EnQuest PLC (3EQ.F) Earnings Call Transcript

Good morning, ladies and gentlemen, and welcome to the EnQuest plc 2025 Full Year Results Presentation. [Operator Instructions] Before we begin, we'd like to submit the following poll, and I'm sure the company will be most grateful for your participation. I'd now like to hand over to the management team from EnQuest, Amjad. Good morning.

Thank you very much, Mark, and good morning, ladies and gentlemen, and welcome to our 2025 Annual results presentation. I thank you very much for taking the time to join us today. My name is Amjad Bseisu. I am the Chief Executive Officer of EnQuest. Joining me today is our Chief Financial Officer, Jonathan Copus; as well as Ian McKimmie, our North Sea General Manager. Jonathan and Ian, alongside colleagues across our international business now, continue to provide great leadership as we drive EnQuest forward together. The world around us truly is defined by volatility, but even more so in the last 4 weeks, but EnQuest stands out for our consistent operational delivery, highly tangible reserve base, disciplined investment and a strategy anchored on diversified growth. I want to start by taking you to look at the fundamentals, which underpin our business. We have a growing reserve and resource base across our expanding operating footprint, combined with the 2P 2C volumes, which are up 18% in 2025 versus 2024. We have made 3 country entries in our business development in the last year, production in Vietnam, a development in Brunei, joint venture with the government as well as upside on appraisal and exploration with the Tangguh Alliance led by BP in Indonesia. However, our 2P reserves are also very highly tangible with 78% of our 163 million barrels in the 1P proven category, a testament to the strength and diversity of our production resource. In addition, we're defined by our operatorship, where we control over 97% of our 2P reserves. This provides us with the opportunity to effectively deploy our differentiated expertise across our portfolio. As we look to continue our track record of extending the useful lives of every assets we have taken over so far, the majority by 10 years or more. This starts with, of course, our safe operations, which are -- which is our highest priority. Our safe results motto is plastered all over our assets and delivered by all our people. We were also proud to consistently have high levels of production and uptime where we have delivered for many, many years, retaining our production efficiency of around 90%, even given the life of the assets being so long. Building on these foundations, our 2025 performance represents another solid year of delivery, extending our track record of meeting targets again. Our reported production was 5.4% up versus 2024. Following the July completion of our Vietnam acquisition, our pro forma production of 45,600 barrels a day was above the top end of our 40,000 to 45,000 barrel a day guidance range. Fundamentally, our strategy is underpinned by our established top quartile operating capability. For 2025, the production efficiency across our assets was 89%, and this would have been 92% had we not had the unplanned third-party infrastructure outage at Ninian, which impacted our Magnus production. The performance of Magnus post the outage was exemplary, with high levels of uptime and a successful delivery of a very successful drilling and well enhancement campaign, bringing us back in line with the full year targets, even with the 5-year (sic) [ 5-week ] outage at NCP. That performance last year gives us confidence that we can recover from another third-party outage at NCP this year that's impacted Magnus. With a softening 2025 commodity price, macro volatility and continued challenges in the U.K. fiscal regime, we remain focused on cost optimization wherever possible, and this is part of our strength and our DNA. It was pleasing, therefore, to see us maintain flat operating costs through cost discipline and through FX hedging and our unit OpEx reduced year-on-year. The disciplined approach has been determining our history throughout EnQuest and has enhanced our ability to consistently optimize value for mature and underinvested assets. As we now grow our Southeast Asia business entering Vietnam, Brunei and Indonesia during 2025, we remain confident and focused on key skills that are transferable that can be deployed to optimize these long-value assets. Our expertise to extend decommissioning performance where we have now executed 84 wells in the U.K. since 2022 over the last 3 years, plus a further 21 wells in Malaysia is exemplary. This performance sets us apart from our most active competitors as we decommissioned -- we are by far the largest decommissioner in the Central and Northern North Sea, having completed more than 45% of the wells in that area. It's noteworthy that our performance which used to be 35% below the benchmark, is now skewing the benchmark and our performance now is 15% below the benchmark in the decomm area. It was a very busy year for us last year. So beyond our co-delivery of our operation and production, we have executed a number of very important transactions, all of which contributed very positively to our strategy. We added the first transaction in Vietnam early in the year, where we took over production asset