Serica Energy plc (SQZ) Earnings Call Transcript & Summary

Good morning, and welcome to the Serica Energy plc full year results investor presentation. [Operator Instructions] Before we begin, I'd like to submit the following poll. I'd now like to hand you over to CEO, Chris Cox. Good morning to you, sir.

Good morning, and welcome to our full year results for 2024. I'm joined, as usual, by Martin Copeland, CFO; and Andrew Benbow, our Group Investor Relations Manager. Thank you to those of you who have submitted questions ahead of the call. As always, we have a good amount to get through, but do please post any further questions you have during the presentation. Should we not get time this morning, then please contact Andrew directly. We are happy to respond to every question we receive. Martin and I will now run through a presentation and then answer as many questions as we can in the time available. Our usual disclaimer is available for anyone to read. However, while I'm on this slide, it does allow me to also say upfront that, unfortunately, for regulatory reasons, we're not able to comment on or address questions in relation to the possible offer and reverse takeover with EnQuest. We would refer shareholders to what we and EnQuest said in our respective announcements on the 7th of March and also to the dedicated section on our website with all disclosure relevant to this. We start with a brief introduction to Serica Energy, especially for anyone new to our story. We are a significant producer in the U.K. North Sea, with roughly 5% of the U.K.'s domestic gas production coming from our Bruce, Keith and Rhum assets and a total of 10 producing fields in our portfolio. We have a broadly even mix of oil and gas, meaning that we are not overly exposed to the price fluctuations of a single commodity. Our production comes primarily from 2 main hubs with the Bruce hub being predominantly gas and the Triton hub predominantly oil. We have the potential to generate material free cash flow with the Triton hub having tax losses and generating capital and investment allowances from our ongoing CapEx program, which shelter its profits from the high tax rate on the U.K. continental shelf. We have plenty of opportunities in the portfolio to add to our production. Some at Triton, we have seen preliminary results from and others that are contingent resources, which we plan to convert into reserves in coming years. Alongside investment in new wells, our cash generation also supports material shareholder returns. We have returned over GBP 250 million to shareholders through our dividend and carried out an inaugural share buyback in 2024. While we absolutely intend to continue with this track record, and you will note that we have today announced an adjustment to our final dividend in order to rebalance our capital allocation, and both Martin and I will cover this more in our comments today. It is worth adding that we also contribute meaningfully to society and the U.K. economy. And over the last 3 years, we have, in fact, paid over GBP 0.5 billion of taxes to the exchequer as well as contributing to the U.K.'s security of energy supply. In addition, our balance sheet strength bolstered by the lowest level of decommissioning liabilities among our peer group, help support our continued focus on value additive M&A where we continue to evaluate a range of opportunities across the North Sea and overseas. And last, but by no means least, we are always striving to reduce our emissions, which remain below the North Sea average for emissions intensity. The next slide shows our unchanged strategy and business model. The first tenet of which is, of course, safety. This is our top priority, and we absolutely believe that the practices that drive good safety performance also drive good production reliability. So as well as operating safely, what are we here for? We're here to create shareholder value, and we aim to do this by operating and growing a portfolio that delivers free cash flow and support sustained investment as well as growth and returns. When looking at the outer circle, there are some things that I think we do very well and others in which we can improve. I believe, for example, that we excel at subsurface analysis and have a great M&A team. But we need a more balanced portfolio for predictable performance. Safety is always a continuing work in progress and our operational efficiency has been poor of late. However, we understand our gaps, and we know what we need to do to improve. Serica has a history of generating value from mid- to late life assets, and I firmly believe we can continue to create value in this area. I spent a large part of my career working on mid- to late life fields, delivering organic growth and building companies, and there is a tremendous potential here, both organically and with the right market backdrop and M&A expertise to deliver transactional value creation. Our portfolio should be producing over 40,000 barrels of oil equivalent per day on an average basis, and would be if we could deliver even basin average annual uptime. This represents a significant opportunity compared with recent performance. The natural decline rate of our assets is roughly 15% per year but the current Triton drilling program can offset this through 2026 and beyond, with the potential for further work on Kyle or at BKR and possibly Buchan Horst to do the same for the remainder of the decade. As well as organic opportunities, we are also actively pursuing multiple M&A opportunities at present. One, of course, you know about, and as already mentioned, I cannot comment on this further. There are though many other active processes in which we are involved. We will, however, always be disciplined when it comes to M&A. We know that bigger does not always mean better for shareholders. And hence, our focus is absolutely on value creation and cash flow accretion. If the right deal isn't available at the right time, the strength of our asset portfolio means that we do not have to transact. Nonetheless, we are confident that there are things out there which we can get done and that will create value. As we do this, we will not lose focus from optimizing the cash generation to come from our current portfolio. But of course, there's no cash generation without production. And as you are all aware, 2024 was a disappointing year, with 2025 frustratingly for us, and I'm sure for you, starting out in a similar fashion. This graph shows the last 15 months of net production, and it is clear how erratic that has been. The frustration is that as the early results from recent drilling demonstrates very successfully, the portfolio can be doing so much more. As you can see, in the right-hand bar on the graph, the day before Storm Éowyn, we produced over 50,000 barrels a day with over 25,000 barrels a day net to Serica coming just from Triton. While we cannot expect this daily rate to become an annual average, given well decline and normal uptime, it is worth noting that on this particular day, there were, in fact, also wells being worked on at Rhum, that meant BKR was not producing at its full potential. With production still to come from new wells at Guillemot and Evelyn, you can understand why at the time of our trading statement on the 21st of January, we were very upbeat about the possibilities for 2025. And we remain excited about those possibilities. The barrels have not disappeared, and