Good morning, welcome to our Capital Markets Day, the first such event we've had since I joined Serica roughly two years ago. It's great to see so many people made it in today, especially on a wet Tuesday with a tube strike. I've spoken to many of you individually, but it's great to have everyone together in one place. Thank you also to those who have been able to join online. Thanks to everyone who submitted questions ahead of time. I hope that you'll find that all of those will be answered during the presentation today. There's been a lot of change over the last two years, both to the portfolio and to our organization. I think we have an exciting vision of the future to share, and that is what we intend to do over the next 90 minutes or so. This is our usual disclaimer. I'll give you plenty of time to read that. There you go. This is our agenda for the session today. As you can see, I'm joined by a number of my colleagues, and they'll be doing most of the talking, thankfully. After I've summarized our strategy and track record of delivering that strategy, Carla Riddell, our Chief Technical Officer, will run through our existing production assets, what I like to think of as the engine room of the business. The production from that engine room is set to generate material free cash flows going forward. Martin Copeland, our CFO, will then discuss what we plan to do with that cash and explain how we allocate capital to create optimal value for shareholders, balancing our allocation priorities between growth projects and direct shareholder returns. Fran Preston-Bell, Public and Government Affairs Lead, will then explain the political environment in which we operate and why in all outcomes we have confidence in delivering value from our growth projects. Finally, Rich Hiney, our Head of Subsurface, will go into some detail on what is of greatest importance to an oil and gas company, the rocks. Rich will share what he and his team have learned about our asset base over the last couple of years and why we are excited about the investment opportunities that lie within them. Finally, we have allowed plenty of time for Q&A once we have finished the presentation. Since I joined Serica, we have been busy on three fronts: adding to the portfolio, high-grading the organic growth opportunities within that portfolio, and putting in place the right team to deliver those opportunities. We have a lot more to do. We are entering an exciting new phase for Serica as we look to continue growing the company and delivering value for shareholders. This is us delivering on our strategy unchanged by the current commodity price environment, and we are pleased to be able to confirm today that we are currently tendering for a rig that could undertake a multi-well drilling program across our assets beginning in 2027 and running through most of 2028. This program will target material reserves and resources that promise short-cycle, rapid development and could add a combined 30,000 bpd of incremental production. This would allow us to deliver annual production of over 50,000 bpd into the next decade. As you will hear, this is tax-efficient spend that we forecast will be more than covered by free cash flow based on our planning assumptions. This, in turn, allows us to introduce a sustainable distribution policy that cements our existing track record of dividends but adds the potential for further shareholder returns in line with company performance. Before we get into those important topics, let me provide a quick overview of where Serica is currently positioned. We are a leading U.K. North Sea company, the sixth largest producer, and delivering over 10% of total U.K. gas production, aiming above all else to do so safely and efficiently and with the lowest possible emissions footprint. Our production is growing. We expect to reach 65,000 bpd by the end of the year, and it is also getting increasingly diversified as our acquisitions complete. Production will come from 25 fields by the end of the year. This production generates material free cash flow, and we already have a robust and tax-efficient balance sheet, recently strengthened by the $300 million Nordic bond issuance. We are set to move to the main market in Q3, and when we do, we will qualify for FTSE 250 inclusion later in the year, ready for our next exciting phase. We are well-positioned to operate in the U.K. North Sea with a robust financial position from which to execute our strategy. This is the strategy that we're executing. It's very simple. It's a two-pronged strategy delivering smart M&A deals and unlocking value from operations and our exceptional subsurface capability. By delivering on this strategy, we believe we can create significant value for shareholders through a compelling mix of growth and returns. This is what we think we can deliver. Growing and sustaining material cash generative production with the potential for annual production of over 50,000 bpd from 2027 into the next decade. This growth comes from low risk, short cycle projects, infill drilling and tie-backs, not large multi-year projects. Of course, this is not the extent of our ambitions. M&A remains a key value driver, and we have plenty more to do. This will be delivered by a highly experienced management team. When I joined Serica two years ago, there were certain gaps in the organization that needed to be filled, and we have strengthened Serica's organization capability to ensure we have people in place to support the company's next phase of growth while retaining our entrepreneurial culture. We've made a number of targeted senior appointments across a number of areas, which has materially improved our decision-making, our talent management, and our ability to deliver for shareholders. The final piece in that jigsaw is the hiring of Scott McGinnigal as COO, bringing a wealth of experience of North Sea operations across major operators. Scott joins us on the 29th of June. I would like to thank Mike Killeen for his tenure as COO over the last two years, and I'm very pleased that he will now be switching to lead our critical West of Shetlands business unit. Stephen Lambert, who many of you will know, has also elected to step back from the frontline, although we're very pleased he will still be supporting us in a part-time role, at least through the end of the year. Alessandro Agostini will be picking up Stephen's commercial responsibilities on the Executive Leadership Team, in addition to his non-operated assets role. John Stockdale, our General Counsel and Company Secretary, will also be joining the Leadership Team. The result is a Leadership Team that is strategically aligned and better equipped to manage the scale and complexity of our enlarged asset base and is ready to deliver more. We also have a first-class board with the right level of experience and expertise to guide and challenge. We are well set for the move to the Main Market and the FTSE 250 later this year. As you can see, Serica has been delivering on our strategy. We have consistently grown our reserves and resources. We are set to have tripled production over the last five years by the end of this year, run in a financially sound way that has delivered material returns to shareholders. In total, over GBP 300 million has been returned to investors since Serica started its dividend policy. We intend to run the business in such a way that continues to deliver material investor returns. As we deliver a mix of M&A and organic growth investment, we're aiming to continue this upward trajectory alongside shareholder returns. We are proud of our track record in M&A, with a great team that is able to identify and execute value-accretive projects. From BKR to Prax and Spirit, we do smart deals, moving swiftly to capture opportunities, typically investing in a way that the sellers are