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

Ladies and gentlemen, thank you for standing by, and welcome to the EnQuest 2019 Full Year Results Conference Call. [Operator Instructions] I must advise you that this conference is being recorded today on the 9th of April 2020. I would now like to hand the conference over to your first speaker today, Amjad Bseisu, Chief Executive. Please go ahead.

Thank you very much, Nadia, and good morning, ladies and gentlemen, and welcome to our 2019 full year results presentation. In light of the situation with COVID-19, we had to convene this presentation remotely. And at this difficult time for many of us, we appreciate you taking the time to join us and hope that you and your families are well. Safety is our top priority. We've been monitoring the evolving situation with regards to COVID-19, and have been working with a variety of stakeholders to ensure we have the right response and advice to protect our workforce and maintain our operations. Bob will outline more specifically the actions we've taken during his presentation, but I'm pleased to report that at present, our operations at Dons have not been materially impacted by COVID-19. We continue to monitor the situation, and we will react appropriately. Joining me today on this call is Jonathan Swinney, our Chief Financial Officer; and Bob Davenport, our Managing Director for the North Sea operations. I'll first take you through our recent decisive actions to lower our cost base given the prevailing macro environment and lower oil price environment before moving to the group's 2019 performance. Bob will then cover the operations in more detail, and then Jonathan will present the financial results. I'll then return to summarize before we move on to the Q&A session at the end of today's proceedings. Now turning to Slide 3. Before we talk about 2019, I thought it's right that we talk about the actions that we've taken based on this new environment. Since our announcement of the 19th of March of initial cost reductions, we have continued to review our operations and identified additional savings beyond those identified on the 19th of March 2020 for 2020 and 2021 both operating costs as well as capital costs. These can be safely implemented while maintaining our guidance of 57,000 to 63,000 barrels of oil per day. These include the decision not to restart production of Heather and Thistle fields, and combined, these high cost operating fields would have been expected to contribute about 5,000 barrels a day in 2020 and 2021. We expect 2021 production to be lower again due to some deferrals in 2020 and 2021 of drilling and workover activities. For 2020, the group is targeting full year based operating expenditures savings of $190 million, down 35% from $525 million originally identified to $335 million. 2020 cash capital cost is also expected to be reduced by almost 50% to circa $120 million. This excludes any reduction of Kraken as we continue to drill the 2 Worcester wells. With the additional cost savings we've identified, we're expecting to be free cash flow breakeven in 2020 at an oil price of $33 a barrel, down from $38 a barrel previously announced. Given our robust Q1 performance where we've realized about $280 million, this means we've actually only need around $25 a barrel for the rest of the year. In 2021, the group is targeting unit operating cost of $12 a barrel, and again, lower CapEx and a breakeven of cash flow for the full year of just $27 per barrel. These significant savings are driven primarily by cost savings of Heather and Thistle, but also through to the removal of non critical and discretionary operating expenditures and support costs and the reduction in capital costs that I have mentioned. So with no senior facilities amortizations due in 2020 and long-dated bond maturities expected in October 2023, we are very well positioned to manage through a sustained low oil price environment. Our 3 largest assets continue to generate meaningful operating cash flow even at low prices, and in the medium to long term, will offer us low-cost resource maturation opportunities which are aligned with our proven differential capabilities. Moving to Slide 4. We have a proven track record in lowering cost base and focus on investments in those assets that matter the most. By having high equity ownership and operatorship on our assets, the decision can be made and controlled by EnQuest and executed by EnQuest effectively. As mentioned, the largest single reduction in expenditures comes from the Heather and Thistle decisions where costs will be incurred as abandonment expenses and shared with our abandonment partners. We've also removed other discretionary spending, and we'll be reducing the size of our workforce as we go from 7 operated assets in the North Sea to 4. This reduction also includes Alma/Galia, which we've already highlighted and is planned to be commissioned later this year. As part of this cost reduction, Jonathan, myself, other nonexecutive directors, Bob, other ExCom members have taken a voluntary 20% reduction in pay for the next 3 months. This will be reviewed at the end of 3 months. We'll continue with drilling the Worcester wells at Kraken and during all -- deferring all additional drilling in the U.K. for the rest of the year as well as in 2021. Our 2021 drilling program in Malaysia will also be reduced, but we will be enhancing our intervention program there. We would reconsider introducing capital when the oil price environment is more favorable. As such, we're confident that we're