are still in the ground. So let's move on to deal clearly and openly with the issues that have arisen. In 2024, the key issue at Triton, as many of you will be aware, was with the single available gas export compressor. This compressor suffered multiple failures of the dry gas yields during last year, and Dana initially struggled to identify the root cause of the failures. But in December, we believe the cause was correctly identified and fixed and then Storm Éowyn hit. It's worth pausing here to note that we appreciate that people will naturally extrapolate from the issues we've had to questions about the fundamental integrity of the FPSO and how fit for purpose it remains. As you would expect, we and Dana are not leaving any stone unturned when it comes to the FPSO and hence, commissioned an engineering report from Kent Group, which confirmed our view that the FPSO is fundamentally sound. Things that can typically require an FPSO to be drydocked are not an issue. It was built with a double hull and that has been confirmed to be in good shape. And there are no fundamental issues with either the swivel or the turret. The same conclusion has also been reached by another independent third-party study. There are other FPSOs of similar vintage that are functioning well in the North Sea with far better uptime. So we know that we can get Triton into a much better place than we have seen in the recent past. So let me address what is the current issue with Triton. Storm Éowyn caused a crack to open up in one of the onboard crude storage tanks. Now that sounds worse than it is, but these problems occur quite regularly and are normally fixed within a few days. To fix them though, you need to weld inside the tank. And given the obvious ignition risk that this creates, the tanks need to be purged through the injection of inert gas to replace any residual hydrocarbon gases. As this was happening, issues were found with the integrity of the pipe work carrying the inert gas. This was clearly a safety risk, and the path to resolving it has been an evolving situation. Initially, as we announced, mid- to late March seemed an appropriate target for completion of the maintenance. However, following further investigation with all piping and valves in the inert gas system and the venting system to the cargo oil tanks being inspected, it became clear that a more significant work scope would have to be undertaken to replace whole sections of pipe work in this system on the FPSO. It was also necessary to completely empty all cargo tanks on the vessel prior to starting any of the repair work. The schematic on this slide shows the entire inert gas system and the venting system, which essentially runs the length of the vessel, about 200 meters. You may be able to make out sections of pipe in yellow which means they require repair, and a few sections in red, which need to be completely replaced. Although it's not visible on this scale, there are also 30 isolation valves in the system which need to be replaced. We've been working hard with Dana to put in place an appropriate forward plan that minimizes downtime over the course of the year. So we're pleased to be able to announce today that the operators plan is to bring forward the summer maintenance program to begin that work while the FPSO is off-line for these ongoing repairs. This makes a lot of sense. When carrying out a maintenance, it effectively takes a week or so just to purge tanks and shut down operations as well as then taking a similar time to ramp up when you restart. As a result, simply combining the 2 outages saves 2 weeks of downtime this year. By June, we should have an overhauled piping system, a second compressor in place and a much more confident outlook for reliability going forward. Now that we have much more clarity on the way forward, we were able to reinstate production guidance, but of course, there will unfortunately be an impact on our full year annual average guidance. We cannot make up for what will be a loss of Triton production for at least 4 months. Production guidance for 2025 has therefore been amended to between 33,000 and 37,000 barrels of oil equivalent per day. With maintenance work at the Triton FPSO set to complete in June, and no subsequent summer shutdown, portfolio production in the second half of the year is forecast to be well ahead of the annual average guidance figure. I think it is important to explain how we get to these figures. We are keenly aware of our recent failures to meet guidance, and therefore, we want to be very open and clear about our assumptions. The midpoint of that production range assumes that Triton comes back online at the end of June, which is intended to be a prudent assessment of a restart date with the operator currently believing work will be completed at the start of June. The midpoint also presumes 80% uptime of the Triton FPSO in the second half of the year, a figure that we would hope can be bettered. We have built in P90 expectations for our 2 newest wells, which have not produced yet. We think this is prudent, although the drilling results look very encouraging, and the first 2 wells have delivered rates significantly better than the P50. The potential of these new wells is what excites us going forward. As I mentioned, our portfolio is producing over 50,000 barrels a day in January at a time when BKR was operating below its capacity and with more to come from Triton. So let's move on to look in more detail at the new wells. 4 wells have been drilled in our Triton Area campaign, and we are delighted with all of them. In fact, with this program, and the drilling of the Belinda well, which started recently, we are one of the most active companies over the last 2 years when it comes to drilling development wells in the North Sea. And importantly, the program to date has been conducted safely and on time and on budget. To date, due to the issues with the Triton FPSO, only 2 of these wells have added to production. They alone would have offset a year of portfolio decline and 2 more are ready to produce when the FPSO starts up again. While it may be obvious to some, it is perhaps worth clarifying that the drilling operations are completely unaffected by the FPSO issues. The wells are being drilled for Serica and Dana using the COSL Innovator rig and with Petrofac well management. And we have been very pleased with how our contractors and operating teams have worked together so effectively on this campaign. With that, let's look at the 2 new wells that we have not yet reported on. On the right-hand side of this page, we have shown extracts from the ultra-deep resistivity tool, which is a display we have used previously to show the results of the first 2 wells. Red and yellow colors indicate reservoir sands with good oil saturations. The first of these was drilled very successfully with Dana as operator, being the W7z well on Guillemot Northwest. We only have a 10% working interest in this field, and so it will make a minor difference to our production. But as you can see from the diagram at the top right, it has shown similarly promising results to those we saw on our earlier Bittern and Gannet wells. As has EV02 on Evelyn, a field in which we have a 100% working interest. The well encountered 300 meters of excellent quality reservoir mainly at either end of the horizontal section, which should in turn lead to very good production. It is worth noting