If you look at Simba, sorry, in Gabon, just, you know, so where the whole story has been around capital efficiency and around infrastructure and that exploration. The Simba development, that's probably best highlights the opportunity set.
If you go back in time, Simba-2 appraisal well, we drilled that kinda late 2018, and that was put on stream in January 2019. Within, I think, about four months. The investments are paid off pretty rapidly. We've then since drilled, I think it was 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 2022. Again, that had a rapid payback. The production has declined as expected, but now we've matured a number of new prospects in the area with the targeted drilling at the end of 2023. That's a good story around capital efficient sort of projects, you know, 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 local. I talked earlier about the Wamba discovery that's on a long-term production test and which is gonna help define the development potential in the area. In Cote d'Ivoire, a slightly different story. We're super excited about there's a strategic position that we've built in the Tano Basin. The Tano Basin, remember, is across Jubilee, TEN, and Ghana, and then it covers into Cote d'Ivoire. We've now got two blocks, and you can see on the map, CI-524 and CI-803. 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 that are producing in the adjacent TEN and Jubilee fields. The first drillable opportunities in CI-524, we're maturing that and, you know, 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 the FPSO. That'll continue through 2023. The operator, which is CNR, they're also considering plans for significant investment for further development drilling campaigns. That's a little bit about the operation. Let me talk about strategy. 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'll enhance energy security for the nation, but also facilitate industrial development. I think from our perspective, it's gonna unlock value from a very substantial gas resource space. You know, I touched on exploration strategy in the context of CI, but when you look at 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, you know, as explained in the context of Gabon, we've got access to infrastructure that enables pretty rapid development of the discoveries. That focus, I think, will remain, and you'll continue to see us unlock opportunities from there. 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. 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. I think as we de-lever, Richard talked about the whole cash flow generation. I think as we de-lever, we'll create financial flexibility that enables us then to consider additional opportunities for growth.
When you look at these critical actions that I've just described and these catalysts, the action plans for each one of these are very well-defined. Also importantly, the delivery of each one of these catalysts is embedded in our KPI. There's a clear focus on delivery for these. When I look at all of these together, I think there is where we stand today, we see a very compelling value proposition. 2022 has been a year, as hopefully you've seen now, is of strong financial operating and drilling performance. Along with that, there's been significant progress on a number of fronts, including the most notably on the Jubilee Southeast project.
Overall, when we look at it, our delivery is well ahead of the plans we'd set out in late 2020, and 2022 kind of built on 2021. All of this performance, it underscores what we've talked about continuously, the deep potential in the asset base. 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, that will accelerate de-leveraging. As you de-lever, there is material equity value accretion.
What I would submit to you is that that accretion process is now de-risked. 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. As you look at the hedges rolling off that Richard talked about, we've got very significant oil price upside. When you look at a strong balance sheet, you've got visible and accelerated de-leveraging. Our conviction is this is the year people stop worrying about the debt at Tullow, and I think that's gonna 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. You can see kind of why when we look at this, we're excited about the very compelling...
I think it's a unique proposition that Tullow offers today. That's kinda story, but I just wanna pause here, 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 wanna thank the team for their commitment and delivery. Also, you know, 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. Thank you, and Richard and I here, we can answer any questions. Over to you guys.
Thank you very much, Rahul and Richard. We'll go to questions now. For those on the telephones, I'll just remind you, if you'd like to ask a question, please press star one. Our first question is from Chris Wheaton at Stifel. Go ahead, Chris.
Good morning, Rahul, thanks very much indeed for the presentation and for, you know, outlining, you know, what's been, you know, the end of the moment of a years of transformation for Tullow, so very well done indeed. Let me start there 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 two years, or are we still gonna see decline, but more like, say, 10% a year decline with 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.
I would have thought if you're stabilizing production, you need to start to be thinking about where the resource development comes from. You would be thinking about exploration spending on 10 and 24 included in your, sort of your, on the Côte d'Ivoire side of the board. Is that included in what we've talked about on production, sorry, on the CapEx guidance? That'd be great place to start. Thank you.
