Tullow Oil plc (TLW) Earnings Call Transcript & Summary

Good day, and thank you for standing by, and welcome to the Tullow Oil plc 2021 Half Year Results Conference Call. [Operator Instructions] For your information, this conference is being recorded. Now I would like to hand the conference over to your speaker, Rahul Dhir, Chief Executive Officer. Please go ahead.

All right. Thank you, Andrew, and good morning, everyone. Thank you very much for joining. We're very pleased to have this opportunity to update you on our progress in the first half of this year, and we want to give some thoughts also about our strategy and performance. But I thought before we start our presentation, I just wanted to share that we've announced today that Les will be stepping down. This is by mutual agreement. I'm sad to see that -- well, he's not going yet, but I'm certainly sad to see him go. But he's been a real partner with me as we've steered Tullow through the whole turbulence of the past year. And as you all know, he's been a key architect of our financial turnaround. So now today is not goodbye and that he's committed to staying at Tullow till the end of March. But I did want to thank him for his huge, huge commitment and his leadership. So let me start. Just I really wanted to start with the reflection of where we are today. So we've done a lot in the last year to turn the company around. We've reset our cost base. We've simplified our capital structure. And we put the group on a much firmer financial footing. As you know, we're looking to allocate around 90% of our capital to West African producing assets. These create a lot of value to generate very material cash flow. And we're now very well set up to deliver a sustainable self-funded production from these assets. We also have other areas in our portfolio where we can unlock value, and I'll talk a little bit more about this, particularly in Kenya and in exploration. We prioritized efficient and safe oil and gas operations in our host countries while minimizing the environmental impact. And as you will see, and this has been part of our ongoing commitment through our work, we will deliver shared prosperity and will create value for our investors, for our staff, host nations and communities. And Tullow has had a long and proud history in Africa, and I believe we're very well positioned to continue as a leader in the continent's oil and gas industry. So you'll remember kind of a little over 10 months ago we held the Capital Markets Day. And there, we told you that we would focus on a few things. So these included delivering sustainable self-funded production, improving our operational performance in Ghana, including reducing well complexity and rig downtime. We said we would commence a multiyear investment program in some very well-defined and profitable opportunities across both Jubilee and TEN. We said we would deliver a revised Kenya field development plan. We will continue to rationalize and unlock value from our exploration portfolio, which will then align with our production-focused strategy. And we said we would look to refinance our debt to create a simplified capital structure whilst continuing with our cost-conscious approach. And we also said we would evolve our ESG strategy. So these are all the things that we kind of talked about 10 months ago. And today, I'm pleased to share that we've delivered on each one of these commitments. But it's important to underscore the work doesn't stop there. We're in a mode of continuous improvement, and we remain focused on delivering value from our existing assets. So to that end, what we have done is we have further refined our plan for 2021 to '25. So if you remember, we talked about a 10-year plan, but Les and I will share more details of the kind of 5-year slice of that today. And what we've done in the middle column that you see on this slide, some very exciting near-term catalysts that provide us and you as well with line of sight to both growth and value creation. But overall, what you should expect from the business plan over the next 5 years is that we will deliver growth in production, in reserves and underlying value, along with the cash flow to support deleveraging. And the plan is at $65 oil we will be able to reduce gearing to below 1.5x. So that's gearing as much as net debt to EBITDA by 2025. So we'll talk more about how we do that. But before we do that, let me focus on where the world is today. And this is an important slide because it kind of sets a little bit about our purpose. So notwithstanding the ongoing focus on reducing the use of fossil fuels, we believe that the world will consume more energy. We also believe that fossil fuels will remain an integral part of the energy mix for some time to go. So the logical conclusion is there's need for oil and gas resources to be developed and produced, but what's important is it's got to be done responsibly and with minimal environmental impact. And where we work, particularly in Africa, we experienced firsthand how the oil and gas industry can be an engine for economic development. And we also see at the same time in Africa continues to suffer from extreme energy poverty, and only about 3% of global emissions are expected from Africa by 2040. That's an important point. So there's a really strong case for a fair transition, where energy -- where African economies, they have the opportunity, like the rest of the world till now, to benefit from the responsible development of these resources. And with the oil and gas industry influx, there's many companies that are allocating capital away from upstream and they're divesting assets. So we felt it important, I think, today given all of this flux and uncertainty that we got to make a clear statement of our purpose, which is that we are committed to being in Africa. We have the opportunity actually to be a leader in Africa, where we're delivering safe and efficient operations while we bring shared prosperity and reduce our environmental impact. So our net zero commitment which we've talked about before, that's an important aspect of this plan. Let me just now share with you how -- the specifics of kind of how we do that. So obviously, the net zero commitment is an integral part of our license to operate. We have a responsibility to reduce and, in time, eliminate the emissions under our control. And within our business plan, we've budgeted for a number of technical projects that would help eliminate routine flaring on our Ghana FPSOs by 2025. So some of these include debottlenecking around gas processing and include things like process modification. And not to take you in the weeds, but the sorts of things we're looking at are quite specific. So one such project is, we're looking at a bidirectional gas line, so that's linking Jubilee and TEN. And what that enable us to do is to have optimum uptake and injection of gas where it's required, both for reservoir management and pressure support. So that's an example of kind of how we look to optimize gas utilization and reduce flaring. I think we've talked about before, there's been the Jubilee, we have a gas debottlenecking plan that's underway. It's a series of small projects. We expect that to be completed by next year. And we've defined the number of process modifications for TEN, and that will be planned when we have the TEN shutdown, which will be sometime in the next 2 years. So that's the focus on the facilities. But in addition to this, we're also progressing work on nature-based offset projects. And there's a lot of stuff in this going on. But it's a new area, it's an evolving area. And we want to look at this organically. So what we're doing is we're building up our capabilities in this space. The plan is we'll look to invest in new carbon offset projects, but focus in our host countries. We're screening projects that mitigate deforestation, that address for this degradation. What's interesting is that typically in these projects they involve a degree of social investment as well. They're in this kind of social project. So they're well aligned with our broader sustainability strategy. So I think over the coming years we'll look to update you on the work that we're doing. So I'll talk a little bit more about the assets. But before I do that, let me hand over to Les, and he'll cover the -- our first half results. So over to you, Les.

