Earnings Transcript for TLW.L - Q4 Fiscal Year 2020

Rahul Dhir: Good morning, everyone, and welcome to our 2020 full year results presentation. So when I was a child, I was taught that the universe only helps those to help themselves. And I hope you'll agree that at Tullow, we've not really left any stone unturned in helping ourselves. And that's starting to pay off. So the delivery of our business plan is underway. And our plans are increasingly derisked. So the improving commodity prices, obviously, is also helping. And all this increases our confidence in our refinancing plans. So today, Les and I will share how the business has performed last year. We'll also take time to share our progress on delivering the business plan and also to update you on our refinancing discussions. And then we'll be pleased to answer questions at the end. So if I can have the slide, which is the full year results, Slide 5. So just to give you a quick overview. So 2020, as you know, was a year of very significant change for Tullow. But importantly, as we emerged as a stronger and a more focused company. We have a very robust with the cash generated business plan and a strategy which is focused on our most productive assets of the highest returning vessels. Now despite the challenges due to COVID and some operational issues and also OPEC+ cuts, we delivered production that was in line with the expectations. We also started to see the early impact of the operational turnaround in Ghana with higher gas offtakes, increased water injection and better facility uptime. In fact, both Jubilee and TEN had over 95% offtake. In Kenya, as you remember, the license was extended, and we're reassessing the development plans with our JV partners. We went through fairly radical rationalization of our exploration portfolio, which saw exits in Comoros, in Jamaica, and we had reduced our footprints in the Côte d’Ivoire and in Peru. Following that rationalization, our focus really is now to fully evaluate our material positions in various emerging basins and to unlock values in these. The exploration team is also working and helping create additional value from our established producing operations in West Africa, particularly focusing on near field and infrastructure-led exploration. Our self-help initiatives, and that we'll talk more about these, they're poised to deliver in excess of $1 billion, including about $400-plus million in asset sales in the past year. The completion of the Uganda sale that we talked about last year was a great achievement, and we're also on track to complete the sales of Equatorial Guinea and Dussafu asset in Gabon in the first half of this year. Importantly, I'm very pleased to say we announced today, and I'll talk at about this, we will be net zero by 2030 as part of our commitment to sustainability. This commitment also underscores and reflects our desire to work closely with the host communities and governments and all our investors to deliver a long-term and a sustainable business. The 10-year business plan that we presented at the Capital Markets Day last year, that's expected to deliver $4 billion of pre-financing cash flow. So that's a $55 flat rate. All the hard work that we did to reduce the cost structure and to instill capital discipline, it also provides tremendous leverage to the oil prices. So for instance, for a $10 increase in oil price, we expect the prefinancing cash flows to increase by $1.5 billion. So that's the tremendous kind of boost that we have, which is a consequence of the work that we did to bring the cost structure down. If I move on to the next slide. Really, as far as the business plan is concerned, we're now kind of in the delivery mode, and we're executing the plan. So it's been a little over 3 months since we shared the plan in -- at the Capital Markets Day in November. Since then, we've awarded key contracts, we secured JV approval. For this year's budget, we've completed year-end reserves, and we've had another successful RBL redetermination. And all of these events, they've validated our views, they've [indiscernible] our conviction that this new approach will deliver a very compelling combination of highly visible and sustainable cash flows along with several additional sources of the band. The resource basis, which is really key, is -- who is underlying the producing assets is very robust, and it's got very significant regeneration potential and this was evident by the 160% of organic reserve replacement that we achieved in 2020. We're making good progress on gas commercialization and with gas offtake is going to plan for this year. Also given the very large portfolio of compelling opportunities in Ghana and the improving commodity outlook, we believe there is an opportunity to consider accelerating the drilling program with the second year. So this will be something that we'll consider carefully with our JV partners over the coming months. The recently announced sale of the assets in Equatorial Guinea and Dussafu speaks to the quality of the nonoperated portfolio, but it also enables us further to allocate capital to the high-return assets in our portfolio. So the improving commodity outlook potentially creates a better environment to unlock value from our significant positions in the discovered and emerging basins. So all the innovative technical work that is being done by the teams, that should certainly help. So let me explain now how we're working on the delivery of this plan for this year. So 2021 is a foundational year in the delivery of our business, and it's also key in terms of our turnaround story. So I'm pleased to say we've had a good start to the year in terms of operational performance. So gas sales, water injection, facilities uptime, they've all been consistent and perhaps in some places somewhat better than expected. We expect the working interest oil production to be in the range of the guidance we've given earlier, which is between 60,000 and 66,000 barrels of oil per day. Obviously, this will be adjusted once we have completed the sales of Equatorial Guinea and Dussafu. Very importantly, we'll start in multi-well drilling campaign in Ghana next month. So the Maersk Venturer has arrived in Ghanian waters on Saturday. This program will help us offset the recent decline and deliver production growth next year. And I'm going to share some details on this in the operational overview. In Suriname, the GVN-1 exploration well is underway, and we expect the results in the next quarter. Elsewhere in exploration, the team is very focused on maturing prospects across the portfolio. But there's a particular emphasis on Guyana, where there is a lot of excitement, and I'll show some clarity. We're making good progress on delivering cost savings across the business. And very importantly, we're on a journey to become a performance-focused organization and where every barrel matters and every dollar counts. And this is a very fundamental change really in our culture and mindset. And I think it puts us and prepares us to be really competitive in really any oil price environment. So with the strong business delivery, with increased liquidity, improving commodity prices, all of this, it really supports the constructive financing discussion that we're having with banks and the bondholders, and that we'll cover a bit more in detailed in this section. But let me first share an important development this year. So on the next slide, we're very pleased to say that we're committed to becoming a net-zero company by 2030 in terms of Scope 1 and Scope 2 emissions. We've defined projects to deliver part of this. So we have -- it's a combination of decarbonizing our operating assets in Ghana. And then in addition to that, we'll have residual emissions, which we will address through a nature-based carbon removal program. So the investment in the decarbonization projects over the next 3 years, that will result in an increase in gas-handling capacities, both in Jubilee and also enable process modifications in TEN. So that will -- both of those things will enable us and put us on track to eliminate routine [indiscernible] in Ghana by 2025, so really good, in fact. I think to offset whatever the residuals are, we're doing a lot of work to identify high-quality removal projects, which would be things like reforestation, afforestation and conservation. So that will allow Tullow to -- which we will invest and that will help us achieve our net zero emission by 2030. We also want to make sure that we're aligning our -- the carbon offset strategy with government priorities. And obviously, as you know the regulations are emerging but we also want to align this with shared prosperity strategy which is something we will -- we have invested in where we work with our host communities to create a socioeconomic opportunities. So it's a tremendous development. I think it's something that's going to become to our way of working, our ethos, and we're very pleased to share this with you. Let me now hand over to Les, who will discuss our financial performance and our outlook.