and extended that by the end of the year by another 4 years. We added material reserves and resources via these country entries in Vietnam and Brunei and a significant prospectivity of gas in the Gaea and Gaea II blocks in Indonesia, where we have world-class partners. In Malaysia, we commissioned a project which was signed in March of last year, the Seligi 1b gas project, utilizing the resources that we have that are nonassociated gas resources and entering an agreement with the government to access those resources. Within that 9-month period up to December, we delivered first gas in December 2025 and reached production of 70 million standard cubic foot a day, which is our contractual agreement with the government of Malaysia. Subsequently, we've continued to optimize our gas capability through requests from PETRONAS to add additional gas resources given the gas situation in the world, and we were able to debottleneck and add additional resources of 30 million -- production of 30 million standard cubic foot a day, getting us to 100 million standard cubic foot a day most of March. This represents 40% upside on our contracted volumes and demonstrates an important role that we can play in supporting Peninsular Malaysia's gas demand in this difficult time. Enhancing our platform for growth, we also increased our transition -- transaction-ready liquidity by $200 million in 2025, underpinned by a strong refinancing of an RBL executed by Jonathan and the team. After securing the support of 8 leading banks, our facility now totaled $800 million across a loan tranche and a letter of credit tranche with potential for another $800 million via an accordion facility. The cash tranche was undrawn at the end of last year. Last month, we also demonstrated that we could bring value -- significant value accretion in the U.K. by settling the Magnus contingent consideration mechanism with BP on attractive terms. The $60 million settlement removed $433 million liability from our balance sheet and ensured more than $750 million of undiscounted future cash flow that would stay with our business. All of these activities and business development entrances reinforce our disciplined approach to investment and our commitment to deploying our key resource, our time and our capital where we see the best value creation. It's important to also look at the growth opportunities that we've created with our business development. And as you can see here, we have a robust production growth over the next few years. Looking at our existing portfolio ex acquisitions in the U.K., it displays the increasing importance of our Southeast Asia assets within our production mix. You can see that we will be -- we are roughly today at about 1/3 in the Southeast Asia business and 2/3 in the U.K., going to 55% in Southeast Asia by 2030. The U.K. production will be maintained around current level through a continued investment in infill drilling, well intervention and enhancement work and reservoir management as well as continued commitment to maintaining key asset equipment to protect our top quartile performance. It's also important to note here that the North Sea production plot in navy blue is essentially a 2P profile with very little contingent 2C resources included at this stage. Our job now is to try and progress these exciting organic opportunities we have at the Magnus Lower Kimmeridge Clay Formation and the Kraken Enhanced Oil Recovery development alongside the potential at Bressay and Bentley for 2C resources and to move all these into 2P resources. I'm quite excited about the Magnus LKCF, where we have a very low recovery factor of -- in the low 20s of 300 million to 400 million barrels of oil in place. As we produce our existing Brent reservoir, we -- which goes down in time, we will be able to use the same slots to then focus on the Lower Kimmeridge Clay, which has a significant resource with low recovery factor. The EOR also from Kraken can add significant resources as we've discussed. We have recycled that into to look at various different polymers and various different injectivity and are moving that forward quite well. I have confidence in our teams that we will be able to again move a lot of those 2C resources to 2P resources. Let us look a little more at the Southeast Asia business in more detail. This slide breaks out the Southeast Asia production to the end of the decade to see the component part and to demonstrate the path to 35,000 barrels a day equivalent net to EnQuest, almost doubling from where we are this year. We have already increased our production from the '23 levels of about 5,000, 6,000 barrels a day to about 17,000 barrels a day as we speak today. We can see the PM8/Seligi oil baseload being supplemented now by the Seligi gas through, first, the Phase 1A transportation agreement in '24, '25 and now through the sale of gas rather than just a tariff for gas, which is the 1B nonassociated gas production on vastly improved fiscal terms. Beyond that, we also have added Vietnam production, and I'm hopeful that we can access additional volumes there beyond those shown here now as we have received the 4-year extension of the Block PSC secured in February. And now we can look at prospectivity in Blocks 12W beyond the initial period, which will allow us to do more investment there. In Sarawak at