Thank you very much, Mark. 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 four weeks.

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. production in Vietnam, a development in Brunei, joint venture with the government, as well as upside on appraisal and exploration with the Tenggol 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 asset we have taken over so far, the majority by 10 years or more. This starts with, of course, our safe operations, 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 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 five-week outage at the NCP.

That performance last year gives us confidence that we can recover from another third-party outage at the NCP this year that's impacted Magnus. With the softening 2025 commodity price, macro volatility, and continued challenges in the UK 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 discipline approach has been determining our history throughout EnQuest and has enhanced our ability to consistently optimize value from 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 UK since 2022 over the last three years plus a further 21 wells in Malaysia, is exemplary.

This performance sets us apart from our most active competitors. As we decommission, 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 decom area. It was a very busy year for us last year, beyond our core 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 four 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 2 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 non-associated gas resources and entering an agreement with the government to access those resources. Within that nine-month period up to December, we delivered first gas in December 2025 and reached production of 70 million standard cubic feet 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. We were able to debottleneck and add additional resources of 30 million production of 30 million standard cubic feet a day, getting us to 100 million standard cubic feet 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 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 eight leading banks, our facility now totals $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 significant value accretion in the UK 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.

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 UK, it displays the increasing importance of our Southeast Asia assets within our production mix.

You can see that we are roughly today at about a third in the Southeast Asia business and two-thirds in the UK, going to 55% in Southeast Asia by 2030. The UK production will be maintained around current level through 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 in the low 20s of 300 to 400 million barrels of oil in place. As we produce our existing Brent reservoir, which goes down in time, we'll be able to use the same slots to then focus on the Lower Kimmeridge Clay, which has significant resource with low recovery factor.

The EOR also from Kraken can add significant resources. As we've discussed, we have recycled that into 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's 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 parts 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 2024-2025 and now through the sale of gas rather than just a tariff for gas, which is the 1B non-associated 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 four-year extension of the block PSC secured in February.

Now we can look at prospectivity in Block 12W beyond the initial period, which will allow us to do more investment. In Sarawak at the Diwa 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 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 Maragi fields based on our net 50% share.

First gas is targeted towards the end of the decade. Through the building of this profile, we've 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 UK with our existing two 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 UK 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 UK tax asset. Phase 1B in Seligi; Diwa, 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 got a strong record of delivery and a great team, which sees us as well placed to execute our strategic aims. 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 UK 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.

I think the first point from a financial point of view is our capital structure. It is the financial foundation of our business.

In the last two years, our focus has been to simplify that capital structure and to make sure that it is 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.

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 2027. At the 31st of December, our cash was $269 million.

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. The two paths for 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. 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.

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 receive 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. 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 arrangements.

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 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 US dollar. Our unit opex in the period fell by 2%, and it was $25 a barrel.

Adjusted EBITDA in the period was $504 million. When you look at the face of the income statement, there are two significant events that are worth just pausing to discuss.

The unwind of the $433 million balance sheet liability for the Magnus contingent consideration results in a net gain from the buy-in of that profit share of $239 million. We also see the one-off non-cash tax charge associated with the 2024 decision to extend EPL by two years.

That was enacted in March 2025, and it leads to a one-off non-cash 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 nine 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. 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. 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 two 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 a syndicate of eight 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 paying 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 of 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 UK 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 UK.

It is there and available to shelter profits from CT and SCT, and those tax losses are simply held, and they're very easily utilized. Hedging.

Hedging is something that 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.

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 maintained 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 are exposed to higher oil prices, and in 2027, about two-thirds of our production is exposed to higher oil prices. We will continue to manage that portfolio, striking a balance between protection of our budgets, but also maintaining some upside leverage to the highest commodity price environment.

Then finally, in terms of guidance, in 2026, we have production guidance of 41 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. If we look through that, you can see that we are continuing to maintain downward pressure on operating costs.

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 PM8/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. You'll have seen, as I mentioned earlier, that this morning we have announced a $20 million dividend.

This is a structural part of our capital allocation process, and it is the latest step on our distributions journey. I'll now hand over to Ian, who will walk you through the operational highlights and performance of the business.

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 of our operations, and we've got plenty to be excited about as we look forward to 2026 and beyond.

delivering safe results, as Amjad has touched on already. Safe operations is our license to operate and underpins everything that we do.

I'm pleased to see that 20 2025 saw us return to the standards of safety performance we're used to, and what we always strive for, zero. On this, we achieved a level of lost time incident frequency that significantly outperformed sector averages.