Les Wood: Thanks, Rahul. Good morning, everyone. I just want to share a few words, first of all, by way of introduction. Hardly, it feels like if we remember, just how extremely challenging 2021 -- sorry, 2020 was globally is worth reflecting just for a moment. Only 11 months ago, Dated Brent reached a low of around $13 per barrel, averaged just $18 per barrel in April and only $29 per barrel in May. We also saw a huge change in the differentials for what that's improved when they fell to around minus $9 per barrel back in May. Despite that backdrop, we've made huge strides over the last year to put Tullow in a stronger financial foundation. With the advent of vaccines, promoting economic recovery and the control injected by OPEC+ on all supply, we've seen a sharp recovery in oil price, reaching $70 per barrel just recently. We also took decisive actions in 2020, which means we are well positioned to take advantage of our sustained oil price recovery this year. I'll begin on the next slide, which is reflecting on a few of the financial highlights for the last year. As I said in my opening remarks, we did take decisive actions in 2020 and that has certainly put us on a stronger financial foundation. Here are a few of the things that we've achieved so far. As Rahul mentioned, we've delivered a strong operational business turnaround as we seek to grow production into 2022. And Rahul will say a little bit more about that in his operational update shortly. We've also secured $1 billion of self-help from asset sales and annualized cost savings from restructuring the business. But we're not done there. We continue to drive efficiency and continuous improvement and expect to achieve further savings. We also said at Capital Markets Day, a robust 10-year business plan. It delivers around $4 billion of prefinancing cash flow and what we will see is a conservative $55 per barrel oil price. This is funded on a deep portfolio of highly economic opportunities with fast payback and good overall prices. Also, with the recent advent of increase in oil price, if you look at our plan at $65 per barrel, there's a further $1.5 billion cash flow available. All of that, of course, is underpinned by prudent commodity risk management policy, which continues to provide revenue protection while we're retaining access to upside. As I was saying as well as with these results, which we and my team prepared, all we want to is thank them for all their efforts. We did all of this by the people experienced a significant amount of change, and we thank everyone for their commitment. With that has become a positive mindset shift, focus on all of our costs, capital discipline and value accretion. And as Rahul said, if you pay attention to every vow and every dollar, then it means you can take advantage of an oil price recovery. These critical actions, including the recent recovery, are providing positive impetus to our ongoing refinancing discussions. I'm going to say a little bit more about that shortly. But first of all, let me talk about the numbers. So this is a slide you will be familiar with. Despite the challenging external environment, our business has performed well in 2020. Revenue is lower compared to 2019, but that's primarily driven by the adverse impact of lower realized oil prices, in our case, by around $11.5 per barrel. And EBITDAX is also impacted by price but also year-on-year production. That said, as I mentioned on the importance of hedging, that revenue was underpinned by $219 million of net hedge giving us a realized Brent oil price of around $51 per barrel. You'll see on the right-hand part of the slide, there was a loss after tax of about $1.2 billion, primarily driven by noncash oil price-related impairments, about $250 million, primarily in TEN and exploration right-offs of around $1 billion which we discussed with the half year from Mali and Uganda and Kenya. Capital expenditure was $288 million after adjustment for Uganda. This was down $62 million or roughly around 18% from budget and 41% from what we said back in 2019. And what this demonstrates is in 2020, a rapid response to external market conditions. Free cash flow was $432 million. Recall, we were at minus $213 million at the half year. So we certainly recovered over the second half. We had a $500 million consideration within Uganda. Without going, of course, with a big redundancy program from our major organizational reductions, now we experienced the usual P&L and working capital. Consequently, that's taken our net debt from $2.8 billion to $2.4 billion. Because of that, we just EBITDAX that I mentioned getting from $0.02 to $0.03. So overall, a good set of numbers. Now I'm going to talk a little bit on the next slide about how we're addressing our near-term debt maturities. As I mentioned, our CMD in November, we laid out a 10-year business plan, which delivers the $1 billion that I mentioned. I also mentioned that the $10 per barrel, it gives us another $1.5 billion. So it takes us to $5.5 billion, reflecting the strong levers that the business has to price. And of course, this then provides a strong foundation to tackle our near-term debt maturities. This is all complemented by the delivery of our self-help. We completed Uganda in only 7 months from signature, and we expect to receive an extra $75 million when FID taken later this year. On the 9th of February, we announced the sale of our Equatorial Guinea and Dussafu assets at Panoro Energy for $180 million, which we expect fully in the first half. We also issued our circular last week, and we've set our general meeting for 18th of March to get approval for the EG transaction. Following extensive business restructuring, we've embedded in excess of $125 million of annual cash savings in our business. We've also completed 3 redeterminations. All of which done under challenging circumstances, most recently agreeing $1.7 billion debt capacity with liquidity headroom of about $0.9 billion. Along the strong underlying business performance and recent strengthening of oil price, we're providing a positive impetus to our ongoing discussions with our creditors, all of whom have appointed advisers. I know there will be a keen interest on this topic and know there are questions at the end, but I trust that you will understand that Rahul and I will not be able to provide specific details given the commercial sensitivity. However, what I can say is we are engaged in constructive discussions and are confident that we will be able to reach agreement in the first