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

Good afternoon, ladies and gentlemen. Welcome to the EnQuest PLC Investor Presentation. [Operator Instructions]. The company may not be in a position to answer every question it receives during the meeting itself. However, the company will review all questions submitted today and publish responses where it is appropriate to do so and these will be available via your Investor Meet company dashboard. Before we begin, if I may, I would like to submit the following poll. And if you could give that your kind attention, I'm sure the company would be most grateful. And I'd now like to hand you over to Head of Investor Relations, Ian Wood. Good afternoon, sir.

Thank you. Thank you for your introduction, and good afternoon, ladies and gentlemen, and welcome to our retail shareholder focused presentation. As [ a ] outline, my name is Ian Wood, I head up Investor Relations team here at EnQuest. You also have on the video line with me today, my colleague, Craig Baxter, our Senior Investor Relations Manager. The purpose of today's meeting is really to provide you in an additional forum outside of our Annual General Meeting for both existing and potential noninstitutional holders to engage with us, understand who we are, what our strategy is, what our achievements are, et cetera, and ask us some questions about the business. So as the operator outlined, the Q&A box is open for people to submit items I'd like to discuss, and we'll come to those at the end of the presentation. So the format is pretty straightforward in line with others. I'm sure you've attended, which is Craig and I will cover the EnQuest business and then we'll turn over to the Q&A section. So without further ado, I will start with an overview of who we are. So EnQuest is an independent energy company. Our operations are focused in the U.K., North Sea and in Malaysia. We were first listed on the U.K. and Swedish Stock Exchange back in 2010. And our focus at that point in time was really on the upstream business and on taking mature and underdeveloped producing assets from majors and other operators and driving further efficiencies in their operations in order to extend their lives and a maximize recovery of oil and gas. And then eventually, we would obviously move them into decommissioning once they cease economic production. So as you can see from this slide, we've got a number of assets that are in production today. They're primarily in the U.K. North Sea. Although we do obviously have our major asset in the Malaysian basin. All of these have combined -- have material reserves and resources that we're looking to exploit. We also have the Sullom Voe Terminal, which is an onshore process internal in the U.K., up in the Shetland Islands and as I've outlined a bit later on, this is very important to both our existing upstream and our new energy ambitions. We've also got a number of assets that we have now moved into decommissioning over the last few years as they have reached the end of their economic lives. And so we are managing those decommissioning programs on behalf of other partners. So as you're no doubt aware, the energy landscape is in transition. The wider macro environment has also had some challenges, not least in the last kind of 12 months or so. And obviously, to be a successful organization in such circumstances, the business has to continue to show the resilience it's shown over many years, but also the creativity and adaptability that are sort of core part of our DNA. And we think the combination of the assets that we've got within the business, the people we have within the business and the capability set we have really sets the company apart from any of its peers, and we're really able to provide an offering across the entire energy transition spectrum as we see it today. So being true to our roots, as you can see from this slide, our business model has the upstream business effectively on the left-hand side there, and that remains our core business. This is what we'll deliver the cash flow over the medium to long term, but we are very cognizant of the changing energy landscape and want to play our part in a sustainable transition and so we've enhanced the business model in the last 12 to 18 months or so to include complementary strands of infrastructure in new energy, which is the kind of middle green bit there, and this is where we aim to repurpose existing infrastructure that supports the delivery of our renewable energy and decarbonization ambitions. And we also have the -- a more fulsome strand around decommissioning where we will effectively manage end-of-life production and then ultimately, the safe cost-effective and as low carbon as possible, decommissioning of those operations that have reached the end of their useful lives. So let's jump into a little bit of background on each of these business units that we have within the organization. The first one, a couple of slides relate to our upstream business. So again, going back to our roots, really, we focus on 3 core areas for improvement when we look at assets that we want to take into the portfolio. Obviously, we have health and safety and CO2 emissions reductions in mind as we develop these assets, but fundamentally, we are looking to ensure that we exercise strong cost control and capital discipline and lower the running cost of these assets. We look to drive improvements in the uptime, so ensuring that they run more efficiently, a bit like tuning your car more regularly and ensuring it is in its most efficient mode, and therefore, it's cheaper to run and obviously produces more hydrocarbons in good time. And then obviously, we look to also see what the reservoir opportunity is and enhance the recovery of the significant oil and gas reserves and resources that remain in place at many of these assets that others before us probably would have left behind as they move on to new developments that they tend to prosecute. So on this slide, you can see on the left, our ability to lower costs when compared to those incurred by previous owners. So Magnus down 57% on average under our operatorship versus north sort of $60 a barrel in its final few years with BP. We also took cost down in the Malaysia asset. And it's not just the day-to-day running costs where we exercise such a focus. It's also in the capital program as well. So obviously, we developed the Kraken asset back in kind of 2013, '14 through to 2017 when it first came on stream, originally had a budget of $3.2 billion, and we managed to deliver that for $2.2 billion. So significant savings there as we drove improvements through our strong drilling performance, but also strong contractor management and looking to ensure in the supply side worked with us to achieve efficiencies on the sort of cost and performance basis. On the right-hand side, it's a little bit more operational focus. Again, obviously, we've got our safety stats there. which is still pretty strong, although recognize a slight deterioration in 2022 that we are obviously very conscious of improving as we move forward and are focused on a kind of continued improvement mindset. In that arena is without strong safety, you have no license to operate these assets, but the other section there in the middle sort of is really the core of our uptime objective. So we really aim to get the production efficiency or uptime of these assets to be above 80%. So that means it's running full bore, if you like, 80% -- running a full capacity for 80% of the year, recognizing we have shutdowns and you will have other instance and so on, that cause platforms to trip from a safety sort of standpoint and ensuring that we keep our people safe offshore. And we've got a good track record of keeping things high in this regard. So Kraken particularly has shown an exceptional performance at 93% uptime last year, and it was above 90%, I believe, the year before. And for floating production units, which is what the Kraken facility is rather than a fixed installation, they tend to operate in the kind of low 70%. So we really demonstrated good operational capability there. And this has continued really into 2023 at both Magnus and Kraken. So although we had some issues at Magnus in the early part of 2022, there have been a number of improvements put in place throughout the year, which Craig will cover some of those a bit later. And really, we've seen very, very strong uptime well north of 80% at both assets through the first quarter of 2021 -- 2023, sorry. So with such strong performance in terms of lowering costs and improving asset uptime, generally, this means you can run the assets for longer than they would have been run for in the hands of previous owners because you're effectively driving efficiencies into day-to-day operations. And so they remain economic for longer. And so since our inception, we've extended the useful lives of every asset that we've taken into our operatorship, so as some examples there on left-hand side. Obviously, as we -- as you do that as well, you tend to extract more resource naturally because you're running it for longer than the previous operator would have done. And so alongside this natural life extension through strong uptime and cost control, we've also looked at where we can extract additional resource, largely through infill drilling, where we have a really strong operational capability to extract additional reserves. And that combined has effectively delivered a reserve replacement ratio, which is effectively your number of additional reserves you've added versus the amount you've produced at the time. So you can see we produced 1.6 -- sorry, we've added 1.6x the amount of reserves into the portfolio versus that which we produced. So since that we started with sort of 80-odd million barrels of oil, we've produced around 200 million barrels, and we still got 190 million left to produce. And that's without accessing further opportunities that we see within our portfolio that I'll come on to in a moment. Particularly from a sort of sustainability standpoint, we think this is quite compelling. It's better to make the best use of what you already have rather than perhaps going out exploring, expanding significant capital, expanding significant carbon and creating new production facilities and installing them. So best to make the use of what we have While we do transition to a new lower-carbon world in the decades to come. So as I alluded to just now, this slide outlines the opportunity set, if you like, over and above that which we showed on the previous slide in terms of reserves and resources. So we -- across our assets, really, we've got quite extensive multiyear drilling programs, particularly Magnus, PM8/Seligi and our nonoperated asset Golden Eagle. These will be -- they should see us kind of develop that 190 million barrels of reserves that I noted, but also could potentially access more of the resources that also sit behind it, which are present, don't have a kind of full development plan in place, and therefore, you're not allowed to recognize them as reserves as yet under the various regulations that we report against. So in Malaysia as well, we've got extensive , as I say, extensive drilling campaign, but there's also a huge gas opportunity out there. And at the moment, that gas is owned effectively by the regulator by PETRONAS. So we're in discussions with them as to how we can access that gas and produce it through our facilities. It sits effectively in the same reservoirs and would be produced through the same infrastructure as we currently operate. And therefore, we think there's an opportunity there for us to work with PETRONAS on a mutually beneficial basis to release that gas resource, but largely domestic use in the Malaysian Peninsular. And then at Kraken, while we've got some infill drilling opportunities, these will largely be backed up by some additional analysis that we're doing on the seismic. So this is where you take effectively a snapshot of the field's reservoir and all the different geological layers in there and what layers may be hydrocarbon bearing or oil bearing and which then are the best spots to drill a well in terms of extracting that resource. And so we did a huge seismic campaign about 18 months or so ago processing that data, takes time, frankly, particularly when you've got to amalgamate it with the history that we've got at the field as well and make sure we're understanding everything appropriately, but that should put us in a good place in the coming years to reinstate a drilling program at Kraken and extract additional reserves and resources there as well. So is that Golden Eagle, while we're not operator, there are multiyear well programs that we're discussing with the JV partnership, the joint venture partnership, there. Obviously, we believe we've got strong drilling capability. So we are working with the operator to share our experiences and expertise to see if we can optimize any future drilling program as we go forward. So while that -- those drilling programs and the kind of the organic