that the reservoir properties are quite different in the 2 fields, and we, therefore, expected to have a section in the middle of the Evelyn reservoir that was not such good quality. However, the section we encountered at the very end of the well was outstanding and better than we were expecting prior to the drilling of the well. The combined impact, therefore, of the 4 new wells at Bittern, Gannet, Guillemot, Northwest and Evelyn is what really excites us about the potential for the second half of the year. The outcome of these wells continues to reaffirm the value that our subsurface and wells teams working with our contractor partners can deliver from these mature fields. And there is much more to come from the portfolio. In this context, you might consider it odd to be taking this optimistic tone on a slide that actually shows a fall in 2P reserves. The first time Serica has not at least had a 100% reserve replacement ratio in recent years. My optimism therefore, needs a bit of explanation. As, of course, reserves is a metric that we want to see at least remaining flat, if not increasing year-on-year. A large portion of the 2P reduction this year is due as normal to the 12 million barrels of production, with a significant part of the rest being the result of a reevaluation of the 2 Bruce well opportunities already booked in 2P. These are the SCE and SCW wells, which have been in Serica's reserves, in fact, for a number of years. Thanks to a detailed reevaluation of our subsurface team using reprocess seismic, the scale of these opportunities has been reduced, although they are still likely to prove economic. However, the important point is that the process that concluded this was the very same process that resulted in a material increase in 2C resources elsewhere. We, therefore, are not too disappointed by this, where one opportunity now looks less attractive, we now see many new targets, some of which may prove to be more attractive. But these opportunities have not yet reached the level of maturity necessary to be booked as reserves as that requires more detailed analysis and economics. So we are generally excited by the fact that for the first time, we are disclosing a hopper of contingent resources of 89 million barrels, i.e., over 75% of the size of our 2P reserves. What is more, it is important to appreciate that not all contingent resources are equal. And I happen to believe that the quality of our 2C opportunities is such that we can anticipate a high percentage eventually being reclassified as reserves in the coming years. 30 million barrels of our 2C relates to our interest in the Greater Buchan area, including the Buchan Horst development, which is a very attractive project but for which we will need to see confidence in the longer-term political, fiscal and regulatory backdrop before committing to execute. The remainder represents infills or tiebacks in our existing hubs, just the kind of short cycle, quick payback and tax-efficient investment we have been undertaking to date. And as you can see, there are a lot of opportunities from which to choose. This is a complex slide, but its busy nature is indicative of how much we have going on. As we move from left to right across the page, we see more mature opportunities. From exploration and immature concepts on the left to approved projects and existing production on the far right. Our aim is to do the work, analyze and where technical analysis looks positive, move those opportunities on the left of this diagram through the various stage gates to the right. So on the left, we have our exploration assets, including an additional asset, Fynn Beauly, which we will pick up when the Parkmead deal completes and other less mature opportunities. But it is on what makes up the contingent resources and the justified for development columns that I want to now focus. Extending the life of our assets would bring with it an increase in reserves as would further drilling across our portfolio. You will see that there are 3 tubing head pressure reduction projects that we have high-graded in to justified for development this year. These are all no-brainer projects. They are essentially low CapEx projects, which reduce the pressure against which the wells have to flow and hence accelerate production and with it value. We expect to be taking FID on these in 2025 and moving ahead with the projects next year. I also want to shine the spotlight a bit on Kyle. This license in which we have 100% was awarded in the 33rd and potentially last licensing round. As you can see from the map, we picked it up with the intent to establish if it could be rerouted via Bittern into our Triton area. And the more work the team has done on it, the more we like it. It can easily be tied back into Triton via Bittern. With the appropriate fiscal and licensing environment, there is the potential for first oil in 2028, on a project that could be twice the size of Belinda, which is currently being drilled, with over 11 million barrels of 2C resources. Kyle is an example of why the government should revisit the proposal not to issue new licenses. It shows that the industry is still able to generate new projects, which use existing infrastructure, reduce imports and don't add to the U.K.'s emissions. The headline grabbing stories around the North Sea come from the celebrated mega projects in the basin. But is these kind of incremental short-cycle opportunities that are potentially more important for the future of the North Sea. Having looked at the Triton area fields, as we have previously indicated, the same team has been set to work on the bigger sand pit that is BKR. There haven't been any new wells drilled on the Bruce field since 2012, but what was subscale and would not have attracted capital allocation for BP can offer serious material potential for Serica. Our team have carried out a full reassessment of the field, building the first full field dynamic simulation model. As you may be able to see from the map, it has identified a lot of opportunities. The colors are a bit difficult to make out, but in the center of the map, our 2 bluish shapes, which are the SCE and SCW opportunities mentioned earlier. To the top right, there are some orange colored shapes, which are some opportunities which are currently being evaluated and scattered across the rest of the map are a number of reddish shapes, which are immature opportunities still to be fully evaluated. Of course, not all of the opportunities will mature into drill-ready targets. But they will be ranked, and we will select the best ones based on a range of criteria. We will have a lot of choice, which is a nice problem to have. The opportunities in Bruce range from infill wells into areas not drained by the existing wells, potential horizontal wells into a lower permeability layer above the main Bruce reservoir and enhanced production from an oil zone in the southern part of the field. There is still a lot of work to be done, but we expect to uncover more 2C resources as that work is completed. We will mature these through the course of this year, high-grade opportunities and aim to include some in our 2P as we get drilling plans in place for the end of 2026 and into 2027. And now I will pass over to Martin who will talk about our financial results for the year, and update on our balance sheet and capital allocation to help deliver the value we see in these opportunities.