half of 2021. Now to the next slide. I want to say a little bit about oil price and to put our assumptions in context. This is a chart that we used back at the CMD in November. As I mentioned, with the vaccine rollout gathering pace, the control being exerted by OpEx custom supply, we said we're seeing a strong recovery in oil price. And you can see that from the change in the forward curve and a significant improvement that we've seen just recently. You can also see the blue shaded area, which has been a broad revision to the external oil price that forecast by a number of external experts. All that does is it puts the business plan assumption of $55 per barrel, now we're at the bottom of the external range. And it continues to underscore what we said previously that the $55 per barrel flat nominal is a conservative long-term assumption. We've also seen some of the advantage of that increase in price. Our realized price in January was $55 per barrel and realized price in February was $62 per barrel, all of which was set against the budget originally $45 per barrel, and we updated the market in our trading statement at $50 back in January. If you look specifically in this year, a $10 per barrel increase will generate an additional $100 million of additional prefinancing cash flow. We remain committed to building a sustaining and low-cost business, which will be resilient at low prices and provide material upside at high prices as you can see from the numbers I just quoted. Now to the next slide, where I'm going to talk a little bit about how we're allocating our capital. Really, this is a slide between 2 parts. And in some ways, if you look at the second part of the slide, dealing with a historical high level of spending. And then on the second part, how we maintain ship capital discipline going forward. I showed this back at Capital Markets Day. It's worth reminding ourselves that this approach to capital discipline is the departure from the past, and we sought to spread our capital more broadly, progress opportunities right across our portfolio. So we're now be forfeiting really underproduction assets and not doing that going forward. On the right-hand side, as you are aware, we've taken material noncash impairments and write-offs in 2019 and 2020, primarily driven by oil price revision to a long-term price common with the industry and also addressing the historical high spend I just mentioned. We now have our assets carried at an appropriate value for the new oil reality and long-term oil prices. On the left-hand side, you can see a detailed breakdown of the capital. [indiscernible] was less than $300 million, so it was $288 million. If you remember, we set out for the year at $350 million. So we were able to do that time to time that I announced, demonstrating our ability to reduce our spend and to respond to the low oil price environment. We have a forecast of $265 million for this year, $265 million, following the approval of the work program budget. The final number for the year will be subject to the timing and completion of the 2 asset sales that we announced in February, and we will update that at that time. We'll be focusing our capital on a low-cost production base, and we'll be focused on the wealth of [indiscernible] plus payback opportunities. And again, it's something we showed previously within that low $150 million to $450 million range, which allows us, as we did in 2020, to act in any 1 year to a volatile oil price environment. So we will have a disciplined approach. And we're only focused on a low risk-producing assets, and we do maintain a lot flexibility to retain and respond to oil price volatility. And I want to say a few words on the next slide about our Jubilee and TEN assets. This is quite simple this chart, but a very important chart. It demonstrates the advantages of a material resource with already installed infrastructure. The chart on the left-hand side shows that we already have relatively lower unit operating costs. We also know that there's opportunity to improve this further and are progressing key initiatives in both Jubilee and TEN. The chart on the right-hand side is a remainder of our strong portfolio of production investment opportunities. We've already invested about $5.7 billion net capital so far in Jubilee and TEN development reserves and resources that we have. We intend to invest a further $2 billion net over the next 10 years, around 75% of that will be in wells, with the remainder on subsea infrastructure and facilities. That will be an approximate cost of $10 per barrel in Jubilee and about $14 per barrel in TEN. As you can see from the chart, which was shown previously, IRR is in excess of 80% average at $55 per barrel and excess of 130% at $65 per barrel. These opportunities are also robust at low prices and it gives us the confidence to invest. These are structurally advantaged assets and underscores the resilience of the Ghana assets to withstand lower prices and increased leverage to oil price offset as I mentioned previously. I'm now going to say a little bit about our 2021 guidance. This slide is a simple summary of our 2021 guidance figures. These are all in line with the January trading statement. All the figures, as I mentioned earlier, will be adjusted for the EG and distribute transactions once we complete, which we expect to be in the first half of this year. We expect prefinancing cash flow to increase about $0.3 billion at $50 per barrel following deal completion, and a further $10 per barrel increase, as I mentioned earlier, will add around $100 million of prefinancing cash flow up to about $75 per barrel. So just a few things to say in summary before I hand back to the Rahul. Firstly, the team has done a great job in 2020 despite an extremely challenging external environment. We're taking steps to improve robustness of the balance sheet. We're seeing impact of the focus and improvement performance reliability in our operations to underpin cash flow generation. We've made a good progress on implementing our actions on cost to make it more competitive and also maximize the value of assets. We've taken decisive portfolio action as you've seen with the sales of Uganda, EG and Dussafu. These are delivering value, strengthening the balance sheet, and we've also been optimizing our exploration portfolio. Together, all of these actions are creating a great resilience for our business in, of course, an increasingly challenging and volatile world. So with that, I'll now hand back to Rahul.