portfolio, if you like, offers us opportunity really for kind of sustainable long-term levels of production at reasonable rates, the growth aspect, I suppose, is something that's also on our mind. And really that -- in terms of material growth, I think it's fair to say that's more likely to come through an M&A transaction. And as this slide sets out, we've got a good track record here of delivering really value-accretive M&A transactions across both the U.K. and in Malaysia. And really, we're focused there on what can we minimize our cash outflows on upfront. So try not to pay significant consideration for those assets, but then ensure that we get the quickest payback possible for whatever outflow that we actually have to pay in terms of the deal. Now there may be other transactional structures around this like at Magnus, where we brought the first 25% for nothing and keep all the cash flows and the next 75% interest, we paid $100 million for, and we share some of the future profits with BP, the previous into that to kind of ensure that both parties received good value for that investment. So that's that $100 million that we invested in Magnus, that paid back in less than 12 months. And similarly, in Malaysia, we invested a very small amount upfront. Clearly, the cash flows there are slightly reduced from the nature of the contracting structure that you have in Malaysia, which is called a production sharing contract. And so we share the revenues and profits with the host government more so than you do in the U.K. in terms of a tax and royalty kind of rating, but still, we managed to achieve payback well within 12 months there as well. And our most recent acquisition at Golden Eagle, we paid significant sum of money out, which I know a lot of shareholders followed that in terms of the placing an open offer that we put out through in terms of equity base. So we thank everyone for their support for that, but from a cash perspective, it's already paid back that initial cash outflow of $250 million as well. So we've got a strong stable base of opportunities, and we've got a significant kind of track record of delivery on M&A. But it's not just upstream kind of capabilities around drilling and operational uptime, et cetera, that helps us drive value. The decommissioning business that I mentioned earlier, come under first strand of the business, is also a very important area of our capability offering. So here, our ability to manage and execute large-scale decommissioning projects, which is what it is in the U.K., particularly with the size and scale of the infrastructure that's installed. This capability effectively means we can mitigate our future cost exposure because you're probably seeing on our balance sheet, and we've got sort of $700 million of decommissioning obligation to pay over the next 20 years or so. So it's not insignificant sums of money that we're managing there. So anything we can do to make that more efficient is clearly good news from a cash perspective, but also, as we do more of this decommissioning, more and more participants, particularly in the U.K. North Sea, would be looking for others to manage that decommissioning project on their behalf. And so this could well become a very strong underpin to any M&A transaction that we do, where we could demonstrate the value we can drive through effective management of decommissioning on behalf of others to ensure that people pass off the assets in good time. We enjoy some of the cash flows as we run them for late-life asset management as we do in our current upstream business, and then we take them into a smooth and well-planned decommissioning phase. I mean, last year, we did -- we really started to, I suppose, demonstrate how good we could be in this arena. We delivered the largest multi-asset well campaign in the Northern North Sea. So this way you have to -- under regulations, you have to physically plug and abandon, so stop any hydrocarbons potentially flowing out, leaking out of those wells once you finished your economic kind of production from the reservoir, so we did 24 wells last year across the Heather and Thistle [indiscernible] all on time, on budget, et cetera. So that's a huge effort considering we kind of started looking at this only 24 months or so -- 36 months or so ago. A lot of that is to do [indiscernible] kind of similarities to our upstream drilling capability, use drilling rigs to kind of reverse the installation of all the pipe work and steel work down in the wellbores. And so we can apply that drilling capability and decommissioning similarly to how we do in the upstream business. And as you can see with the chart on the left, almost 50% of future decommissioning costs in the U.K. North Sea are estimated to be quite well plug and abandonment based. And so again, if we can drive efficiencies there, that's a huge win from a cost and NPV and cash flow standpoint. We also -- it's not just about the drilling. We do look at changing technologies and improvements in technologies and in terms of how we maybe cut sort of the platform, how we dismantle the platform, et cetera, and that will also help drive efficiencies in this cost pool as we go forward. So that's in that pink box there really of [ removals ] is a significant area, which you can drive further efficiencies and cost optimization. So clearly, we've got strong capability upstream and decommissioning, lots of efficiencies that we can drive and lots of what we feel are competitive advantages. Let's now look at infrastructure new energy where we similarly think we've got an advantaged position. So this slide, you can see a picture of the Sullom Voe Terminal there on the northern tip of the Shetland Islands. As I mentioned, this terminal is a really important part, both our upstream and our future new energy business. It was one of the largest terminal -- oil terminal in Europe and processed up to 1.5 million barrels of oil a day. Clearly, the U.K. North Sea production has come down generally, so it doesn't produce quite as much today, but it does still allow us to export our Magnus field oil production, and it also supports other U.K. North Sea participants, both on East of Shetland development and the West of Shetland oilfield developments that are still in process and have many, many years still to run particularly on the Western Shetland side. So you can see here, given there's a huge oil tanker on the right-hand side here on one of the jetties. This is a massive site, multiple storage tanks. It's already in an industrial zone in terms of regulatory landscape. It's got storage facilities. It's got pipeline networks, it's got power, et cetera, already instilled on the site. And really what we need to do here is, first, to support the long-term upstream business is rightsize the terminal and reduce kind of the capital and maintenance commitments of managing this site because clearly not all of it is used anymore given the throughput at the site. If we can sort of move to other decommissioning costs around by repurposing the site for some of the new energy business, so we could use some of the brownfield kind of platforms, if you like, the concrete bases and other elements, pipelines, et cetera, and not have to decommission in yet, then that can actually [ enter that ] the charge out, if you like, to the users of this terminal remains low and supports the economic life of oil production in the North Sea. And then clearly, that also allows us to develop some of the new energy opportunities that we see here. So we think having a stake and operating this site really puts us at an advantage to others who are looking at prosecuting new energy projects because a lot of those have got to go build areas or develop brownfield areas. And so having that industrial site already in our hands is a huge competitive advantage for us in the new energy space. And of course, as we progress this, we've been probably talking about new energy now as a business for, again, sort of 12 to 18 months or so, and it was a glid in the eye, if you like, just start. And now really, we're getting quite excited about 3 particular strands that we can see a good benefit to EnQuest and clearly, its investors as well. So these opportunities are laid out on the slide. You've probably heard some of these before, based on many of our recent presentations and market communications, but Carbon Capture Storage is a massive area of focus for many jurisdictions, but it was a big area of focus in the recent sort of treasury announcements around funding and so on. Clearly, we're looking at whether we can access any of that funding in this round or in later rounds, but at the same time, we're also looking at how we can make this commercial model work any time right without relying on other government funding, et cetera. And so within the CCS landscape, with the pipeline connections to offshore with the jetties that we have that you saw in that picture and with knowledge of offshore assets and reservoirs, we think we can effectively reverse flows and bring carbon CO2 into the terminal in liquid form, pump it out to the reservoir and then store it permanently in those reservoirs. And that's a significant volumes of carbon as well kind of up to 10 million tonnes per annum. I think the U.K. is looking at trying to prosecute 30 million tonnes or so per annum coming around by 2030. So we could be a significant player in the U.K. CCS landscape. We have applied the 2 offshore licenses to stall that carbon in areas that we know very well, they're co-located to some Eastern Shetland oil fields close to the Magnus area effectively. And so we hope to hear about those awards in the coming weeks and months, and we can really sort of start -- kick start further developments in this area. Clearly, another project there is, given the scale of the sites connectivity is electrification, you may not be aware, but there's a huge amount of wind in the island in terms of wind power being developed, both on the island and offshore Shetland. It is a very, very windy place. So rest assured, I have been there and I can verify that. And with that wind power, we believe we could effectively install an aggregated system on the terminal that then provides access to the U.K. main grid, but also could provide wired connection to offshore installations, particularly Western Shetland fields to ensure that they can be electrified and therefore, have a lower carbon footprint in terms of how they are run and managed. And clearly, that's an area that the U.K. government and the Scottish government are very keen to ensure that we decarbonize our existing industries as well as future industries. So I mean, that's something that we're looking to prosecute as well from the terminal. And then the third one, which is probably a little bit more longer dated in fairness is the potential production of green hydrogen or other associated derivatives. Again, you've got the wind resource there. Not all of it will be required or could even get into the U.K. main infrastructure in terms of the capacity available for bringing electricity in. There's a much bigger multi-gigawatt development happening offshore Shetland's. And so to monetize that as early as possible, we may be able to install electrolyzers again on the site that we have already developed green hydrogen that can then either be further processed into other derivatives or be distributed either by the jetties, et cetera, and shipped off to other locations or we needed to [indiscernible] other connectivity through pipelines, et cetera, as well. So lots of opportunity in infrastructure and new energy space really anchored in that strong hold in position in the Sullom Voe Terminal. And you may be thinking, well, that all sounds like a lot of money to invest for us as shareholders. Fundamentally, the projects are expensive, but we're looking to prosecute these effectively as low cost as possible. So we're not spending more than a couple of million dollars really a year at the moment where we do the studies and build-out the understanding of how these projects could work and what we look to do is bring in partners at the right point in time who then contribute the physical cash, if you like, to develop these opportunities. We're effectively offering up a ready-made or nearly ready-made sites that need some repurposing as our kind of equity into new energy projects as we go forward. So looking to see this in a very low-cost manner as well. You're probably listened to me enough now, so it's best to get another voice on the presentation. So -- but just before I hand over, we really believe we've got a unique business model. We have some strong capabilities that go right throughout the -- that transition landscape, whether it's upstream, infrastructure, new energy or decommissioning. And we believe we can be an important player in adjusting very sustainable kind of energy future, managing the needs of today's energy requirements by developing oil and gas and then developing lower carbon [indiscernible] in the future. So with that, I will now hand you over to Craig.