You can also see here we brought off 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 into 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 Kraken 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 three wells identified at the Pembroke, Cambria, and Maureen reservoirs, and we'd like to return to drilling at Kraken by executing 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've an integrated project team currently working on simulation modeling to identify the upside, and we're also then, following an initial period of testing in '25, we're progressing with a polymer chemical selection in the lab and putting together plans for pilot testing. Beyond the existing Kraken field, there's the potential for EnQuest to create a production hub involving our large-scale developments at Bressay and Bentley.

The three fields lie 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 that each step is derisked by the previous phase of activity.

Kraken's heavy oil development is built upon HSP, a hydraulic submersible pump, technology. That's a technology that is essential to take Bressay and Bentley developments forward.

This unique expertise aligns EnQuest's operatorship of the three fields in the NSTA 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 UK.

Bressay's 2C reserves are 100 million barrels, circa 100 million barrels of oil, and 20 billion billion cubic feet of gas. Bentley has resources of 130 million barrels of oil in 2C.

Our plan is to develop a sequential development, initially with a Bressay gas cap development, which we tie back to the Kraken FPSO, where it 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 will 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 the performance of our 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 prizes remaining in the North Sea.

Moving onto Magnus. Magnus performance in 2025 was really really impressive.

We recovered from a five-week third-party infrastructure outage at the Ninian Central Platform. Despite that outage, Magnus production was 8% up year-on-year, the normalized efficiency excluding that outage of 93%.

Phenomenal performance from 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.

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's 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.

Starting next month, we'll commence a six-well a six-well drilling campaign, which will include targets at Lower Kimmeridge Clay formation, an area of Magnus field we believe holds significant value. Following on from another unplanned outage at NCP earlier this year, we're pleased to see that Magnus has again bounced back with production approaching 19,000 barrels per day since early March.

This gives us confidence that we'll 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 Alwyn export beyond NCP end of production.

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, with FID planned for middle of 2026.

We have a concept which is technically sound, and the purchase of long-lead equipment this year will set us up for a 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 this has been made possible after 12 years of exceptional performance in Malaysia, where we've been celebrated 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 nine months. 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 three well workovers and boosting gross production to more than 10.3 thousand 10.3 kbd per day in the fourth quarter.

Most impressively, just seven months after completing the acquisition, EnQuest agreed with PetroVietnam an extension of the Block 12W production sharing contract on its existing terms out to 2034. This provides us with the opportunity to assess the significant prospectivity across the block, including multiple gas discoveries and additional drilling targets.

Moving back to the UK, 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 the 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 UK's decarbonization ambitions, and the work we are progressing shines a light on SVT as a microcosm of the energy transition. 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. Across the period, we're now responsible for 47% of the P&A work across the Northern and Central North Sea.

In fact, the Northern North Sea alone, taking that alone, that figure 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 UK team deliver the heaviest lift in the North Sea during the year, the removal of the 15 15,300-ton Heather topsides. I'd encourage anyone to go to our website, watch the video.

It's an incredible feat of engineering. EnQuest also deservedly won the UK OEUK Excellence in Decommissioning Award for the Heather project, becoming the first company to win the 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 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. Again, it's exemplified by the presentations that you just heard.

We are a top-quartile performer, a 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 has 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.

Our strategic imperative remains the execution of growth, both a large transaction that can be significant, as well as organic and inorganic growth. 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 from

Sure. Thank you very much, Mark.

Thanks, gents, for the presentation. I'm pleased to see we have a lot of Q&A that's come in while you've been talking.

Amjad, I'll come to you. Maybe we've given a bit of a forward view this year, but 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 three to five years, in your view?

Thank you for the question. Again, 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.

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 UK holding steady. We are very hopeful that there would 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 six 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 the Lower Kimmeridge Clay formation, where the recovery factors are low in Magnus and we can continue drilling wells.

Organically, I think we can probably hold our production in the UK. 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 UK.

Then in Asia, we are looking to double before the end of the decade again. Again, we're continuing to look at inorganic opportunities there, too.

Thanks very much, Amjad. You mentioned the UK fiscal regime, you won't be surprised, Amjad, to learn there've been a few questions from attendees around EnQuest's 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. There are a lot of questions on this subject, Amjad, maybe the easiest thing to do would be for you to give a brief summary on EnQuest's engagement and your sort of hopes and thoughts on how we might move forward in terms of the UK fiscal regime.