Rahul Dhir: Okay. Les, thank you very much. And what I wanted to do is start the discussion on operations with a focus on health and safety because this is fundamental to how we operate. And let me just -- on this chart, we're going to talk about COVID because COVID had a very significant impact in the way we managed our business, we managed in 2020, and we expect that, that will continue for much of '21. Our response to COVID has benefited from very close cooperation with the government of Ghana. We did experience a number of COVID cases offshore, but fortunately, these did not impact production. The response was well managed. So the spread was contained. And fortunately, everybody who was impacted, they've all recovered. But we continue to implement very stringent quarantining and testing procedures, which have all been very successful introducing the risks and also ensuring that we have safe operating conditions. More broadly, again, around the -- across the organization, we've supported all our colleagues during this process with ongoing programs in health and well-being. Let me just turn on to safety, as you see on the chart on the right, we continue to benchmark our performance against industry standard metrics, and we look at things like sort of overall injury rates. So for 2020, our overall injury rates per million hours, so that's the rate. They went up when compared to 2019, but also were above the industry averages for 2019. But if you look at 2020 more deeply, particularly focusing on our Kenya operations and the Ghana FPSOs, what I'm pleased is that we had 0 lost time injuries and 0 recordable injuries. So that represents a very excellent performance for both of those operations. And it's particularly remarkable on the 2 FPSOs, where a lot of activity took place, particularly in the first half of 2020. We did have 8 injuries on the other sites. Fortunately, they were all minor with rapid full recovery. But clearly, this is not acceptable, right? And would it -- we're very relentless in terms of eliminating all of these from our business every day. So also, as part of that in 2020, we were very proactive in delivering a very impactful life-saving rules campaign in the fourth quarter. This was also coupled with a series of safety stand downs, which helped just reinvigorate the EHS leadership. And the team they continue -- there is continuous learning. So they're learning from near misses, they're learning from incidents, and we have developed a safety improvement plan, which has got kind of 4 key areas. So there's safety leadership, there's learning from incidents, there's contractor management and process safety. So we're very committed to making sure that we're improving our safety performance, particularly this year as well, and we make sure that no one is hurt in our operations. Let me turn to then talk about the resource base because this is fundamental to the compelling story that we have. So we've got a very large resource base and a reserve base with organic growth potential. So the 2P reserve base, the chart that you see on the left, is 260 million barrels. Now more than half of this is in Jubilee, about 1/4 is in TEN and about 20% is in the non-op. And that's the number pre the disposals of Equatorial Guinea and Dussafu. What was interesting is we added 45 million barrels to the 2P reserves last year. And this is really a consequence -- so it's the first manifestation of the impact of the business plan. So in Ghana, it was a direct consequence of accelerating particular projects into the license period. And in the non-op portfolio, it reflected updated views on assets like Simba and Espoir. Now that 45 million barrels more than offset the 27 million barrels of production, so we had a net increase. Also, when you look at the contingent resource base, that, of course, reflects the sale of the Ghana assets. But particularly, let's focus on Jubilee, right? So where we've currently produced only about 17% of the oil in place. Now our expectation is that we would recover about 45% of the oil in place. So we've got a lot to really produce here. And there's potential for further recovery from acceleration of residual resources into the license period and step out drilling. TEN is at an earlier stage of its development, and it's only produced about 9% of the oil in place. And that's out of a 1 billion barrel field. Now relative to TEN -- sorry, relative to Jubilee, TEN has a much more significant contingent resource space that will add significant incremental potential. And then in TEN, the current thinking is within the license period a recovery factor of about 30%. But we believe there is potential to significantly increase this recovery factor to around 50%. So there's a tremendous amount of upside intent. So you can -- that's the reason why we're excited about both of these assets. Let me talk specifically about both Jubilee and TEN and give you some historical context and frame our future plans in that. So as explained, Jubilee is a world-class resource, right? But the -- when you look at the historic performance in Jubilee, that's been disappointing. Now a big factor which impacted historic production was just kind of under investment. So what you see is -- and what we've done in the chart on the left is we've plotted out production by vintage. So what you'll see is that production naturally will decline, and you've heard me explain this before. But in order to sustain production, you need reinvestment, right? And what to me was striking when you look at this chart is the lack of consistent drilling, particularly in the last few years, right? In addition, historic production was impacted by poor uptime, by constraints on gas and low water injection. And then you had -- you see the 3 big dips in the production. So those are 3 major events that had quite a material impact. So in 2016, the dip was related to the Turret failure; 2018, it was related to 2 shutdowns that were, again, part of the repair of the Turret; and then 2019 was impacted by increasing water cut from the early vintage wells. And what's interesting also is that you look at our current sort of well stock and you can see the vintage of this, and we're producing from kind of a lot of the older wells. So that also is -- kind of helps understand and put in perspective the production decline that we saw last year and this year. But given the scale of the resource base and the existing infrastructure, this is obviously a relatively easily reversible problem. And to that end, we've identified an inventory of over 25 wells so far, and we'll execute a consistent drilling program, particularly in Jubilee over the last -- over the next 5 years. And look, I mean, that's the first time since probably 2013 that we're going to see a consistent drilling program. And what's interesting, of course, is that these are more better-defined opportunities. They may be smaller than what we were doing, say, in 2011, 2012, but given the existing infrastructure in place, they're very profitable, and they help restore production and they pay back pretty quickly. That's what Les talked about. And the drilling inventory, like I said, of the 25 wells, you've got about 15 oil producers, which is a mix of infill and then in the eastern part of Jubilee, so Jubilee Southeast and Northeast, you have 10 water injectors, where the primary purpose of these would be to increase recovery and increase reservoir pressure, and I'll illustrate the impact specifically in a subsequent slide. Future production is also going to be impacted by the improving operating performance and increased facilities capacity. So gas offtake, for example, we're targeting 150 million scf a day, and uptime, we're targeting sustained levels in excess of 95%. Water rate, the current levels are over 200,000 barrels of water injected per day, and we're looking to target increases up to 275,000 barrels a day. And that's aligned with the increase in water injection -- in the number of water injection wells. Let me now turn to TEN, where it's really the story that is slightly different. So firstly, we have a very reliable FPSO. So the uptime currently at TEN is about 99%. TEN also has a lot of capacity. You can go up to about 100,000 barrels of oil per day. That's at the facility. So please don't confuse this with the production forecast. So -- and over 300 billion scf per day of gas capacity retention. So that's -- the point of that is that's a unique opportunity to add reserves and production, okay? Now historically, the TEN production was impacted by a couple of things. So one was there was disappointing performance from Enyenra, and then the other one was, you'll remember, there was a delay in the start of the drilling due to the border dispute. So if you look at this chart, you see there's been very little consistent drilling in TEN either since the initial wells in 2016. Now I think when you look at TEN itself, it's got Enyenra, it's got Ntomme and it's got other fields. Now Enyenra is different from Ntomme and from the Jubilee field in terms of its deposition characteristics. While it's better understood today and we've identified potential in step out areas, both to the north and the south in Enyenra, the bulk of our future development plans will focus on Ntomme -- extending Ntomme both to the West and the Northwest. So that's kind of similar type of story as what we're seeing in the Jubilee kind of -- eastern part of Jubilee. Now here again, in TEN, we have an inventory of 25 wells. That includes producers and water injectors and a couple of gas injectors. And we expect here the near-term drilling will help stem the decline and then we'll restore production over the medium term as we convert a lot of the contingent resources into reserves. Now let me provide some color -- so