Thank you, Ian, and good afternoon, ladies and gentlemen. So turning first to production in terms of our 2022 performance. We delivered a strong performance during the year with the 2022 figure of 47,259 barrels of oil per day, representing just over 6% increase versus 2021, And that also represents delivery at the midpoint of our full year guidance range. In general, as Ian kind of alluded to strong uptime has been a feature across the portfolio, including the continuation of top quartile production efficiency at Kraken. And again, Ian has touched on it, but it is worth repeating that the 93% production efficiency achieved there is around 20% higher than the UKCS average for a floating hub such as Kraken. At Magnus and in Malaysia, well programs during the year represented low cost production enhancement scopes and we have benefited from a full year of production following the October 2021 completion of the acquisition of the Golden Eagle asset. So if we can turn to Slide 12, please. So if we take it beyond production, we delivered a very strong performance relative to our other key guidance indicators for the year. The group's operating expenditure of $396 million was lower than we guided, primarily reflecting strong cost discipline in the face of inflationary pressure. And we also benefited from a weakness in Sterling. It's worth noting that our OpEx cost base is 70% denominated in Sterling. So obviously, the weakening of the pound did benefit us in terms of our reported dollar currency. In terms of decommissioning expenditure, that was driven by the extensive well program that Ian mentioned, Heather and Thistle, where we delivered those 24 wells that was 13 at Heather, 11 at Thistle, which was obviously a very, very productive campaign. And we also optimized our capital expenditure program by focusing on quick payback well work opportunities, both Magnus and PM8/Seligi in Malaysia. A really good example of this was the A6 well at Magnus, so this was already -- this was originally earmarked as an infill drilling target, but we were able to be quite innovative, and we implemented a perforation campaign rather than infill drilling which delivered similar incremental barrels at a fraction of the cost. So these are the sort of things I think EnQuest has been really good at over its history, and that's obviously something we continue to target at these assets in terms of inorganic -- sorry, in terms of organic opportunities. Turning to Slide 13. So basically, the results of these efforts that I've just outlined can be shown most clearly in the reduction of our net debt. So the chart on the left-hand side that we're looking at here shows the pace and quantum of our deleveraging with net debt reduced by 41% during 2022. Our leverage ratio has declined from 1.6x to 0.7x over the year representing really good progress towards our stated leverage target of 0.5x net debt to EBITDA. Our focus on deleveraging has continued into 2023, and our net debt position at the end of February was further reduced to around $624 million. It's particularly noteworthy, and I'll discuss why, but it's particularly noteworthy, we have now reduced the cash drawings under our reserve-based lending facility to $282 million versus the original commitment that was agreed in October of $500 million. Another major undertaking for the company during 2022 involved exploration of a variety of options to refinance the group's capital structure. In October last year, we successfully delivered a comprehensive refinancing, involving a reduction in our gross borrowings and extension of the maturity of our RBL and U.S. high-yield bonds out to 2027. This was a really big piece of work for EnQuest, and it was a significant achievement given the volatile backdrop in all financial markets last year. In accordance with our hedging policy and in line with RBL requirements, we've also optimized our hedging program in recent months, and it now involves a significant use of put options, which is something that Salman Malik, our CFO, alluded to you at the half year. This protects cash flows while providing reasonable exposure to higher oil prices. And it's worth noting that the cost of premiums is an allowable expenditure to be offset against EPL. For 2023, we've hedged 7.9 million barrels predominantly through a combination of puts and costless collars, 4.6 million barrels are hedged through puts at an average price -- average floor price, I say, of $60 per barrel with the remaining 3.3 million barrels being hedged through costless collars at an average floor of $56 per barrel and an average ceiling price of $75 per barrel. For 2024, we are purely utilizing puts at this stage. And those -- we've done 3.2 million barrels and average floor prices around $60 per barrel. Turning to Slide 14. I I'd like to take a few moments here to cover the energy profits levy and the impact it's had on our business. So as most people on the call will be aware, the introduction of the NG products levy in May '22 and then the subsequent amendment and extension in November to, I guess, what we would call EPL 2.0 has drastically changed the U.K. fiscal landscape for companies such as EnQuest. And it's fair to say that over the intervening months, we've endeavored to engage government and discussion, both directly and through our association with industry bodies, about the consequences of this levy. The levy has a number of unintended consequences to the industry, generating several challenges, but also some opportunities, which I'll look to describe to you today. In terms of the challenges, so essentially, the levy takes money out of the system, the extension and the increase in the EPL and the absence of a price floor at which the levy would cease to be applied results in borrowing bases across the sector being reduced by 40% to 60%, and our RBL was not immune to that. We repaid $118 million of the RBL in the first quarter of this year following redetermination, and that brought the outstanding RBL balance to $282 million and within the available capacity. The next redetermination is scheduled for June of this year. Despite the challenges, the changes in the EPL regime also, believe it or not, create some opportunity for EnQuest, which is obviously an important for us to focus on. As you can see from the bar chart at the bottom of this slide, our relative tax advantage has increased from 66% to 160% relative to a full taxpayer. What effectively this means is that cash flow from assets is now worth 260% in our hands relative to a company with no tax losses who are full U.K. taxpayer. This relative advantage, along with our core capabilities, support our ambitions to pursue accretive M&A opportunities and enhances our ability to bring our tax losses to bear and create win-win outcomes in structured negotiations. Secondly, the enhancement of the tax incentives associated with decarbonization expenditure could also support our plans to repurpose the Sullom Voe Terminal into one of the largest new energy hubs in Europe. The primary way this could be achieved is it creates a large incentive for full tax paying strategic and financial partners. So as Ian laid out, EnQuest is going to continue to spend low single-digit millions as we prosecute the opportunities at Sullom Voe, but some of the beneficiaries who will probably become clients and partners are full taxpayers. So for every [ GBP ] 100 that they were to spend in such an endeavor that would reduce basically decarbonization investment, they would be able to offset $109. So it's 109% enhanced allowance. I can move on now, Ian thanks, to Slide 15. So I'd like to conclude by discussing our guidance for 2023. So we expect production to be between 42,000 barrels of oil per day and 46,000 barrels per day, including the drilling campaigns that we've got planned at both Magnus and at Golden Eagle. Operating expenditure is expected to be approximately $425 million, with the increase versus 2022, largely reflecting specific areas of inflation such as resourcing costs as well as the phasing of activities. Cash capital expenditure is expected to be around $160 million for the year. We've looked to optimize CapEx in light of the EPL. It's been a real focus area for the company and management. Accordingly, we do plan to execute the 3-well drilling campaign at Magnus, where we have a great track record of delivering quick paybacks as well as a platform drilling campaign that's planned at Golden Eagle. As we've previously announced, we have deferred Kraken's Western Flank drilling, but we utilize the additional time we now have to complete seismic interpretation work in order to identify the best well target locations in the flank. Decommissioning expenditure is expected to total approximately $60 million, primarily reflecting ongoing well campaign at both Heather and Thistle as well as preparatory work in advance of future subsea decommissioning at the Dons, at [indiscernible] and also at [indiscernible]. I'll now pass back to Ian to summarize and conclude.