Yeah. Again, Craig and Jonathan have been very involved alongside myself with the interactions with the government.

We've had a very constructive interaction with the government. I've been on the the Fiscal Forum now since it's it's beginning, which is which is when the when the Labour government came in.

This was established to look at what the energy profits levy and how that could be shaped for a future levy, which is a future tax, which I think is is would be more palatable. There was a bit it's been a very constructive discussion with government.

I think the mechanism, the oil and gas price mechanism which the government's come up with, is conducive for industry, will also help industry re-engage 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.

I do look forward to a growth industry coming back into the UK. 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. I do feel that can only be reversed if we can look at this new mechanism, which we welcome.

What the government's come up with is welcomed by industry pretty much unanimously, I feel. Both Craig, myself, and Jonathan have been interacting in different lines with government to make sure that our voice is 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 last few years.

Jonathan, if I may, 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 one eight or on a 12-month rolling basis.

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. Rather than going through each question individually, maybe you could just reiterate your sort of key thoughts on our hedging strategy, please.

Absolutely. 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 price that's quoted there is the average price, $71.30. 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, the anchor point of any sort of hedging conversation, in part, is two two things in my mind.

One is: where did we allocate capital? What were our oil price assumptions?

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.

We entered this year allocating capital at $65 a barrel. Today, we're sitting here with oil prices sitting at about, I think, $100 a barrel when I came onto this call, but it's very difficult hour to hour to predict where that is going to be.

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.

I think that, as we move through the course of this year, 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.

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?" 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.

As I said, hedging is not something that we just started doing this year because the oil price has gone up. It's a structural part of how we manage our business, and we utilize hedges through the cycle.

I think in the results today, you can see how the hedges that we put in late '24 and early '25 stood us in good stead. Of course, those hedges were 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. I hope that gives a bit more color of how we think about it.

That's great. Thank you, Jonathan.

I'll stay with you, if I may, Jonathan. I'm going to group a few questions again, which are all around the capital structure, which you outlined as a single slide.

We've got a question just on a point of clarification around the RBL maturity, please, Jonathan, and what that timeline is. 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.

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.

Okay. The new RBL has a maturity in December 2031.

I think that's a really important, interesting point, because something has changed in the RBL market in the last sort of 6 to 12 months. It used to be that 2030 was a sort of brick wall, that it was very difficult, or it was impossible, to push RBL maturities beyond.

A lot of this related to the net-zero policies of banks, which kind of kicked in in 2030 and said, "We can't get beyond that date." Now, we and a number of others have kind of broken through that wall in the last 12 months.

That's not saying that the transition targets and things are not important to the banks. They still are, and we still go through a rigorous process in terms of how the banks carbon-account for the lending that they provide to us.

It shows that there has been this move that has opened up more capital coming into the sector, and not only is that expressed in terms of extending beyond 2030, but also in the range of banks coming in. People who had exited the sector are back, and there are also new entrants who are, to a degree, kind of disruptors in the market as well, I think it's a very vibrant market to have refinanced into.

In terms of the bonds, yes, we have the bonds alongside our RBL, and they have maturities late in 2027. What I would say about the bonds is that there are two things that are important, right?

One is that you need to be ready for the refinancing of those and be planning ahead, and the other one is that you need to be agile in terms of accessing market opportunities and windows of opportunity. Clearly, where we're at on the timeline to that maturity, part of our capital planning work is actively thinking and managing that.

We are well positioned both in terms of our delivery as a business, but also, I think that things like the Magnus contingent consideration settlement, a very important moving part in all of this, because they are very strongly credit-enhancing transactions. I noted the fact that that deal removes a $433 million contingent liability from our balance sheet.

Bond markets is an important part of our capital structure and, it's sort of central to our continuous sort of capital planning in terms of readiness for the eventual refinancing, and we have a number of windows ahead of us to do that. Then the last part of the question was about the rating agencies.

I think from a rating agency's point of view, we get a lot of positive acknowledgment and discussion for how we run the business, the levels of our uptime, the quality of our delivery, the tangibility of our reserve base, which I think is really exceptional. I think what we've also seen is very positive commentary around the transactions that we've done to date.

Vietnam was described by the rating agencies as a credit-enhancing deal. Clearly, the Magnus contingent consideration is a strongly credit-enhancing deal.