going to execute our plans effectively and efficiently in this new environment. Turning to Slide 5. Our 2019 performance, which seem long time ago now, was particularly strong. As you can see, we've met our operational targets, financial targets and ended the year with a much stronger balance sheet, lower cost and material debt reduction. I'll now turn to the Slide 6 which outlines our deliver, de-lever, and grow strategy. As Slide 6 outlines, our production has increased by 24% to 68,600 barrels a day. This was primarily driven by a full year contribution of Magnus and improved performance at Kraken. I'm particularly pleased with the performance of Kraken and the improvements there and the asset continues to perform very well throughout this year. We've also delivered another strong operating cost and capital expenditure performance both on schedule as well as costs. On the operating cost side, we've reduced our OpEx to $21 a barrel, reflecting growth in volumes and revised strategy at Magnus -- gas strategy at Magnus, which reduces the amount of gas that's being injected into the reservoir and purchased. Our total operating cost for 2019 was $518 million, below the guidance of $550 million. On CapEx, we've delivered the DC4 drilling program in Kraken in the first quarter, and we drilled in PM8/Seligi in the third quarter and delivered both pipeline projects ahead of budget and schedule over the summer. In the fourth quarter, we started with a 2-well infill drilling program in Magnus, which has been recently concluded. Moving on to the delever on Slide 7. As you know, we prioritized debt reduction and have made significant progress in this regard. We've continued to meet our amortization schedules early, and have paid full amortizations for this year. Clearly, in the current price environment, further material debt reduction is more challenging, but the actions we are positioning and we've taken to reduce our cost will allow our balance sheet to be very strong and allow us to have positive cash flow at even lower oil prices. Moving on to Slide 8. Our growth performance has been strong. We've seen strong execution both in operations as well as subsea projects. We have removed our capital spend for operating expenditures, but recently concluded the Magnus drilling program, which first started in late 2019, which adds production in Magnus this year. We also are continuing our capital program for Kraken as wells are being executed as we speak, and that should also add production for this year. We will -- we have increased the idle well restoration program in PM8/Seligi, and that continues to be very successful and add production there. In our 3 largest assets, we have the largest opportunity set, and I'll set that out in the next slide. So on Slide 9, the charts show our reserves and resource base at the end of 2019. Overall, our reserves were down 13% compared to the end of 2018, but 10% of that was production throughout the year. The additional amount of reduction relates to Thistle and Deveron and the Dons revised -- downward revision on reserves. These were almost entirely offset by increases in group's growth assets, Magnus, Kraken and PM8/Seligi. When the macro conditions are right, we will have substantial opportunities to pursue within our 2C resources, our contingent resources, primarily located in our Magnus, Kraken and PM8/Seligi fields, as you can see in the slide. Our year-end 2C resources is 173 million barrels of 2C resources, primarily in these 3 assets. We've also now added a large 2C resource associated with an award of the PM409 contract, offshore Malaysia. The audit of our results was made after our decision not to restart Heather, and so we've already removed the associated volumes. Our subsequent plans will also not restart Thistle, which will result in an additional 11 million 2P and 2C resource removal at the end of this year. Turning to Slide 10. Despite the current macro situation we find ourselves in, we are as committed as ever to working responsibly for the benefit of our stakeholders. Safe results has and will remain a fundamental pillar of our business, and it is the franchise that makes EnQuest work, safe operations and safe results. Strong environmental performance is also critical to our activities. And it's important to understand the role we continue to play in this wider energy transition. Through our business model, we improved performance and efficiencies of already producing assets through short-cycle investments, avoiding the need for costly, carbon-intensive and long-dated new developments. We recognize we must endeavor to minimize carbon emissions from our operations as far as practical, and play our part in U.K.'s legal requirement to be carbon-neutral by 2050. We also sell Kraken oil which has low sulfur directly to maritime industry buyers, playing a vital role in reducing sulphur emissions accordance with IMO 2020 by selling directly to the fuel oil market and avoiding refining related emissions. We've also voluntarily reduced our flaring levels in Malaysia and are targeting long-term reductions in SVT as part of our ongoing transformation program there. In 2020, our program of work is being undertaken to put in place that will include specific, measurable emission reduction targets, which will form the basis of our 2021 corporate targets. We're also pursuing a number of other initiatives across society and the government landscape, and you can see some examples on this slide. I will now hand over to Bob to cover our operational performance in more detail.

