EnQuest PLC (3EQ.F) Earnings Call Transcript & Summary

Ladies and gentlemen, thank you for standing by, and welcome to EnQuest PLC 2020 Half Year Results Presentation. [Operator Instructions] I also must advise that this conference is being recorded today. And I would now like to hand the conference over to your first speaker today, Amjad Bseisu. Thank you. Please go ahead, sir.

Thank you very much, and good morning, ladies and gentlemen, and welcome to our 2020 half year results presentation. At this difficult time for many of us, we appreciate you taking the time to join this presentation, and hope you and your families are well. Safety has been and continues to be our top priority, and we've been continuously monitoring the evolving COVID-19 situation to ensure we have the right response and advice to protect our workforce and continue to maintain our safe operations. Indeed, we are one of the first companies to test our staff before they mobilized offshore to our assets in the U.K. and Malaysia, or to Sullom Voe Terminal. And I'm very pleased that throughout this pandemic, our operations have remained materially unaffected. Joining me today on the call is Jonathan Swinney, our Chief Financial Officer; and Bob Davenport, our Managing Director for North Sea operations. I'll first take you through the strong performance we've had in the first half of the year and then provide you an update on our cost reduction program and transition program that we've outlined and our future growth opportunities at Bressay. Bob will then cover the operations in more detail, and then Jonathan will present the financial results as usual. I will then return for a summary before we move on to the Q&A session of today's proceedings. And operator will provide you the instructions on how to ask questions at that time also. Now turning to the next slide, Slide 3. We've had a good start for the year. As you see, our production has been 66,000 barrels of oil equivalent per day in the first half, despite the early shutdowns and decisions on shutdowns on a number of our assets. We reacted very quickly to shape our business in response to the changing macro environment, both COVID and the significantly lower oil price. We're maintaining our guidance for the year, which we changed in around April, although we currently expect the full year current outturn to be towards the upper part of the range. We've also made good progress on implementing our cost reduction program and continue to expect to meet our targets, with free cash flow breakevens at $33 a barrel for 2020 and a target of reducing that further to around $27 a barrel in 2021. With our strong first half performance, we've been able to generate around $87 million of free cash flow in the period and reduced our net debt to $1.35 billion. That's for the backdrop of probably the most charging macro environment and oil price environment since our inception as a company. We remain focused on liquidity and liquidity management, our further reduction and strengthening our balance sheet. And we've continued to enter hedges at around 50% of the second half of the year has been now hedged. At the same time, we continue to look for future opportunities, and I'll discuss a bit more in detail, a low-cost addition to our asset base of the Bressay oilfield, which is expected to add up to 115 million barrels of 2C resources. Turning now to Slide 4, and given the challenging price as well as operating environment, we have performed very, very well. We've had strong production efficiency across all our operating assets, and delivered production ahead of our expectations. This will be covered in more detail by Bob, shortly, but primarily the performance has been driven by higher-than-expected performance at Kraken, and average gross production this year has been ahead of the top end of guidance. As I will outline also, we've delivered another strong operating cost and cash capital expenditure performance, as I outlined in the next slide. Our unit operating costs, which we have been targeted at $15 a barrel going forward are around $14 a barrel for the first half. And we've kept tight control on both operating and capital costs, which are in line to be $120 million for the year and -- of which we have spent $101 million. This is down from our original budget of $230 million of CapEx for the entire year. As you can see from the next Slide 5, much of our cost reduction program has come from our decisions to proceed cessation of production at a number of our fields, and we're making good progress in that regard. Our application for cessation of production on Heather has been accepted by the regulator, allowing us now to begin preparations for decommissioning and reducing our share of cost to 37.5% from 100%. On Thistle, we've lodged our application for cessation of production with the regulator in July and once approved, the decommissioning phase will begin, and our share of cost will also materially reduce from 99% to around 6%. While at the Dons, we are in the process of seeking approvals for its station of production, with production expected to cease in the first half of next year. At the same time, discretionary spending has been removed, and we've reduced the size of our workforce, in line with our smaller operational footprint. As such, operating expenditure in 2020 are expected still to be around $335 million or $15 a barrel. That's down from our original $525 million, $190 million reduction. For capital expenditure, as I just mentioned, we have completed the Worcester drilling in Kraken and