I think that the other thing that's on the rating agencies' radar is also scale. I think, certainly from our point of view, we have a very clear view, which is that the pathway towards significantly enhancing our ratings and things is not just about operational delivery, it's also going to be about delivering scale.

Having a balance sheet and available liquidity to transact as a business is very important, and it's very important to unlocking that positive credit pathway in terms of seeing reratings as well. We're well positioned to deliver that.

As Amjad said, we are very active along both of our growth pathways from an organic and a transactional point of view, those being Southeast Asia and the North Sea, and these are two parallel growth transactional pathways which are clearly not mutually exclusive. A big focus on delivering step change in scale for us as a business as well.

Thank you, Jonathan. Sorry for throwing so many questions at you in one go.

I'll give you a rest now, but don't go too far, because I'm going to come to Amjad on a subject that he may bring you back in on, Jonathan, which is the subject of dividends. Obviously, we've talked about the increased dividend for this year, and we've got a selection of questions from James Hosie at Shore Capital, Amjad, we've got Alejandra from J.P.

Morgan, and also retail investing like Hassnain. If you can give me a sense, Amjad, I'll kind of try and summarize if I can.

Give me a sense of kind of your thinking on shareholder distributions, kind of what prompted the decision to increase the dividend this year, and whether there are considerations around buybacks that get discussed at board. I think just a bit of an insight into that would be much appreciated.

Okay. Thank you, Craig.

We have committed, I guess almost four years ago, that we will make the distributions to shareholders as part of our capital allocations for the years to come. The first time we actually did share purchases was two years ago, and we implemented a program to do share purchases, I think in 2024.

That was implemented over '24 and '25, that was committed to in '24. We were slightly below the amount that we were trying to purchase, and at that time, we were driven by the calculus that our share price presented a great opportunity to purchase the shares, because compared to our net asset value or our view of our net asset value, it was a better option for the company to do.

Last year in 2025, the board approved our maiden dividend, which was $15 million, and that was again driven by the market wanting to, and many investors asking us to consider dividend policy and to start a dividend policy, which we have started. Again, in light of our performance of the last year, in light of the simplification of our capital structure that Jonathan talked about, and Jonathan really led through the RBL, and in light of our enhanced liquidity and an enhanced balance sheet, I think we thought it was right to increase the dividend by almost a third, by a third exactly actually, to $20 million.

I think it's a progression. It shows confidence of the board in the balance sheet and in the ability to pay more dividend over time.

Again, I think we continue considering the options of buybacks, and the dividend, and a combination of both. I think the confidence of the board in raising the dividend by a third clearly shows the confidence of the board in the future and the confidence of the board in the ability for the company to continue paying dividends in the future.

Thanks very much, Amjad. I'll stay with you, Amjad, if I may, and talk a little bit about projects.

We've mentioned in the presentation today the NCP bypass, and Ian gave us a view of what you could see in the future a sort of production hub at Kraken. I've got a couple of questions along these lines, Amjad, if you don't mind.

The first of these is can you give any view on a quantum of cost on the NCP bypass? Also, there's been a question from Ron around tie-backs have been now kind of de facto given the green light by the government.

Where does that leave us from a regulatory standpoint on Bressay? Connected to that, Amjad, a question we usually get is the EnQuest Producer FPSO, and where does that fit in as a piece of the puzzle, and could it be used in the UK, for example, as a future development option?

Sorry again, Amjad, for the multiple questions. I'm trying to summarize as much and get as many questions answered.

No, no, I welcome the questions. It's great that we've got an engaged audience, which is fantastic.

In terms of the Ninian bypass, it is part of our capex estimate, which is $160. It is a project which we are executing quickly, because I guess next year will be the year we will be looking to put it in place as the Ninian field gets closer to cessation of production.

That is moving at pace, and I think we will be looking to award that contract within the next say three months or so, and execute partially this year and execute the remaining next year during the most selective weather windows that give us the best options. Again, I think that's the way that we look at it in terms of optimizing the weather options to make sure that our costs are controlled.

Indeed, actually, that's how we find our contractors are able to take on the weather costs or weather caps during these weather windows that are best. Actually, we're very focused, laser-focused on making sure we get the right weather windows and right caps on these capex programs, which is extremely important.

Again, that allows us our control of costs, which we're very good at. That's in place.

It's part of the fairway of our capex this year and next year, and it's being done, I think by a great team led by Mick Tulloch, who's been with us for many years, has executed a couple of the subsea projects in the past, and again, this works very well with his and his team's expertise. In terms of tie-backs, the first and most obvious one is Bressay.