not prepared to. The deals announced last year will have resulted in cash coming into the business on completion and were immediately value accretive, as well as adding to our growth options going forward. Although the pace of M&A may be slower this year because of market conditions, we have not changed what we are looking for, cash flow and credit accretive deals where we can add value through the drill bit and through smart structuring in the North Sea and beyond. Once we acquire an asset, we know how to create further value. I'd like to take a couple of minutes to share two examples of that. Firstly, our Bruce-Keith-Rhum complex is a great example of how a focused and diligent operator with low overheads can squeeze more out of mature fields. Since taking over operatorship, we have extended the productive life of BKR by 10 years and seen a fivefold increase in combined reserves and resources. This has been achieved through a combination of sensible cost control and a very hands-on approach to managing the well stock. Every single well has had the benefit of at least one workover intervention during Serica's ownership, some of which help to maintain the well's existing production, some of which add new production from different sand intervals. This is a very different approach from the previous operator, BP, who anticipated decommissioning the fields this year. We now see production lasting at least into the 2030s. That is before we even consider the potential for drilling new wells in these fields, and more about that drilling to come later. One area where we have drilled wells in previous years are the fields which tie into the Triton FPSO. Where our subsurface and drilling teams have achieved spectacular success. Last year saw the completion of a five-well drilling program with outstanding results. Delivered on time and under budget, each well is set to add significant production, with all of them delivering initial production rates of over 5,000 bpd. A great achievement. This means we have significant latent production at Triton that is set to mitigate natural decline over the next several years. This is the kind of success I am confident our subsurface team can deliver across the portfolio. Before you hear about that, I will invite Carla to describe that engine room, which today generates the cash, which gives us the capability to reinvest. Carla? Thank you, Chris. For those of you who don't know me, I'm Carla Riddell, Chief Technical Officer, I joined Serica in September last year. I'm responsible for the business' technical function, which includes subsurface developments and engineering departments. I come from a technical background as well, myself as a geoscientist and also in asset management, having worked across the U.K. Continental Shelf for operators such as Centrica and Spirit Energy. What I want to talk about are the solid foundations that Serica is built on. It's our assets and the subsurface resources that underpin them. We have a robust reserve base. These images illustrate with reserve life running into the middle of the next decade. The Bruce and Triton hubs remain our key areas, both for reserves and for production. However, the acquisitions announced last year have significantly diversified this and bringing in new U.K. continental shelf assets and basins into our portfolio. We've retained our broad balance between oil and gas, slightly weighted towards gas, and the Spirit acquisition, which completes later this year, brings in more gas too. After which, gas will constitute 54% of our reserves. This diversity is also in a mix of production and development. As you saw from Chris's slide earlier, we have materially grown our 2C resource base. You may have heard us say in the past, not all 2C resources are equal. I want to really focus on the short cycle rapid return projects that we have in our portfolio. The doability is there. These are low complexity, simple developments with minimal additional infrastructure. These are projects that can efficiently deliver reserves replacement, contingent resources, 2C that can be converted into 2P reserves, production, and cash flow. We're opportunity rich, and the growth and diversity in our asset base is also reflected in the diversity of our resources. You'll hear more about this from Rich later on. Of course, it wouldn't be possible to talk with such excitement about the new projects that we're maturing without the confidence in the robust cash flow from our existing base. This forms the bedrock of the growth. 2025 was a disappointing year for us, driven by issues at Triton. 2026 has been more robust and stepped up in Q2. This production is a better signifier of what our portfolio is capable of delivering, with production rates close to 50,000 barrels of oil a day in this period. Volumes will increase further as acquisitions complete, especially production from the Spirit Energy portfolio, the green slice on this graph. After completion, we'd expect production to be around 65,000 bpd. This isn't a stretch target, it's what we would be producing today if all acquisitions were complete. We continue to grow our production from that of 2025 simply by the greater stability in production from our core assets we're seeing today. This all starts with the Bruce hub, our cornerstone. It's an example of the right asset in the right hands, how it can be optimized to deliver for shareholders and indeed for the U.K. It's an asset that potentially would have moved into the decommissioning phase under its previous owners. It's still delivering material production right now. It has additional life extension opportunities above the ground and significant volumes of gas under the ground available for extraction through infill drilling. When it comes to base production from existing well stocks, they're more to give there as well. On good days, Bruce will produce over 20,000 barrels consistently. All too often we see it doesn't get there due to unanticipated operational issues and repairs. Investment in reducing the maintenance backlog is paying off, and we're seeing that greater stability. Renewed focus can deliver incremental improvements, and this year we've looked at building on production stability by chasing marginal gains to get closer to the 20,000 bpd stability. By focusing on production optimization across the organization, we've launched a program called Meet It Beat It, an initiative where as well as our technical teams evaluating, we've looked to those who know our assets best, our people, for ideas for optimization, which is now paying off. On Bruce already, we have a number of wells back online just by thinking differently to solve our challenges. Production stability has also been taken through to the operational regime, optimizing the process of bullheading. This is where we use high pressures to push back the liquids that fill up the wellbore into the reservoir. It gives a period of efficient dry production at enhanced rates. What was originally a test is now part of a cyclical process in how we operate our wells. We've also recently commissioned a new flare gas recovery system, taking gas that would have previously been burned as flare back into the production system, reducing emissions, also providing additional production. This project is cash generative and benefits from the highly attractive decarbonisation tax allowance. There's plenty more to come from Bruce, and we are committed to delivering it. Extending production potential well into the next decade is also the focus on Triton. Here, the recent drilling campaign has completed with production from those wells to follow. The extensive maintenance program in 2025 addressed problematic pipelines, a host of critical remedial work totaling 14,000 hours, valves replaced, joints replaced. There's still more to do. The