Thanks, Rahul. Good morning, everyone. As Rahul mentioned earlier, we announced today that I will step down as CFO in March, but after the '21 reporting cycle. Timing is right now that we've completed a number of steps to strengthen the group, which was culminated in the refi that we did back in May. As Rahul said, I'm not leaving yet. So there's still work to do over the next 6 months. So I look forward to catching up with as many as of you I can to say thank you. Meantime, it's a great opportunity to have -- to update you on the first half, which is a good set of results. I confirm our full year guidance and also underscore the positive progress that we've made on simplifying our capital structure and strengthening our balance sheet. So firstly, to the numbers. As Rahul said, our business has performed well in the first half, delivering strong operational performance. As you'll see from the numbers, revenue is essentially flat year-on-year with lower sales volumes, broadly offset by around the $9 per barrel increase in realized oil price. Unit OpEx is up, primarily a result of lower production, extended COVID-19 operating procedures, and then the residual work related to the shuttle tanker operations for the TRP. We delivered a profit after tax of $93 million and free cash flow of $86 million, which includes the one-off fees associated with refinancing our near-term debt maturities. Capital expenditure was around $100 million -- $101 million, to be precise, with phasing bias to the second half, primarily as the rig in Ghana only commenced work in April, also related to the timing of non-op activity like Simba, which we'll talk about in a little bit, and also the long leads for Jubilee Southeast and then really the mixture between Jubilee and TEN activity with the rig. And Rahul will tell you a bit more about these shortly. Net debt had reduced by around $700 million from a year ago to $2.3 billion, following cash received from asset disposals and free cash flow, and gearing is down from 3x to 2.6x. And now to the 2021 guidance. This slide is a simple summary of our 2021 key guidance figures. Where appropriate, guidance has been adjusted for the first half completion of the Equatorial Guinea and the Dussafu disposals. We've narrowed production guidance towards the top end of the range, including an adjustment for the Jubilee shutdown moving into 2022. While unit OpEx is higher for the reasons I mentioned earlier, we're still on track for our cash cost savings of $125 million per year. And as an example, net G&A is down by of 50% compared to the same period last year. Both CapEx and decommissioning have been adjusted slightly to reflect the current forecast of activity phasing over the balance of the year. We expect underlying operating cash flow to be around $600 million, and that's at $60 per barrel. And as a sensitivity, a further $10 per barrel increase for the second half as around $50 million of free cash flow. And now to the progress that we've made on strengthening our balance sheet. At our November Capital Markets Day, we laid out our cash-generative 10-year business plan. Together with the improving performance of the business, evidenced by our numbers, delivery of $1 billion of self-help from asset sales and the material cost savings realized from the business and, of course, the strengthening oil price environment, these all created the platform to successfully complete a comprehensive refinancing of our debt back in May. We are able to simplify our capital structure with no material debt maturities now until 2025 and with a significantly reduced but very supportive bank group, providing a $500 million RCF facility. We've also underpinned our revenue and cash flow through a material 3-year hedging program, and over 75% of that is already implemented and that's built on what we already have in place, with downside protection, with average weighted floor for a significant portion of our production of around $48 per barrel to the end of next year and at $55 per barrel in '23 and also through to May 2024. We will complete the implementation of the program by the end of the year, as we said when we issued the bond in May. Built on our strong asset base, we have a business plan that has the ability to keep our enterprise value flat or growing, which as we deleverage should translate into an increase in equity value. We're confident our assets are capable of delivering up to $4 billion of operating cash flow at $65 over the next 5 years. After adjusting for CapEx, including decom costs and ongoing financing costs, we expect to generate up to $1 billion of free cash flow, and this will be used to reduce our debt. We have some flexibility, as you'll have seen in the statement on our capital investment, and our hedging gives us comfort and confidence to invest despite the continued volatile oil price outlook. I've previously explained '21 and to some extent '22, our transition years, as a production-focused activity set. It translates into increased revenue and, in turn, free cash flow generation. We have the breadth of opportunities and flexibility to adjust capital investment to respond to the oil price environment. And we expect to reduce our leverage to well within our target range of 1x to 2x. So in summary, we've posted a good set of first half results. We've confirmed the full year guidance for the year, and the comprehensive debt refinancing completed in May does provide the financial platform to deliver on our long-term business plan. So with that, I'll hand back to Rahul.