the DEWA cluster, we are progressing plans for a cost-effective first phase development now with a base of 1.2 Tcf of gas in place. This initial phase is expected to deliver production of 9,000 barrels a day with a recoverable volumes of 28 million barrels equivalent, both net to EnQuest. In Brunei, we're progressing plans on our 50-50 joint venture, which has been finalized with Brunei Energy Exploration, the government company, with the expectations that we can access 15,000 barrels a day from the Merpati and Meragi fields based on our net 50% share. First gas is targeted towards the end of the decade. Through the building of this profile, we have continued to enhance our relationship across the region, and I look forward to driving further growth across our Southeast Asia business. In summary, I'm very excited about the opportunities, which will provide organic growth, both in the U.K. with our existing 2 stellar assets and a very much focused material growth through acquisition, which we have delivered in Southeast Asia. The recent deals in Southeast Asia highlight our commitment to growth, a disciplined approach to M&A and a strategy to invest capital where we identify the most favorable returns. However, given our significant relative tax advantage in the U.K. with our big tax asset that's going up from about $2 billion to $3.2 billion this year, we will remain focused also on growing our North Sea business in the coming months, enabling us to release and accelerate the value within our U.K. tax assets. In all our endeavors, we look at diversifying and improving our overall carbon intensity by adding more gas to our commodity mix. The projects I've discussed in Asia are all gas-based projects, Phase 1b in Seligi, DEWA, the Sarawak project, which is gas; Brunei, the Merpati project, which is gas as well as the prospectivity in Gaea, which is gas driven in the discoveries that they've already made. In short, we've had a strong record of delivery and a great team, which sees us as well placed to execute our strategic aims. But I'm also recognizing that we have done an exceptional job in reducing our emissions. Our emissions now from our 2018 baseline are down 45%, very close to the 2030 target set by the U.K. government. I'll now pass to Jonathan to take you through our financial performance.

Thanks very much, Amjad. Good morning, everybody. Apologies if I cough my way through this. I've got a bit of a cold. But -- so I think the first point from a financial point of view is our capital structure. It is the financial foundation of our business. And in the last 2 years, our focus has been to simplify that capital structure and to make sure that it's fit for purpose in terms of supporting our growth ambitions as a business. The latest step in that was the refinancing of our RBL in November 2025. And alongside that RBL capacity, we also have access to bond markets, and we have $644 million of bonds outstanding with no maturities before the end of '27. At the 31st of December, our cash was $269 million. And in terms of cash and undrawn facilities, our committed liquidity as a group was $679 million. As we build our investment programs, our capital priorities are clear. We are focused on fast payback investment. And what we're looking to do from that is to drive growth, drive diversification and also internationalization. And the 2 parts of that are organic and also acquisitional. In 2025, we paid our first dividend and shareholder returns are a structural part of how we allocate capital. And you'll have seen this morning that we have increased our dividend from $15 million last year to $20 million this year. Amjad also mentioned that we have strong control over our assets. We operate 97% of our 2P reserves. And we strongly believe in the potential of those assets, and we are in full control of their future. And you'll have seen in February that we announced the settlement of the Magnus contingent consideration. This contingent payment relates back to the transaction in December 2018, where we acquired 75% of Magnus from BP. And as part of that deal, they received a 37.5% pretax cash flow stream from the asset. Now by buying that in for this $60 million settlement, it has removed a $433 million liability from our balance sheet, and on an undiscounted basis, that means that there's an additional $777 million of cash flow from the Magnus asset, which is now in our hands, which otherwise we would have been paying out to BP. So it's a great example where we have confidence in asset, we back it with our capital. And of course, the thing that hasn't changed in this deal is that there's no change to the decommissioning arrangement. We have 100% of the operating equity, but we pay only 9% of the decommissioning liability. Turning to the income statement. In 2025, we delivered revenue of $1.1 billion. Now underlying that was 5% production growth. But in the period, Brent also declined, Brent prices declined by 15%. We offset some of that impact through our commodity hedging gains, and I'll come back to hedging later in this presentation. Cost of sales totaled $838 million, and our underlying operating costs remained flat year-on-year, and that was despite a 10% weakening in the U.S. dollar. Our unit OpEx in the period fell by 2%, and it was $25 a barrel. Adjusted EBITDA in the