brought 2 Wells onstream at Magnus in the first half of the year. But we've deferred other major product activities and reduced our capital expenditures from $230 million to $120 million for this year, of which most has been spent in the first half. These measures have allowed us to continue to lower cost base and to focus on investments on projects that matter the most, while preserving liquidity. Turning now to the next Slide 6. As you know, debt reduction remains a priority, and we continue to make progress in respect to this. We reduced our debt from $1.41 billion to $1.35 billion at the end of June. Our net debt-to-EBITDA has trended up slightly, as the rolling 12-month EBITDA has declined with the lower oil prices. However, pleasingly, the ratio has remained below our target at 2x net debt-to-EBITDA. We've made also early voluntary repayments on the Tanjong Baram project financing facility, and continued to reduce the Sculptor facility, which is the Kraken-related facility, as previously outlined. We have no further payments due in 2020 as the senior facility payments have been made earlier this year. Clearly, in the current price environment, further material debt reduction are challenging, but actually are taken in positioning us well to manage through this period and to continue reducing our debt and strengthening our balance sheet. Turning to the next slide. Whilst our immediate response to the current environment was to make a large transformation of our business footprint by reducing our high-cost assets, we continue to look at opportunities for growth. Slide 7 shows the continued look into the future with us closing on the Bressay deal in June. This allowed us to acquire operatorship and a 41% interest in the Bressay oilfield from Equinor for a consideration of GBP 2.2 million. This deal was really based on the capabilities of EnQuest in delivering both heavy oil, as we've done with Kraken, subsea tieback projects, as we have been in the upper quartile over the last few years as well as subsea projects. We'll build on the learnings from the Kraken development, which has been the first subsea heavy oil developments in the U.K. North Sea, fully subsea and believe Bressay could be highly synergistic with Kraken, which is only 12 kilometers way, indeed, closer than some of our drill centers. Bressay is also a very large field with about 1 billion barrels of oil in place. And upon completion, we expect to add up to 115 million barrels of net 2C resources, materially increasing our 2C resource base. [Technical Difficulty] key scenarios that we are considering. This will also reduce Kraken's emissions and costs, as we extend the field life and use gas instead of oil or diesel for power. Turning now to Slide 8. As we look into the future, it's important that we continue to play our part in the transition economy. We are well placed as a transition company and have taken many existing assets from others and improved their environmental performance. Indeed, that's one of our goals is when we take over assets, we improve their performance. Controlling and lowering emissions is a key element of how we operate. We've voluntarily limited gas emissions in Malaysia below the regulatory limits for the last several years, whilst we favor selling Kraken cargoes directly to shipping markets to avoid the sizable emissions relating to refining, heavy oil and help reduce the sulfur emissions also with the IMO 2020 regulations. In addition, the decision to cease production actually at Heather, Thistle, Alma/Galia and the Dons longer term, we'll see our scope 1 and 2 emissions reduced by around 15% in 2020 versus 2019. Looking ahead, we're targeting a further 10% reduction in emissions over the next 3 years through the implementation of various economic activities and initiatives. In aggregate, this means we're targeting a reduction of around 25% in emissions over the last 4 years -- over the 4 years. Longer term, our participation in the energy hub in Shetland will provide us with further opportunities to consider. We're also committed to working on a diverse workforce in our business and have moved at present to around 20% of our leadership teams being female. We're committed to improving this further. We continue to also support international women in engineering, and we'll look at other initiatives in the U.K. as well in Malaysia. We've already begun investing in the future, sponsoring 1 student in STEM at the University of Malaya. We are committed to sponsor an additional 2 students in the next year. We've also signed a momentum of agreement to sponsor the IChemE Accreditation for 1 of the universities, the National University of Malaysia. This accreditation is expected to improve the employability of graduating students of about 80 to 100 individuals each year. Bob will shortly outline our transformation 2020 program and how that's resulted in an extensive change to our U.K. business, in particular. Throughout this difficult process, we've treated our people fairly with respect and looked to preserve as many jobs as possible. I'm also pleased that through this process, we've been able to keep all of our U.K. apprentices in employment. Regrettably, these changes has meant significant number of roles that have been removed from operations and from the organization, and many of our colleagues have now left EnQuest. I would like to sincerely thank those who have contributed to EnQuest over the years and wish them well in their future. I will now hand over to Bob to cover off our operations performance in more detail.