Thank you, Amjad, and good morning, everyone. Amjad described our decisive actions to reduce spending and drive down unit costs within our rebalanced portfolio. So I'll begin with an overview of the group's excellent operational delivery in 2019, then share some detail from each area and finish up by describing our actions to maintain safe operations right through the ongoing COVID-19 critical period. On Slide 12 now, so first, our overall 2019 production performance. The group delivered near top end of guidance with production at 68,606 barrels equivalent per day, that's up 24% versus 2018. Northern North Sea production was 27,237, that's up around 41% from 2018, reflecting increased contribution from Magnus and more than offsetting the unplanned shutdowns at Thistle and Heather. Central North Sea production in the period was 7,544, higher by 19% from 2018, and this was driven by higher volumes at Scolty/Crathes. Kraken average net production was above top end of guidance, delivering net production of 25,172 for the year. Here, we achieved marked improvement in uptimes since the first quarter along with strong performance from DC4. And Malaysia production of 8,653 was slightly higher than 2018, reflecting high production efficiency once again and the impact of the idle well program. I'll now go area by area and provide more detail, beginning with the Northern North Sea. Now on Slide 13. At Northern North Sea, the main driving factor -- sorry, the main factor driving the material production increase was our full working interest and strong performance at Magnus. Here, we delivered strong production efficiency, around 81%, along with plant debottlenecking and barrel-adding well work. At Thistle, the precautionary down-manning of the platform restricted production in the fourth quarter, following good production and water injection efficiencies in the first 3 quarters. And at Heather, following the safety incident involving a gas compressor, we shut down production from October. At the Sullom Voe Terminal, we have continued to deliver safe and stable operations to our customers. Transforming SVT cost efficiency remains fundamental to our strategy to deliver long-term value at Northern North Sea. During the year, the oil and gas authority endorsed a revised SVT owners strategy to extend the life of the facility in support of maximizing economic recovery for their 33 offshore fields that export crude through the terminal. Turning to Kraken. Production in the period was slightly above top end of guidance with daily average just over 35,700 barrels per day gross. Production efficiency was strong following the resumption of 2 train operations in March, average of around 80% in the second quarter and over 95% in the fourth quarter, which is up materially on the first quarter average in the high 50s. This improvement follows a program of targeted initiatives, focusing on main power engines, upside power, water pumps and oil coolers, combined with improved maintenance and spares management. We successfully completed DC4 drilling in quarter 1, marking the end of the original field development plan, and I'm pleased to report that the DC4 area continues to perform very well. Subsurface and well performance remains strong at Kraken, and the group continues to optimize production through improved injector-producer well management with the field now at full voltage replacement and with stable water cut trends. We have now produced more than 30 million barrels from Kraken since first oil in June 2017. The strong reservoir performance, combined with sanctioned drilling in the Western area, which is now ongoing, led to a small increase in net 2P reserves at Kraken at year-end after adjusting for production in year. And we continue to see big potential in the Western area to pursue when the time is right. Now on to Slide 14. At Central North Sea, for the fields there, average production was up 19%, reflecting the safe delivery and replacement -- sorry, reflecting the safe delivery of the replacement pipeline at Scolty/Crathes ahead of schedule and the positive impact of the 3 electric submersible pump replacements done in the second half of 2018, combined with excellent production efficiency of over 95% at Alma and Galia. In Malaysia, production was up 2.6% compared to 2018, driven by PM8/Seligi. Here, the group delivered high levels of production efficiency, well over 90%, along with continued success in low-cost idle well reactivation, where 11 wells were returned to service during the year. These very profitable campaigns have been fundamental to arresting fuel decline since EnQuest assumed operatorship. We also concluded the second 2 well drilling program in the area in the third quarter as planned. In summary then, each of the operational areas performed very well in 2019, and we have started 2020 strongly. So for the full year, reflecting the CapEx reduction and the plan not to restart production at Thistle and Heather, we expect production to average between 57,000 and 63,000 barrels of equivalent per day for this year. Going forward, we see lower unit costs and plenty of drilling options to pursue when market conditions support this, especially at our 3 core assets, Magnus, Kraken and PM8/Seligi. Now finally on to Slide 15. A few words about how we are actively managing through the current COVID-19 critical period. We are all aware of the global pandemic, the health risks this poses and the necessary restrictions placed on our daily lives. As a responsible operator, we've been working with a variety of stakeholders, including industry and medical organizations to ensure our operational response follows expert advice and is appropriate for the level of risk. These actions keep our people safe while maintaining normal operations. Appropriate restrictions on offshore travel have been implemented, including self-declaration of symptoms and pre mobilization temperature screening, our normal communicable disease protocols have been updated specifically for COVID-19 with additional offshore isolation space and capability to transport the impacted individuals back onshore in dedicated helicopters. As you would expect, offshore and at the terminal, we have down-manned less essential roles, meaning we can continue normal operations whilst creating space for social distancing and, when necessary, temporary isolation of individuals showing symptoms. And of course, our onshore workforce are working from home. So far, our operations have not been materially impacted, and we continue to monitor the situation and will respond accordingly. With that, I will now hand you over to Jonathan to take you through the financial results.