I want to bring you now into specifically what we're going to do in 2021. And this is an interesting slide. So I'll just need to explain this. So what we have on the top left, we've illustrated TEN, so that's kind of a top-down view. And the currently developed areas that you see are in dark green and areas for future development are in light green, and the gas is shown in red. So that's the chart on the top left. On the top right, we have a cross section. So think about that as a slice of cake, and that's through the Ntomme field. And what you see in the cross-section is the oil is green in the middle, the section in gas is red at the top, okay? So that's the chart. Now what we have is 2 producers and 2 lines, those are indicated as with the capital letters P. In the absence of any gas support, the production from these 2 kind of Ntomme oil producers, it's declined by over 20,000 barrels a day just to pressure depletions. There's no support. They're just producing a natural pressure depletion, right? Now when you look at that and you say, okay, that's the rationale behind why we have a gas injector, which is that GI, the capital GI in the square box that you see, that's going to help reinstate production from these 2 wells by repressurizing the oil reservoir. And what this does is it's acceleration as well as its new reserves, okay? Now similarly, on the bottom left, we've illustrated Jubilee. So again, the same idea, the currently developed areas are in dark green, the areas for future development are in light green, and the gas is shown in red. And the plan in Jubilee is to drill 2 infill producers and 1 water injector. So this is as part of the program for 2021. Again, we have a cross section, which is in the middle. So actually 2 cross sections. So let me focus on the cross-section in the middle. And what it illustrates is the impact of a new producer. So that's the key with the square outline that you can see. And that's drilled at the upper part of the reservoir. So what it does is it's accesses what is called, in a sort of a technical word, attic oil. So this is oil that's bypassed and it cannot be accessed by the existing producer, which has now got substantial water cut, right? So the idea with this infill well is to access bypassed oil, right? The cross-section on the bottom right, it shows a new water injector, which is labeled WI again. And that water injector, you can see comes in at the bottom of the reservoir. So the reservoir sort of goes up. The water injector comes in at the bottom of the reservoir. And it supports the producer, which is labeled P, and that producer, again, has not had pressure support. So it's been a natural decline, and it's -- the production has declined by 12,000 barrels a day because of pressure depletion. So the oil is there, but it doesn't have the energy to push it out. So that's why you're injecting the water. So that's the kind of -- the sorts of things we're doing, but let me now switch to kind of show you how we've delivered these wells. So we're excited about starting a multiyear multi-well program. The Maersk Venturer that's -- it's going to be -- is contracted to what is planned to be a minimum 4-well program. The rig arrived in Ghana on Saturday, and we're expecting the first Jubilee well, which would be a producer, next month. What we've done is by simplifying well designs, by implementing integrated planning and leveraging scale in the supply chain, we see a 20% to 30% reduction in our average well costs. We're also targeting 70 days to drill and complete a well. So we should be able to drill and complete in a typical year somewhere between 4 to 5 wells. So the 2021 program, as I said, has got 3 Jubilee wells, so 2 producers, 1 water injector, and there's a gas injector in Ntomme. We expect the producers, the infill producers to add about 8,000 barrels per day in the first year. The water injector will add about a similar amount of oil. This is because it's providing support to an existing producer, which is declined. Similarly, the gas injector in Ntomme, we think will provide about 6,000 barrels a day incremental from the 2 wells that it is supporting. So that's the production -- that's how the production impact of both the producers and the injectors come in. I've just shown you an illustrative 2022 schedule. Please don't hold us to this because this is just illustrative and it will be refined with the JV input. But the point is that we should be able to drill at least 4 wells across Jubilee and TEN next year as well. And as I said earlier, given the large inventory of drilling opportunities, with over 50 wells that I described across Jubilee and TEN. So it's fairly obvious that if commodity prices recover, we would look to accelerate. But that's, again, something that we would plan with our JV partners. Let me now turn to our nonoperated assets. Because non-op is a great business. I mean it has delivered consistently over the last 5 years. A stable production in the kind of 22,000 to 25,000 barrels a day. 2020 production was impacted by COVID restrictions; and then secondly, we had OPEC+ restrictions, which impacted particularly production in Gabon in the back end of next year. The 2021 production is forecasted to be 22,500 barrels a day. So that's kind of flattish. But the impact of the disposals will have to be factored in. And we also see some high-value development projects that are being matured, and this will be contributing to investment in 2022. So for example, in Côte d’Ivoire, we have the Espoir infill program, and in Gabon, we have a Simba expansion project. If I move on to Kenya, just pleased to share that the government, they approved the 2021 work program in budget and the license extension has been granted till the end of 2021. At the Capital Markets Day, we announced that there was a joint decision amongst the JV to reassess the development plan and to design a project that's economic at low prices. But while preserving the phased development concept, that was fundamental to it. And last year, we completed the early oil pilot scheme, over 2 years of production data, and we had a lot of good reservoir data. That is now being used to help redesign the full field development concept. Now what we're also doing along with our JV partners is we expect that the revised assessment should be completed sometime in the second quarter of this year. And in parallel, we're working pretty closely with the government of Kenya. So we're looking at securing approvals for environmental and social impact assessments for the project. And also looking to see how we can start working to finalize the commercial framework. But I think realistically, we'll provide a detail -- more fuller detail in the second half of this year. Moving on to exploration, and I wanted to talk a little bit about Guyana, where we're continuing the prospect maturation across both the blocks. We've got newly reprocessed 3D seismic across both Kanuku and Orinduik. It's an exciting process because we're looking at opportunities across 3 plays where we have multiple targets across both tertiary and the cretaceous. Additionally, we're looking at a lot of work on better understanding the petroleum systems, I think I talked about this at the Capital Markets Day. That's been completed now, and I think we have a much better understanding of how the oil quality distributes across the reservoirs. And this year, remember, was one of the key challenges when were drilled back in 2019. We've done a lot of work also on reservoir distribution across the block. So that's helping us. It's revealed the kind of number of these stacked slope channels, so those are interesting. So that is all being matured now. And particularly in the Kanuku block, which is operated by Repsol, the focus is to identify drillable prospects for a 2022 well commitment. Suriname, not much to say other than the drilling is underway. We're looking to target dual targets in cretaceous turbidite play, and we're expecting the results in the next quarter. I also wanted to highlight 2 kind of other interesting areas in our portfolio. One is in Côte d’Ivoire, where we reprocessed some 3D seismic. And what we've identified is the extension of the prolific Guyana play. So it's kind of next door into this block, Côte d’Ivoire CI-524. We've identified multiple cretaceous reservoirs at the kind of subregional level, including we have some deepwater slope channels and loads that are similar to what we see in Ghana. So the team is moving towards prospect maturation. Now we own 90% of this license. So we've been looking at a partner for the next phase, which would be ready to test how these plays have matured. Quickly on Argentina, we have 3 blocks, which are all offshore in an area that's really dominated by the majors. So we're working to better understand the prospectivity there, and we'll then develop what our strategic options are. So I think just quickly to conclude, purpose and the strategy that we set is very clear. And we've set out a kind of 10-year business plan at the Capital Markets Day. So the focus really now is on delivery. And we've had a good start to the year. We have a low cost base that I talked about, Les talked about, which is leveraged to the oil prices. And we're implementing plans to deliver production growth. The self-help measures that we've discussed, they are delivering real value. And we're identifying a lot of upside also in the nonproducing assets. So all of this, it positions us really well for the ongoing refinancing exercise. But very importantly, as you look beyond that, we're building Tullow to be a successful company that will create value, irrespective of the oil price in any old price environment. So thank you very much again. I'm going to stop here, and we look forward to your questions.