Okay. Thank you very much, Les. So we're talking about production performance and building operational excellence. This is really fundamental to who we are and, therefore, it's a major focus for the entire organization. And we're working and we're delivering on many, many different fronts. So let me just run through this. So firstly, we started a multi-well, multiyear drilling program in Ghana. That's progressing per plan. We have 1 well on stream that's the J56P. There is another 2 wells which will be on stream due this year. And the drilling performance has very much been within budget and on time. Some good lessons learned. And that's -- so I'm pretty comfortable with where we are. I think the uptime story has been very good. We've had uptime in excess of 98% on both Jubilee and TEN FPSOs. That's the third year that we've had in a row of improvement. We've increased gas processing capacity at Jubilee to over 200 million scfs a day. And we've maintained reliable gas supply from our operations. And gas offtake from GNGC has been consistent around 110 million scfs a day. And we believe there is some potential for improvement to 130 million scf and possibly even beyond that. The other good story has been water injection. We've had sustained water injection over 200,000 barrels a day in Jubilee. And that's quite important. That's helped with voidage replacement. And thus, it's one of the factors that's been useful in managing decline in Jubilee this year. We've got plans, we're going to add water injection capacity, which will help further optimize production. So all this has resulted in good production from the operated assets, and also that's been supported by stable production from the non-op portfolio. And at least the delivery for the first half of the year has been at the top end of the guidance that we gave. What I wanted to do now is to share some details about our assets, and that will help you also better understand the plans and investment priorities as we go forward. So I'll start with Jubilee. I think most of you know, this is a big field. It's got nearly 2 billion barrels of oil in place. And to date, we've produced less than half of the expected ultimate recovery. Now a significant factor, we talked about this before in the past, which has impacted historic production has been under investment. And I've highlighted particularly in March how we were looking to change this with the launch of kind of multi-well, multiyear drilling program, and that kicked off in April. The illustration that we have on this page, this is a really interesting one because it shows how a significant part of the resource, it remains untapped. You can see both in the core of the field but also in the eastern flank. And obviously, given the quality of the field that we have, Jubilee provides a very profitable investment opportunity over '21 to '25 period. And that's through a combination of infill drilling, facilities expansion. And there are 2 sanctioned projects in the eastern part of the field, there's Jubilee Northeast and Jubilee Southeast. And I'll talk about those in more detail now. So if you remember from the previous slide, there's eastern flank of the Jubilee. That provides an opportunity to recover an additional 170 million barrels gross. And the catalyst for that is to have some enabling infrastructure, subsea infrastructure because it all links back into the FPSO. That includes their kind of new production loops and some water injection infrastructure. It's fairly simple. It's a minimal infrastructure, and it allows us to really open up this entire undeveloped area. So the 2 projects that you see here is the Jubilee Southeast project, so that's highlighted in blue. That requires just one production manifold, and there are 2 water injection manifolds. And then what you also see in this is the Jubilee Northeast project, so that's highlighted in green. That just requires one additional water injection manifold to provide pressure support. The returns, as you can see, are excellent. And with the sanction on both these projects, the plans are, we would see first oil in '23 and then it is sort of -- there's additional infill potential, particularly in Jubilee Southeast. Now I want to talk about TEN because it's an interesting story. So TEN has over 1 billion barrels of oil in place initially. Now TEN is really made up what we call 3P. So it's Tweneboa, Enyenra and Ntomme. So Enyenra has got about 20% of the oil in place. And what we're calling the Greater Ntomme and Tweneboa area, the GNT area, that has the other 80%. So to date, when we look at the production, we have produced probably less than 1/3 of what the expected ultimate recovery is. And as you know, the activity to date on TEN has largely been focused on Enyenra and to some extent on Ntomme. And Enyenra has been challenging right from the start. Now since the Capital Markets Day towards the end of last year, we've been working pretty hard on TEN along with our partners. And we also used some new data, which is from the recently acquired 4D survey. So we've had the opportunity to really deepen our understanding of the TEN development in the production area. So that's given us a much better understanding of the remaining potential. And while the historic focus was in Enyenra, we've evolved the kind of forward strategy in TEN is really to concentrate on some big and more cost-effective pools in the Greater Ntomme and Tweneboa, the GNT area. And in fact, we've got 2 kind of strategic wells in the GNT area which we're looking to bring into the rig sequence in the near term. So that would be some time in the next 2 years. And what they will do, and that's an important catalyst, they'll help us better understand the overall resource base at TEN. And if oil prices stay stable, we would have the opportunity to accelerate the future development of TEN into the kind of more near term. Because if you look at our business plan, the 10-year plan that we shared at the Capital Markets Day, the first 5 years are very Jubilee-heavy, the second 5 years are very TEN-heavy. I think with these strategic wells, assuming oil prices stay kind of at current levels and so we can potentially look to accelerating that. What's also interesting in TEN is the -- that in addition to oil we have very significant non-associated gas resource. This is particularly in TNAG and TNAG West. And that can bring very material value to the government and to Tullow. So I would say TEN is an evolving story. Enyenra is disappointing, has disappointed in the past. I think if we look at production to date, Jubilee has been fantastic, TEN has just been barely on expectation and part of that is ongoing challenges at Enyenra. So what you'll see is a lot more emphasis and focus on the GNT area, and that's something that we're very excited about. If I switch on to the non-operated portfolio, we've got our non-operated production in Gabon and Côte d’Ivoire that is really providing positive cash flow. It's a combination of existing production. There's a great stuff here in infrastructure and exploration. And we've got a large number of diverse, low-risk investment options and projects. And what's interesting, the non-op stuff, it really highlights the value that we can unlock through focus and through our strong cooperation with JV partners. Now in non-op, production has been steady in 2021 and we expect this to continue through next year. We've had some issues in Espoir and Côte d’Ivoire, where I think we laid this out in the statement today, we've got an extended shutdown which would commence in 2022. There's one ongoing just now as remediation works are carried out. So despite that, we've seen stable production. And the big thing has been Simba, which is an exciting field. This is one where we have 57.5% with Perenco as a partner and operator. What we did was following the sales of both EG and Dussafu, we reallocated capital to this project. So we accelerated the expansion. And that's seen us bring another production well on stream. And so recent rates of about 12,500 barrels a day gross, that's from Simba 2 and 3 together. So that's an approximate increment gross of about, I think, about 5,000 barrels a day. And what we're doing with Perenco is that we're looking to a new pipeline that will allow us to significantly increase the fluids that we're currently exporting. So Simba remains an exciting field. We've got some additional prospects as we look to allocate capital on this as we go forward. Let me move on to our -- more of our exploration focus. So the business plan, as you know, is focused on the producing assets. But we have some very attractive exploration licenses in emerging basins. And as part of that strategy, what we're seeking to do is to limit capital exposure that we have from historic commitments by farming down our equity shares or reducing exposure to interested buyers. Now it's not a great time to be doing this. And if I'm frank with you, I'd say, well, look, there is a chance that we're not able to farm down the stuff this year. So if the efforts to farm down or extend the commitments are unsuccessful, we will have about $50 million in the CapEx for next year, roughly split evenly between Guyana, where we look to drill a well, and Argentina, where we have a seismic commitment. But just to pause on that, it reflects either way. If we're successful in the farm down, we mitigate the capital exposure. If we're not, both of these blocks are interesting. We'll have better data from these activities and that will strengthen our position and it could add value for future portfolio management activity. So either way that works. But also, I just wanted to pause here because we've done a lot of work in terms of really defining our exploration strategy. And things like Simba, things like further development in TEN, focus on CDI or CI-524, which is the block in Côte d’Ivoire adjacent to TEN, that's where you will see us apply a lot of our geoscience expertise. And really, the idea is that there's great intellectual property and knowledge within the team to leverage that to focus on areas which are near infrastructure where we can create value quickly whilst managing the exposure to these emerging basins. Let me switch gears now to talk about Kenya. And