operator, Dana, has made significant changes to the team as a total revamp in policies and procedures. The focus has been on doing the basics right as the foundation of achieving stability and operational performance. We are comfortable with our alignment with the operator. They're doing the right things and are focused on the same goals as us. That is extending asset life, stable production from recent wells, and providing further potential for tie-backs in the future. There's more to be done. There's a planned shutdown in Q3, as we've already guided. That's set to be over two months. There's more investment there in stability-enhancing activities. A walk-to-work vessel is already on station. This takes the number of people on board up by 20%, but significantly more people available to be liquidating work scopes both at day and night shifts. Things are looking a lot better for Triton. Production is currently stable. As you can see from the production chart on the slide, this has averaged around 20,000 a day in Q2 to date, with an impressive 95% uptime as a result of operational stability. This stability is coming from a more disciplined approach to fault-finding and predictability, allowing early interventions. Operations on Triton are currently being run on one compressor, where the focus has been around maintaining stability. The second other compressor is functional, serving as a backup to support and step in. While two compressor operations would accelerate production potential, we're learning a lot about the optimum production regime right now and what's still to come from the wells drilled over the past couple of years. The focus rightly remains first and foremost on securing stability. On Triton, we have substantial tax losses to offset, making this source of production especially valuable to the Serica Energy bottom line. On to our next hub, a step into a new basin for Serica Energy that's the most prospective in the whole of the U.K. CS, the west of Shetland. By bringing the Shetland Gas Plant and the Greater Laggan Area into our portfolio, we've added additional production from GLA averaging around 4,500 BOE a day. We look forward to taking analysts and investors there in due course. I can confirm that the Shetland Gas Plant is as shiny and new close-up as it appears on these photos and videos. You can see that in the excellent operating efficiency and uptime of over 90%. After completion of the GLA acquisition on the 26th of March, and while the Lancaster field was producing, our production from the West of Shetland was at rates of over 10,000 barrels equivalent a day. Lancaster ceased production as planned on the 3rd of May, with production over 66% above forecast, and the last oil lifting attracting a premium to Brent and GBP 56 million. The field has now moved into the decommissioning phase, there's minimal infrastructure for removal and the opportunity to execute this in a cost-effective manner as part of the drilling program for which we are currently procuring a rig. The current West of Shetland production is what we hope to be just the beginning for our interests in the basin. Our positioning with SGP provides an enabler as critical infrastructure for the U.K. gas strategy in the basin. In our portfolio, the Glendronach development and a fourth well on Tormore both offer exciting potential opportunities to grow equity production, simple and rapid ways to access known volumes. Further classic examples of the right assets in the right hands, as these already assessed upside potentials with low subsurface risk simply did not screen for capital allocation from the previous owner, TotalEnergies. The West of Shetland is the most prospective basin in the UK CS. There's an estimated five TCF of discovered and prospective gas resources. Much of this is in the catchment area of SGP, and some of it sits within Serica-operated acreage, the blue on the map. Third-party throughput is already benefiting Serica and our partners in GLA by sharing operating costs at SGP, which are largely fixed, and sharing them across the volumes going through it. It's not a theoretical concept. The Adura-owned Victory gas field started producing via the Shetland Gas Plant in September last year, significantly reducing GLA partners' share of the plant's operating cost and extending the economic field life of the fields. Negotiations for processing of another third-party new field, Tornado, are advanced, with potential startup by 2029. We look forward to being open for business for further potential beyond Tornado in the coming years. It's this potential that we saw when we made the acquisition last year. We're working to diligently mature opportunities and turn that potential into reality, and value for Serica. Indeed, to materially contribute to the U.K.'s energy security. Look to another new basin for Serica, the southern North Sea. We look forward to adding 15% stake in Cygnus Field, a strategic asset with future potential and one of the U.K.'s largest producing gas fields. Cygnus has a high uptime, low operating costs, and low carbon intensity. Importantly, there's an active drilling campaign ongoing. The addition of around 13,000 bpd from the Southern North Sea. The transaction terms themselves include Spirit Energy, the seller, retaining liability for the costs of decommissioning of the operated portion of these assets. Serica will gain the experience of efficient decommissioning by managing the execution, something which can be deployed as and when needed in the future. Finally, onto our other producing assets. It provides us with diversification and cash flows away from our main hubs, and this includes Erskine, Columbus, and Orlando. The latter is set for cessation of production in the first half of next year. We're delighted to be adding to this part of the portfolio with the imminent completion of our latest deal, which will conclude in the middle of this month. 10% interest in the Catcher area and 5.21 in Golden Eagle GEAD development. Currently, together, these are producing 2,500 BOE a day. Another great addition to the portfolio and delivered by a busy M&A team. In summary, our producing assets deliver robust cash-generative production, and there's plenty more to come. Over to Martin to discuss our philosophy of how we allocate this capital. Great. Well, thanks, Carla, good to see everybody here. Before I walk through our capital allocation framework in detail, I wanted to give a brief update on our balance sheet and the actions we've taken and are continuing to take this year, all of which have been very much in support of the delivery of the medium-term plan we're laying out today. Following the very successful completion of our inaugural Nordic bond, which priced at a highly competitive seven and seven-eighths, we have $300 million of total debt all through our bond, having now repaid drawings under our RBL. With a cash position of $228 million as of the 31st of May, that gives us net debt of just $72 million. A net debt to EV ratio of approximately 5%. That is conservative by any measure. It has also come down materially from the $200 million net debt position we carried at the end of 2025. With what we know will be a strong cash generation month in June, including the completion of our ONE-Dyas transactions in mid-month, we remain very much on track to be net cash when we report the half year in early August. Once we conclude our RBL refinancing in early Q3, we will also have no scheduled amortization until 2029, and the bulk of our debt, in fact, not due until the bond maturity in 2031. However, the more important development underpinning our next phase of growth is the very material liquidity we enjoy today. Combining our cash balance with the $456 million of undrawn but committed capacity under our existing RBL gives us $684 million of total