Thank you very much, Bob, and good morning, ladies and gentlemen. Turning first to the summary slide on Page 17. The group put in a strong performance and achieved its operational and financial targets for 2019. The priorities of the business are, deliver, de-lever and grow, and we've delivered on all of these. The results themselves are driven by the material growth in the group's production, reflecting improved performance at the Kraken FPSO, increased volumes from Scolty/Crathes, higher production efficiency at PM8/Seligi, the contribution from Magnus and higher realized oil prices. This strong performance has facilitated a significant reduction of debt during the period. Realized oil price in 2019 was $65.3 per barrel compared to $64.2 per barrel in 2018. In 2019, we recognized $24.8 million of hedge gains compared to $93 million of losses realized in 2018. The realized price, excluding hedges for the year, was $64.2 per barrel, 7% lower than in 2018, which was $69.4 per barrel. Saleable barrels were less than production mainly as a result of the entitlement barrels in Malaysia being around 67% of the working interest as well as shrinkage of around just over 1%. Entitlement barrels for the year at PM8/Seligi are expected to continue to be around 70% of working interest barrels. Revenue also included gas and condensate sales of $120 million, mainly derived from Magnus gas sales, which included about $72 million associated with the resale of purchased gas no longer required for reinjection in the Magnus field. The increase in production led to a decrease in operating cost per barrel from $23 per barrel to $20.6 per barrel. Higher production and realized oil prices also resulted in EBITDA and cash generated from operations increasing to $1.007 billion and $995 million, respectively. However, we recognized a noncash post-tax impairment of $562 million, reflecting lower long-term oil price assumptions and changes in production profiles, mainly at Heather/Broom, Thistle/Deveron and at the Dons. Net financing costs decreased in 2019, mainly reflecting a reduction in bank interest of $27 million as a result of the group's ongoing accelerated repayment of the senior credit facility. With the prevailing low oil price, February's interest payment on the retail bond was paid in kind, and the April high-yield bond will also be paid in kind. This is added to the group's issued debt at redemption. And at current low oil prices, the bond coupon will continue to be paid in kind. At the end of 2019, our net debt had improved to $1.413 billion, having repaid $70 million of the 2019 RCF amortizations in 2018. During the 2019, the group repaid a further $325 million, including $120 million relating to the April 2020 amortization. An additional voluntary prepayment of $35 million was made in January 2020, settling the October amortization. As such, no further amortizations are due in 2020. At the end of February, net debt has been reduced to $1.368 billion with cash and available facilities of $268 million. As you can see on Slide 18, the operational performance I highlighted on the previous slide has delivered strong cash flows from operations in 2019. The primary driver of the improved cash flow this year was the 24% increase in production volumes which primarily came from the group's highest margin assets, Magnus and Kraken, while gains on the group's commodity hedge program more than offset the $5 per barrel decline in average market prices. This positive movement in cash flows also includes the reimbursement of EnQuest's $100 million cash consideration for the Magnus acquisition. These positive movements were partially offset by a combination of the unwind of positive working capital movements in 2018 as well as the $50 million received in 2018 from the exercise of the Thistle decommissioning option. Turning now to Slide 19 and our capital spend, where we had a focused production enhancing program. Cash capital expenditure for the year amounted to $238 million. Kraken continued to be where the vast majority of CapEx is focused with the completion of drilling at DC4. Approximately $100 million related to work in prior periods but settled during 2019. In the Northern North Sea, the expenditure mainly related to the Dunlin bypass pipeline, which was completed in June and the commencement of the 2-well drilling campaign at Magnus in the fourth quarter. In the Central North Sea, most of the cost relates to expenditures on the Scolty/Crathes pipeline. In Malaysia, the group continues its 2-well infill drilling campaign in the third quarter of the year. Slide 20 outlines our net debt performance. As you can see, our net debt position has improved materially from around $1.77 billion at the beginning of the year to $1.41 billion at the end of 2019. With EBITDA of $1 billion, we achieved net debt-to-EBITDA ratio of 1.4, materially ahead of our target of being below 2x. As outlined on Slide 18, net cash flow from operations totaled $962 million in 2019, up from $794 million in 2018, and cash CapEx was $238 million. We paid BP $52 million in relation to the vendor loans associated with the acquisition of the additional equity interest in Magnus, along with an additional $22 million of profit share. Net financing and other costs are primarily made up of interest on our debt facilities and the FPSO lease. For 2020, we have hedged approximately 4 million barrels for the year, the equivalent of around 20% of our net entitlement production. And as you've already heard, we are implementing significant cost and capital expenditure reduction programs to drive down free cash flow breakeven to around $33 a barrel. Turning now to Slide 21. While we are focused on driving down our free cash flow breakeven in order to continue to position ourselves for a continuing low oil price environment, it is important to remember that our debt maturities are long-dated. Our bank debt matures in October 2021, and our expectation is that the bond's maturity date will be extended to October 2023. The Sculptor Financing facility is also due in 2023 and is simply repaid out of the cash flows of the 15% interest in Kraken. At the end of February, the outstanding amount due had already been reduced to around $107 million, reflecting the strong performance at Kraken and higher price environment in the first 2 months of the year. The repayment due in 2020 relates to the Tanjong Baram project finance facility and this has no material impact on liquidity as the group will receive around $50 million from Petronas during the year, more than offsetting the required repayment. The combination of our quick and decisive cost reduction plans and our long-dated debt facilities means we are positioning ourselves to manage through the current low oil price environment. And with that, I will now hand you back to Amjad.