We have gotten an extension of the Bressay contract till the end of this year. Indeed, the NSTA and the government are very keen on the decarbonization of Kraken, and the decarbonization of Kraken would come through the ability to produce gas from Bressay.

We are looking at that. It's not yet in the sanction phase.

We probably will be sanctioning it sometime in the next year, probably maybe around this time next year or slightly earlier or slightly later. Again, we are just looking at early stage of moving that forward.

The dates of getting the Bressay gas into Kraken will be around the end of the decade. That's the timing that we need to get the adjusted field development plan in place and get the gas flowing to replace the diesel that's being burned in Kraken for the production of Kraken, which requires actually a lot of hot very, very hot water, critically hot water, 140°C.

That's probably the only tie-back now that we're looking at. The government has talked about, with the oil and gas pricing mechanism, the incentives for tie-backs, which we're looking forward to hearing on those tie-backs and how those will be structured.

Indeed, we are looking at some additional Kraken wells and Kraken possible tie-backs, too. We will wait to get the government's views on how that transpires in the future.

At present, linking into the EnQuest Producer, we had requested the use of the EnQuest Producer to derisk the Bressay field, and indeed look at using it for a limited period up to the end of the decade. That was requested a couple of years ago, and using the producer would have allowed us to drill four wells.

We have a vessel which is relatively new, only used five or six years, we're very proud of that vessel, and we thought we could use it on that. The government has not approved that field development plan, and that's why we've moved to the gas development on Bressay.

I think that was the one that we're looking at for now. I think at that time, government's looking for electrification of any new facilities in the going forward.

I think that was the calculus that they were looking at, and we had looked for an early production facility just to try and justify the field or get the economic returns of the field that we would see in the existing fiscal regime. That was what's happened with the EnQuest Producer.

The EnQuest Producer still lies in Nigg, and she was part of the Bressay project, and at present, we're just looking at options for deployment both in the UK and outside the UK there.

Thank you, Amjad. Staying with you, Amjad, and you've talked a bit about our sort of decarbonization credentials, and obviously, we're proud of that, we're proud of what we've achieved through the CDP rating this year.

We've had a question from James, which is around the way in which our existing infrastructure and subsurface expertise, and I would probably argue other parts of the business as well, Amjad, how could they give us a competitive advantage and how could they be utilized on decarbonization projects such as carbon capture and storage? What's the transferability of skill there?

Yeah. I think especially carbon capture and sequestration is very, very transferable.

We had four licenses in the East of Shetland, the Magnus license for carbonization, and this segues from our oil field. Instead of decommissioning the oil field, we would actually be able to utilize that, and it's linked, obviously, the linkage with Sullom Voe.

We are looking to utilize that infrastructure, transition the infrastructure indeed in time. Magnus was a good example.

We also have Thistle, one of our old fields where we have all the data. Then we had two other fields, Tern and Eider, which were ex-TAQA fields, which we were looking at carbon capture and sequestration there for those four.

We've made great progress on the two that we have, including getting to Phase 2, where we're looking at reservoir modeling. The reservoir modeling actually is done by the same team that had worked on Thistle for a long time, as we're doing static and dynamic models there for CO2.

Indeed, even with support from some colleagues in Malaysia, between the colleagues in the UK and the colleagues in Malaysia that are all subsurface experts, we're looking at executing the reservoir modeling for these two remaining fields. We have let go of the other two licenses.

We feel we've got Thistle, which has got enough capacity now it's a starter pack when the government is ready. The government has indicated that they will not give us any indication on mitigating our carbon emission tax by offsetting that tax if we are able to reinject CO2.

Until that is in place, which we're hoping for that to be in 2028 or '29, we're continuing to do the technical work and trying to understand the capital costs, which are front-footed given we have a pipeline from Sullom Voe where we can take liquid CO2, put it in a pipeline, and then look at injecting it in Thistle initially, and then in Magnus longer term. We're working very hard on that, but again, we need visibility on the ability to inject CO2 and get a credit against our CO2 emissions for that to be economic.

Obviously, just injecting it for the sake of philanthropy is not going to work, we need to get offset for our tax. We are paying almost $100 million in tax for the emissions that we do.

We emit as an operator about a million tons a year. I have to say, we have made huge progress.