Thanks, Chris. This slide gives a snapshot for key figures from our results announced today, which for the first time for a full year, are presented in U.S. dollars, including a restatement of 2023 in U.S. dollars. Although overall, our 2024 performance was impacted by the well-rehearsed challenges of the Triton operation in Q4, we nonetheless generated strong CFFO after tax of $403 million, which enabled us not only to invest materially in the portfolio with $ 278 million of CapEx and OpEx but also to make very material cash distributions to shareholders in dividends and buyback. The $ 132 million we paid out in the year comprises the 14p per share final dividend for financial year 2023 and the 9p per share interim for FY '24 as well as a $19 million for our inaugural buyback. I will comment further on our adjusted dividend approach later. Finally, we retained our focus on best-in-class ESG reporting and emissions reduction and our 17 kilograms of CO2 per barrel of oil equivalent was better than the basin average. And we are continuing this focus in 2025, including with progressing a flare gas recovery project on our Bruce platform, which will be tied in during the 2026 summer maintenance. Turning to the income statement. Our $727 million of revenues for the year equated to realized prices after hedging of just under $60 per barrel of oil equivalent, slightly down on the roughly $64 per barrel of oil equivalent in '23 and over $100 per BOE in 2022. Lower realized prices also reflected like-for-like volumes down some 2 million barrels largely due to the Triton downtime deferring that production and revenue and a change in the commodity mix with gas at just over 60% of volumes as opposed to 50% in 2023. Although our overall OpEx came in essentially in line with our guidance at $330 million, with the increase in 2023, largely explained by a full year of the post tailwind in large business in 2024. The impact of the lower volume of barrels meant our OpEx per barrel was around $26 per BOE, up from $21 per BOE in the prior year. The P&L tax charge was $68 million, down sharply from $252 million in 2023 as a result of lower pretax profits and rate effects. Our book tax rate of 43% was down from 66% in 2023 due to the application of losses and capital allowances as well as benefiting for the first time from group relief from in-year losses which I will expand on more in a minute. Turning to the balance sheet. The strength of our position and the positive support of our bank group as well has allowed us to continue to invest in the portfolio whilst paying out considerable shareholder distributions in the year and all the time while weathering the impact of deferred production and revenues from the Triton outages. Our adjusted net debt, which removes the accounting impact of unamortized loan fees stood at $83 million at year-end or 0.2x EBITDAX, which is very much at the low end of our peer group, giving us the capacity to invest in the portfolio and grow through M&A. This relative resilience of the portfolio is demonstrated by the fact that our net debt position as of the 27th of March was essentially the same as at year-end. This, despite the fact that we continued throughout the period we spend on our Triton wells program, and that we've had no production or of course, revenues from the Triton area since the 24th of January. Our cash generation year-to-date was helped by stronger Q1 gas prices relative to Q4 2023 and to Q1 2023. With NBP averaging 116p per therm across the quarter and also that our tax computations meant that no January installment cash tax was owing. On which note, another important aspect of our FY '24 balance sheet that I want to highlight is that not only did we have no tax payable this year, but we also have a $71 million tax receivable. This year-end receivable reflects the amount of overpayment of tax through the installment process in 2024. Well, clearly, the outturn on Triton production was not what we would have wished. There is at least a partial financial silver lining from this. The impact of the lost revenues, coupled with strong investment during the year meant that our subsidiaries, which hold our Triton assets ended up generating a taxable loss for the year. This position, which was only determinable following the year-end through our tax computations allowed us to benefit from group relief for in-year losses, which offset tax already paid in advance largely in respect to BKR where we have no tax loss shelter under the ring-fenced tax installment system. The cash impact of this will be reflected in 2025 and will likely be recouped by being set off against tax charges for the July and possibly October tax installments and will go some way to help offset some of the cash flow impact of Q1 2025 Triton outages. Now that -- turning to the next slide, now that we have -- we and our peer group have all reported, we have been able to update our usual analysis to show that Serica remained in a standout position in terms of our decommissioning intensity. The peer group is a group of independent listed E&P companies with material operations in the U.K. Norway or Denmark where they have already released their 2024 results. The table shows the as reported pretax decommissioning provisions, adjusted where relevant, including for ourselves, by disclosed decommissioning related contingent payments or reimbursements. And that all of that divided by the reported 2P barrels of oil equivalent. While the value impact of these future liabilities is typically reflected in NAVs, we nonetheless consider that our positioning does give us greater balance sheet flexibility in terms of lower calls on posting decommissioning security, especially when compared to our sub-investment-grade peers. Back to the topic of tax, which is hard not to spend time on when we remain in the world of 78% headline rate following the additional 3% of EPL that was the gift of the new government bestowed from the 1st of November. The left-hand side of this chart shows how the headline tax rate is built up from the 40% in the permanent regime, to the now 38% EPL on top, but we've also shown where we are on capital relief following the autumn budget. So the CapEx that we are spending on Triton and, to a lesser extent, on