Okay. 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. I think that's the first thing. I think from a... You would expect it to, you know, I think the goal, Chris, is to, on an NFA basis, to try and hold ourselves to the kinda low double digits or high single digits. To give you a sense, I think this year, if you look at our kinda guidance, I think we're down about 12%, I think, from last year. If you take out the shutdown, which is about 4%, you're at about 8%-9%, I think, decline.
That's largely as a consequence of increased water injection and gas injection. I think it won'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 gonna go into kind of, you know, if we're not drilling any new gas injectors and things like that, there'll be some costs which are associated with the shutdown, which are captured in the CapEx for this year. 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, there are probably four 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 you know, gas sales agreement. Then you have what we call prospective resources. That's kind of prospects that are within license and adjacent to it. We haven't put a timeframe 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. Richard's gonna kinda balance out how we look at debt repayment, and how we look at capital allocation in Jubilee and TEN. What we haven't done is we haven't defined specifically when we start drilling in TEN.
What I wanna 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." Yeah, I'll stop there. You asked about CDI. CDI, we're looking to target kind of an exploration well for next year.
Thanks, Rahul. The next question is from Matt Cooper at Peel Hunt. Go ahead, Matt.
Hi, good morning. Three 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, are the deeper reserves that were discovered by the Jubilee wells last year included in your year-end 2022, 2P reserves? 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'd be great.
Okay. On the first one, Matt, we haven't done the work yet in terms of defining what the price would be. you know, I think the mandate to the team is to not be constrained. 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 the work. TRACS, I think, completed the work. I'm looking at Matt, our Matt, it's at end of October.
Yeah.
I think we'll double-check it, but I don't think it's included, Matt.
Right.
On the buyback, I'll turn to Richard.
Yeah, sure. I mean, I, where we're sitting today, I think as I outlined, you know, we've got $1.1 billion of liquidity. We're generating a lot of cash. You know, we've got time till our next debt maturity. You know, there are lots of options we've got available to us to address our sort of debt maturities. The key for us is to be opportunistic and do things on a sort of our terms at the right time for the company. We're sort of not guiding to any specific type of outcome or the timing of those.
Okay. 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. Sorry, just finally follow up. 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.
No. No.
Um-
Work to be done.
Yeah, that's... Yeah. it's to just-
Okay.
I think, but just to kind of frame it for you, it's one horizon in one well, so it's not gonna be like, you know, hundreds of millions of barrels. It's, the way we look at it is, 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. The value of that would run into some very significant numbers, for us, and the production contribution is material.
Okay. Well, yeah, look forward to getting more of an update on that in the coming months.
Sure.
Thanks, Matt. Our next question is from Mark Wilson at Jefferies. Go ahead, Mark.
Thanks, guys. Big year ahead. Excellent to see 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? How much of that is on drilling? The second part of that question is your current drilling rig in Ghana. Just how long do you have that on contract for, please? Thank you.
Let me hand over to Richard.
Yeah. From a CapEx perspective, certainly, you know, 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. I suppose, if you take the $300 that we're spending in Ghana this year, $100 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 is drilling costs.
In terms of rig, we had contracted it for four years, starting in April 2021, Mark.
All right, excellent. Okay. Got that for a good while yet. Second question, just like 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 scf a day around this time, but, and growing potentially to 200 million. Just check where that stands in terms of offtake and whether the, and what the capacity of the FPSO. I think you said that would expect it to be 190 scf a day by now, with possibly increasing.
Two different things, Mark, let me. There is what we call kind of gas handling capacity on the FPSO. In essence, kind of that allows us to deal with the associated gas that comes out of the oil production. The gas handling capacity can be a constraint because as you increase oil production, you produce more gas. One of the things we've been doing consistently over the past two or three years has been increasing the gas handling capacity. I think this year again, we're gonna look to increase the gas handling capacity further to about, I think to 30 to 40 million scf a day. That's kind of one side of it. The other part of it, which is the gas export capacity. Between sort of...