Thank you, Amjad, and good morning, everyone. Amjad just described our very positive achievements so far this year and the progress we've made within the ongoing global challenges. I'll now provide an overview of the group's operational performance in the first half of 2020, then share some detail from each operational area. Before I do that, I'll first take you through the organizational changes we have made in response to the wider economic environment, as outlined on Slide 10. As you will have seen from our announcement this morning, we have reorganized our U.K. North Sea business into 3 operating directors that report to me. These directories are: first, upstream, which includes Magnus, Kraken, the Greater Kittiwake area, including Scolty/Crathes and Alba assets; next, midstream, which includes the Sullom Voe Terminal and our pipeline operations; and finally, decommissioning, which includes our Heather/Broom, Thistle/Deveron, the Dons and Alma/Galia assets. This transformation enables the group's directors to maintain unique capabilities and focus on those activities, which deliver operational excellence and safe results at each of its assets. Upstream focus is on high production and operating efficiency, effective reservoir management and continuing to cost effectively develop resource opportunities at each asset. Over time, it's natural that assets will move from upstream through to decommissioning, as they progress through their field life cycle. The timely transfer of these assets allows for effective end of field life management, and the development of relevant decommissioning programs, building on the knowledge gained from earlier programs. At the same time, our midstream business focuses on providing safe, reliable and low-cost service for customers, while exploring opportunities for new business at the terminal. I join Amjad in thanking and recognizing all of our colleagues, including those who have recently departed from EnQuest. While it's difficult to see them leave our business as a result of the restructuring, I am confident that this reorganization will underpin our future success. Now moving on to Slide 11 and moving through a summary of our H1 2020 production performance. The group delivered, as Amjad said earlier, above the top end of the guidance, with production at 66,055 barrels equivalent per day, and that's a small decrease of around 4% versus H1 2019. Magnus production was 18,806, that's up around 6% compared to H1 last year, reflecting high production and water injection efficiency. Kraken average production in the period was above top end of guidance at just below 39,000 barrels per day gross, driven by good performance from the FPSO and high production efficiency. Production at the other North Sea assets was 11,471 in the period. This is lowered by around 40% compared to the same period in 2019 and impacted, of course, by our decision not to restart production at the Heather/Broom and Thistle/Deveron fields. It's worth noting here that the Heather and Thistle assets produced around 9,000 barrels a day equivalent in the same period last year. So on a like-for-like basis, the remaining fields did produce at higher levels year-on-year. Over in Malaysia, production of 8,306 was slightly lower than first half of 2019, reflecting no contribution from Tanjong Baram asset. I'll now go area by area and provide more detail, beginning with Magnus on Slide 12. At Magnus production, as I said, has increased by about 6%. This reflected our strong production efficiency of around 86%, along with high water injection efficiency of around 91%, as we continue to optimize production activities in the asset. This, combined with 2 new wells coming on stream in March, which are performing in line with expectations has partially offset some gas compressor downtime experienced during the first quarter. I'm pleased to report that these compression issues have now all been resolved. During the fourth quarter, a 1-week maintenance shutdown is planned to carry out some essential work at Magnus. Turning next to Kraken. Production in the period was 19% higher than the comparative period last year with daily average production, as I mentioned, just below 39,000 barrels a day growth. This was driven by really good performance from the FPSO with high production efficiency averaging around 86%, and good water injection efficiency at above 90%. Subsurface and well performance remains very good, and water cut evolution remains stable, and we continue to optimize production between the injector-producer groups following recent well testing. And drilling at Worcester is complete with the new producer-injector pair on stream late in the second quarter as planned and producing in line with expectations. A 1-week shutdown is also planned for maintenance at Kraken. In this case, we expect to conduct that in September. And finally, cargo pricing has remained robust as we continue to optimize sales into the shipping market with Kraken oil being a key component of IMO 2020 compliant low-sulfur fuel oil. Moving on to Slide 13 to finish up. And other North Sea sales, average production was 40% lower, primarily reflecting our CoP decisions outlined earlier. Again, as I mentioned, with Heather and Thistle fields producing about 9,000 barrels a day in the same period last year, the remaining fields produced at higher levels in this year. These reductions at Heather and Thistle were partially offset by the improved production in Scolty/Crathes following the pipeline replacement project last year and by strong production efficiency at Alma and Galia, which performed in line with expectations ahead of the field's planned cessation of production on the 30th of June. At Thistle, project activities continued with the successful removal of the crude oil storage tanks completed in July. The facility will remain unmanned for the remainder of the year with a well abandonment program targeted for 2021. Production at the Dons was negatively impacted by a lack of gas supply -- for gas lift as a result of the shutdown at Thistle. And as Amjad mentioned earlier, we're now working towards CoP. In Malaysia, production was broadly in line when compared to the same period in 2019. Here, the group continued to perform well with excellent production efficiency of around 96%, along with higher gas sales, at our PM8/Seligi asset there. In June, we successfully completed a short planned maintenance shutdown with the total production outage of around 2 days, which was well ahead of schedule compared to the original planned 5-day outage. In summary then, we've delivered a strong performance across each of the operational areas during the first half of 2020 with no material impacts due to either COVID-19 or the organizational transformation. With our realignment now essentially complete, we are set up for a continued safe, reliable and profitable delivery in this lower energy price environment. I will now hand over to Jonathan, who's going to walk you through our financial results.