period was $504 million. And when you look at the face of the income statement, there are 2 significant events that are worth just pausing to discuss. First of all, the unwind of the $433 million balance sheet liability for the Magnus contingent consideration results in a net gain from the buying of that profit share of $239 million. We also see the one-off noncash tax charge associated with the 2024 decision to extend EPL by 2 years. That was enacted in March 2025, and it leads to a one-off noncash tax charge of $124 million in our accounts. Stripping out that tax charge, we would have delivered a net profit for the period of $126 million. Turning to cash flow. We generated operating cash flow of $498 million in the period, and we invested $179 million in our CapEx projects. Now that investment is grounded by our usual annual programs of maintenance that allow us to maintain the high levels of uptime and the safe operations that we are so proud of. It also included growth CapEx, and that was specifically spent on Seligi 1b, where we accelerated the delivery of first gas by 9 months and also Magnus drilling, and we'll be returning to Magnus for more drilling in '26 and '27. We undertook an extensive program of decommissioning work and the capital cost of that was $57 million. In the second half of the year, we had a number of significant cash costs. The first of these is our tax bill. We paid $107 million of cash tax. And of course, as a taxpayer in arrears, that tax relates to activities in prior periods where the oil price was higher. Looking to 2026, we would expect the tax bill to be lower given the movements in underlying oil prices. We also completed the acquisition of Vietnam, and we made a $20 million cash payment on completion, and we incurred cash costs of $18 million relating to our RBL refinancing. We also, of course, paid our dividend in June, which was $15 million. Net of all those movements, net debt at the end of the period was $435 million. I mentioned the RBL facility and the refinancing. So this refinancing replaced our earlier facility, which was a $500 million RBL that had a $75 million letter of credit sublimit within it. We now have an $800 million RBL facility, which consists of 2 tranches, a $400 million loan tranche, which was undrawn at 31st of December and a $400 million letter of credit tranche, which simplifies the management of our decommissioning security arrangements. The RBL refinancing was supported by the syndicate of 8 leading international banks, and that composed of both existing lenders, but also a number of high-quality new relationships, which we brought into the RBL. The cost of the RBL is SOFR plus 4%. We were previously playing SOFR plus 4.5%. The RBL also has an accordion, which is $800 million, and that accordion provides the ability to extend both the loan tranche and the letter of credit tranche by $400 million each. At the 31st December, cash and available facilities was $679 million, and that was an increase of $200 million versus the position at the 31st of December 2024. Stepping back from this refinancing process, I think it's a great validation of the tangibility of our assets and also a great validation of the quality of our delivery and our teams within EnQuest. It also, of course, highlights the strong levels of support for the sector within the banking community, and we're very proud of the banking relationships, which we take forward in this RBL facility. Alongside our operating assets, of course, our other asset is our tax position as well. Our U.K. tax loss position at the 31st of December was $3 billion, and this has been built up through material levels of investment by EnQuest in the U.K. It is there and available to shelter profits from CT and SCT, and those tax losses are simply held and are very easily utilized. Hedging. Hedging is something that we -- is part of how we manage our business. And we use hedging as a tool to manage our business throughout the commodity price cycle. Now we refreshed our hedging strategy in the second half of 2024. And our focus as a business is to underpin our budget and the next 24 months ahead of us. And by doing that, we also maximize the capacity available under our RBL. Our typical approach is to maintain unhedged length in near months and then have a rolling portfolio of hedges across the subsequent periods. What we also do, of course, is opportunistically look ahead and we lock in volumes for near-term cargo liftings when we see price spikes, and that has become much more a component of how we're managing near-term volumes, obviously, in recent months. That hedging strategy in 2025 maintains strong protection and through a program of swaps, we saw an average floor price of $70 a barrel. In 2026, we've maintained an active hedging program. And as of today, in 2026, we have 5 million barrels hedged at an average price of $71.30. In 2027, we have 3.5 million barrels hedged with an average price of $64.40, and we have a small hedge position in 2028. What it means is that on a net entitlement basis, in terms of our unhedged exposure to oil price upsides, about 50% of our point forward volumes across '26 are unhedged and they're exposed to higher oil prices. And in 2027, about 2/3 of our production is exposed to higher oil prices. And we will continue to manage that portfolio, striking