group liquidity today. We manage the business on the basis of a minimum liquidity floor of $200 million, sized to be roughly half our annual operating cost base. The material headroom above that level that we have today is deliberate. It supports our confidence to embark on the next organic CapEx phase whilst also remaining opportunistic in M&A and ensures our ability to sustain this investment together with the base dividend through commodity price volatility. Aside from the bond, we have two ongoing corporate finance work streams, which we expect to conclude in the coming weeks. We are very advanced in refinancing our RBL, and I'm pleased to say that we've seen strong appetite from our existing bank group, quite a few of whom are in the room today, and a number of our new banks to support the refinancing. We are aiming for a $500 million facility, essentially the same as today, but we'll also expect to add a $250 million LC tranche, affording us better flexibility in posting DSA security for our enlarged portfolio. As is typical, we also expect to have an accordion feature of up to the full $750 million facility size, facilitating further M&A-led growth over the coming years. We are also progressing well on the necessary steps for our move to the main market, which we target completing in Q3. Turning now to the structural frame around our approach to capital allocation. This slide portrays the philosophy that underpins how we prioritize the different calls on our capital, and in particular, how we intend to balance investment with shareholder returns. Three overarching principles guide our approach. The first is, of course, the essence of what we're about as a company, creating shareholder value, but always without sacrificing balance sheet strength. We are acutely aware of the dangers of a stretched balance sheet. Given the volatility of commodity prices and the range of other risks we face in terms of tax, regulatory, operational, subsurface, and costs, we recognize that although debt should form part of an efficient balance sheet, retaining low leverage and ample liquidity would allow us to create shareholder value without hindering our strategic flexibility through an overstretched balance sheet. Recognizing the importance of this, we are today setting out more detail of the financial guardrails we impose on ourselves. These have been designed specific to the current U.K. tax regime and include a through-cycle leverage limit of net debt to EBITDAX of less than 1.25x and the $200 million liquidity level I just referenced. We also see prudent hedging, which we believe our RBL-mandated levels represents, as important to protect the base. Even if, at times like we've seen recently, it can be frustrating to forgo a degree of upside. The second overarching principle is that we believe the investment case for an E&P company like Serica should, of course, be to deliver growth, but to do so while also offering shareholders a reasonable ordinary dividend, which we see as demonstrative of financial discipline. Managing the business to deliver a stable ordinary dividend is consistent with allocating capital with a long-term mindset and keeping shareholders front of mind in every choice we make. Accordingly, today, we are introducing for the first time a distribution policy comprising a base level within the context of a payout ratio frame, the details of which I will return to shortly. The third principle is that we continue to want to grow the company, not simply to offset natural decline. The reason for wanting increased scale is not size for its own sake, but because greater scale translates into a higher quality of earnings and more reliable cash flow generation, which in turn translates into a low cost of capital, and hence, we hope, a better valuation. We're not setting an explicit production target, but what we can say is that we're aiming over time to reach a BB-type credit rating, which requires both greater scale and commitment to the kind of disciplined financial metrics we're introducing today. M&A, prudent organic investment, and a move to the FTSE 250 are all of a piece with this direction for the company. Consistent with these three principles, creating shareholder value, delivering a stable dividend, and growing the company, the capital allocation pyramid sets out our order of priorities for the allocation of our post-tax cash flow from operations. The foundational non-negotiable call on capital is the spend required to maintain our license to operate. Maintaining safe and reliable operations, investing to ensure the continued resilience of base production levels from our key hubs, and the investments in regulatory compliance measures, such as our emissions reduction action plans that bring our assets into line with the OGA plan. This spend is targeted at and sized to support our objective of extending the life of the key hubs at least until the mid-2030s. Above that comes what we think of as protecting the base. This is about ensuring that we maintain a conservative balance sheet, but importantly, also protecting the base dividend level. From that solid core, the next priority is growth, both organic CapEx and M&A. This sits squarely with our principle of growing the company. I'll give more color on how we triage opportunities in a couple of slides. After these priorities have been met, consistent with our shareholder distribution policy, we retain optionality for further distributions. Our policy provides for up to 30% of post-tax CFFO to be paid out in the form of further dividends or buybacks above the base dividend. As the pyramid makes clear, only after the strategic priorities have been met. The message of our capital allocation philosophy, I hope, is simple. License to operate and balance sheet strength first, a stable ordinary dividend second, investment to sustain and grow long-term value third, surplus capital return to shareholders where it's responsible to do so. We believe this framework should appeal to all investors. For equity investors, it provides visibility, discipline, and meaningful participation in upside. For credit investors, it shows that distributions are governed by clear financial guardrails and that resilience is prioritized over short-term payout maximization. Striking that balance is central to how we intend to create durable shareholder value over the long term. Having set out our overall philosophy, this slide unpacks what protecting the base means in practice. It comes down to three things: maintaining a robust capital structure, ensuring we always have ample liquidity, and implementing a disciplined hedging program. Guardrails which, taken together, protect both our operations and the base dividend. We follow three principles in our hedging program. First, downside protection. We hedge specifically to protect our cost base, including the payment of the base dividend across the cycle. Second, disciplined implementation. We layer the program over time, consistent with our RBL requirements. These vary with levels of drawing under the RBL, with our current level of hedging reflecting the pre-bond levels of RBL drawings. Third, we favor costless structures, very largely in the form of collars, in preference to options that require premium payments, so we're not paying away cash flow for the protection. The charts show the level of our current hedge book, including showing the bank price decks, as protecting floor prices above bank price decks boosts our borrowing base and hence our liquidity, and this effect is more acute in gas than in oil, where the delta between bank price decks and market is especially wide. As we indicated at the time of our results, we remain roughly 60% hedged in 2026 and 50% in 2027. We have also included our normal updated hedge tables in the appendix of the materials. This slide