Thanks, Craig. Just a couple of more slides to go before we get to the Q&A. So this -- you'll probably be familiar with, if you've looked at any of our materials in the last couple of presentations that the group has made a half year full year. So this is our CFO, Salman Malik's priorities. As Craig outlined, we made good progress on a number of these already during 2022. So the first one, particularly in terms of resetting the capital structure, and that significant refinancing that we did back -- throughout 2022, really across a number of our debt instruments, improving their maturity profiles, et cetera, was a great achievement. We also hugely deleveraged the balance sheet to be significantly reduced the amount of gross debt as well and we'll continue to focus on that going forward. I think it's very important in -- particularly in volatile credit markets and what you've seen that Craig outlined with the impact of EPL on reserve-based lending facilities, et cetera, across the sector. We need to reduce debt as much as possible and ensure that we're kind of masters of our own destiny somewhat. So deleveraging will continue to form a core part of our focus for the coming years. Thirdly, we talked about it a lot, cost discipline, optimizing the capital program, that's all around making sure that we do things as efficiently as possible and spend money in the right areas to drive value, whether that's drilling or operating costs, ensuring strong uptimes, et cetera. And we also want to pursue the accretive M&A landscape, which, again, we believe we're advantaged in. Similarly, the energy transition landscape is moving around us, and we think we've got a very strong position there with our Sullom Voe Terminal. So we'll continue to work hard on those dual track growth options. And then last but not certainly not least, it's very much within management's thinking around getting to a point at which we can start to provide shareholder returns. Clearly, it's going to be post some additional deleveraging, particularly this year with some of the amortizations that we've got both in the RBL and our old retail bond that we have to repay in October of this year. So we've got a more cash outflow, shall we say, in 2023, but we would anticipate from 2024 and beyond, we'll be in a stronger position at which we can start to develop a shareholder return element to our capital allocation framework. So just very quickly, we've said all of this before. I'm not going to read every box on there, but we think our capabilities set us apart from our peers. We've proven this over many years. Craig outlined the extensive work program that we've got this year. And within the business model, we remained focused on operational excellence in upstream to deliver the cash flows and drive that deleveraging. We're also going to look to prosecute the [ I& ]E opportunities and particularly looking forward to the outcome of the Garden capture storage license application that we made. And then indeed, commissioning, we've got another extensive program to prosecute and just further embed our capability there improved to others that we could be a great decommissioning partner going forward. So with that very brief summary, I'd just like to thank you for listening. And now I'll turn over to provide the audience with their opportunity to ask us some questions. So I think I'll hand back to the operator.