Thank you very much, Jonathan. So now turning to the summary Slide #23. As you've heard, we performed well in 2019, delivering on or ahead of our targets, production was up 24% year-on-year, unit OpEx was down 10% year-on-year. Our capital program was focused and successfully delivered, ahead of time and on budget. We've significantly reduced our debt through the combination of early and scheduled repayments. And at 1.4x net debt-to-EBITDA, we're materially ahead of our year-end target of 2x net debt-to-EBITDA. This strong performance has set us up to take the necessary actions which we are now pursuing in a low oil price environment. Turning to Slide 24. We are well placed to manage a sustained low oil price environment. We've outlined that we are implementing material operating costs and capital expenditure reductions to significantly lower our cost base. Our group free cash flow breakeven is targeted at $33 per barrel in 2020 or $25 a barrel for the remainder of 2020, given the first quarter realizations. Free cash flow breakeven is targeted at $27 a barrel in 2021. While these actions have reduced our production expectations, free cash flow has improved significantly, and there's no senior credit facility amortization due in 2020 and the long-dated bond maturities at the end of 2023 give us very strong positioning to manage through a sustained low price oil environment. When macro conditions allow and improve, our 3 largest assets offer significant low-cost maturation opportunities for 2C resources of over 170 million barrels. These are low-cost barrels and are aligned with our proven differential capability in drilling subsea projects to allow us to develop those low-cost barrels. Thank you very much for listening. I'll hand back now to Nadia for the Q&A session.

[Operator Instructions] The first question comes from the line of [ Stefan Fuco ].

I'm aware of the increasing differences between that would describe as paper power and physical, so between perhaps what we see on our screen as being $30 plus a barrel and maybe what you receive. So I wonder whether you could give us a sense of the sort of prices you're getting for the North Sea production at the moment, of course, excluding the usual differential we see on Kraken for its quality.

Thank you, Stefan. A very good question. We have put in place, Stefan, a hedging program for our dated front line exposure or the difference between what you see on the screen and what you get as physical barrels. So our production for the second quarter has in place 100% hedge for the dated frontline exposure, excluding Kraken barrels, which are sold on a low sulfur fuel oil equivalent. So I think we are well positioned to be covered in this environment of the large delta. And the -- obviously, the hedges are at very favorable prices compared to the physical versus paper differentials, which we're seeing, which are near $10 a barrel. Our hedge is in the low single-digit numbers for the 3 months.