describes how we evaluate growth opportunities against a single consistent investment framework. The process we follow is largely in line with industry norms, we aim to undertake a holistic assessment on a risk-adjusted returns basis for both organic investments and M&A opportunities. We do not have a single threshold measure, rather we look across the full set of considerations and strategic objectives. Importantly, we do so on a basis which is tailored to the specifics of the UKCS operating and tax environment. The framework itself has three lenses. The first lens is assess, the evaluation of the project or M&A opportunity economics. Here we look at the full range of standard financial and industrial yardsticks. We look at all of them, not selectively, because every metric tells you something different about the shape of the returns. As we indicated in our RNS this morning, we're confident that the program we are planning can deliver IRRs in excess of 40% and rapid payback based on our planning assumptions. The second lens is frame, how the investment fits into the portfolio and our strategic objectives. This lens covers fit with the prevailing macro and regulatory environment, how it works with our existing portfolio, as well as the potential for synergies and the opportunities that may be unlocked. The Bruce wells we are planning illustrate this through the impact they have on the hub economics and asset life extension, but also in their ability to unlock a further phase of drilling in the north of the field. The third lens is risk, the assessment of all risks inherent in determining a risk-adjusted view of value. We look across HSE, subsurface, project execution risk, operational, including JV dynamics, infrastructure risk, and especially importantly today, we consider regulatory and of course, fiscal risk. You will hear more from Rich shortly on the opportunities being matured for possible sanction later this year, and against which this framework is being applied as we finalize the 2027 to 2029 drilling program. Our M&A track record is one of Serica's key strengths, as Chris highlighted earlier. We're proud of our execution in this area, not least in the deals we announced in the back half of last year and are completing this year. Deals that have transformed the scale and diversification of our business, bolstered our pool of strategic tax losses, and will end up with us not paying out any consideration on their completion. We are equally proud of our reputation with sellers as a straightforward, consistent and reliable counterparty. You can therefore expect us to continue to be active in M&A as the main route to meeting our growth objectives. It is, of course, always hard to say too much about M&A objectives for obvious confidentiality reasons. We did want to give some pointers to the kinds of situations we're looking for. Above all, we're seeking opportunities that fit with our strategy, allowing us to create and capture value transactionally or from synergies of the deal itself, but which also bring with them further potential to unlock or create added value through the combination of subsurface and commercial skills. Although we're not wedded to this, we prefer operated high working interest positions as they afford us greater strategic flexibility to unlock such value at pace. As you've heard from Carla, we see our position in the GLA, including the interest in the Shetland Gas Plant, as just the kind of situation where we can deploy this strategy in practice. While it remains a work in progress today, we are actively trying to unlock an opportunity for material value creation for Serica, resulting from the change of ownership and operatorship of the GLA assets from TotalEnergies to Serica. This comes from precisely the combination of impacts we like to see in a mid-life asset like GLA and the SGP. The opportunity to move forward with infills and tiebacks that did not make the cut on a global basis for TotalEnergies. The opportunity, supported by our O&M partner, PX, to realize efficiencies and cost savings in plant operations. Combined with the opportunity for what we hope will be a mutually beneficial partnership with Adura and Ithaca on Tornado and the subsequent fields in the West of Shetland Gas Corridor. We look forward to updating the market on each of these steps in due course as they crystallize. We apply the same assessed frame risk framework I described on the previous slide to M&A opportunities. We seek a risk-adjusted return above our cost of capital from completion, and the risk dimension includes deal structure, such as the decommission retention we have in the Spirit deal, or the very low to zero completion payments resulting from historic effective dates seen in all our 2025 deals. It equally applies to the pre-planning and structured implementation of integration activities, which we've been rolling out sequentially as we complete on the various deals during this year. In terms of the type of deals we expect to see, we think 2026 will be quieter on M&A, and especially on cash deals, as high and volatile prices, combined with the wide discrepancy between forward curves and fundamental commodity price expectations created by the Iran war, will tend to make buyer and seller alignment very challenging. We do see the possibility for more relative value deals, including possibly share-for-share deals, that allow us to advance our strategic objectives. For the right deals, we would be willing to use a combination of our shares and cash as acquisition consideration, but also where we are confident, based on our diligenced investment case and synergies, that we can show NAV and cash flow per share accretion. In terms of geographical focus, we've consistently communicated that we would like a presence in another region. Our rationale for this is largely one of continuing on our pathway of diversification and higher quality of earnings through also diversifying away from U.K. basin maturity, political and fiscal risk. Although by its nature, we believe it's important to remain somewhat flexible and opportunistic to be successful in an M&A strategy, we do want to hunt in places where conditions are ripe to continue our approach of unlocking value from mid- to late-life assets, ideally acquired from majors. One such region that we think may fit this playbook is Southeast Asia. We are already pre-qualified by PETRONAS in Malaysia, for instance, and our team has been spending time building our network in the region and screening opportunities. We believe that we've demonstrated the capability, discipline, and deal structuring judgment to be an active and value-creating acquirer. We expect to continue in that vein as a key enabler of our growth ambition. However, we were patient when we believe the price is not right, but also decisive when the opportunity is right. Turning now to rewarding the shareholders. In common with a number of our peers, we are today announcing for the first time for Serica, a shareholder distributions policy that we believe positions the business well for the future. The policy from FY 2026 is expressed as a payout ratio of post-tax CFFO. Importantly, we expect that in most circumstances it should deliver no reduction in our payouts and indeed afford the potential for higher distributions over time. As the chart on the left shows, since we began paying dividends in respect of FY 2019, we've paid an average of 25% of our post-tax CFFO in dividends, and hence the 15%-30% range we are introducing today sits comfortably in line with past practice. Our intent, as illustrated by the right-hand side of the slide, is to maintain a base level of dividend that is sustainable through the cycle while retaining the option to give shareholders meaningful participation in increased distributions in periods of higher