Ian, Craig, that's great and thank you much indeed for your presentation this afternoon. If I may, I will just bring back up your cameras now. [Operator Instructions]. But just while the team take a few moments to review those questions that were submitted already. I would like to remind you that a recording of this presentation, along with a copy of the slides and the published Q&A can be accessed via your investor dashboard. Ian, Craig, we did receive a number of pre-submitted questions ahead of today's event. And as you can see there in the Q&A tab, we've also received a number of questions throughout your presentation this afternoon as well. So firstly, thank you to all of those on the call for taking the time to submit their questions. But guys, perhaps if we may start with the pre-submitted ones and then we'll look to take those that have come in during the presentation. The first question that we have here reads as follows; Following the amendments to the RBL, is the accordion feature still available for acquisitions?

Yes, the answer to that simply is yes, it's available. Clearly, we need to get lender consent and they do their own kind of valuation because it's there really for future acquisitions, if you like, as a pot of money that we could go after. And so clearly, the banks would want to look at the value of what those assets are and does it support them lending us more money. If it does, then we could access that accordion facility according.

The next question that we have here reads as follows; What is the value of SVT on the balance sheet?

Yes, it's a good question because we talk about the value that, that offers to the business. From an accounting perspective, it's de minimis. I mean, effectively, it's been written off given its age, first in production in the 1980s. And so there's no sort of balance sheet value, shall we say, that subscribed to it under accounting rules, but it's effectively a cost pool at the moment, whereby any operating costs or capital expenditures are then shared amongst the users of that terminal. Going forward, we think it's got significant value because it would cost significant sums of money to develop a new brownfield area on which to prosecute new energy opportunities. And so that's really in our mind what the value is, but as a balance sheet angle, it is not in our fixed assets as it were as a valuation.

Perfect. The next question that we have here talks to free cash flow and reads; Are you able to provide any guidance as to likely free cash flow for '23 and '24 on the assumption that Brent remains around current prices?

Yes. I'm happy to take that one. Thank you, Jake. So unfortunately, we're unable to provide anything that could be construed as a profit forecast in this forum, but for 2023, we have provided significant guidance on the key component elements of this calculation. So if I take you through those, that might help. So we have production guidance of between 42,000 and 46,000 barrels of oil per day. We have OpEx of circa $425 million, CapEx of circa $160 million and decommissioning expenditure of circa $60 million. We've also got a couple of other cash outflows that we've talked about previously. So we've got the Golden Eagle contingent consideration of $50 million that's payable this summer. We have the stub on the GBP 7% retail bond, which is circa $135 million due in October of 2023. And as part of the Magnus profit share mechanism, we are due to pay within the accounts, we've stated we're due to pay somewhere in the region of $80 million, sorry, to BP versus $46 million that we paid last year. And we'll also have an EPL payment, which relates to 7 months of 2022 taxable profit. So that's from when the date of the original EPL coming in, in May 2022. And the total estimate is -- there's a number of estimates out there, but our sort of consensus, our broker consensus around $70 million which is around half, which was paid in December '22. So if you take those component parts and to employ your view on oil price for the year, then you should be able to arrive at a senseful estimate for free cash flow and I would say as well, on the EPL, it's our status as holding historic tax losses, which means we pay 1 payment effectively in arrears for EPL.

The next question that we have here that was pre-submitted asks; Do you expect to be able to leverage EnQuest's large tax losses in 2023 or 2024, sorry? And if so, can you provide any guidance as to how this might be done?

Yes. I'll take that one as well. So yes is the answer. We utilize around $500 million of our tax losses to offset corporation tax and the supplementary charge in 2022. I would expect to offset any CT and [ SCT ] due in 2023 and 2024 on our existing business at current prices. We would expect that to continue well into tail end of this decade. Looking forward, we see our tax losses as a key enabler for U.K.-based M&A. Our tax loss are currently in the region of $2.5 billion and we have the potential to access a further circa $1 billion through Bressay entity, which houses Bentley. And that's for the future, but it's something we could access as the project develops. These tax losses provide us with a, we believe, a competitive advantage in terms of negotiating any acquisition, and we'd be able to structure any deal to be win-win for both EnQuest and for the seller. The tax advantage created by these tax losses was previously 66%. As I noted, as we retained 100% of cash flows while full taxpayers retained only 60%, but now having seen the EPL come in, and that relative advantage increased where we now retain 65% cash flows, whereas a full taxpayer would retain on a simple basis, 25%. So to be honest, this reality is what's causing some of our peers to consider departing the UKCS, and that will ultimately result in less competition for us in terms of acquisitions. It's probably worth noting that amongst our peers only Ithaca and Equinor are the only ones that have sort of any significant tax losses that would be in the relevance of ours.

And perhaps a couple of final questions here that were pre-submitted. Why has the decision not been made on EnQuest Producer?