So the reference price, I would say, because of what you've put in place, assuming that we are still at this paper barrel price of $33 or whatever, that's really an indication of what you get.

Yes, that's right. I mean the differential we have is negative, but it's in the -- on the average of 3 months, it's in the low single digits.

The next question comes from the line of Andy Brough from Schroders.

Jonathan, can you just remind me what the average cost of your debt is? Just the interest charge is quite high compared to the year-end debt number.

Yes, we pay 4.75% over LIBOR on the bank debt on the --

What number was that? 4.75%?

4.75% over LIBOR on the bank debt. On the Kraken Sculptor facility at 6.3% over LIBOR.

Okay.

Also, the interest charge, Andy, includes the Kraken lease.

Right. How much is that?

The -- it's around about $50 billion, $55 billion or so. So it's significant.

The next question comes from the line of James Thompson from JP Morgan.

We've obviously no 2 recessions this time. But when I compare EnQuest today to 2014, I think the differences are pretty stark. Back then, you had several billion dollars of committed CapEx ahead of you and OpEx was nearly double. You've got a pretty -- you sort of -- you described to us, I guess, this morning, a pretty static outlook for your liquidity. And I imagine your early repayment of the facilities has been initiated by the banks, given this unexpected environment. So it feels to me that rather than being purely on defense, debt reduction, which has clearly been the focus, it seems that maybe you've got more advantage at this point in time to take the stress of -- or take advantage of distress elsewhere in the sector? And I guess, with that in mind, could you maybe talk a little bit about the asset market today? Are there many assets available on the market? Do you see an opportunity to expand in the North Sea and beyond?

I'll take the first part of that. I don't know if Jonathan wants to add on the difference with 2014. You're absolutely right. We are in a very different place today than we were in 2014. And indeed, the ability to take such swift action and reduce cost -- operating cost by 40% and capital cost by 50% is just an indication of the flexibility of what we have today versus 2014. You're also right about the advantages with looking at assets. We've been active and continue to be active in looking at assets. If you recall, we did the Magnus deal actually in the depths of the low price scenario last time, I think we do have differential capability. We have taken Magnus from $60 a barrel operating cost when we took it over to $15 a barrel or below $15 this year and even lower going forward. So you're absolutely right. We do see this as an opportunity. Some where others have higher cost structures, I think we could look at taking over assets, and we continue to look at that. Magnus was done in the depths of the last downturn as well as if you think about the reductions in Malaysia, which were over $100 a barrel operating cost when we took over and we've reduced those to $15 a barrel also. So we are -- we continue to look at the asset market. The market today, I would say, is on hold. I think everyone is recalibrating the long term prices. We have been in processes and continue to be in processes, but I think things are on hold until people reassess or sellers reassess the landscape in terms of what price they would like to achieve long-term for their assets. I think the old norm of maybe 60 to 70 which was -- where transactions will be executed is being challenged now. And I think it will take a bit of time for sellers and buyers to recalibrate. Jonathan, do you want to add anything about balance sheet post 2014 vis-à-vis 2014?

Yes. I mean, I think, James, you're quite right that we are in a very different place compared to 2014 and going through the restructuring in 2016. So having paid all the amortization all of this year puts us in very good stead on a go-forward basis. So yes, we're in a much stronger position than we were 3, 4 years ago.

Great. And separately, in terms of cost savings, I think the decisions you've made to shut the late life assets is the correct one. I mean, frankly, you're playing your part in balancing what has been a stubbornly oversupplied market for the last few years. I mean, could you maybe talk a little bit about continuing that process? I guess I'm thinking about the Dons and refining your -- or high-grading the asset base into your bigger and lower cost assets?

So I think the growth assets, which include Kraken and Magnus and recently also Kittiwake, with the addition of Scolty/Crathes offer us relatively low cost per barrel. And I think those will continue to offer that in the U.K. and in Malaysia, obviously, PM8/Seligi is $15 a barrel operating cost. So as you see, James, next year, our target for operating cost is $12 a barrel. So we are challenging ourselves to be even lower. And you're absolutely right. These assets have been suddenly high cost. I mean, they were late life assets. And I think we've just -- we've made the decision that suddenly high costs need to move. So we have shifted our business model to looking at lower cost barrels as continuing for the future. Now your question about the additional assets, we'll continue looking at the assets. We are closing down Alma/Galia as planned for this year in the second half. So we will have 3 assets decommissioned this year. And we'll continue looking at the Dons, I think, into the future, just depending on the environment for oil prices. The Dons operation is -- the people there, we've had an exceptional team out there working the Dons on the northern producer. It's 1 of our best operated assets. And I think the team has done an exceptional job at reducing costs. The number of people out there is also -- is very low. I think we just have over 40 people operating that asset. So it's a relatively -- it's very, very efficient asset, very high production efficiency, but we will continue looking at it in the -- given the landscape change in the coming year.