this is again quite interesting. So if I go back a year ago, so when I came, I was very skeptical about the project. And I think we had had many kind of false starts and there'd been a history of disappointment. But the scale of the resource was large, and I think I said this in one of our sessions. If this was like West Texas, you'd make a lot of money. So we really decided to say, look, let's kind of do an objective root and branch review of the project to understand it. And we recognized we don't have a monopoly on good ideas. So we said let's work with our partners, both with Total and Africa Oil. And they've done a lot of work and their perspective. So we took all of that input. And then also we had some very interesting dynamic data, which was acquired through the EOPS. So EOPS basically was an extended well test through a number of zones, a few wells, both in 2 of our biggest fields, right? As we worked through this data, a different picture started to emerge for this project. So firstly, our estimates of the oil in place, they increased to about 2.85 billion barrels from the previous numbers we had. Now I'm going to talk about the audited numbers, so I used as a basis kind of our previous audited estimates about 1.7 billion -- 1.8 billion barrels. And I think it's fair to say it probably was the first time it reflected a common understanding of the geologic model with our partners. And then what was interesting, the gold standard in my mind of kind of verifying stuff is dynamic data. So these estimates were validated with data from the EOPS, but they were also being independently assessed by GaffneyCline. So GaffneyCline has done work with both Tullow and for Africa Oil. And also what GaffneyCline have done through their work is they've increased the life of field, the 2C resource number to about 585 million barrels, and that compares to close to 430 million or so we had before. So a good picture on the in-place and a much better improved picture on the recoverable. So what does that do to the overall project? Now what's the key, I think, to the economic development if you have a remote resource like in Lokichar, is infrastructure. That's probably the single biggest thing. So what's important then you say, look, my first phase project, the cash flows from that are critical to justify the construction of the midstream infrastructure. And once you have the infrastructure in place, even smaller accumulations can become economic. So we're really focused on saying, well, how do we make the infrastructure viable? So what you see is a revised development concept that's based on a higher plateau of 120,000 barrels a day. Now this is just not made up. This is based on real data. And because it's important, I'll share a bit more detail here. So as I've said earlier, we had EOPS as really like extended well test. So we had flow rates from wells in both Amosing and Ngamia. They showed a lot of potential. And remember, these were flowing without support from water injections. And these rates were higher than we had expected. And we were achieving these with a 500-psi drawdown. So now the development plans we look for jet pumps, the drawdown would be much higher. So good confidence in the initial production rates. What you see in the chart on the bottom of this slide, it shows -- this is a bit geeky, but I just wanted to show -- share this with you. It shows the bottom-hole pressure data from the Ngamia 8 well. And what you'll see is, of course, the pressure drawdown it reduces as you produce from these wells. But once the wells shut in, the pressure begins to build up, right? And you see it starts to approach the original pressure. It doesn't get there, but it gets close. The point of that is that demonstrates continuity and connectivity. And therefore, you see there's large volumes in these things. So these wells are connected to large volumes. The other thing was recognizing a very simple fact that production potential varies across all of these fields. Some parts are really good, some parts are average and some parts are bad. And in an onshore development, we didn't need to produce -- we didn't need to develop each field first. So we recognize we could achieve a higher plateau in a more economic manner if we drill the best parts of the fields first. And of course, once the infrastructure was in place, as I've said before, the forward producers would become economic and we could sustain the plateau by drilling the rest of the field. The other thing is that with greater confidence we have in water injectivity, we're also planning to implement water injection earlier and with the denser water injection pattern that will help again sustain the higher plateau. So what you have is a new development design, which is more robust from a capital effectiveness point of view. So a simple metric, unit costs, if you look at inclusive of CapEx, OpEx, tariff, they've reduced from $31 to $22 a barrel. So where are we now? That's the question. We have submitted a draft FDP to the government. We're on track to submit the finalized FDP by year-end, which was, remember, part of the license extension commitments from last year. At the same time, we're seeking strategic partners based on their revised plan. There's good interest there. I'm sure you have questions. I can't tell you a lot more than that. Alongside the partners, we've also taken the opportunity to improve the environmental and social impact of the project. So we've limited carbon emissions, are looking to utilize renewable sources of power, and we're supplying water to local communities. And it's a good project from a government perspective because it will provide a long-term stable source of income. We're working very closely with government in all the other aspects. Now I know many of you have seen the slides of Kenya for the last 10 years and many promises have been made and broken. So I don't want to stand here and make more promises today, right? I think the point I just wanted to make was that, look, the work we've done, we did it with an open mind. We worked with our partners, we did objectively, and the project is looking interesting. And if done the right way, this could be an important value driver both for Kenya and for our strategic partners. So we have a clear path forward. Some things we won't be able to share, but that's -- I just wanted to be as transparent and give you a picture of where we are. So I think just to try to wrap things up, what you see is we've got a number of well-defined projects that support production potential. So what you'd see over the next 5 years, a lot of activity, including infill drilling options, new projects and some strategically positioned rounds. As I said before, the current business plan is Jubilee-heavy in the first 5 years with focus on TEN in the later part of the decade. There's a potential acceleration of additional wells and defined projects, which we look to bring with the second rig potentially from 2023. That will be an important catalyst as well. In addition to that, we have both infrastructure in that exploration in Kenya as upside. And roughly, just as Les said, we would execute these for CapEx somewhere between $1.3 billion to $1.5 billion over this period. And we have flexibility. I think the key for you to understand is that we got flexibility to adjust the capital spend if volatility is extreme. Now hedging, I think, protects us. But if it's super extreme, we do have flexibility to adjust the CapEx. So I think we're pretty much set to deliver sustainable self-funded production, with some very material options to generate additional returns. And what I wanted to show on this slide is that there is a clear kind of reserve replacement expected from currently defined projects. This is what we know today. Now given the large resource that underpins the producing assets, we'll continue to mature opportunities, which will add to reserves and production. So it's not a static picture. And overall, what you'll see is the business plan will deliver growth in production, reserves underlying value, along with the material cash flow, which will support deleveraging. So just to bring all this together, we've spoken a lot today about the future. But also, we've done a lot in the last year to turn the company around. And the team, myself, the rest of the organization, we're having a lot of fun, but we're committed to continuing that momentum. I think it's fair to say we're well aligned, probably better aligned with our partners than ever. That's bringing better ideas and more effective ways of working. We're working as an open team, so the culture with a lot of engagement from excellent people. I think the one thing that's been fantastic is just the quality of people in Tullow is great. So we're building that open team culture. This remains a transitional year. So our focus, our priority is to deliver the targets. We'll keep a very close eye on cost. It's not easy to do that with rising oil prices, generating cash flow and repaying our debt. I think it's fair to say we've also kind of earned our place to look ahead to growth. And I think I'd say we're well positioned to continue as a leader in the oil and gas industry in Africa and to deliver returns for our shareholders, but also kind of host countries. And I think also you'll see in our results today, we've -- this is kind of unusual step, we have taken the opportunity to outline our purpose. We really felt strongly it's important to do so clearly because you know the industry is in flux. And as many companies that allocate capital away from upstream and they divest assets, particularly in Africa. But I wanted to say, at Tullow, we believe that Africa's oil and gas assets should be developed. They should be developed responsibly, efficiently and for the benefit of Africa. And we've got a long history, a proud history. And I've had a chance to engage with a lot of host governments and communities. This is who we are, and we remain committed to the continent. And through the continued delivery of our plans and confidence, we'll deliver shared prosperity and will create value for our host nations, for our community, for our investor staff. So that's just concluding that. I hand over to the operator. Happy to take questions.