Jubilee, we could comfortably export 150 million scf a day. Typically, what has happened in the last two and a half years, Mark, is that we've been consistently able to ship over 100 million scf a day of gas. 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. We're not constrained from our side. When you look at Jubilee and TEN together, we can comfortably supply 200 million scf of gas a day. To make that happen will require incremental midstream processing capacity to increase on the Ghana side. Whether it's GNGC or another plant. 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, I'd say, 200 million scf pretty comfortably.
Got it. Okay. The point of the duty I've expected to have.
Sorry, Mark.
Gas ratio. You know, you're not gonna run into Just to confirm, the Jubilee Southeast wells, which, you know, increase oil, but they would have a lower gas oil ratio.
Yes.
you don't expect to run into-
Yes.
gas export capacity.
Yes. I think... I mean, the idea generally is that, you know, the wells, as you start producing them, newer wells have lower GOR than older wells. I mean, that's kind of the simplistic thing. I think what's happened if you look back over the years, last two or three years, kind of 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. That has, you know, within a constrained gas processing capacity, you can increase oil production.
Okay. If I may, just one last question. You say you've submitted the an updated FDP for Kenya. Could I just ask where that stands for approval and how that affects the license terms? Where is the expiry of that license now you've submitted an FDP, please?
Good question, Mark. 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? That was certainly gonna. That protects the license. The next stage is for the FDP to be approved. There has been a lot of pre-work done through last year and the beginning of this year. Remember, we had a change of government in Kenya, so you've got a new leadership team at the ministry. We worked with them to finalize the FDP, which we kinda did, 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. In terms of the license term, where does that stand right now?
Right. So that... What happens then is once the FDP gets approved, then we're working on a concept to say, like happened in Uganda, look, then you have the next step is FID. Once you do that, then your production period starts. 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 would start.
Okay, thank you. I'll hand it over.
Thanks, Mark. Next question is from James Thompson at JP Morgan. Go ahead, James.
Hi there. Morning, Rahul, morning, Richard. A few couple of questions from me. Just in terms of your 2023 outlook, I mean, obviously a little bit more 2H weighted than would 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 mid-year point in 2023? Secondly, in terms of the kind of medium term cash flow outlook, you've kind of given us the guide at $180. Could you maybe talk a little bit about where you see sort of the cash break even over that period? You know, 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. Maybe you could just give us an update on, you know, potential risks there in terms of the tax disputes and risk to that sort of free cash flow profile. That would be great. Thank you.
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 you know, that's the transformation point for us point forwards, you know, with the infrastructure spend coming off, decommissioning spend coming off and production ramping up. Yeah, 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 in 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 breakevens on the cash flow, look, we don't tend to look at it like that. You know, there's $1.1 billion of CapEx in that period.
You know, if oil prices were to start falling away from where they are now, we would reassess that capital allocation. It becomes quite a circular assessment. I mean, the things that you can look at are, look, we've got OpEx down in Ghana to $9 a barrel, 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, you know, further reduce our breakeven. Sorry, I missed the final question was on tax.
Also Uganda royalties.
Yeah, just an update really in terms of the processes there would be great.
Yeah.
Because they're potentially a risk for your free cash flow guidance.
Yeah. Look, I mean from a tax perspective, look, we've got the three processes now within arbitration. You know, we filed for the BPRT arbitration back in 2021, and that hearing is in October of this year with the likely decision in the first half of next year. Look, these processes, you know, take time. You know, we're very confident of our position. Look, You know, I think as we've said in the statement, we'll look to sort of continue to engage to sort of to address these points over the near term. The question on Uganda, look, we, you know, the magnitude of that, you know, there's two thresholds.