Thank you very much, Bob, and good morning, ladies and gentlemen. Turning first to the summary Slide 15. The group has made very good progress towards its operational and financial targets during what has been a challenging period. The results from sales are driven by the group's strong production performance, reflecting improved performance of the Kraken FPSO, increased volumes from Scolty/Crathes, higher production efficiency at PM8/Seligi and the contribution from Magnus. Realized oil price in the first half of 2020 was $43.6 per barrel compared to $66.1 per barrel in the first half of 2019. In the first 6 months of 2020, we recognized $35.2 million of hedge gains compared to a $7.6 million hedge gain realized in 2019. The realized price, excluding hedges for the first half of the year was $39.9 per barrel, 39% lower than the first 6 months of 2019, which is $65.4 per barrel. Revenue was down 48%, impacted by the oil price, but also by the amount of salable barrels. Salable crude was 19% lower than the first half in 2019, primarily as a result of moving from a net overlift to a net underlift position. Salable barrels are also affected by the entitlement barrels in Malaysia being around 66% of the working interest. And finally, there was shrinkage of around 1%. The group's operating cost decreased to $174 million during the first half of 2020, primarily reflecting the group's focus on cost control, including the decision to cease production at Heather and Thistle. The average unit operating cost decreased by 28.3% to $14.4 per barrel compared to $20.1 per barrel in the first 6 months of 2019. EBITDA and cash generated from operations decreased to $275 million and $283 million, respectively, driven by lower revenue, partially offset by lower cost of sales. We have incurred a noncash impairment as a result of low oil price assumptions. The post-tax impairment on our assets was $252 million, and there is also a derecognition of undiscounted deferred tax assets of $433 million. The impairment of the deferred tax asset does not affect the value of the losses, and we continue to have access to the full $3.1 billion. Cash capital expenditure during the first 6 months of the year was $101 million, with drilling programs at Magnus and cracking completed in the period. Net financing costs decreased in the first half of 2020, mainly reflecting a reduction in bank interest, as a result of the group's ongoing accelerated repayment of the senior credit facility. At 30th of June 2020, our net debt has improved to $1.351 billion. With our strong production performance and the implementation of our cost reduction program, the group generated free cash flow of $87 million in the first half of the year. As you can see on Slide 16, the operational performance, I highlighted in the previous slide, has delivered robust cash flows from operations during the first half of the year. This slide shows waterfall comparison with the prior year. The primary driver of lower cash flow is down to lower realized oil prices with gains on the group's commodity hedge program, mitigating the impact of the decline in average market prices. Lower sales volumes reflected the movement from a net overlift position at the end of 2019 to a net underlift position at the end of June 2020 and was partially offset by lower cash operating expenses. We've also had a positive working capital when compared to the first half of 2019, where there was a negative unwind of the $50 million working capital position from the end of 2018 and the timing of a cargo receipt associated with the Kraken oil sales fell into the second half of 2018. Turning now to Slide 17 and our capital spend. As mentioned earlier, cash capital expenditure for the period amounted to $101 million. Kraken continued to be where the majority of CapEx was focused, with the completion of the drilling of an injector-producer pair on Worcester in the second quarter. Our Magnus' focus was bringing 2 new wells into production during the first quarter and in the other North Sea operations, approximately $17 million is related to the settlement of deferred payments for the Scolty/Crathes process pipeline replacement project from 2019. Our program is very much weighted towards the first half of the year with limited expenditure expected in the second half of 2020, and we're on track to achieve our full year capital expenditure guidance of around $120 million. Slide 18 summarizes the impacts of the previous slides on our net debt performance. As you can see, our net debt position has improved from around $1.41 billion at the end of 2019 to $1.35 billion at the end of 2020 -- sorry, at the end of June 2020. I've already outlined the movement in net cash flow from operations of $275 million and our cash CapEx of $101 million for the first half of 2020. The group cash flows also benefited from the receipt of $70 million being the first of 3 installments from PETRONAS for reimbursement of our capital -- outstanding capital expenditure relating to the Tanjong Baram project. The total payment for the year will be approximately $50 million. We also paid BP a total of $26 million in relation to the vendor loans associated with the acquisition of the additional equity interest in Magnus and their share of profit. Net financing and other costs are primarily made up of cash interest paid on our debt facilities and tracking FPSO lease payments. In aggregate, we generated $87 million of free cash flow during the period. However, the prevailing low oil price, interest payments on the bonds was paid in kind, which is added to the group's issued debt. In line with our hedging policy and in order to continue to protect liquidity, we have continued to enter into hedges at an average price in excess of our targeted free cash flow breakeven for the year of $33 per barrel. For the remainder of the year, we've hedged approximately 5.5 million barrels which is the equivalent of around 50% of our net entitlement production at an average price of around $38 per barrel. While we continue to focus on liquidity management, it's important to note that our debt maturities are longer-term with no amortization payments turns on the bank debt until April 2021. And as you can see from Slide 19, our bank debt matures in October 2021. And depending on the oil price, we would either expect to be repay -- expect it to be repaid out of cash flow or any remaining outstanding amount to be readily refinanced or extended. We do not expect to refinance the current credit facility by October 2020, and therefore, the maturity date of the bonds will automatically extend to October 2023. The scope of financing facility has a final payment date in 2023 and is simply repaid out from the cash flows of the 15% interest in Kraken. At the end of June, the outstanding amount due have already been reduced to around $91 million, reflecting the strong performance at Kraken. We've made very significant progress on our cost reduction program and the strong performance from our assets means we are well-positioned to manage through the current oil price environment. And I will now hand you back to Amjad.