Tremendous progress to reduce our emissions by 45%. A lot of the projects we're talking about here that we're looking at, we did a flare gas reduction project for Magnus, which we committed to and that's also part of the capex that you see.

We've done all reduction of gas in Sullom Voe, where we're taking the Viking wind electricity, which will pretty much replace fully our gas turbines and the electricity generation on Sullom Voe. We're going down by 95% plus.

Again, that's follow the NSF, the new stabilization facility project, that also is taking all gas and putting it in pipelines, there's no flaring or routine flaring, and the electricity is now generated by green. We have done tremendous job in reducing our emissions.

We are at 45% reduction from the 2018 baseline, ahead of the 50% target by 2030, which is a very aggressive target by the UK government. I'm very proud of where we are today.

We also were rated as A- in the CRP process, which is the Carbon Reporting Production Reporting. Again, I think we're the only oil and gas company that's been rated A- by the CRP.

Again, we are reporting properly, but also we have made tremendous progress in that respect.

Thank you, Amjad. I think that's covered the majority of the questions.

I am going to close with one further question, Amjad. For anyone whose question was maybe a bit too detailed and hasn't been read out, please feel free to contact me directly, and I'd be happy to cover anything that wasn't covered specifically in this presentation.

Amjad, I'll come to you to close with a question that comes from Alejandra at J.P. Morgan, but encapsulates a number of questions that have been asked, which is around what are your views on M&A, both in the North Sea and across Southeast Asia, and what do you see as kind of remaining bottlenecks and what's your outlook for EnQuest in this regard in the coming months?

I think we've done a tremendous job in Asia in entering new projects. We've entered three new countries and we did a project in Sarawak.

I think we've got a great base now to continue growing there. We'll continue to look at opportunities there.

I think we are recognized in Asia as probably the best, if not one of the best, but I think probably the best independent operator. Again, and the main country that has the expertise in Asia is Malaysia, and now for the first time ever, we've had two awards, the Platinum Awards for Operator of the Year.

This is given there are other operators: Shell, Exxon. The list of operators in Malaysia is kind of a who's who list of the largest companies and the most competent companies in our industry.

I think we should be very proud of that. I do think that gives us the ability to continue growing in Asia, because again, I think we are differentiated in our capability there.

Now, as an independent, we're probably in more countries than any other independent in Asia. The UK's remains critically important.

We will be able to increase our tax asset, as Jonathan had in his slides, and that will give us additional dry powder, both to accelerate our own organic usage, but also the inorganic usage, which gives us M&A opportunities. We continue to look at M&A opportunities in the UK.

There are fewer players now with tax assets, and then so I think our opportunity to try and now we have higher prices that is even more exasperated. I do believe prices, with the removal of some 2 to 3 million barrels a day of production capacity across the chain so far only in the Middle East, I think that will strengthen prices for the future.

That will enable the tax assets that even exist with some of the companies to be expunged at faster pace. We are lucky to have a very significant tax asset due to our two Kraken developments, which gave us 2.5 billion, plus the acquisition of Bentley, which gave us another 2 billion.

We have 1.2 billion. We have significant assets that remain with us, and I think we will be able to use those to try and triangulate an acquisition which is highly accretive in the UK.

With that, I guess, Craig, should I close or is there any other questions?

Feel free, Amjad. Any closing remarks would be great.

We think we've covered all the questions. As I say, anything that's not been covered in this presentation, I'd be happy to take directly and go back to the individuals.

Okay. I guess I am extremely excited about the period that comes.

I think EnQuest has not been in this shape, really since our inception 16 years ago. We now have a strong balance sheet, we have significant liquidity, we have a positive macro trends with the oil prices being higher, but also with gas prices being very high.

We have shifted to gas, where our production now is probably around about 30% gas-based in the future, and we're probably around the 15% even at present. I think we have increased our gas from zero to a higher exposure.

We're getting very, very good exposure to additional projects in that side. I'm very excited about the future.

I'm excited about our capability, and that really translates into what I think is a very bright future for EnQuest. I'd say, this is probably the best time that I have seen, probably since our inception.

We had some great years when we started, and then I do feel our balance sheet, with the two big projects that we had and the massive reduction in oil price that came around '14-'15, for the last 10 years, we have had limited ability to grow significantly. I think that ability now is unshackled, and you've seen that in Asia.

We've made three we've made acquisitions in three countries, and developed projects in two projects in Malaysia. Our growth potential, I think now is great given our resume, and given our people, which I feel are our most important asset.