a balance between protection of our budgets, but also maintaining some upside leverage to the heightened commodity price environment. And then finally, in terms of guidance. So in 2026, we have production guidance of 41,000 to 45,000 boe a day, and this includes the impact of the third-party infrastructure outage at Magnus that we reported in January and February. Our operating expenditure guidance is $450 million. Now one of the important moving parts in operating costs for us as a business has been foreign exchange. And this is something else that we actively hedge. And our operating cost guidance includes in it a $30 million accommodation for FX impacts in terms of dollar weakening. So if we look through that, you can see that we are continuing to maintain downward pressure on operating costs. And as Amjad said at the beginning, cost management is a key part of our DNA. Our CapEx program for 2026 is $160 million, and that includes production-enhancing drilling and workover campaigns at both Magnus and PMA Seligi in Malaysia and also long lead items in terms of the NCP bypass, which Ian will talk about, which is an important project in terms of managing our exposure to third-party infrastructure going forward. Decommissioning costs in the period are guided to be $60 million. And you'll have seen, as I mentioned earlier, that this morning, we have announced a $20 million dividend. And this is a structural part of our capital allocation process, and it is the latest step on our distributions journey. So I'll now hand over to Ian, who will walk you through the operating highlights and performance of the business.

Yes. Thanks, Jonathan, and good morning, everyone. My name is Ian McKimmie. I'm the North Sea General Manager for EnQuest. As Amjad and Jonathan have clearly laid out, 2025 was a really strong year across all our operations, and we've actually got plenty to be excited about as we look forward to 2026 and beyond. First, I'd like to start with our most important consideration, delivering safe results, which Amjad has touched on already. So safe operations is our license to operate and underpins everything that we do. I'm pleased to say that 2025 saw us return to the standards of safety performance we are used to. And while we strive for 0 on this, we achieved a level of lost time incident frequency that significantly outperformed sector averages. And you can also see here, we brought up some very impressive performance milestones at Kraken, PM8/Seligi and Kittiwake and also recognized in Malaysia with the HSE Excellence Award at the PETRONAS Emerald Awards. Moving on to operations. Getting Kraken, we continue to set the standards of FPSO performance with Kraken. We delivered a production efficiency of 95% in 2025. This continues an exceptional performance at Magnus over a number of -- Kraken, sorry, over a number of years, and we're almost 30% ahead of the North Sea average for an FPSO. As you look forward to the next phase of Kraken operations, there's a lot for us to get after. We have a strong infill well campaign with 3 wells identified at the Pembroke, Cumbria and Maureen reservoirs, and we'd like to return to drilling at Kraken by executing them -- these targets in 2028 and 2029. We've also got material upside with our enhanced oil recovery project. We're targeting about 40 million barrels equivalent upside from that project at Kraken. We have an integrated project team currently working on simulation modeling to identify the upside. And we're also then upon initial period of testing in '25, we are progressing with a polymer chemical selection in the lab and putting together plans for pilot testing. Beyond the existing Kraken field, there's a potential for EnQuest to create a production hub involving our large-scale developments at Bressay and Bentley. The 3 fields like close to each other and have similar properties, the oil viscosity increasing from Kraken to Bressay to Bentley. We believe the fields can be developed sequentially so each step is derisked for the previous phase of activity. Kraken's heavy oil development is built upon HS -- hydraulic submersible pump technology, and that's a technology that is essential to take Bressay and Bentley developments forward. This unique expertise aligns EnQuest's operatorship of the 3 fields and with the NSTA's core principle of having the right assets in the right hands. EnQuest wants to ensure that these strategically important resources are developed for the U.K. Bressay 2C reserves of circa 100 million barrels of oil and 20 billion cubic feet of gas and Bentley resources of 130 million barrels of oil in 2C. Our plan is to develop a sequential development initially with the Bressay gas cap development, which would tie back to the Kraken FPSO, where we will replace the diesel that's currently being used to run the power generation at the FPSO, significantly reducing Kraken's operating costs and transforming its carbon footprint. Production of the gas cap would then derisk the future oil development at Bressay, which would likely utilize our expertise in the HSP pumps. By prioritizing Bressay development, we can then first evaluate performance of lifting pumps in a higher viscosity setting before any future development at Bressay. In summary, Bressay and Bentley hold almost 250 million barrels of oil