Thank you very much, Jonathan. And turning now to the last slide of the presentation, Slide 21, please. So as you've heard, we've made very good progress since the start of the year, and arguably, the most challenging macro and oil price environment since our inception as a company. We have kept our people and assets safe and operational to an effective management of the evolving COVID situation. We've moved quickly and decisively, taking difficult decisions to permanently shut in some of our assets. These decisions have made a material impact on our business. It has lowered our cost base and reduced our cash flow -- free cash flow breakeven levels, enabling us to generate free cash flow and reduce our net debt in the first half of the year. These decisions have also allowed us to materially lower our emissions in 2020. We remain on track to meet our financial and operational targets for 2020, set out in April, with production now expected towards the upper part of our full year guidance. We also continue to look at ways to further reduce our free cash flow breakevens in 2021 and beyond, targeting $27 a barrel in 2021. We will focus on further reducing our net debt and strengthening our balance sheet. At the same time, we've continued to assess and look at opportunities for future growth. Signing an agreement to acquire an operating interest in a very synergistic field, the Bressay heavy oilfield, which will add material 2C resources to our portfolio. Bressay offers the group an opportunity for a long-term, low-risk phased subsea tieback project potentially to the Kraken field, which could also reduce emissions, costs and extend Kraken's field life. As such, I'm extremely proud of our performance for the first half of the year, and I'm excited about our future prospects. With that, I'd like to thank you for your time, and I can now hand back to the operator, so we can move to the Q&A section of today's presentation.