prices and elevated cash flow. Although the cash flow numbers shown on the right-hand side of the slide are illustrative, at the midpoint of our 2026 guidance put out this morning of GBP 470 million-GBP 520 million post-tax CFFO, a GBP 0.16 dividend would correspond to around 17%. We intend to maintain the base dividend level unchanged at GBP 0.16 per share. In years of stronger cash generation, we would aim to supplement that base dividend with a mix of additional dividends and possibly buybacks, potentially up to the maximum 30% payout range. We've set the range with reference to post-tax CFFO because we see that as the point in the cash flow statement at which capital allocation decisions are made and prioritized under the philosophy I outlined earlier. We believe that the 15%-30% range allows us to balance the calls on that capital between organic investment in the portfolio, servicing our debt, and giving a fair reward to our shareholders. We do not want to be too prescriptive on where we will land within the range in any given year, as it will depend on a number of factors decided at the time of declaring the final dividend, including where we are in the wider capital allocation context. When growth CapEx or potentially in future deleveraging is the priority, we would expect to be at the lower end. When those calls on capital are less pressing, shareholders can expect us to be looking to be at the higher end. In all cases, our intent is to maintain the base dividend and to supplement it with additional supplementary dividends or buybacks rather than to flex the base itself. This final capital allocation slide brings the framework to life by showing the relative scale of how we expect post-tax CFFO to be deployed over the 2027- 2029 three-year plan period. It is illustrative rather than prescriptive, as the actual mix will move with prices and with the evolving opportunity set. We hope it gives a clear picture of the shape we currently expect. Starting from the left, post-tax CFFO is 100% of the funnel based on current market consensus commodity prices, which are set out in the appendix of the materials and our current hedge book. It is, of course, worth noting that there is a bit of a feedback loop between the amount of post-tax CFFO and the CapEx choices we make, as capital allowances created by our CapEx serve to reduce tax spend and hence boost post-tax CFFO. From this total, we first meet certain fixed obligations such as interest and any abandonment expenditure spend, as well as some residual contractual M&A consideration payments we have. We then see the largest spend being on CapEx, but split between resilience and growth spend. The resilience or maintenance CapEx, combined with some of our operating costs, is effectively our license to operate and sustain our hubs into the middle of next decade. We are then projecting a little under half allocated to growth CapEx based on what we see as the most likely configuration of first-phase projects from those that Rich will run through shortly. That leaves healthy free cash flow before distributions from which we pay base dividends and under this scenario, have spare cash which could be distributed or retained depending on broader circumstances. Under these planning assumptions, we are able to fund the program of investments and base dividends from internally generated cash flow. We will, of course, also retain the ample liquidity buffer that I outlined earlier, and hence we are confident that we have a good strategic flexibility to capitalize on M&A opportunities and to deal with commodity price variability and other eventualities. Over the 2027- 2029 plan period, our intent is clear: deliver production at levels in excess of the 2026 annual average level, generate free cash flow in every year at the plan price deck, pay an annual base dividend of 16P per share, retain the ability to pay additional distributions, and preserve meaningful optionality for M&A opportunities consistent with our strategy. Before I close out my section and hand over to Fran, I want to spend a moment on detailing the key features of Serica's tax position, which remains an important part of our investment case. Serica more than doubled its tax loss position during 2025, primarily through our Prax Upstream acquisition, but also generated more as a result of the Triton issues during the year. We had RFCT and SCT losses of roughly $2 billion each, as well as roughly $500 million of EPL losses, all as of the 31st of December 2025. We've included on this chart our normal approach of showing the aggregate value of these tax attributes amounting to just over $1 billion on a notional basis. This value assumes we'd use the losses all in one year, which of course, we cannot. Our loss balances are reasonably evenly spread across the subsidiaries holding our Triton assets, as well as the entities into which we've acquired our GLA interests, the Catcher and GEAD stakes, and where we will acquire the SNS assets from Spirit Energy. Importantly, we do not have any losses in Serica Energy UK, which is the entity which holds our Bruce, Keith, and Rhum interests. That means we expect our 2026 activity there will be taxed at the full 78% rate, it also means that if we proceed with the planned Bruce infill wells, that CapEx spend is highly tax efficient, being relieved at up to 84.25%. Across our planned investment program, which spans subsidiaries with varying tax positions, we estimate that under our planning assumptions, roughly 65% of the pre-tax CapEx spend will be sheltered by the application of first year of the decade. Our planned investment program at Bruce is the most efficient offset to tax payments from those assets, and we still retain ample loss balances, which should enable us to remain competitive in possible U.K. M&A deals in the coming years. With that, I will hand you over to Fran, who is the expert in Westminsterology to cover what we're expecting in terms of government policy developments, including, of course, the new OGPM tax. Thanks, Martin, and good morning, everyone. I'm Fran. I'm the public affairs and government affairs lead at Serica, and I joined last September, after working for the Trade Association on Fiscal Policy. U.K. politics continues to make front page news. In fact, I think it probably always will make front page news. From rumored leadership challenges to inflection points on policy, both in our sector and actually across the economy. It's hard to believe that we aren't even two years into Starmer's premiership yet, and we're less than 500 days since President Trump's inauguration. I think that may be today. Happy 500 days. Navigating and positioning Serica well in this environment is important, and it's something that we continue to be really focused on to deliver shareholder value. Many of you will have followed the tax changes the sector has faced over recent years. Since the Energy Profits Levy was first introduced, it's been tweaked several times by the former government and then this leadership. Thankfully, though, after lengthy debate and consultation spanning two governments, in November last year, the Treasury announced they would be introducing the Oil and Gas Price Mechanism or the OGPM. They committed to introducing that by 2030 or earlier if the thresholds were triggered. This is a novel tax for the UKCS, and this government intends to apply this indefinitely. The OGPM, whilst described as a windfall tax, is actually very different to how the Energy Profits Levy works. OGPM is only taxing the revenue generated above GBP 90.90 a therm for gas, and it's charged at 3% lower than the current Energy Profits Levy rate. The difference in tax base is therefore significant. Under OGPM, it is only that delta between prices realized and the GBP 90 or GBP 0.90. EPL taxes all allowable profits. The other important distinction is that OGPM will only apply in specific price scenarios because of that GBP 90.90, EPL is always applied. This means, as Martin showed, we don't bake OGPM payments into the long-term planning the same way as EPL. We continue to push this government that OGPM should be introduced as soon as possible. The comments that the Chancellor made in March, that some of you might have seen, followed engagement with Chris and other senior leaders in this sector, it's one that we will be holding them to. We all know that the introduction of the OGPM would be a helpful confidence boost to the UKCS, the supply chain, but also a net positive for the UK Exchequer. It's fair to say that the sector is changing. The international names we used to associate with the North Sea have left or decreased their presence, paving the way for more agile and U.K.