BKR still benefits from up to 84.25% capital allowances. And where we can find things that qualify, we can get up to 109% relief. In this category, we are progressing a flare gas recovery project on the Bruce platform, which will be tied in, in 2026. This is a real win-win project in that it reduces our emissions that also qualifies for decarbonization allowance and hence, the capital cost is effectively totally funded by reducing our tax payable at BKR. However, the main thing that we wanted to address on this slide is that in part due to the expected recent production from the Triton area, but also due to investment choices we have made, such as the investment in the Belinda field development, our tax loss balances are now expected to provide a shelter against corporation tax and supplementary corporation tax through the remainder of this decade. Our year-end loss balances remained at over $1 billion with $1.1 billion of corporation tax losses and just under $1 billion of SCT as well as over $150 million of EPL losses. With the latter, the product of our relatively active investment program since the May 2022 introduction of the EPL. We also have just over $500 million of activated investment allowances. Using the simple maths we normally show of applying the relevant rate to the applicable loss balance, these losses would retain $500 million of notional value. So while we continue to invest in the Triton area and thanks to these loss balances, our oil production is largely sheltered from tax even if we have no loss tax loss balances in the entity that owns BKR and the vast majority of our gas production. Thanks to the tax attributes and the tax rebate I've already discussed, we anticipate meaningfully lower cash tax payments this year than we have seen in the last 2 years. Finally, a brief word on the ongoing tax consultation just launched by the government that runs through to the 28th of May. We are engaging direct and in conjunction with our peers and trade bodies on responding to this consultation. However, it is encouraging that many of the proposed features of the new regime look to be aimed at fixing some of the issues with the EPL. The 2 key things that need to be established though are what constitutes unusually high oil and gas prices where the new tax would kick in. And we believe that we need to ensure that the new tax regime does not wait until 2030 to be implemented as is currently envisaged. As we indicated at the time of our January trading statement, we've set our CapEx budget for 2025 broadly in line with 2024. Unlike '24, we have no abandonment activities and expenditure in 2025. The bulk of the program continues to be our Triton well program. We've spent this year on closing out the Gannet GEO5 costs, the Guillemot and Evelyn wells as well as on drilling and completions and SURF activities related to Belinda. We are confident that the strong project delivery and technical success of the wells drilled to date will translate into the kind of highly attractive post-tax economics that formed the basis for our original investment decisions. Once we've seen a decent period of production following the resumption of the Triton FPSO, we are looking forward to coming back to show our shareholders the realized economics of these short-cycle projects, which will, of course, form the blueprint for the exciting future opportunities about which Chris has already spoken. In addition to the Triton wells, we're also going ahead with a range of smaller capital projects on both Bruce and on Triton, which are designed to enhance overall medium-term reliability and resilience. For moving Buchan Horst forward, we are essentially waiting for the outcome of the environmental statement consultation, although the recent statements by Rachel Reeves in relation to Rosebank and Jackdaw are clearly encouraging in terms of where this will land, but the joint venture will also want clarity on the EPL successor regime and its timing. Our investment case remains anchored in the twin tracks of organic investment in portfolio renewal and healthy shareholder returns, supplemented by M&A, where transactions can enhance our ability to deliver more of the same and hence supercharge the investment case. And we intend to deliver this all while retaining a conservative financial frame. As we've announced today, we have, though, taken the decision to adjust our final dividend in respect to 2024 to 10p per share bringing the total dividend attributable for the year to 19p, down from 23p for the prior year. When this has translated into actual pounds, shillings and pence or in fact, U.S. dollars, that means that together with the buyback, we undertook in late spring 2024, the cash call on our business and shareholder returns attributable for the year will be essentially the same for 2024 as for 2023. However, the reason for this rebalancing today is, in part, prudent, reflecting the structural shift in the profitability of the business following the imposition of the EPL in 2022 as well as the continued operational and commodity price volatility to which we're exposed. But our decision is more importantly, to ensure that we can deliver a sustainable continuation of this twin track strategy, balancing the allocation of cash generated by our business between reinvestment and returns. Our load star for capital allocation will remain at least for as long as we retain the fiscal regime that we have on the UKCS right now, CFFO after tax. When we calculate this, we focus on deducting the accounting measure of current tax, as the ring-fence corporation tax installment payment regime can make cash tax swings very material. In this, we will look to retain a level of dividend, which is competitive with our peers in terms of the proportion of CFFO after tax. We may vary the mix between dividends and buybacks, but we'll always look to have a base level of dividend in the mix. We know full well that buybacks divide opinion, but we do believe that there will be times where if we were able, under the regulatory provisions that governed buybacks, it may make sense for us to utilize them. And we intend, therefore, to seek approval to refresh our buyback mandate in our 2025 AGM. And now I'll hand back to Chris for some closing remarks.