[Operator Instructions] And our first question comes from the line of James Thompson.

A couple of questions, please. Firstly, Jonathan, can you just run us through the refinancing piece again? I mean, obviously, the bank debt is due in 2021. I mean, given the oil price outlook now, what's your expectation for refinancing of the bank debt? And secondly, Amjad, obviously, you've made an acquisition on Bressay. I mean, clearly, that looks like kind of option for you really. It's something that's probably not going to get sanctioned at this sort of oil price, but clearly, a better macro can help. I just wondered whether you could maybe comment at all on whether there's any more opportunities in the U.K. North Sea, particularly post BP's big strategy call and their decision to significantly reduce their upstream. I mean, is that something where maybe EnQuest can potentially get or build their asset or continue to build their asset base?

Okay. Jonathan, do you want to start, I will take the second question?

Yes. I think on the bank debt, obviously, we're very confident. Obviously, the first $65 million, which is due on the 1st of April this year is -- we'll have no issues paying that. And then I guess, the question is around the bullet payment, the final $360 million. Obviously, it all depends on oil prices for the rest of the period up until then. I think if they stay at similar levels to this, then obviously, the amount that we would end up, as I said, I think, potentially on the oil prices, we could repay out of pure cash flow. If they stayed similar to where they are, there would be still some less and certainly well less than half of that final bullet payment, in which case, certainly, I think I'm very confident about being able to refinance, that will only be a small amount, either through a small loan, considering the amount of security the assets have, that would be very easy, or indeed, potentially extending, it would depend on the lenders themselves. I think I've certainly had very -- the lenders have actually been very supportive of us all the way through and certainly with us repaying all of our amortizations early. They have been very supportive on an ongoing basis. So very confident around being able to refinance all of that to the extent if needed and might not be needed at all.

Okay. On your second question, James, I mean, the Bressay is an option, but I don't look at Bressay only as a development, a large development. Indeed, I think the -- it being very close to Kraken. We are 12 kilometers away from Kraken, as you know, and that distance allows us to look at low-cost options, similar to what we've done with the Western Flank with drilling 2 wells there. So I think that's something we will look at as a possibility for the future. In terms of other acquisitions, you've mentioned BP, you mentioned others. I think we are -- we continue to look at opportunities and clearly similar to Bressay and similar to the deals that we've done in the past on production assets, those need to be capability driven, hopefully with very limited upfront consideration. And that's the key, is we are not really looking to look at deals where we bring something to the table, similar to what we've done in Kittiwake, PM8/Seligi and Magnus, where we were able to take assets which had significant upside but we were able to reduce their cost base to make them very, very economic. And so I think that would be kind of our first quarter call in terms of looking at assets in the portfolios that the majors are offering.

Okay. Okay. That's very clear. Just one separate question, if I may, actually. In terms of the EnQuest producer, what are your thinking about what you can do with the vessel at this point in time? And how much is it going to kind of cost to keep it stacked at the key side in the U.K.?