-centric operators like Serica. That change in ownership and consolidation means the top players are now only focused on the UKCS. This creates significant opportunity for pace around decisions and greater alignment that will be beneficial for Serica but also the U.K. We know that the U.K. needs oil and gas and will do for decades to come. The Prime Minister has said it, the Chancellor has said it. Even the Secretary of State for Energy, Ed Miliband, has said it. We also know that the remaining opportunity in the UKCS is well within the Climate Change Committee's net zero aligned demand profile. A Rystad Energy report published recently even highlighted that the majority of that potential is currently sitting licensed and in the hands of operators. In this environment, with the backdrop of ongoing geopolitical pressure, the case for domestic and secure energy production is significant. Serica and others will continue to be an important energy partner for the U.K., with our current portfolio responsible for production facilities that support over 10% of U.K. gas production. We are a leading producer. We can continue to provide significant value to the U.K. through both production, jobs, and economic contributions. As Martin highlighted, we all know, the tax story is only one part of the policy architecture that we face in the U.K. In addition to fiscal policy, the regulatory environment is also an important consideration when looking at projects and how they might progress through those frameworks. By its nature, the UKCS is a highly regulated environment, given its maturity, its environmental considerations, its health and safety requirements, but it's an environment that Serica is well-placed to operate in, and our track record shows that. Earlier this year, following the publication of the North Sea Future Plan in November last year, the King's Speech announced the intention to bring forwards an Energy Independence Bill. This bill will legislate a number of changes which will be important to the UKCS regulatory environment. It's important to note that this bill has been trailed since the campaign in 2024. This is not a bill being brought forward in response to Iran. It's an important milestone for the U.K. and the energy policy as a whole. That North Sea Future Plan covered a range of energy measures, including in relation to the workforce and the broader energy landscape and demand-side policy. Specifically on oil and gas, it introduced a specific measure called a Transitional Energy Certificate, or the catchy name TECs. TECs are the proposed measure to deliver this dual manifest of commitment of, one, not granting licenses to explore new fields, and two, supporting the management of existing fields. As I mentioned, there is a recognition that oil and gas will be with us for decades to come. TECs, as currently drafted, will allow companies to develop new, unlicensed oil and gas projects to support the management of existing fields. They'll allow access to acreage either adjacent or in close proximity to an existing field, with that accumulation being unlocked via tieback. It's important to note that our current activity program does not require any TECs to progress. However, they may be an important part of the UKCS regulatory architecture in the future, and so we remain active in advocating for a credible delivery. The conditions around the measures proposed are important, particularly when you recognize that the UKCS is a well-developed, with significant infrastructure basin. Many of the new developments today, and indeed the opportunities that Rich will outline shortly, will tie back to existing hosts, even in the immature basins like the West of Shetland. Several reports from industry commentators like Rystad and Woodmac have highlighted that the majority of those unlicensed opportunities are all well within the tieback distance that we're used to on the North Sea. The bill is also intended, though, to introduce changes to the NSTA objectives, plus various other measures, as I mentioned, in the energy system. What's important to remember here, though, is the bill has to become an act before any of those measures can be put in place. Historically, big energy bills like this one takes time to move through the legislative process in Parliament. It'll start in the Commons, it'll move to the Lords, and it will move through various different processes. Given the depth and breadth of this bill, I would expect this to be the same. The other side that we have to look at when considering projects is the consenting and approval processes, and it's essential to consider what type of project we have and what are the approvals that it will need to move forwards. In fact, a number of the opportunities that Rich will discuss further requires a range of consents and approvals depending on the nature of the specific project. The required information for project approvals has evolved in recent years. Following the Finch ruling, there was a need for operators to make additional assessments around Scope 3 emissions. Not all projects are the same. As I said, there's a range in regulatory requirements and processes. For example, our own Belinda project was granted the necessary approvals in four months back in 2024 when it was first submitted, which is a contrast to what you often hear about UKCS projects. There are a number of other examples that sit with operators who've went through similar periods of time. This is because of the type of project they are. They're different to the flagship projects that you might have heard of, very much still looked at and considered and applied for in the right regulatory environment. The projects in our program that Rich will talk through are very well-suited to the narrative and the direction of travel from government and the policy changes that they are making. Serica's well-placed alongside the others to continue to support U.K. demand, we're very excited about the projects that we have to come. With that, I'll pass to Rich. Thank you, Fran. Good morning, everyone. My name is Rich Hiney. I have the privilege of heading up Serica's subsurface team. It's a pleasure to be able to share some of our exciting organic growth projects with you today. I'm a geoscientist by background, and I joined Serica as part of the Tailwind transaction in 2023. My colleagues have already touched on some of the projects across our expanded portfolio. Now I'd like to look at these in a bit more detail. In this section, I'll cover infill and redevelopment projects in Bruce, the greater Triton Area, the Greater Laggan Area, and some of our newly acquired southern North Sea assets. These are what we describe as short-cycle opportunities with a relatively condensed timeframe from drilling to first production. Collectively, they have the potential to unlock 34 million BOE reserves and contingent resources and add around 30,000 bpd of incremental production. Final investment decisions for