Thanks, Martin. So that effectively concludes the presentation, and we want to leave time for Q&A. So I'll sum up very briefly. We look very confidently at 2025 and beyond. We have multiple catalysts ahead, increasing operational efficiency, maturing the exciting opportunities in the portfolio and progressing some of the multiple M&A opportunities also. There is the chance for us to create significant shareholder value. And with that, I will hand over to Andrew, who will run the Q&A.

Thank you very much, Chris. And thank you to everyone who submitted questions. I think it's fair to say we already have too many that we'll be able to deal with at this time. So I'd like to reemphasize, as always, if you do have any questions you feel we don't answer, then please e-mail them to me. I can guarantee that we will reply.

The first question is something we did cover in the presentation, but I think it's worth reemphasizing. And that is Triton so bad and poorly maintained that needs a dry dock shutdown?

Yes, I think we did cover that a bit. Look, absolutely not. We've got a couple of independent reports that say the vessel itself is in good shape. The things that you would worry about typically with an FPSO are the hull, the swivel and the turret. Those are the things that if there's a serious issue, you might have to go to dry dock to fix it and you'd be off station for a long time. And these independent studies show that we don't have those issues with Triton. Where we've had problems is the kit that sits on top of the boat basically. And that's -- it's the same kind of kit that you'd have on any fixed platform. So no, I don't think we've got a fundamental issue with the vessel itself. We do have a problem with keeping production flowing. And that's largely down to -- we need to improve the maintenance and stay on top of it. And that's what we're doing, and that's what Dana is very much focused on.

I think that probably leads quite automatically into the next question then, which is what lessons has Serica learned from the prolonged Triton FPSO outage?

Well, unfortunately, there's nothing new in this. And we kind of knew that stuff like this could happen. When I first joined Serica, I did say we got production issues on both Bruce and Triton. And it takes a couple of years to fix those things. And so I'm not going to sit here and try and tell people that everything is perfect and we won't have any other outages. The fundamental issue is to get good uptime performance, you need to clear your maintenance backlog and stay on top of it. And the pipe work that we are having to repair and replace at the moment on the FPSO, just hasn't been maintained well enough. And it should have been fixed a couple of years ago, and it wasn't. And so now we're playing catch-up. And it's those kind of things that are causing us problems. Obviously, we had an issue last year with a compressor. That's the one delicate piece of kit that we have. Everything else is pretty agricultural and it's simple. It's like owning an old car, if you don't maintain it properly and you don't change the oil, you're going to have problems. And that's kind of where we are. But I'm encouraged that Dana realized this, I think they've got some really good team in place now, actually, who are getting after this and fixing the problems that have been created over the last few years. So yes, the question is about what lessons have been learned. And unfortunately, I've seen the lessons before, and it's not a massive surprise. But we know how to fix this. It's not rocket science. It just takes time.

Maybe just to add. I mean the one thing -- I mean I obviously covered it already in my remarks, but -- we have also learned interesting lesson, which is that there can be silver linings in terms of actual cash generation even when you don't have production because of the impact of -- the ability that's given us to use group relief in year, which is only available for in-year losses, which is not something that Serica has actually had before. So that was actually an interesting lesson and obviously, it was only -- we only really determined that after the year-end because that was the only point at which we could figure out the entities had actually been a taxable loss making.

I think sticking with Triton, we'll try to move on from it in the next couple of questions. And this is probably one for Martin. In light of recent events, is the company actively reviewing its 2025 CapEx priorities, continuing to invest in wells that tie into the Triton FPSO does not seem like a capital-efficient strategy at this time. I think, Martin, if you just touch on capital allocation and Chris...

Sure. I mean look, I mean, hopefully, in the remarks that we put today, we are very confident that these are temporary issues that will get fixed. And I know it can feel sort of all encompassing when you -- when they're right on top of you. But we're very confident that and hopefully have delivered that message clearly today that they will get fixed. So the production that is being -- and the value that's being unlocked by our drilling campaign and the CapEx that's being spent on it is deferred production and deferred value. It's not lost. And clearly, that's recognized not only by our reserve reports, but also our banks, for instance, who are clearly aware of everything and where we are. So no, I mean, we're continuing on with the CapEx, but it's not because we're kind of doing so in a kind of non-responsible way, we completely understand and believe it's the right thing to be doing.

Yes. Just to add to that, Look, a couple of things. Firstly, we're committed to the rig to drill these wells. So even if we stopped, we'd still be on the hook for most of the cost. But more importantly, they still represent incredible investment opportunities. And we said last year that we expected payback on those first 2 wells in 6 months or so, okay, they've not been producing for a few months. They'll be back online in June. They'll still pay out before the end of this year. And the 2 new wells look like they'll have similar potential. So we wouldn't be investing in these if we didn't think it was the best possible use of our cash. And if we had more opportunities as good as these, we'd be sanctioning those as well.