equivalent in 2C reserves, making them among the largest development remaining in the North Sea. Moving on to Magnus. Magnus performance in 2025 is really impressive. We recovered from a 5-week third-party infrastructure outage at the Ninian Central Platform. Despite that outage, Magnus production was 8% up year-on-year, a normalized efficiency excluding that outage of 93%, phenomenal performance for an asset that's been in service for over 40 years. That was underpinned with a successful well work program through the drill bit and through well intervention. And we also did a lot of work optimizing our water injection, making sure we get the effective sweep and right pressure support in the right areas of the field. As Jonathan has covered, we have strong conviction that Magnus will remain a key asset for EnQuest over the next decade and the settlement of the contingent consideration mechanism gives us full access to the upside from future enhancement works. And starting next month, we will commence a 6-well drilling campaign, which will include targets at the Lower Kimmeridge Clay Formation, an area that at Magnus field, we believe holds significant value. Following on from another unplanned outage at NCP ridge earlier this year, we're pleased to say that Magnus has again bounced back with production approaching 19,000 barrels per day since early March. This gives us confidence that we will again deliver our Magnus targets, but we're also progressing plans to mitigate third-party impacts on the asset. The NCP Bypass Project is a key project, which we're progressing alongside Total to protect Magnus export and export beyond NCP end of production. And we've got the full support of the NSTA. We have foundations in place now and are focused on moving through the project state gates efficiently, FID planned for middle of 2026. We have a concept which is technically signed and the purchase of long-lead equipment this year will set us up for the successful execution of the bypass in 2027. Moving on to Southeast Asia. Amjad talked earlier about the momentum we're building as we grow that Southeast Asian footprint, and it's been made possible after 12 years of exceptional performance in Malaysia, we will be celebrating being named Operator of the Year for the second year in a row. At PM8/Seligi, we continue to deliver safe, efficient operations and we increased production by 13% in 2025. However, the acceleration of the Seligi 1b gas project that best displayed EnQuest's ability to optimize asset performance having brought first gas forward by 9 months. And even then, we've pushed for further enhancements and have regularly supplied 100 million standard cubic feet per day to support increased Peninsular Malaysia gas demand during March. In 2025, EnQuest welcomed our new colleagues in Vietnam with a deal to acquire Harbour Energy's Vietnam business completing in July. The team quickly set about actioning proactive well enhancement scopes, delivering 3 well workovers and boosting gross production to more than 10.3 kbd per day in the fourth quarter. Most impressively, just 7 months after completing the acquisition, EnQuest agreed with Petro Vietnam an extension of the Block 12C production sharing contract on its existing terms out to 2034. This provides us the opportunity to assess the significant prospectivity across the block, including multiple gas discoveries and additional drilling targets. Moving back to the U.K. Our midstream business continues to provide uninterrupted service across the Sullom Voe terminal in Shetland, and we're also nearing completion of some major rightsizing projects at the site. Beyond the new stabilization facility and the long-term grid connection projects, which together will reduce emissions by around 90% at SVT, there are also opportunities being managed by a wholly owned subsidiary, Veri Energy, which could deliver material decarbonization and renewable energy at scale. These projects really matter to Shetland and to U.K.'s decarbonization ambitions and the work we are progressing shines a light on SVT as a microcosm of the energy transition. And before I hand back to Amjad, I think I'd like to cover some of the continued excellence being delivered across our in-house decommissioning function. Following the completion of P&A work at both Heather and Thistle during 2025, we've now completed a P&A of 84 wells since 2022. And across the period, we're now responsible for 47% of the P&A work across Northern and Central North Sea. In fact, Northern North Sea alone taken that figure alone, it rises to 55%. This means we are now the main driver of sector benchmarks, and yet we're still outperforming North Sea average for well cost and P&A duration. 2025 also saw the U.K. team deliver the heaviest lift in the North Sea during the year, the removal of the 15,300 tonne Heather topsides. I'd encourage anyone to go to our website and watch the video. It's an incredible feat of engineering. EnQuest also deservedly won the OEUK Excellence in Decommissioning Award for the Heather project, becoming the first company to win this prestigious award twice. On that note, I'll summarize by saying EnQuest has again demonstrated excellence across all aspects of its operations, and we look forward to the considerable opportunities ahead. I'll now hand back to Amjad to close.