I'll take that -- sorry, Ian. So essentially, the EnQuest Producer is still a valuable asset to the company and it's valuable in that it retains optionality for repurposing, it could be used in 3 ways I can think of. It could be repurposed in the future EnQuest development such as an early production facility on Bressay as one technical option. It could be sold to another entity for cash or it could even potentially be used as an equity offering in any external development. So it's a very highly spec-ed piece of kit, if you like, it's got tremendously impressive sort of power generation, and it's an asset that's working very well. So with relatively minor modes, it could be useful in a number of different [indiscernible]. So what we feel is that keeping the vessel warm stack at the Nigg Energy Park as it is right now, it's a really inexpensive way to retain this optionality, and it's a cost in the low single-digit millions per year, circa $3 million a year.

Perfect. And perhaps the final pre-submitted question. What percentage of future free cash flow will be allocated to share buybacks. What percentage to dividends?

Sure, I'll pick that one. So right now, this is a question actually that a number of you have asked as I scroll down the question, so forgive me, I'll try and answer all of them in one go. But effectively at the moment, this would be a board decision as to the dividend policy. That process has not yet happened, but we are driving very much towards from 2024 onwards, we'd like to be paying a dividend. So the actual construct has not yet been decided and may well vary over time between is it a fixed dividend? Is it a percentage of cash flow? Is it buybacks? What kind of methodology may be used? And some of that will be predicated on our views of our position at a point in time, some of the future, some on the relative value merits to our investors of those, clearly, if we felt the share price was significantly undervalued at a point in time, it may be more beneficial to do buybacks along those lines rather than a stable steady dividend, hence per share type thing. So yes, apologies. No firm news exactly on how that will make, but it's definitely part of the work stream over the coming months or so for us to really try and articulate internally what we think it could look like. And then obviously, we'd have to go to the board -- EnQuest Board to a formal approval. And then hopefully, in due course, we'll be able to announce something a bit more fulsome on that.

Perfect. And as you can see there in the Q&A, I know you've just been having a quick scroll, but perhaps if I may, just hand back to you just to address any of those and where it's appropriate to do so and perhaps in some instances hand it back over to Craig, but if I may, just hand it back to you just to address those, and then I'll pick up from you at the end.

No problem at all. There's a number of questions come in, which is great. So thank you very much, everyone, for your time on this. The first one, Craig, it's a 2-part question, but perhaps, Craig, if I could ask you to answer the first bit, and then I'll take the second. So I'll do it in -- I'll read it out in 2 sections. So this is from Frank. What are you doing to correct the public's misconception that their payments of higher electricity and gas bills are a direct gift in their minds to fact cap operators of oil and gas production facilities in the North Sea? It means that all political parties have nothing to distribute the public of or even a tax specialists like Dan needle, who talks about GBP 5 billion of oil and gas revenue under the previous EPL structure, having escaped.

Okay. Thanks, Frank, for the question. And I think it's no exaggeration to say that this has been a huge impact on Ian's and my ear, which is understandable given the sort of seismic nature of the change that EPL has brought. So essentially, what we have done is we've been extremely active both as a direct entity. So we have sought contact with individual ministers. We've contacted treasury. We've written a number of letters putting forward the case for a number of advocating a number of changes to the EPL, but the most, I guess, the most pertinent of which would be the inclusion of a price floor, which we see as a real necessity in order to get people back to business in terms of investing in the North Sea. And we've also been active participants with some of the industry bodies such as Britain [ DEC ], such as OEUK, where we've been cosignatory and representatives and being full participants in all of their communications. I think sometimes it's been -- some of our peers in the U.K. have been a little bit more vocal about their participation, but I can assure everyone on the call that the EnQuest has had a place at that table and has been a full participant. So we've made a lot of representations. I think like many on the call. I think it's probably fair to say that we've also heard some of the indications and leaks and whispers that a price floor is being discussed at government. We're not in a position to verify that, but we've certainly heard those same [ weeks ], if you like. I think the government has trailed it they haven't quite been able to cross the line and put it into play, recognizing it probably is a little bit of a political hot topic, but we are -- we do remain hopeful that sort of sense prevails and a price floor is implemented.

Thanks, Craig. Perhaps just before I jump on the next one, there was a number of questions around EPL and you have answered them. The majority of them there, I would say. Just another one further down the list that talks about the potential for -- this is from Tom. So the potential for, if the Labor Party came into power and they were able to prosecute retrospective taxes or bring in retrospective taxes, are we able to take any action against that? How are we preparing for kind of a labor government, I suppose, or changes to the tax regime in general?

I mean, I'd probably prefer to be more general, if I may, in terms of -- I think what the EPL has done at its core is it's taken the U.K. from being probably the most stable fiscal regime in the world and made it appear very unstable. And our sector has suffered from that instability, i.e. can confirm, obviously, we have discussions around what could come next, EPL, both a price floor coming in, which should be a positive versus some of the rhetoric that has been espoused by the Labor Party around potentially removing some of the enhanced allowances, such as the CapEx and decarbonization allowance that we've discussed on this call today. And we have to be prepared for all eventualities. Obviously, any retrospective application would be extremely unwelcome and we would do everything we could in our power and our collective power as an industry to ward that off. But even looking forward, we have to be prepared that EPL is around for the long term and potentially could be enhanced from the view of the government in terms of its scope. So we are preparing for all eventualities, but it would probably be premature to comment at this stage in terms of what that would actually look like.

Thanks, Craig. I think that's fair. And obviously, we would hope that we would continue to have the tax loss position that enables us to still enjoy that advantage of owning assets in terms of cash flow protection that we can offer versus other operators in the basin, which could give us a chance to grow the business even further as Craig outlined in the presentation earlier. I think that's probably all the questions on EPL. Sorry, there was one more question from Frank that I'll come back to you now, which was around the board changes that we announced just last week, whether their decisions to step down from the board were linked to the lack of new energy skills. I mean, certainly, that's an element of it as we look to have a Board that can support the entire business model. We need to make sure we've got the right skill set at a board level, but similarly, it relates to sort of standard good practice from corporate governance, I would say, whereby certainly 2 of the directors who decided to step down over 6 years of their turn. And yes, that's the normal good practice is around 6 years you would step down. You can go to 9 years, but after 9 years, you consider to be actually not independent anymore. And so this felt like a good time with us kind of new Chairman on Board looking at how we can prosecute and support the business in the new energy landscape. So we'll be looking to bring successes in as quickly as possible to support that strategic delivery. I think, Frank, as you also had a question with many others on this call, I think Michael has his question and a couple of other individuals as well around when might that new energy business deliver cash flow and start to require perhaps more significant investment, I mean, I think it's fair to say in the very near term, it will be minimal cost output from us as we've talked about, this kind of few million dollars per annum to ensure we get our submissions in for various regulatory pieces that we might want to participate in prosecute studies, et cetera, around how we develop this, bring together sort of partnerships and so on. I'd say, in terms of cash generation is back half of this decade in the second half of the decade, some could come a bit earlier, just really depends on some of the regulatory frameworks and how they might evolve over time that you could see potentially carbon capture, for example, accelerating if the license applications are strong and then you can build the value chain and where are the emitters can you then get those emitters to capture the carbon and then get it onto ships, ship it to the terminal, et cetera, et cetera, we could look at how we can accelerate that. Similarly, electrification, if electricity effectively is available in good time, we may be able to assist with developing future sort of Western Shetland oil fields by providing with that electricity in a good time frame to [indiscernible] bring oil and gas production online, albeit in a lower carbon manner. But really, yes, it's not for the next couple of years, for sure. but we look to do what we can to bring that in as soon as possible. The next question is, again, from Michael S. So this is around revenue per barrel in Malaysia is lower than the North Sea. Is it due to the royalties or other arrangements in place and Craig if you like to pick that one up?