The next question is one that actually, I'll take it can be answered very quickly. Could you provide free cash flow guidance at $70 barrel oil? The answer to that at the moment is that because we're in offer period, we can't provide any free cash flow guidance at all. We can't give any profit forecast. So we have to be very careful on what we say. It's one of the things that when we say that we can't talk about the current offer, it's something we also can't talk about any future guidance in that respect as well. So we will talk about that more in future presentations when we are allowed to because I think we all like the slide we gave that kind of showed our future potential cash flow generation. Another one for Martin here, does the $ 71 million tax rebate get paid directly to Serica or does it reduce the balance of payments in 2025?

So yes, I mean, as we still expect to be a taxpayer, the most logical thing for us to do is just to net it against our tax returns for the installments in July, and depending on exactly how much tax we are in July, it may be some of it into October as well. I mean, in theory, we could go and file for it to be paid back to us now, but we're -- clearly, we're not in a stressed balance sheet position at all. So there's no real merit in us doing that. And so most likely, we'll just net it off our future tax payables.

Another one for you, I'm afraid, Martin, why not hedge more? Is it not sensible to eliminate the risk of substantial falls in commodity prices?

So okay, good questions. We hedge in line with the requirements of our reserve-based lending policy. And we think actually that it's quite well balanced in terms of what it has us do. And there's a slide in the presentation, which I didn't go through at the back shows you exactly where the hedge position is. So we keep topping it up to maintain the level of hedging that's compliant with that. But a couple of other things just to observe on that. On gas, to a certain extent, because our gas is 78% taxed, right? That acts as quite a dampener to exposure to the commodity price. So it's kind of like a natural hedge to a certain extent. And there's also a bit of a risk of overhedging if we're not careful because of that tax regime. So we do -- we don't want to be overhedging either. And then finally, I'd just say that I think our -- many of our shareholders, probably the majority, I think, still want to have a decent amount of exposure to the commodity price. And oddly for us, we've always been seen as a kind of gas company. In reality, we're actually probably more exposed to oil in terms of the commodity. But just to give you figures, we're 40% hedged for our production in 2025 and 20% for 2026 right now.

While you're in full flow, is the change in presentational currency purely to ease comparisons with peers? Or is there anything related to expectations of sales into dollar-dominated markets relative to sterling-dominated MBP?

Well, I mean, basically, as I mentioned, because we -- in our oil production, which I know, obviously, we haven't been producing so much of it because of the Triton issues, but oil is a dollar-denominated commodity, and that is actually less taxed or effect tax on that right now. So our cash flows are probably actually more linked to oil than they are to gas today, and that's a bit of a change for the company. So actually, we probably become a bit more inherently dollar-linked. So that's, if you like, one of the kind of fundamental drivers that reflects that. And in fact, our subsidiary, which -- the Triton subsidiaries that have our oil assets are dollar reporting subsidiaries in themselves. Of course, at the group consolidated level, it's a presentational issue in dollars, and that is in part due to the fact that we wanted to ease comparison because essentially all of our peers report in dollars and it just makes life a lot easier for folks.

Another one, I'll take quickly because someone to ask for an update on the OFAC license. So just that I may have missed the announcement that, that was extended until February 2027. Moving back to one for Chris, I think, which is relating to Bruce and drilling and how things would be done. The question is would you be able to develop more than one of the targets outlined with a single well?

It's -- I mean, we'll look at it. There are areas where we have adjacent fault blocks that we think might not be currently being drained. Whether we can drill a horizontal well that catches both of those is a possibility. So we will look at it. But as you saw on the map, if you could see the colors, mostly the discrete fault blocks that have some gap in between them. So we'll obviously look at that. The other thing I'd say about the wells is, most of those opportunities are likely to require semi-sub to drill, and they'd be drilled as subsea wells. There is potential that we could drill platform wells from Bruce. There is a rig on Bruce that has been mothballed. And one of the things we need to look at is, do we have enough opportunities to justify, putting that rig back in service. And I think if we've got more than 3 or 4 wells that we can drill from it, it will probably make sense because then we could use it for decommissioning as well.

Going back to one for Martin relating to the change in dividend. Should investors anticipate a similar reduction in the interim dividend? And does the change signal on expected increase in capital spending on the existing portfolio in future years.

It's going to be a bit annoying this one because I slightly have to use the same rationale that Andrew just mentioned about cash flow forecast because projecting a forward dividend is also a form of profits forecast and because we're in the position of where we are, we can't do that. So I can't really comment on that other than in sort of generalities. Clearly, at the time, we would come to declare an interim, we should on all accounts have Triton back up and running and everything should be in good order, and we'll -- the Board will obviously look at where we are around that at the time. But obviously, we would expect to carry on normal practice in relation to the payment of an interim dividend. And sorry, what was the second part of the question?

It is about future -- does it mean that you can expect Serica spending a lot more on capital expenditure in coming years?