Operator: [Operator Instructions]. The first question comes from the line of Michael Alsford from Citigroup.

Michael Alsford: I just got a couple, if I could, please. Just firstly, on your net zero target, obviously looking to reduce Scope 1 and Scope 2 emissions by 2030. Could you talk about what the incremental costs will be to deliver that target over and above your $2.7 billion CapEx guidance for the 10-year period? And that's my first question. And then just secondly, I'm just thinking about portfolio. You've obviously made some progress around selling assets through Uganda in West Africa. But I'm just wondering if you could give some sense as to whether that's now largely done, and you're now happy with the portfolio? Or are you still looking to try to monetize more assets in order to pay down debt?

Rahul Dhir: Thanks, Michael. So firstly, on your -- so on the decarbonization projects, which is about gas debottlenecking at Jubilee and also process modifications. That's a lot baked into the business plan that we shared with you guys at the Capital Markets Day. The way we're looking at the nature-based solutions that's to really address any residual kind of harder-to-abate emissions, those costs would be incremental, but the approach, and I wouldn't want to go specifically into that, but our view is that we're going to look at projects organically and the capital cost of that is going to come perhaps later in the decade. But if you do it organically, we think it's going to be a more gradual spend as opposed to big chunky spends. So that's on the costs. I think in terms of asset sales, look, we've been consistent in terms of that we're not doing any fire sales and things like that. But I think fundamentally, with the self-help delivery of nearly $1 billion, right, there is no -- and the delivery of the business plan and operational performance, we don't really see any need for further disposals. But I'll make -- I mean, the generic point I would say is that, look, if somebody puts a big number on the table, you would look at it. But that's -- I mean look, that's a generic point. But no, otherwise, no, I think we're feeling pretty good about where we are.

Operator: The next question comes from the line of Rachel Fletcher from Morgan Stanley.

Rachel Fletcher: Two for me, please. This morning, you gave guidance for the incremental improvement in cash flow generation at higher oil prices, which is very useful. At the Capital Markets Day, you guided for a reduction in gearing to the lower end of the 1 to 2x net debt-to-EBITDAX range I think you said by 2025. So how should we think about the time line to net debt reduction at higher oil prices, please? And then also, you mentioned this morning that you could accelerate your drilling program at higher oil prices. Again, at the Capital Markets Day, I think you mentioned that you have these additional upside opportunities, so increasing field recovery, developing near-field discoveries, et cetera. What sort of oil price would you need to start into these activities?

Rahul Dhir: Okay. So I think on the first one, Rachel, if you look at kind of a 10-year guidance on what we call sort of prefinancing cash flow, so that's really CFFO minus CapEx, that's about $4 billion at $55 over the 10-year period, right? That number we're saying, if you go from $55 to $65, that number goes up by $1.5 billion, right? So that's about -- what is 37.5% uplift, right? So that's huge. Now if you take a 5-year view, we would say look, disproportionately, let's say, a part of that comes into 5 years, obviously. So we would see an acceleration of the deleveraging, right? I mean that's the simple point. And we're starting to see just even with this year, almost a 50% increase in our prefinancing cash flows, right? So from about $0.2 billion, we said it's going to go -- a $10 change would go another $100 million. So certainly, I think, definitely, it's good news for us in that we'd settle the business to be able to delever even at low prices. But as prices go up, the deleveraging pace accelerates. The second thing is in terms of the kind of reinvestment, as you saw from the chart that Les had shown, which was a relay of what we'd shown on the Capital Markets Day, we have a deep inventory of investment opportunities, right? And they pay back super quickly. So it is logical -- so -- and remember that, that returns that Les showed you that 80-plus percent, that's at $55 oil, right? So I think the discussions we're going to have with our partners is that if we believe that oil is going to be above $55 flat over the next 3 to 4 years, do we need to look at acceleration opportunities? So we're not looking -- because the portfolio is so robust, Rachel, even at lower prices, we don't need very high prices to kind of trigger that.

Operator: The next question comes from the line of Chris Wheaton from Stifel.

Christopher Wheaton: The background on the well maturities at Jubilee and TEN, I think, really interesting. It gives a lot more insight into your production target. So that's very helpful. Two questions for me, if I may, both for Les on finances. Firstly, a question on your balance sheet. I note that all of your debt is now in current liabilities, even though the RBL shouldn't be in current liabilities. Could you explain why that change has happened since the half year last year, please?

Les Wood: Yes, Chris. I mean, it's a pure accounting treatment thing, which there was updated guidance from IFRIC at the back end of last year, which requires us to assess that on that basis. That's not what we expect to happen. It's just a pure accounting thing. So that's why it's demonstrated that way on the balance sheet.

Christopher Wheaton: Could you elaborate a bit more on that guidance? Is it to do with the going concern statement? Is it to do with the liquidity look forward test? Both of those conditions were present at the half year results when the debt wasn't all in current liabilities?

Les Wood: No. I mean, it isn't to do with those tests specifically, Chris. It's just if you kind of look at the accounting guidelines and, as I say, as per IFRIC and a discussion with our auditors, EY, that's what we're required to do. As I said, it's not what we expect the outcome to be. So that's why we show it that way on the balance sheet. We're going to always get into more detail off-line. But sure, we are -- and I can think.

Rahul Dhir: I think Chris -- sorry, Chris, just to give you a little bit more sort of context. I mean, look, the problem in a sense that, that would address it, right? So you saw with the -- at the Capital Markets Day, we said we can delever. That's what I explained to Rachel, right? Now that deleveraging process, if oil prices are higher, becomes faster. So the only clearly question you're trying to address is I have a mismatch of timing in terms of where my debt maturities are versus where my cash flows are. So it's a refinancing question, right? So I think putting the accounting to one side, I think the substantive kind of problem you're trying to solve is a relatively simple one, which is it's a question of refinancing. So I just wanted to kind of give you that context.

Christopher Wheaton: That's very helpful. Second question was on the liquidity look-forward test. In the statement, you talked about submitting a liquidity forward test. This is based on your base case assumption of $50 this year, $55 onwards and includes I think the words you've used in statements are additional mitigating factors. Could you explain what those mitigating factors are, please?