Thank you very much, Ian, and thank you very much, Jonathan. Again, you can see through the presentations, the level of excellence that EnQuest delivers across the operations, but also across the finance and commercial, which is -- which makes us all extremely proud of what we've done so far and our journey over the last 16 years. As I conclude, I just want to go to the proof points that underpin our business. And again, it's exemplified by the presentations that you just heard. We are a top quartile performer, top quartile operator. We operate 97% of our resources. We have skills that can be deployed across geographies, and we've proven that. Our transitions, both in Malaysia 12 years ago and in Vietnam recently and into Indonesia and Brunei all exemplify the strength of the organization and the ability to expand. Our balance sheet is now simplified, as Jonathan mentioned, and much strengthened and is very much now transaction-ready, as you can see. As a result, we're well set to build our strong foundations, both organically as well as inorganically. And our strategic imperative remains the execution of growth, both a large transaction that can be significant as well as organic and inorganic growth. So thank you for your attention this morning. I will now hand over to Craig to lead our Q&A, both side and again, if you want to send questions.

[Operator Instructions] Before the guys take a few moments to review the questions submitted already. I'd just like to remind you a recording of this presentation, along with a copy of the slides and the public can be accessed via your Investor Meet company dashboard. Craig, if I may, I'll bring up your camera, if I could please hand back to you to moderate through the Q&A, and then I'll pick up from you at the end. Thank you.

Sure. Thank you very much, Mark, and thanks, , for the presentation. And I'm pleased to say we have a lot of Q&A that's come in while you've been talking. And Amjad, I'll come with you, but we've given a bit of a forward view this year. I'll come to you to ask how large could the business realistically become if we continue executing our buy and improve strategy over the next 3 to 5 years in your view?

So thank you for the question. Again, I mean, we have shown the growth in Asia aspirationally and organically to almost doubling from where we are today, and we have doubled from a couple of years ago. So this would be going to 35,000 barrels a day. As I mentioned, the gas project in Malaysia has now doubled our production there to 17,000. And I think that will also double again. I do see the U.K. holding steady. We are very hopeful that there will be changes that will allow us to not only just continue with the infill programs, which are quite significant in Magnus, which we have executed over the last couple of years, we'll execute this year with 6 additional wells, but also allowing us to look at the wells that Ian mentioned in Kraken and mentioned in terms of the EOR project, which is exciting in Kraken as well as also what I'm extremely excited about, which is this Lower Kimmeridge Clay Formation, where the recovery factors are low in Magnus and we can continue drilling wells. So organically, I think we can probably hold our production in the U.K. And if we can get some of these new projects across the line with a better fiscal regime and some more incentives, I think we can go back to growing in the U.K. And then in Asia, we are looking to double before the end of the decade again. And again, we're looking for continuing to look at inorganic opportunities there, too.

Thanks very much, Amjad. And you mentioned the U.K. fiscal regime. So you won't be surprised, Amjad, to learn, and there's been a few questions from attendees around EnQuest level of engagement. Obviously, there's been a lot of discussion in the press over the last few weeks and months around engagement between treasury, government and industry. And there are a lot of questions on this subject, Amjad. So maybe the easiest thing to do would be for you to give a brief summary on EnQuest engagement and your sort of hopes and thoughts on how we might move forward in terms of the U.K. fiscal regime.

Yes. I mean, again, Craig and Jonathan have been very involved alongside myself with the interactions with the government. We have had a very constructive interaction with the government. I've been on the fiscal forum now since its beginning, which is when the labor government came in. This was established to look at the energy profits levy and how that could be shaped for a future levy, which is -- or future tax, which I think is -- would be more palatable. So there was a -- it's been a very constructive discussion with government. I think the mechanism, the oil and gas price mechanism, which has come up with by the government, which the government has come up with, is conducive for industry, will also help industry reengage in investment and recommit to investments in the basin, which I think is very important. We have seen production go down by 80% since our peak in 2020 and by almost 50% since our 2019 production just before COVID. So I do look forward to a growth industry coming back into the U.K. I think it's important that we've seen the level of jobs come down very significantly. We continue to see job losses, 1,000 jobs a month according to Experian. And I do feel that can only be reversed if we can look at this new mechanism, which we welcome the government's -- what the government has come up with is welcomed by industry pretty much unanimously, I feel. And we -- both Craig, myself and Jonathan have been interacting in different lines with government to make sure that our voice has been heard.