I don't think it's -- I mean I don't see it's a lot more. I mean, in fact, I think it's pretty clear that 2026 will probably be a -- well, almost certainly will be a lower CapEx period than we've seen in '25 and '24 because we will have completed our existing Triton well program. And in fact, partially because of the actions of the government, which have essentially created a hiatus in really committing to new projects. I think for the whole basin, there will probably be a bit of a dearth of activity in '26, and then hopefully, we'll be able to pick it up towards the end of '26 and '27 is just when you factor in the planning times and the cycle times, let alone us needing and actually to know exactly what the regime is to get approvals, it's hard to imagine that we're going to have to be able to have meaningful new CapEx in 2026.

Yes. While we can't comment much on profits and future dividends. One thing anyone who follows Martin on LinkedIn will know he likes commenting on his politics. So we'll -- let's take one political one. You stated that the 2 key points regarding the ongoing EPL review were: number one, the level at which prices were considered windfall; and two, the implementation of any findings of the review before 2030. Do you not consider a decoupling of the oil and the gas pricing to also be key?

Yes. Sorry, I mean I didn't comment in detail, but actually, I did mention that there are some good features in the consultation. And one of them is that the government understands and accepts that you should separate oil and gas. They've also, for instance, said that the way in which it recognizes prices should be realized prices. So after hedging, which is something that's impacted other companies than ours badly with the current regime. So there are a lot of, if you like, design folks with the EPL that the regime, the new consultation has actually listened to the industry and looks to be addressing. So I think there's a lot to like about it. The reason I called out those 2 things are, it's all very well having all of those other features put in place. But if the level at which they deem unusually high prices is the wrong level. That's a big deal. And then the last point is -- to me, it's kind of fencible to be having a discussion about a tax that might come in, in 2030. We need a tax that comes in now. And I do think that the sort of force of gravity will probably cause that to happen actually but obviously you can't promise.

Moving back briefly on to Triton. And I think, again, we touched upon this. Who will shoulder all the costs, parts and labor for the repairs and costs for getting Triton back online?

Well, the costs are minimal. I mean it's almost nothing. And that's partly because it's just some bits of steel work and some labor. There's nothing complicated about this. As I said, it's quite an agricultural system and there's...

Chris, just it's not nothing, but it's nothing in comparison to what's already budgeted anyway, right? So it's kind of spend that...

It's minimal. This repair work was already planned for the summer maintenance shutdown. So actually, the pipe work that needs to be replaced and all of the valves that are going in are already sitting in a warehouse in Aberdeen and have been for some time. So it's not incremental spend. It's spent that was going to happen during the maintenance shutdown anyway.

We'll take a couple of quick final ones now because we're running out of time. I think OpEx is unchanged in 2025 despite Triton being down for 4 to 5 months. Does this reflect additional maintenance costs? Or is there no savings to be made for not processing output.

Yes. The reality is that the vast majority of our costs are fixed, right? We do have some variable costs related to sort of tariff charges and the like, but it's relatively small, right, in the overall scale of things. Clearly, costs are fixed until they're not, if you sort of mean, but essentially, they're fixed. And of course, just we've just been describing activities going on, on Triton, right, to fix things. So it's still got costs related to it.

Yes. So before we take the final question, just to reemphasize, if you feel the question hasn't been answered or if they have any other questions at any time, then please do e-mail me, [email protected]. So the last question which we've had a couple of times is, what would the production guidance be for the second half alone based on the full year guidance of 33% to 37%. And also, some people have asked, what is the peak production rate that the portfolio could produce?

So I'm not sure. We're okay to give a number for the second half of the year end?

Well, it's kind of inherent in the guidance. Someone has guessed that it could mean if you're flat in Q2 on Q1, and it should be worth pointing out that January did start with Triton production on as well, and we did do 50,000 barrels a day on certain points, then you can come to the presumption that you'll get to production of the kind of early to mid 40,000 barrels a day.

Yes, it will be in the low 40s. I think as a daily rate in January we were able to do -- I think we did 53,000 barrels a day on a good day -- well, that included a bit of downtime on Bruce on that day. And we've got 2 new wells to add. So on a net basis, we could be above 55,000 barrels a day when everything is flowing in the second half of the year.

So I think with that nicely optimistic note at the end of what the portfolio could be doing. I'll pass back over Chris. If you've got any closing remarks, and then thank you, everyone, for taking your time today.

Yes. I think we're right on time. So just very briefly mentioned kind of highlights that we mentioned going through. Look, we had a poor end to 2024, and we had a similarly poor start to 2025, which is unfortunate and we must improve. The good news is we know what the issues are, and we know what it takes to fix them. We just need a bit of time. Meanwhile, we've got lots of really interesting organic opportunities in the portfolio. We probably can't fund all of them actually, so we're going to have to high-grade those opportunities. And we are looking at lots of M&A opportunities alongside that. And lastly, look, despite the adjustment to the dividend today, it still reflects a very attractive yield for shareholders. And yes, I think I'll close with that.

Thank you very much for updating investors today. Can I please ask investors not to close the session as you will now be automatically redirected to provide your feedback in order that the management team can better understand your views and expectations. On behalf of the management team of Serica Energy plc., I'd like to thank you for attending today's presentation, and good morning to you all.