Les Wood: So the -- on the group-wide funding statement, which we did submit in line with the projection back at end February, we've got the borrowing base approved, which is what we announced, still stand on group-wide funding. But as we submitted that, we believe we've met the requirements. And then -- I mean, quite simply, if you think about today, we're sitting on about $0.9 billion give or take of liquidity. We don't need to add much to oil price actually given our 2 maturities in front of us of $300 million and $650 million that actually meet that test. Therefore, really, price alone actually gets us to what we would see in terms of requirements for the test. It just happens to be an expanding piece of feedback from the bank. So -- but there's all sorts of mitigating actions that we could think around capital of losing on the finance and those sorts of things. But really, you look at price fundamental with -- I mean prices already moved considerably from when we submitted the test. So price alone will reach the requirements of the group-wide funding statement. So we believe we've met the requirements of the test.

Christopher Wheaton: That's brilliant, in fact.

Rahul Dhir: Yes. And just, Chris, just to add to that a bit, you have, as Les said, about $0.9 billion of liquidity, you have another incremental $100 of prefinancing cash flows that come in just on the base of the forward curve for this year. So I mean it's -- you can do the math and you get to it pretty easily.

Operator: The next question comes from the line of Nick Stefanou from Renaissance Capital.

Nikolas Stefanou: I've got two. First one is for Rahul and the second for Les. I'm not sure if I heard you correctly. Is -- on Jubilee, are you now assuming the overall slope recovery to be 45% from 41% that was before? And if that's the case, and maybe if I misheard it, doesn't that -- isn't that a bit aggressive in general, like not so many pits have this kind of like recovery factors? That's the first question. The second one for Les. Les, for the Uganda circular, you were mentioning that under a $45 oil price scenario, your 2022 liquidity shortfall would have been $130 million. In the press release today, when we are looking at $50 as a base case, and on top of that, you have done the EG and Gabon disposal, you still forecast a shortfall. Can you talk a bit about the moving parts of them? Because I have expected about $50 given the Uganda circular, you might have -- you should have been without any kind of cash flow deficit.

Rahul Dhir: So the first one, look, I mean, well done, you spotted this. So yes, so the -- at the Capital Markets Day, we were looking at recovery factors of about 41% across that number based on the 2P, 2C work that TRACS have done is now about 45%. And it's -- look, with the business plan, remember, what we said, Nick, is that we're looking to accelerate reserves into the license period as we bring kind of new projects on. So that's a good news. I mean, that's a practical consequence of the business plan. So that's one. Look, these are world-class reservoirs. I mean the broad sea permeability is fantastic. So my personal view is I think the recovery factors should be higher than 45%. But that's what we see today. But what's interesting is when I still look at what's the residual production outside of 2036, right, that's still quite substantial, right? So we have work to do still to be able to bring that production in into the license period. And certainly, that's not just a good thing for us. I think it's also a good thing for our partners. It's a very important thing for the government. So that's the story. And it's -- look, I mean, that's the reason why we're super excited about this.

Nikolas Stefanou: I understand, but it kind of like feels a bit premature to have these reserves increase, given that the last time you drill that well was in 2019. It somehow have expected to maybe do in -- after you started like your drilling campaign again. If that makes sense.

Rahul Dhir: So look, just -- okay, so help you understand this. So I'll give you a very specific example, right? So take the Jubilee Southeast project, right? So what has happened is the Jubilee Southeast project was a 3-phase project spread over 8 or 9 years, right? It had 2 sets of manifolds. Now what we did was we took a decision. We said, look, we're going to increase the capacity of the first manifold. And so if you can visualize the Jubilee field, the eastern part of the field is less developed, right? So you stick the manifold in and that allows you to then bring in incremental production. So we increased the capacity and as a consequence, we could then compress the first 2 phases together. What that does then is that it brings that resource into my 2P number, okay? So it's a question -- it's a consequence of my -- of how I'm looking to develop my plans, and that's what's driving the reserves. Similarly, what we have done is by accelerating, say, wells that we were going to be drilling in '25, '26, which were never in the drilling program at all, right, those wells then bring in additional resources into this 45% recovery factor. So we weren't trying to kind of increase the recovery factor. The way this has gone about is it's a bottoms-up exercise, Nick. And it's looking at discrete projects. And then what TRACS have done is it's independently assessed. This is their assessment of it. So I think the takeaway that I would say to you is that it gives you a sense. I wouldn't get hung up on whether it's 45% or 50% or whatever, but the fact that it's a big resource. You've got 1.8 billion barrels. You've got infrastructure. You have the ability to keep replenishing it. That's -- I think that's the key takeaway.

Nikolas Stefanou: Okay. And the second one?

Les Wood: Yes. For the second, I knew this question would come up in so much that the slightly, I'll call it, different vintages that I can do that around it. So from preparing what we did for going what was required for the circular and in fact, for the group-wide funding statement, we're doing is that there's slightly different forecast in time but also with the relative price assumption. So therefore, as a result, you see the shortfall as described in the statement back and that's on the back of the circular. And therefore, we get to guess is the most up year, which are obviously not shared publicly with a group-wide funding statement, when you start to adjust for prices that we start to see at the beginning of the year. We're actually seeing that over that [indiscernible] we actually have sufficient headroom. So with all of that, it's just really the difference in vintage and timing of the various analyses used in the pre-test.

Operator: The next question comes from the line of Mark Wilson from Jefferies.

Mark Wilson: I'd like to -- you just spoke to this a little bit on Chris' question, but I just like to understand the difference between the approval of the redetermination we've announced today and the fact that the liquidity test that appears to be related to it is still awaiting for approval. Can you explain the difference of those 2 approvals, please?

Rahul Dhir: Sure. Les, go ahead.

Les Wood: So really the borrowing base, Mark, goes -- is something, as you know, we do every 6 months for March and September. We ask for an additional test in January. We give -- because I guess of all the ongoing discussions and examination of the business plan that was deferred by 1 month to sooner or no later than February. And then we announced that the 26th of February. So with the rate majority approval on the borrowing base. Hand-in-hand with that, we also have additional things that we're required to include. One of which is a group-wide funding statement, which, as I said earlier, when the basis what we've supplied, then we believe we've met requirements of that test. That's something which is currently what the bank doesn't alter the borrowing base that's already been agreed with the bank. And that's something that we are awaiting feedback on. So they are -- we're going at the same time, but the borrowing base approval is independent from the group-wide funding statement approval, which is coming with the banks as I mentioned.