[Operator Instructions] We're taking our first question from the line of Alex Smith at Investec.

Just wanted to ask a quick question on free cash flow and deleveraging. This year, you're guiding to $0.1 billion of free cash flow in quite a strong oil price environment, and this includes contingent payments and disposals as well. So really, without those, are we looking at net flat free cash flow for the year? And I guess the question centers on, how do you plan to deleverage up to $1 billion in less than 5 years? And where does the delta in cash flow come from? Is it weighted towards the end of the 5-year plan? And then secondly, just on the non-op portfolio, are we now done in terms of asset disposals in that department?

Okay. No, thanks, Alex, I'm glad you asked the question because I think the way the -- because remember, we're recovering from a period of underinvestment, right? So the strategy has always been to create some headroom, which is what the refinancing did. It gave us the space by extending the debt maturities to reinvest in the business. The underlying resource is fantastic. We've got good returns. So we created that headroom. What that means, therefore, is that the free cash flow generation is back-ended. That's very clear. Our overall capital structure or kind of strategy is very simple, which is -- and we said this before, which is that over the next couple of years by delivering on the business plan we'll put the company in a much stronger footing. And we will have -- we'll look to refinance on our terms at our time of choosing, okay? And I would submit to you, you look at the evidence of that improving credit quality is already there. The bonds, for example, we priced at a coupon at 10.25%. I mean last night, the bonds traded below -- they're trading at a coupon below 9%, right? So yes, near term, this year will certainly be, as we said, a transition year, lots of kind of additional costs. So -- but we expect that picture to improve because you've got a low cost base and through the reinvestment, as you get to see production growth, you will start to see revenues and cash flow generation. Les, I don't know if you want to add to that?

That's exactly how I would say it. Thank you. And then the second question, Rahul, was on asset disposals from the non-op.

Yes. So no plans, Alex. We -- again, I think what Les and I have said before, somebody puts a big number on the table, that's a kind of huge statement. But no, we don't need to look at disposals now to address the balance sheet.

We are taking our next question from the line of Rachel Fletcher at Morgan Stanley.