Thank you for that, Amjad. I think that's a really good summary of where we've been over the last few months and of course, the last few years. And Jonathan, if I may, I'll bring you in on -- there are a few financially focused questions. The first one, just a point of clarification, Jonathan, from Charlie at Canaccord around the hedges and whether the hedges are for current year or the ones we've referenced from 1 April on a 12-month rolling basis. And actually, Jonathan, if I may, just wider to that, there's a few questions seeking some clarification around our thoughts on hedging, our hedging strategy. And obviously, it's a very pertinent point. So rather than going through each question individually, maybe you could just reiterate your sort of key thoughts on our hedging strategy, please.

Yes, absolutely. Yes. So the table that's in the pack and that is in the results release today, that's our current hedging position. The position that I talked about, the 5.1 million barrels, those are all swaps and the average price -- the price that's quoted there is the average price, $71.30. And in 2027, we have 3.5 million barrels. Those are also swaps at $64.40. I think that in terms of just sort of hedging strategy and the approach, I mean, the anchor point of any sort of hedging conversation in part is 2 things in my mind. Like one is where did we allocate capital? What were our oil price assumptions and also what are the lenders' assumptions and what's the lending market like. Now of course, one of the things that we're managing here is extreme levels of volatility in commodity price markets. And so we entered this year allocating capital at $65 a barrel. And today, we're sitting here with oil prices certainly at about, I think, $100 a barrel when I came on to this call that it's very difficult hour to hour to predict where that is going to be. But of course, we're not like speculators, and we're also not just hanging out to try and capture the highest price on the curve. We're trying to deliver a balanced and risk-managed business where we can move forward, delivering our capital programs, not completely extinguishing our exposure to the oil price, but having a balance between the protections that we can put in place through hedging, but also maintaining a degree of upside and leverage to the underlying commodity price. And I think that as we move through the course of this year, the other opportunity here and our approach to that is that we maintain a block of hedges, which we roll forward as we move forward in our kind of planning cycle as opposed to letting them kind of roll up the curve and become prompt. Now where the current environment is different is that whereas we would usually maintain a fairly unleveraged sort of front end to our production profile in terms of near-term liftings, the fact that we're seeing so much volatility means that we can proactively move into the market. So as well as having a more kind of structural portfolio of rolling hedges, which is what we use to deliver the budget, but also maximize the RBL capacity. What we're doing is we look ahead and we say, well, what liftings are coming up on our assets and where can we lock in pricing on an opportunistic basis. And so I think that combination at the moment is meaning that we can remain agile in terms of hedging markets. We can capture the upside at the front end of the curve. We can maintain good levels of protection above our budget levels, but also not completely extinguish our leverage into higher crude prices. And as I said, hedging is not something that we just started doing this year because the oil prices have gone up. It's a structural part of how we manage our business and we utilize hedges through the cycle. And I think in the results today, you can see how the hedges that we put in, in late '24 and early '25 stood us in good stead. And of course, those hedges are not just commodity hedges. They're also FX hedges as well because as I noted, we saw a 10% weakening in the dollar last year, which is another important moving part in terms of managing budgets and costs. So I hope that gives a bit more color of how we think about it.

Yes, that's great. Thank you, Jonathan. I'll stay with you, if I may, Jonathan. I'm going to group a few questions all around the capital structure, which you outlined as a single slide. So we've got a question just sort of a point of clarification around the RBL maturity, please, Jonathan, and what that time line is. And also if you've got any thoughts on what we might do in terms of the upcoming bond maturities and what options are available to us in that regard. And then finally, there's just a question around our engagement and relationship and discussions with credit rating agencies and whether there's anything you can share that would be illuminating on that, please.