The next question comes from the line of Tom Hemmant from Invesco. Tom, your line is open. Excuse me, Tom, is your line muted? The next question comes from the line of [indiscernible].

Can you hear me well?

Yes. I can hear you fine. Can you just repeat your name, please?

[Technical Difficulty] I just want to [Technical Difficulty]. So first, starting with the physical versus dated [Technical Difficulty] Kraken differential, you said that you have realized a low single-digit negative differential in the first 3 months. I think that in the beginning of the year, this differential was materially positive. So that would suggest that in March, it has turned quite negative. So can you give us a sense where you see the Kraken differential roughly now and for the rest of the year, and what is the physical versus dated differential on your unhedged barrels?

Okay. No, I think you misunderstood what I said. I said, in the next 3 months, we have hedged the dated paper differential. On Kraken, we continue to have positive differentials versus dated Brent. So our sales continue to be positive throughout the first 3 months and into the coming quarters. So that is -- it continues to be positive versus dated Brent. So what I was talking about was specifically non-Kraken barrels. And those -- the exposure on those physical versus paper sales.

All right. But is there any sense to what the differential will be when the hedges roll off?

Differential for Kraken has been positive, above Brent, and continues to be above dated Brent.

Okay. And what is the differential for the unhedged barrels for the physical versus dated? For unhedged barrels? I understand that you hedged it for the next 3 months, but how should we think about the [Technical Difficulty]?

I don't understand the question. What is your question again, please?

So the -- I think the previous caller [Technical Difficulty] that the physical cargoes are selling below what we can see on the screen. And I think that the differential with operators are in high single digits. So I understand that you're hedged for the next 3 months. I'm just trying to get a sense where you -- I mean, where would we be actually selling if you were unhedged, right, because this is where we will be in a few months?

I think Stefan mentioned that the differential is $9, $10 a barrel between physical and dated. So that's what the market is.

Okay. Perfect. That's very helpful. Moving on, obviously, you have liquidity at the moment. You have prepaid the amortizations for 2020. But in case [Technical Difficulty] will take you longer than we think or is more severe, do you see any additional liquidity sources as in [Technical Difficulty]?

I'm not hearing you. Do you want to answer that, Jonathan?

I didn't hear too either in terms of what he said. But his line is breaking up. But I think given where we are, I think we feel very comfortable with liquidity. There's quite an extensive disclosure around our liquidity and our going concerned viability statement. So I think we feel very comfortable around that.

Okay. And regarding your cost savings program, I mean, is that -- to what extent is that expectation [Technical Difficulty] deflation in service costs? [Technical Difficulty] this is the company under the tax [Technical Difficulty] bank interventions or just doing less work on the assets?

So I mean, you're breaking in and out, but I understand the question to be, is this relating to service costs? Or is it mostly reduction of programs? I think it's primarily almost entirely relating to reduction of programs. I think we have a very strong procurement arm and a procurement team run by a gentleman who is a very strong, excellent value [ cohort.] And I think -- I mean, we've gotten very good prices out of the industry. So we're not assuming any significant reductions on supplier request.

Okay. And lastly, when you guide to breakeven $25 and then $27, is that before -- sorry, before or after interest?

After interest. Okay. If we can give somebody else a chance, that would be good.

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

Just checking, you can hear me?

Yes, Mark, we can hear you fine.

First, just an admin point. You show the reserves and split out the Thistle contribution in there. Can I just ask what the Alma/Galia contribution would be? Is that CRP?

In terms of reserves?

Yes, I'm just looking at -- you show the Thistle contribution. Obviously, that's coming off not restarting but...

Are you talking about production, Mark? Our reserves are minimal. We'll be stopping production later this year, and the field is producing around 2,500 barrels a day gross. So there's not really much reserves there.

Okay. Very good. A lot of clarity around the production, the cost savings and I say, no amortization. So we're all very clear and looking robust through the year. So I suppose the single risk that remains is some kind of COVID-related shutdown of facilities. Could you just speak to that, Bob, and the precautions and what risk you would see to 1 of these main hub facilities?