Firstly, on emissions reduction. I think you mentioned that the near-term emissions reduction processes as gas debottlenecking, et cetera, are included in your business plan. But are the costs associated with carbon dioxide offsetting included in that 10-year plan? And when do you expect these offsetting projects to start? And are they required to reach that interim target that you've given today? And then secondly, you mentioned that there's a potential acceleration of additional wells and defined projects at TEN with the second rig that would be from 2023. Is that conditional on oil prices staying above a certain level? And could you give a bit more color on how you're thinking about that?

Sure. So the kind of what we call the decarbonization projects, which are quite simple and straightforward. So that's, for example, increasing capacity, gas processing capacity at Jubilee. So that's a series of incremental projects. We've already increased capacity to over 200 million scfs a day. And the Jubilee process will carry on and will get to our target levels by next year. And similarly, for TEN, we've defined some process modifications. We'll do that when we plan the TEN shutdown. So the CapEx is all included in the $1.3 billion to $1.5 billion range that Les talked about. What is not included is the carbon cost, if you will. Now what we do do if you look at our sustainability reports and stuff we report in accordance with the TCFD disclosures, so we do give sensitivities around impact on our portfolio based on different carbon prices based on different IEA assumptions. But the specific sort of carbon cost, we don't include in the capital costs. You talked about acceleration. So we are working with our joint venture partners. I think at the current levels of oil prices we feel comfortable to bring in a second rig. So we're talking to JV. And in my mind, at least, I'm hoping that we can get ourselves in a position where we can bring in the second rig by sometime in 2023. So I think if prices are kind of north of 60-ish, we would look to do that.

We're taking our next question from the line of Chris Wheaton at Stifel.

One technical question for you, Rahul, and maybe some finance ones for Les. You referred to the voidage ratio and being able to get that up with much more consistent water production. Given you're running well over 1x voidage ratio at the moment, how long do you think it takes before you get that voidage ratio back to quarter 1, and therefore, you really start to see the pressure response in the field? I'm just interested if you could sort of conceptually disaggregate the sort of the additional producers and also the additional water injection and what the kind of impact on the production is from those 2 different factors. Perhaps that's my first question to start, please.

Okay. So I want to try to see if I could break it down a little bit looking at kind of this year. So if you take kind of Jubilee production, right, and the underlying decline, if you do nothing, you don't handle gas, no water injection, you would have about a 20% to 25% underlying decline in the field, okay? That's a kind of natural phenomena. If I look at the first half of the year, we've held Jubilee largely flat, okay? And it's hard to disaggregate, but we've had 2 phenomena happening. One is we've had voidage. Basically, you're seeing the pressure effects pretty quickly, right? So that's -- and the pressure effect, there's a pressure maintenance effect to that. But higher pressure also means that it affects your GORs, okay? So that's one dimension to it. And I'm going to complicate it further. The second thing that's happened is that we've increased our gas processing capacity. So if I increase, let's say, by 5,000 scfs a day, right, and if I have a gas-oil ratio -- that may allow me to produce, let's say, another 1,000 barrels a day of high GOR wells, okay? So this year -- so today, let's say, Jubilee, we're at 80,000-plus barrels a day or about 80,000 barrels a day. We started the year at [73,000]. So the mix today that we're seeing is partly through facilities expansion, partly through improved water injection and partly through the addition of the J56 well. So that's sort of -- I'm not -- I can't disaggregate it further than that without actually laying out a model, but I hope that answers your question to some extent.

No, that's really helpful steer. and it's good to see that progress starting to be made already. Les, 2 questions for you, if I may. I guess you talked about the free cash flow guidance, just going back to Alex's question of that $100 million free cash flow generation this year. You've got quite a substantial free cash flow -- sorry, sorry, working capital outflow in the first half of the year, about $150 million. Is that included in that $100 million free cash flow guidance or is that expected to reverse in the second half of the year?

That's driven primarily by liftings, Chris. So we had -- I said in the statement 7, it was 3 Ghana and 4 smaller non-op which we got the cash in July. So that's all just timing.

Okay. So you expect that to reverse? You're broadly expecting sort of flat working capital year-on-year so there's no working capital swing in that $100 million of free cash flow?

Correct.

Great. Okay. Brilliant. My last question was on Ghana tax. If you refer to Note 9 in the statement, Ghana have, in the last couple of weeks, come up with a tax claim on you of 471 million. If I look back at one of your circulars from the last 12 months, I think it was the Uganda disposal one, that number was about 350 million, 370 million from memory. What -- can you help us understand what's going on with the Ghana tax situation, please, and potential resolution? Are we in extremis heading towards sort of Cairn style multiyear resolution of a liability here?

Sure. No problem. I mean the situation, as you can gather from the notes, is dynamic. Yes, you're right. We did just recently receive a letter. A considerable part of that 471 million over 300 million relates to something that we're already formally in dispute over. And actually, we would dispute all of the items. It's a case of what action we will take from here. And as I think I've said before, both at times of results and also with the circular that we have a very strong sort of legal position on all of these. So discussions continue. And all we're doing is disclosing that we received the latest in a whole string of these that we received from the government, but we're not providing for that because we are confident on our position. So more to come. That's just the latest in the ongoing saga.

We're taking our next question from the line of James Hosie at Barclays.

Just a couple of questions from me. Just on the Kenyan oil project, can you now just clarify what needs to be achieved this year to extend the license? And then on your nature-based carbon removal plans, how should you soon would you actually need to secure projects to achieve the 2030 target? And how much competition do you think you're going to face for good projects? I think in particular about your plans to focus on opportunities in your host countries and whether you end up competing with your JV partners for nature-based solutions in Ghana?