$62 a barrel is when it kicks in, and then it steps up above $70 a barrel. You know, when you're looking, say, higher oil price environment, $100 a barrel, you know, it's close to $50 million a year into perpetuity. You know, it's a, it's a big income stream for the group that, you know, I don't, I don't think is included in anyone's valuations.
Thanks for that, Richard. That's very helpful. Rahul, maybe one for you. I mean, this year, obviously the reserves replacement was dominated by the pre-emption. 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 reserves growth opportunity. I mean, notwithstanding Kenya, which clearly as it gets done will be quite transformational for 2P. Just, you know, sort of the scale in terms of just the organic opportunities for 2023 would be quite helpful.
I think again, just to go back to 2022, James. You had sort of three. You had, what, three bits of organic stuff. You had Jubilee, reserve adds, you had reserve adds in Gabon and then on TEN you had Ntomme. No, you had Tweneboa Oil and some additional infill stuff. Those three were actually the same order of magnitude almost as the pre-emption. Then we had a reduction in TEN, partly because of the riser base well, one of the riser base wells and some performance. It wasn't all driven by the pre-emption.
The reason why 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. I think Matt asked earlier about potentially reserve from the deeper horizon. I think that's gonna be a helpful reserve add. When you look at something like gas, obviously that's gonna be, you know, if we get a gas sales agreement, I think that's gonna be quite positive from a reserve adds as well. Things like Wamba, for example, again, if we have a development plan around that would be. 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.
That's perfect. Thank you very much. Over. Cheers.
You still there, James? Okay. Thanks, James. The next question is from Rachel Fletcher at Morgan Stanley. Go ahead, Rachel.
Thank you. Morning, both. Thanks for taking my question. Apologies if these have already been answered. I've had some technical issues over the course of this call. My first one is just to come back on to the debt. You mentioned that Tullow will be a low-debt business by 2025. You've given some gearing guidance for 2023 and 2024 at, like, 1x net debt to EBITDAX. 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. That's my first question. On the second question, just any guidance you can give on contingent payments that you're expecting this year and next year, please.
Thank you.
Good. That's Richard.
Yep. Look, in terms of what's sustainable for the company going forwards, I mean, I think, when we're below 1x geared, I think, you know, that's a real game changer for us in terms of having financial flexibility going forwards. I think the important thing to add on that, I mean, I think that's 1x geared in a, you know, in a, in a low oil price as well. Obviously, you know, we've done very well. We've hit our targets well ahead of schedule, you know, oil prices have also been very supportive. You know, we need to get that gearing to a position where it's below 1x at a, at a sustainable position, which, you know, as Rahul and I have mentioned, you know, that's very much in the plan from a 2025 perspective.
In terms of the contingent payments, it's, it's very difficult. you know, we don't have access to, all of the data that we used to have when we owned these assets, in terms of production profiles and planned drilling. We sort of see sort of externally as much as, you guys will in terms of progress on projects and drilling campaigns. 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, that we've disclosed. I mean, Uganda First Oil, I think, is being sort of disclosed around 2025. The way the mechanism work, the first payment would likely be in 2026.
I think Rachel missed it because she didn't hear your order of magnitude numbers from that.
Yeah. I mean, at, you know, the trigger price is $62 a barrel, and it steps up materially above $70. You know, if you're looking, say, a high oil price environment, $100 a barrel, it's up to $50 million a year.
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.
Yeah.
Okay. Thanks, Rachel. We've got a large number of questions in the queue. I don't think we'll be able to get through all of them. We'll see if we can get 1 or at least, or maybe two, in. James Hosie, you're next. Go ahead, James.
Yeah. Thanks, sir. I was just wondering, Rahul, if you could just maybe elaborate a bit on the timeframe for submission and then 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 timeframe for POD approval, and what was the second question?
Yeah, for the timeframe for the submission and approval of this new TEN Plan of Development.
Right.
Just how dependent that timeframe is on the gas sales agreement being re-arranged.
Okay. 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. They're separate agreements, but they're sort of linked to each other. I can't give you a specific timeframe, but I, what I will say to you is that there is a real impetus from the government to get both of these done quickly, again, you know, 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.