Shall I take that one, Amjad?

Yes, Bob. Yes, Bob, please. That's for you.

Yes. Happy to answer that question. But first, let me say, our focus remains firmly on delivering safe results, and it remains firmly on ensuring that we protect the safety and well-being of all of our staff and contractors who are working across all other assets. And we're able to do that through carefully managing the way we conduct our operations right through this COVID period. So as I described, we have processes in place which are fit-for-purpose and are aligned with the same sorts of processes that you would find at other operators across the North Sea. So we have confirmed and I think really shown over the last month, that the processes are robust and provide a level of resilience which we're comfortable can extend right through the period and allow us to continue to operate on a normal basis. So again, just to recount, we have procedures to restrict folks from arriving offshore or traveling to offshore who have signs or symptoms. We have protocols in place while offshore to social distance and to restrict the possibility of spreading COVID-19 offshore if anyone does arrive offshore with symptoms. When folks do show symptoms offshore, we have protocols to isolate them and monitor them and provide extra care for them if required and if required to transport them back to onshore. So we've considered this in our plans for the rest of the year, and we've considered this in our assumptions for costs and production and have fully built those in. So again, in summary, our protocols have proven robust, and we're very confident that we can operate and continue to deliver our results this year right through the COVID period.

The next question comes from the line of Sunny Chhabra from Ironshield Capital.

Can you hear me now?

Yes, we can. Thank you.

Just a few questions from me. Firstly, on the decommissioning costs. You mentioned Alma/Galia, Heather/Broom and Thistle getting off-line. Could you give a flavor of the decommissioning costs associated with these over the next 3 years? And also, is there any other decommissioning costs you were expecting? I'm just talking about over the next 3 years?

Jonathan, do you want to handle that?

Yes, that's fine. We're probably in the region of -- for next year -- sorry, for this year, in the region the 20 to 30 or so. And then decommissioning costs on all those assets will be spread over a reasonably long period because obviously, you are looking at decommissioning over potentially a 5 to 7-year period on abandoning your well. So we would look to be spreading that out as effectively as possible and as in a low-cost as possible way. So that kind of 30 range is not a bad number in terms of the amount that we'll be spending over the next 2, 3 years on a per annum basis.

Got it. Secondly, on the CapEx saving plans that you've mentioned, how does that impact the production for 2021 on Kraken and Magnus?

So I mean, we have talked about our assets generally have a single -- low double-digit decline rate. Now we have completed the Kraken wells. So we'll complete the Kraken wells, and so those will start producing in the second half of the year and will have an impact into next year. We are also implementing the IWR, the intervention program in Malaysia. So that should also help us maintain reasonable production there. So we are trying to mitigate that decline from the low double digits even in a reduced CapEx environment. However, obviously, the production next year will be lower given that we're delaying further Magnus and PM8/Seligi drilling.

But should I expect an average of double digit decline, given the reduced CapEx on Kraken and Magnus as well or that's primarily linked with the other field?

I mean, I think we've always said low double digit declines, but this -- we do have the wells being finished in Kraken, which will contribute into next year.

Okay. And on your hedges, could you update on just the remaining hedges over the -- from April onwards? I understand there were quite a few hedges that were expired in Q1. Just wanted to clarify that.

Yes. We continue to have -- we've discussed the hedges on the physical versus paper which continue into the next -- into the rest of the year. And then we also have a hedge -- the hedges on the Kraken Sculptor facility. That's throughout the year, until the end of the year.

And how much was the physical versus paper, just the quantum of the hedges?

So we've hedged all of our production for the next 3 months.

Thank you. Dear speakers, there are no further questions at this time. Amjad, I'm handing over to you for your closing remarks. Thank you.

Okay. Well, thank you very much, everyone, for attending in this difficult time and giving us your precious time. And I know these are precedented times to us in the industry as well as for the whole economy and the economies, it's not something we've seen in the past. So we appreciate your loyalty and continuing to work with EnQuest. I assure you that we're doing everything we can both to ensure the safety of our people as well as the robustness of our company EnQuest. So I'm very -- I'm certain we're going to get through this and come out to the other side of it even stronger. So thank you very much.

And that concludes our conference for today. Thank you for participating. You may all disconnect. Have a nice day and stay healthy.