All good questions. So James, the license extension terms required us to submit a fuel development plan by the end of the year. So we're working -- we've submitted a draft to the government already. And we're getting feedback. So there is a live dialogue, and we're working pretty closely with them to finalize so we have a final submission by the end of the year. So that's the kind of simple thing. And I think I said this earlier that there is a separate process where we're looking to bring in a strategic partner. The timing of that could be slightly different. But we're running both of these things in parallel. The FDP preparation, which will allow us to finalize prior to year-end and then the strategic partner, which will come in some time. So that's one. And then your second question was, I forgot.

Yes. Just the nature-based carbon removal plans.

Yes, sorry. So look, what we've decided to do is rather than kind of chase stuff we think we want to do it organically. The countries we're in, there is a lot of opportunity, right? And so with some speed, we're putting together our own capability. We brought in some outside consultants. So I'd say over the next year or so we'll have a pretty good understanding of the whole realm of what's available within our host countries. And because these are social projects, we felt it's much better to focus on the countries that we're operating in as well. And look, we're not looking to compete. I mean there may be opportunities for us to collaborate with our JV partners as their own plans evolve. We don't see that as a particular issue. But I think because we're going organic we feel we have the opportunity to create stuff that's high quality and then not kind of run around and chase after the same thing that everybody else is. And timing-wise, I mean, look, it's -- the net zero commitment is kind of by 2030. I think if you start working on reforestation or projects that mitigate degradation, those start to kind of deliver credits pretty soon. So we feel like we have a little bit of time in terms of selecting projects. But I'd like us to get going on that pretty soon. So I would say in the next couple of years, that's sort of the time frame we're looking to select projects.

Okay. Just a quick financial query for Les. How much cash tax is assumed in the 2021 for your cash flow guidance figures?

Around $90 million.

We are taking our next question from the line of James Thompson.

Can you hear me?

Yes, we can.

Great. So yes, I have a question -- thank you very much for giving us the 5-year CapEx plan. Just in terms of maybe sort of breaking that down a bit. Could you maybe give us some guidance in terms of the facilities, CapEx requirements for Jubilee Southeast and Northeast in terms of what component of that $1.3 billion to $1.5 billion is infrastructure rather than drilling?

So I think the Jubilee CapEx is a lot more sort of well-driven as opposed to infrastructure-driven. And I would need to check. I think -- I don't know exactly on the top of my head, but I think the Jubilee Southeast project on a gross basis must be a couple of hundred million dollars, I think. So our net number would be probably less than $100 million, I think. That's -- let me do this. I think I'll get Nicola or Matt to reconfirm that. But that's what's stuck in my head.

Okay. So relatively limited infrastructure CapEx?

Yes.

And do you have to do anything to the FPSO in terms of expanding water handling capacity? I mean should we be seeing a sort of shutdown in 2023 sort of time frame?

So what we have tried to do is space things out. So we are doing a lot more brownfield work. So we -- basically, all the gas handling work that we've done has been without a shutdown. We're looking to bring in an additional vessel towards the end of the year so we can sort of track on a bunch of kind of -- accelerate the kind of historic maintenance backlogs and look at some more capacity expansions. And then in early next year when we do the shutdown, we'll look at maybe some more modifications. So what we're trying to do is look at a more continuous sort of project as opposed to do one big massive shutdown. So that's the strategy on Jubilee. And it's been a bit tight with COVID because we're limited on how many people we have on board. So that's been a bit challenging.

Okay. Okay. And just thinking about Kenya and sort of sticking with CapEx. I mean if you look at the CapEx for first oil, the net Tullow share at 40% is kind of $1.4 billion, which is right in the middle of your 5-year CapEx guidance. So is it all on Kenya or is it all on Jubilee? But with that in mind, it'd be really good to understand how you're thinking about how much capital you will or are prepared to allocate to Kenya and how easy it may well be to farm out some of that development CapEx?

So well, firstly, just to be very, very clear with you guys, the business plan from the beginning has nothing on Kenya. So it's got no capital, no production, no value from proceeds and any of that stuff, right? The view that we have is we like the project now, but we don't think that we have the balance sheet or the capital allocation to kind of support that. That's why we're out looking for a strategic partner. And we've had good engagement from that. So I think the way we see it is if you bring in the right strategic partner that mitigates your capital allocation, you'd still retain a material equity stake. So that should be net accretive from a value point of view, right? So that's the approach that we're taking, but it's not included in the capital. Because, again, it wouldn't necessarily -- even though it's a great project, given our balance sheet, it would be hard to allocate material capital to that.

We are taking our next question from the line of James Carmichael at Berenberg.

Just a couple on TEN, just to understand reserves and resources related to the strategy focusing on the GNT area. I know you've got the further reserves update published this morning as well. But just wondering if there's any sort of impact on overall reserve resources in that TEN area from that new focus? And then also just looking at sort of H1 output and full year guidance for the field, if I'm reading it right, H2 production was sort of just under 30,000 barrels a day gross. Is that the level we should be thinking about for 2022? You talked about holding it flat. And should we think about those -- the strategic wells continuing to sort of offset decline or will they contribute to some production?