Yes. So the producer stopped its production on time around the middle -- end of the second quarter. And we are actually making progress towards disconnecting it and taking it to Nick, where it will be then cleaned and readied for either redeployment or resale. So I think the timing will be such that I mean, we'll be looking at a decision in the early part of next year, and it will be then taken away sometime in the next year -- during the next year or so. So I don't look at a large cost. The costs actually are in the GBP 100,000, GBP 150,000 a month range in terms of the cleaning as well as the time it will be at stations. So I don't -- there's not a very significant amount of cost. Clearly, it's very attractive assets, difficult time to deploy these assets. But if we have to just sell it for its value in terms of steel, that's something that's also a consideration.

That was a very strong operational performance given the kind of COVID logistical headwinds that we faced in the first half of the year. So well done there.

Thank you, and no further audio questions at this time. Please continue.

Okay. Any further questions from the operator?

[Operator Instructions] It comes from the line of Mark Wilson.

Yes. I'd like to ask on production of the Kraken field and expectations from here, very strong performance in the first half, 39. And retaining the guidance for the rest of the year does suggest there's actually still some uncertainty, maybe, to the downside in that performance. So with Worcester on stream, do you think it's a given that Kraken will be producing, let's say, over 30,000 in 2021? Have you had some discussion around that? And it would suggest that there's no additional wells, both at Kraken or at Magnus currently planned for 2021, could speak to that. And then lastly CapEx, that doesn't include the decommissioning costs. So could you just give us a reminder of what those costs are this year and what you expect going forward in the coming years?

Okay. Mark, I'll start with the first few questions in terms of production at Kraken, and then Jonathan can answer the ABEX, the amendment cost question for this year and next year. So on Kraken, indeed, I don't think the expectation for lower production comes from Kraken. I think we have outlined in the presentation that we've shut down assets in the first half of the year that contributed 9,000 barrels a day last year to our production. We've clearly also shut in Alma since the first half, and we have, by shutting in the Thistle field, there's no gas going to the Dons, so there's significantly lower production in Dons now. So we've had several thousand barrels a day affected by those 2 assets over and above the Thistle and Heather production. So I think the production for the second half is impacted, first, by the assets that have been decommissioned. And secondly, during the COVID time, we have also delayed or programmed our downtime and our shutdowns for the second half of the year. Indeed, the 3 of our assets will have shutdowns in the second half of the year. That's Magnus, Kraken and GKA. So the 3 of our assets will have shutdowns in the second half of the year. So that will impact the production from those 3 assets, Kraken, Magnus and Kittiwake because we've had a lot of work that needs to be done, and we are planning to do that now in the second half of the year, safety and maintenance platform. So I think we're still very positive. We obviously had 2 wells added in the first half, the producer-injector pair on the Worcester well, which came in on target. So we will see declines in Kraken, but I don't think we'll see declines that are significant. It's been producing quite well. It is a -- I mean, the good thing about Kraken is it starts out with a high-water cut. Because it does come -- it kind of starts like a late age field with a very high water cut because water is a part of the solution. We need to inject high-pressure high-temperature water to emulsify the oil and bring it up to the vessel and then break it. But then that water cut is very, very steady throughout the life of the field. And that's why we have significant reserves yet to be captured there in Kraken. Jonathan, do you want to structure the last question on ABEX?

Yes. On ABEX, I think we've previously said that kind of as an ongoing basis that a kind of around about a $50 million is not a bad estimate over the longer term. Obviously, each year will be slightly different, potentially more, potentially a little bit less, but that's still a reasonable assumption for the next forthcoming years.

Okay. And just to be clear, that ABEX, that isn't in the $120 million CapEx, Jonathan?

Correct. That is not in the $120 million.

Okay. And then just to push back again on Kraken, if I may. It was more that the gross guidance on CapEx on Kraken that I found interesting after [ shut the ] -- I appreciate the shut-in or are shutting in other fields, Alma/Galia, Dons, et cetera. But in terms of the asset performance of Kraken, which has been so strong this year, it just did interest me that the 30,000 to 35,000 range would be retained, certainly at the lower end.

I mean I think we'll give guidance towards the end of the year, as you know, Mark, or early next year on the year, but I'm hopeful that, that's like you that, that would be maintained.

And yes, well done through tough time.

Amjad, there are couple of questions on -- from the webcast, which have come in, which we can answer those.