Yes. I think you kind of covered it in the presentation, and it's just simply a different regime. So the production sharing contract, PSC, effectively has a different mechanism Michael, which means that we share in this good cost recovery and effectively a new share in profit oil. So the way in which that flows through is slightly different and results in having a lower revenue per barrel metric for Malaysia.

Absolutely. Maybe the next one for you as well, Craig, if you don't mind, this is on debt instruments, so from Zander. Could you outline what debt instruments mature this year or '23 [indiscernible] '24 and what the position is of our RCF. I think that's the reserve-based lending [indiscernible] revolving credit facility.

Sure, absolutely. Thanks, Andre, for the question. So essentially, we do have a maturity this year, which is the 7% Sterling retail bond, and we have GBP 111 million of a [ stub ] which is due in the middle of October this year, which is around $135 million. And in terms of the RBL, I think as I've outlined in the presentation, so to sort of walk you through the journey of this. So we started off with a borrowing base in the Q4 or so last year of about $630-plus million and we agreed a commitment level of $500 million for the RBL. On day one of the RBL, we only chose to draw $400 million of it and haven't subsequently drawn. As part of a scheduled redetermination process, which happens twice a year, but of course, the first one, we were one of the first in the industry to go through the reader determination post EPL 2.0 and as part of that, that effectively has reduced the borrowing base. And the main reason for that, I think most people, hopefully, on the call would understand the rationale for the borrowing base to drop is that the banks employ a much more cautious and conservative view of oil prices and then the risks prices. So they're operating in quite a low-price deck. And when EPL first came about [indiscernible], who at the time was the chancellor, noted that there would likely be a price at which anything below that oil price, the levy would cease to exist. That was specifically removed as part of EPL 2.0. So what it means is that in the banking models where prices are in the low 50s, and they are still applying the 35% EPL tax effectively. So across the board, borrowing bases in the sector have been reduced. Ours is no different and as a result, we've paid $118 million in the first quarter of the year to take our outstanding amount to $282 million, which is within the redetermined capacity. Hopefully, that answers the question.

Thank you, Craig. Thank you. Perhaps give you a slight rest and we'll share some of this question. This is around the Kraken field and Bressay and Bentley fields. So there's a question from [indiscernible]. Broken down into a few parts. So I suppose first part for yourself, Craig, perhaps, what are the future prospects vis-a-vis the Kraken field?

Yes. So in terms of Kraken, so we do still intend to drill in the Western flank, to the Western sand, which is just obviously, as I said, in the [indiscernible] the west of the main field. And I think as [indiscernible] and I alluded to, we are in possession of and we are currently working for interpretation of seismic data, which will allow us to really zoom in on the best prospects in which to drill in those areas. So in essence, the deferral of drilling kind of buys us some time to be a bit more exact in our targeting. And we hope to get back to drilling that in the next couple of years. And I think that the most likely option there is that we probably need a new drill center, which effectively is a subsurface piece of kit, which allows you to connect both producer and injector payer, and that would then be connected back to the FPSO. So that's the most likely outcome for crack in the next couple of years.

Thanks, Craig. And then linked to that, I'll just pick this next one up, so you maybe you can maybe take a glass of water, if you want. But the question again, continued from him is the leased FPSO is due to expire in 2025. What are the plans thereafter? Well, effectively, you're right, the main charter lease has an expiration date in 2025, but it has an automatic annual rollover clause in it. So effectively, it just keeps running on an annual basis until the field stops. And the upside of that is we don't really have to do anything to worry about the asset disappearing and also the cost associated with the lease dropped by 2/3 at that point as well because effectively, the lessor, who we've taken the boat from has made their returns, if you like, that they required under their initial investment by 2025. And so from this April 2025, the rate dropped by about 2/3. We have an annual rolling contract thereafter and effectively canceled or behest when the field is no longer economic. Now we do have another option whereby we could purchase the FPSO and then effectively on that and does that then lead itself to other future potential repurposing opportunities, other development opportunities, et cetera, in time. That's something we'll continue to explore as we move forward, but effectively, no risk to production benefits on cost and optionality around future purchase of the asset as well for ourselves. Craig, if you don't mind a couple of questions then on Bressay and Bentley as well, one from [ Hema ], which is what are the prospects that Bressay and Bentley [indiscernible] infrastructure at Kraken and then a further linked question from Michael S. around the exit of Harbor and Equinor from the licenses there late last year, is there a realistic chance of progressing to FID under the current EPL structure?

Okay. Thank you for the questions. So in terms of where those projects stand. So Bressay is definitely on the slate first in the time line for us and Bentley would follow. And while Harbor and Equinor have bowed out. And I would say in speaking to my colleagues from commercial did it in a very sort of gentlemanly way, if you like, because they simply weren't going to -- they didn't want to be blockers to the development, but what it means essentially is that the EnQuest needs to bring in a partner. It's not a development that we would take on as a sole risk opportunity. So that's one stream that's working and that is working in the background in terms of still an attractive opportunity. The other key thing to note within Michael's question, it refers to the impact of EPL and whether that affects the likelihood of progressing to FID. I would say it probably does Bressay, I would say, it increases it because what you're going to see is you're going to see that a full tax paying entity is going to get a huge amount of allowance effectively back from the EPL. So it makes any economics on a decision whether or not to invest in a development opportunity like Bressay. It makes those slightly easier effecting a full taxpayer from memory, I think it's about 91 pints in the pounds back for such an investment. So we're fairly confident that we can attract the right partner in order to work with us in that. I think the original question from [ Himax ] was more nuanced towards how do those potential developments link with Kraken. And I think it's probably at this stage, probably to prematurity to say because we haven't agreed a development concept. One option would be to utilize the [ ingress ] producer that we discussed earlier on as an early production system -- and then as the development were to be enhanced with future drilling, et cetera, you would have to look for a more permanent solution with the tieback to Kraken being again a potential auction. Kraken has proved itself as a vessel whose very well equipped to deal with heavy oil coming on board. So it does have its own advantages, but I think at the moment, it's probably a bit premature to say precisely how those technical solutions are going to find their feet. And again, that would also depend on agreement and alignment with any partner coming into the entity.