Mark Wilson: Okay. Then a couple of follow-ups. I mean, would you announce that approval when it's received, number one? And secondly, the circular speaks to a Ghana tax claim dispute over $300 million. I'm just wondering if that is part of the liquidity and your forecast assumptions that you speak to in today's results.

Les Wood: So on the first item, we would just expect that to be part of our ongoing discussions with the banks. We would take a decision at the time as to what we thought was met and what announced or not. But we've got, as I said, the bigger, broader discussions ongoing. And as far as the -- we have quite a number of detailed discussions actually going at the [indiscernible] on tax, which are currently in discussion with the Ghanaian government but are not included in our forecast today.

Mark Wilson: Okay. And so if I can just throw one operational one in there. Given the increase in oil production you're talking about at Jubilee in the coming year into 2020, how does that relate to gas production? There's no limitation on oil increasing from here given the current levels of gas production?

Rahul Dhir: No. So we basically have enough processing capacity. So we are at about 200-plus million scf a day. I think we will be by midyear on processing capacity, so no constraints there. Offtakes are at about 135 million scf a day. So we certainly see that as being sufficient. Also Mark, as I explained, we're starting to do water injection. So the more water you inject, you have -- it increases recovery, increases reservoir pressure. And as it increases reservoir pressure, it reduces the GOR. And then the new wells that come on stream gives you the opportunity to produce low GOR wells. So there is many sort of things. It's a complex system, but it's between a combination of new wells, gas offtake, which is consistent at what we expect at current levels, processing capacity, which is adequate, I think we're pretty good right now.

Operator: The next question comes from the line of James Hosie from Barclays.

James Hosie: I understand you don't want to say too much about your expansion plans. But just wondering if you could talk about how the recent rally in the oil price has shifted negotiations with your creditors. Is it now the case you're negotiating about -- around higher oil price outlook and flat repayment schedules? Or is it more that simply that any prime to secure new capital become a bit more straightforward in this oil price environment?

Rahul Dhir: So let me maybe have a go at that, James. I think, again, just to remind ourselves that the -- even at the lower oil price, we were always very comfortable and had demonstrated that essentially, we were able to repay that levels down to $1 billion to $1.5 billion over the 5-year period, right? That process accelerates if prices are higher, right? And then the exam question really is our near term, it's a mismatch of cash flow, so you're looking at refinancing, right? That's the problem we're trying to solve basically, right? Now the question then becomes, what's the cost of capital of the refinancing? And what are the options that you have, right? Now I think 2 things we say. One is business performance, which has been good, visibility, derisking the business plan, delivery of the $1 billion self-help, all of those start to help you in the case on your cost of capital conversations. I think the oil price helps you further, and you end up with a wider suite of options. But the exam question is still the same, which is you're looking to a refinancing, and the question will become what's the cost of capital. It's no more complicated than that, frankly. And you guys are kind of experts at this. I mean, you -- it's the bonds have rallied, stock prices are rallied. So all of that provides a better context against which to be having these conversations.

James Hosie: Okay. And I guess the follow-up then, I mean, with the progress in self-help and the higher oil price, I mean, can you, at this point, rule out issuing equity as part of your refinancing plan?

Rahul Dhir: So we've said, look, it's -- the business doesn't need equity. The -- firstly, the CapEx program is self-funded. We're deleveraging. So the business doesn't really need equity.

Operator: We are taking our last question from Al Stanton from RBC.

Al Stanton: I'll be keen to ask three questions then, please. And there are hotspots. So I apologize for that. So first of all, with respect to the emissions, I think net zero in '23 is a great target, but can you give some clarity on what your target is for your carbon intensity before you start offsetting what would be a reasonable objective for the ongoing business? Going back to something Mark picked up with respect to your chat today with the Ghana in revenue authority. Higher oil prices are good for you but they involve in everyone else. So should we be looking at other small print in the circular, such as the dispute on which now looks like a pretty commercial development? Are you going to have to pay a bonus for that discovery? And then an open question rather than a silly question. Why do you have a $105 million on your balance sheet? Is there a benefit to having paid some of your debt down with that cash?

Rahul Dhir: Okay. So let me take, I think, the first 2 or 3, and then Les can answer the harder questions with regard to cash. So the -- so Al -- well, firstly, I'm going to say, hopefully, you look back and say, you said I was running into a burning house back in July. I think we put the fire out and we're rebuilding it in a nice mansion. So hopefully, you'll agree that. I think in terms of emissions, we're looking at 0 flaring by 2025. I can't do the math in my head on the carbon intensity, but we can get back to you on specific numbers on that. But we'd certainly kind of -- I think it's -- our intensity this year was about 29, 30 kg per barrel of oil equivalent. So it would come down substantially by 2025 as we implement 0 flaring. In terms of things like kind of all GRA and other disputes, I think those are ongoing. So it's premature to comment on those, and they will take the course that they take. We don't necessarily see the oil price kind of impacting the outcomes of those. Let me turn over to Les on the cash question.

Les Wood: Yes, it's pretty simple. I mean, your cash to hand until we've determined as part of this ongoing refinancing that we have to ongoing how we're going to make best use. So I think it's a simple. I think the good news is not to repeat all the things that we've said, but given the turnaround, given all the cost savings, given how price is improving, we've actually sitting in a good position, strong position on our liquidity, therefore, to address it. So it's really how we choose to use it and it's all part of ongoing discussions as part of the refinancing.

Al Stanton: Okay. Yes, Rahul, you've done a pretty good job of putting out the fire. I can say that.

Rahul Dhir: Okay. Well, look, I think we've overstayed our welcome, but thank you, everybody, for your time. And again, look, I think the key point that Les and I wanted to convey is that it's -- we have confidence. I think the team's done, I'd just echo, again, this is probably addressed to the Tullow team that people have done a phenomenal job. I think we've really turned our mindsets around. I think the culture is really very performance-oriented, people have a tremendous sense of ownership. Every day, I see people do stuff and it's inspiring, right? And we're building the basis for -- I mean the refinancing will get done. I mean, that's just a kind of step in the road. But really, what we are doing is we're building the basis for a super successful company that hopefully you guys will all be kind of pleased to be part of.

Rahul Dhir: So again, thank you very much, and a big thanks to the Tullow team as well for the journey so far, but it's exciting. It's -- we're looking forward to next step.