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 timeframe on that, but what I am encouraged by is the very active engagement from the government in progressing this. I would just simply say kind of, watch this space, but, yeah. It's something we're working on pretty hard.
Okay. Then does the gas sales agreement for TEN, does that need commitment from elsewhere in expanding the midstream capacity in Ghana as well? Can you do a TEN gas sales agreement but with the existing constraints on the midstream as they are?
I think the idea, if you look at it from a kind of Ghana energy security point of view, what makes sense from their perspective is to say, "Look, we want line of sight on security of supply of X Mcf per day." Right? Whether it comes from Jubilee or TEN, in a way, that's not their concern. One of the things that we've demonstrated to them is our ability to deliver, you know, like I said, a couple hundred million scf of gas per day, and you mix and match sort of where that comes from. That's kind of number one. It's not, it's not specific. We don't think it should be specific to a particular asset. 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 scf per day at 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, by, one by GNGC, one by another company. We're pretty comfortable, I think, that one of those things will come through over the next couple of years.
Okay, thank you.
Thanks, James. The next question is from Dmitry Ivanov from Jefferies. Go ahead, Dmitry.
Good morning. Can you hear me?
Yes.
Thank you, Richard. I guess, like, three quick questions from me. If we go to slide eight with this free cash flow expectations for the next three 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 in free cash flows, assuming $80 Brent price. Just want to be sure that I understand this number correctly. This is like free cash flow before your expected, like, lease payments and the mandatory amortization of 26 bonds. It's approximately $200 million in lease payments and $100 million amortizations.
Just wanted to make sure that, like, this is, like, free cash flows before this amortization and the lease payments. The first question. The second question on your cash flows cash flow position. I guess you mentioned that available cash is $550 around this unrestricted cash position. I would like to understand what's your comfortable minimum cash position and what's your kind of strategy with regards to the location of cash. How much of this is now located outside of Ghana and other operations and what's your kind of target for the location of cash? 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 this on the taxation of this insurance proceeds. I'm kind of curious to understand what was their justification from Ghana Revenue Authority when they kind of sent this, like, claim. What was the justification of this presented by GRA? Any color would be also helpful to understand the kind of their position. Three questions. These are, like, three questions from me. Thank you.
Yep. Sure. In terms of the first question, in terms of lease payments and amortization. Lease payments are included in the operating cash flow number, so they're deducted from the operating cash flow number. 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. 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, we're sitting on a very healthy cash position.
In terms of what we believe that we need from a liquidity perspective to run the group, you know, 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've got at the moment. Probably closer to the $200 million mark. In terms of capital allocation, I think as I mentioned, look, we're continuing to focus our capital. 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.
That, you know, 90% of our CapEx is allocated to those producing assets. You know, that discipline is something that we're going to continue in through the sort of the near and medium term. Focus on, you know, those opportunities that we've got that provide those super short cycle returns, and high IRRs. You know, look, we're really focused on delivering the cash flow that we've set out to delever and just continue to accrue equity value. 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 it, but the, I suppose the event that happened that triggered the insurance that paid out under it happened in Ghana.
I think the sort of the position from the GRA is that, you know, that's because that insurance event happened in Ghana, it's taxable in Ghana. You know, 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. It's very much a corporate tax, corporate insurance policy. Cash in terms of where we hold it. It's all the majority of it is all held in offshore bank accounts. Very little held in country.
Thank you very much, Dmitry. Apologies, everyone that's in the queue still for 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. 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 de-risked. I think we're a very important inflection point where the cash generation, tier cash generation of the business kind of steps up in the second half. No longer I think some of you talked about in the past with this jam tomorrow, I think that is no longer the case.
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 a number of kind of super exciting opportunities we have. Look, it's a transformational journey, I think, but it feels like we're kind of arriving. Thank you again for your time and we'll look to engage with a lot of you in the coming days.