Thanks, Craig. Very fulsome. I appreciate that. We'll skip through down a couple of questions as they've already been answered around EPL and dividends, et cetera. So the next one, which I'll pick up is around SVT ownership and shareholders. So what's the percentage kind of make up there. So effectively, this is from Ronald. Thanks for your question, Ronald. We own, if you like, in terms of equity, probably about, I think, 15% of the terminal as it stands today in terms of kind of the upstream processing plants and so on and so forth. We probably pay costs in the 20-odd percent range because that's the throughput effectively. We've got the highest throughput at the terminal of all those who come in, they're 11 owners in total of the Sullom Voe terminal. And the way it works effectively is we kind of collectively lease the land that that's on from the Shetland Islands Council. And obviously, we have the infrastructure in play there and that the cost, as I said earlier, is shared amongst those owners based on the utilization. When we look at the new energy piece, what we've done is secure exclusivity with the Shetland Islands Council to be the only owner operator, if you like, of the land, the site, on their behalf to aggregate new energy opportunities there. So as we decommission certain parts, which the partnership as it stands today, effectively share the costs open and so on. We then -- we would then effectively have the rights to that piece of land to then build with other strategic partners the new energy infrastructure that's needed on site. So it's a slightly evolving landscape. There's the existing upstream ownership structure, and then there's the kind of future new energies piece, which we are effectively so controlling owners of, which is a great position to be in, obviously, not having to go through multiple committees and companies to get approval for various courses of action. Moving on down then. Again, lots of dividends, which we've answered. Question from Craig M. I'll pick this one up. Have EnQuest considered entering a more stable fiscal regime, for example, Norway? Yes, I mean we've actually -- in history, we've been involved in a number of different regimes saying whether that were actually in Norway for a short period, and we've been in North Africa as well as obviously having our operations in Malaysia and the U.K. So we're not immune to looking elsewhere and operating elsewhere. Clearly, I think our first point of call in terms of M&A and future developments would be U.K. for the fiscal advantage that Craig actually outlined. So while it may seem unstable, our relative tax loss position creates a value opportunity for us to prosecute in that environment. And obviously, we would like to accelerate the use of those tax losses as quickly as possible because that's real value, if you like, that we can extract very quickly, and we're doing that obviously already with the Golden Eagle asset. It doesn't mean we wouldn't look at other areas. Obviously, we've got our step-out in Malaysia already, and we have strong relationships there with the regulators and others. And so in terms of M&A, we would look at opportunities around that kind of Southeast Asian basin, but if the right opportunity comes up, we would look at other basins, I mean we go to our formal kind of new country entry assessments around fiscal, political risk, health and safety of people in structured commercial arrangements, et cetera. There's an extensive process, shall we say, that we go for. But certainly, first call is that let's make the most of our advances in the U.K. probably Southeast Asia is a kind of second area, just given our knowledge of that part of the world and then others may follow if they're the right value proposition. Next question from Ronald S. There's only a couple more questions to go. Any idea when the results of the 33rd licensing rounds and on release. I must admit, I don't know the answer to that question. Craig, if you do know, shaking your head, so we'll try and get back to you on that one, Ronald and see if there's a specific date. I mean I don't believe we participated extensively in that round anyway. So hence, the slight acknowledge there, so apologies. Question from [indiscernible] on the what oil price to the banks use [indiscernible] is our lender banks? I'll quickly pick that one up as well. So effectively, they use a discount from the current price as its own pace. They're probably in the mid-60s for kind of the short term. And then declines quite quickly into the sort of high 50s, low 50s thereafter in terms of a long-term pricing model. So they're very much on the conservative side, shall we say, against forward curves, which you'd understand as credit investor looking to ensure they get their cash back in good course. So they are significantly below the current market prices and current forward curves. And that links back to the point some of you have made any questions that Craig outlined earlier around a price floor and how would that help well if the price floor was at a point of which the banking prices fell below it. Therefore, there's no EPL. Therefore, the value of your reserves are higher. Therefore, they could lend more money. And so the borrowing base of people's reserve base lending facilities could increase. So it would be helpful to get that price floor in place at a reasonable level in going forward. And then the very last question before I'll pass back to Jake our operator again today. This is from Stefan B. Thank you for this question. Is there an interest in bidding on EnQuest in view of your tax loss deductions? How do you feel about being bought out or a merger? Amjad and Salman have been asked this question before in the investor road shows and the various presentations and so on. And we absolutely do what's right for the shareholders. So if it was the right value proposition and someone came in with an offer, then we would have to consider it, take it to the Board review alternatives. And is that the best value than if it was considered to be the best value for our shareholders, then there is certainly no qualms about prosecuting that sort of transaction because it would be the right thing to do for all of you and future investors. So absolutely, we don't have any concerns about it. I can't say whether anyone is or isn't bidding on us because that's -- that would all be confidential in the disclosure at various points in time under regulatory requirements, but certainly, we would have to consider all bids in that regard, and it's a value proposition at the end of the day. So with that, thank you very much. I'll just pass you back quickly to Jake.

Ian, Craig, thank you very much indeed for being so generous of your time there and addressing all of those questions that came in from investors this afternoon. And of course, if there are any further questions that do come through, we'll make these available to you immediately after the presentation has ended. Just for you to review, to then add any additional responses, of course, where it's appropriate to do so. We'll publish all those responses out on the Investor Meet Company platform. But Ian, just before really looking to redirect those on the call to provide you their feedback, which I know is particularly important to yourself and the company. If I could please just ask you for a few closing comments to wrap up with, that would be great.

Sure. Thank you very much. And yet just really a big thank you to everyone who joined us today. I appreciate you taking the time out of your schedules to raise some really useful and engaging discussion points for us. As we say, we think EnQuest is well positioned to play its part in a just and sustainable transition with strong capability in upstream, [indiscernible] and in the future new energies. So look forward to further prosecute in that strategy successfully. To the point Jake just made, if any of you do have other follow-up questions that you'd rather post directly to us. There's some contact details on this slide. Any one of those 4 e-mail addresses will eventually make its way to Craig and I, so we can respond in due course. But thank you once again for your time, and thanks to taking investor meet for hosting us today.

Ian, thank you very much. And Craig, as well, thank you very much indeed for updating investors this afternoon. Could I please ask investors not to close this session as you'll now be automatically redirected for the opportunity to provide your feedback in order that the management team can better understand your views and expectations. I just want to take a few moments to complete, but I'm sure will be greatly valued by the company. On behalf of the management team of EnQuest plc, we would like to thank you for attending today's presentation. That now concludes today's session. So good afternoon. See you all.