So I think we're just in the midst of our '21 kind of resource or reserves assessment. So we'll be able to give guidance once that's done only. So it's probably premature for me to comment. I think what is important, I think, on the TEN picture is that you have a lot of contingent resource in TEN. TEN disproportionately has higher contingent resources, right? And we drilled these strategic wells. Let's say, we have 2, which is one is what we call the riser base well, which would be kind of in the middle of the GNT and there's one in Ntomme Fat West. Those wells will kind of unlock an FID or an acceleration decision that would help move a lot of contingent resource into 2P. So currently, these are all sitting out in the latter half of the decade. So those 2 strategic wells potentially help us bring those forward within the 5-year window, but that decision has not been taken yet. I think Enyenra, we -- like I said, it's continued to be challenging. And so the focus, therefore, is shifting of capital allocation away from Enyenra into the GNT. In terms of guidance for next year for TEN, so we'll get some support from the NTO 6 well which we have drilled, which should come on stream towards the end of the year. So that will help pressure support the Ntomme producers, so that will help the Ntomme decline. But we'll need one more well at least in the rig line for '22. And we haven't quite decided which one that is. So just to give you a sense, I mean, one of -- the strategic wells wouldn't contribute to production next year. They will -- one of them would continue to contribute the following year. So we just -- what we're trying to work through right now on TEN and Jubilee is what's the best way to optimize production, what's the best way to optimize returns and longer-term value. The good news is we have a lot of opportunity. The bad news is it's a complicated decision. So we'll give you guys better guidance, I think, in due course on that.

Yes, that's good. It sounds like TEN's a bit of a moving piece. And then just one sort of quick follow-up just on Guyana. I guess, presumably, looking to farm out both blocks that you talked about [indiscernible] well in Kanuku. Just wondering, a, I guess, if you are looking to farm out both blocks, what it might take to sort of to add additional wells into the '22 program. Any sort of line of sight or [indiscernible]

Yes. So I mean there is a well commitment in Kanuku for next year, and that's about $25 million net. We've got a pretty good prospect. There is good alignment with the JV on that. It's a Cretaceous. There's a primary -- I think it's a primary prospect, which is Cretaceous. And it's really leveraging what we learned from what was that sort of Carapa-1 well. So we're looking to farm that down. If we don't, we still like the well, so we would drill it. And hopefully, that would give us additional data, maybe create more value. But I think our preferred outcome will be to farm that out.

Last question we are able to take comes from the line of Mark Wilson at Jefferies.

First question for Les, please. Slide 11, where you showed 5-year sources and uses of cash. If you just confirm to us, Les, if that includes the finance leases for the TEN FPSO and others? And which of the boxes it's in that you show there? That's the first one. And then second one, I think more for Rahul. You've deferred the maintenance on the Jubilee FPSO into 2022. And with current oil prices, I'm sure that makes sense if it's not needed, but what could we expect in terms of maintenance outage, therefore, in 2022? And I speak to the fact that you say that the gas processing will be expanded to 40 million scf a day by the middle of 2022. Is there an outage required in order to get that capacity in place for the gas? And could you speak to how that higher gas processing capacity can impact the oil on a like-for-like basis versus today?

So Mark, on your first question, in our arithmetic, it appears before the operating cash flow number that I've given you. So it's already included.

And so just again, Mark, the way the approach that we're taking on Jubilee is try and do a lot of things continuously. So don't wait for a shutdown. So when I look at the gas increases and gas processing, we're actually implementing that as we go along and not waiting for the shutdown. So I think I mentioned this earlier to one of your colleagues that we've already increased gas processing capacity just through brownfield expansion to over 200 million scf a day, right? So that's already kind of underway. The second thing that you mentioned is deferring maintenance. We're not deferring maintenance. We're deferring the shutdown, which activates specific things to do. In fact, what we have done is we're bringing in a PSV, a platform supply vessel, towards the end of the year to address some of the maintenance backlog that's kind of built up because of COVID where you have limited people on the road. So the decision to defer the shutdown was through a kind of mix of prioritization of bringing in a PSV. So we're accelerating some maintenance. It was driven by COVID particularly because you didn't want to have a shutdown and then be stuck in terms of not being able to bring in a skilled technician because they had to quarantine for 2 weeks or something like that. So I think by disaggregating, we'll be able to optimize the timing of the shutdown a bit better as well. So the -- so 3 things I'd say to you that the gas capacity increases are -- we're trying to do as much brownfield without shutdowns. Maintenance is a big priority, and we're bringing in a PSV towards the end of the year to address some of the maintenance backlog. And we'll try to optimize the duration of the shutdown to make sure it's as little or as optimal as we can do. So does that answer your question, Mark?

Okay. So I understand the term the gas capacity can be added without a shutdown. Does it -- but we should expect there to be a maintenance shutdown for some reason next year?

Yes. So there will be -- there are certain specific things we have to do with the kind of flare tip, for example, and not to drag you in the weeds, but which will require a shutdown. And then the other question you asked was the kind of production implications. So what happens as we increase gas capacity, we -- very simply, we can process more gas. That means we can produce wells with higher gas-oil ratios. So every day we're trying to optimize wells, right? So -- and the constraint is gas handling. So what will happen is if you were a production engineer on the site, you would -- if I gave you more gas processing capacity, you'll be able to turn on a well that had a higher GOR, right? So there is a positive impact on the oil capacity. And I think I said this to one of the guys earlier that one of the benefits we've seen this year of stemming decline on Jubilee has been because of the brownfield expansion work that we've done on increasing the gas processing capacity in Jubilee. So you'd see that effect as you go along. Increasing gas capacity would allow you to produce higher GOR wells. Okay. Well, I think we're out of time or at least we've expanded kind of time. So again, thank you, everybody, for your participation and interest. And as always, if you have questions, please do reach out to Nicola, Matt. Happy to help. But we're pleased with the results. Hopefully, you have a better sense of what our way forward strategy is. And we're also very proud of being able to define very clearly what our purpose is in terms of creating shared prosperity and value in the host nations that we work in. So thank you again for your time. Bye-bye.

That concludes the call for today. Thank you for participating. You may all disconnect.