the first phase of this activity are expected in 2026. It should also be noted that beyond this initial phase, there could be significant follow-on activity with the potential for adding a further 40 million BOE. We've shown this map before. It's worth emphasizing that these opportunities are spread across four of the main UKCS basins from the west of Shetland, the northern North Sea, central North Sea, and the southern North Sea, which underlines the breadth and the diversity of Serica's growing portfolio. Chris has often said that our business is all about the rocks. That is, of course, true. Importantly, we need to understand the geology and the subsurface in enough detail to reduce risk and uncertainty and to make the right investment decisions. When we bring these opportunities forward, what does the subsurface workflow actually look like? Every project is different, and each comes with its own challenges, but we typically follow a consistent workflow that we know works well. It's the same disciplined approach that we've applied to the five-well Triton campaign completed in 2025, and it's this approach that we're applying across our portfolio today. All subsurface workflows have to be underpinned with good quality data, be that seismic data, well data, fluid information, pressure information. When it comes to 3D seismic data, what we typically do across our portfolio is either reprocess existing surveys using state-of-the-art techniques, or we license the best available 3D from the open market. We move into an interpretation phase, reworking the area from the bottom up, ensuring that we have an updated Serica view rather than an inherited view. Fresh eyes are really important, especially in mature field areas. As you'll see later, we've certainly looked at Bruce through a new lens in recent years, which has led to some of the new targets that I'll be sharing with you today. We use that interpretation to build 3D static and dynamic models. We run uncertainty workflows to test the full range of possible outcomes. We can then use these models for opportunity identification and filter the best ones to carry forward for detailed design, where we test various development concepts and select the best ones for investment. Finally, when we move into the execution phase, we can typically live stream new data directly into our workstations when drilling, for example, to update our models and optimize the development in real time. Underpinning all of this is a robust technical assurance framework, which we call our opportunity to value process, which keeps everything disciplined and consistent between projects. Finally, sitting behind all that is a much bolstered and highly experienced subsurface team, which has more than doubled in size in the past 18 months and is ready to support the much expanded portfolio. Let's get into some of the fields. We'll start with Bruce. Now, the old saying that the best place to find gas is in the middle of a gas field is particularly true at Bruce. It's a highly complex field, but if we can understand that complexity properly, then we can unlock meaningful late life opportunities. Some of you may recall that Apache took a similar approach in the Beryl field, which sits just to the south of Bruce, successfully reversing the decline and extending field life. That's exactly what we're looking to do at Bruce. Here we've identified three near term targets with the potential to unlock more than 18 million BOE 2P reserves and add more than 10,000 bp d of incremental production. Now, as I go through this section, I'll also show where these projects sit within our opportunity to value framework. In the case of the Bruce infill wells, we've recently passed through the select gate, and we're now defining the project to support execution in 2027. On this illustration here you can see the Bruce facilities that are sat up there in the northern part of the picture with the existing wells in black going down into the top of the reservoir at the bottom there. The hotter colors are the shallower parts of the reservoir, and the greener, bluer colors are the deeper parts of the reservoir. What we've highlighted are three new wells in red, which I'll talk to in a minute. These are our planned infill wells that are tying directly into the western area development manifold, what we call the WAD manifold. Importantly, that's exploiting existing infrastructure already on the seabed. Following the workflow I outlined earlier, we now have a suite of fully history matched full field models across the field. This is a first for Bruce because building these models and being able to match the historical production is really difficult. The team have done a great job, and the resulting models have identified actually more than 20 infill targets that appear to be unswept by the existing well stock. We've been able to high-grade those opportunities to pick the top ones based on the size of the target, the economics of the project, the cycle time to first production, and their ability to de-risk or unlock future opportunities. The top targets are what we call South Central East, South Central West, and WAD 5. They're marked as one, two, and three on the map there. These are attractive short cycle projects because they can be drilled close to that existing WAD manifold and tied straight in, which keeps the infrastructure requirements relatively simple and minimizes the environmental footprint. Beyond that, we also see potential in the northeast and the north flank of the field as an attractive follow-on phase with larger volume potential, although those would require additional infrastructure on the seabed. The map that you see on the right there, which is a top-down view of the reservoir, if you're looking from above, really nicely shows the complexity of Bruce, and it is that complexity which sets up some of these opportunities. All of the gray lines that you can see there are actually fault lines in the reservoir, which divide up the field into different segments. It is those faults which act as baffles and barriers to gas production from the existing wells, leaving stranded hydrocarbons in pockets that we can exploit with late life infill wells. Okay, I've talked about our 3D models, and here you can see one version of our Bruce model, our Bruce full field model, which I've mentioned. The colors here show pressure distribution across the field. The purples and the darker blues indicating relatively low pressures, areas that have been depleted by the existing wells, whereas the greens and the lighter blues represent less depleted parts of the reservoir. We're using tools like this to be able to highlight parts of the reservoir that we think are underdeveloped. You can see the south central area in the bottom left corner being one of those areas that we're targeting with the three Phase 1 wells. You've got the northeast and eastern terrace part, which we feel is underdeveloped, and we'll be looking at that for a future development area. Zooming in a little bit on the three wells in the south and the WAD area. You can see WAD 5 on the left. You've got South Central West in the middle and South Central East on the right. The gray sort of shadow zones there are actually the faults that I mentioned on the previous map. They're segmenting the field, and you can see that actually each one of these is targeting a different fault block, and that means that each one of these is actually independent of each other. Detailed planning for the delivery of these three wells is well underway. We recently completed the survey work on the seabed to assess the shallow hazards and support the location of the rig. As we move into the drilling phase, we're looking to deploy technology that we've used successfully on the five-well Triton campaign in 2025, which helps us to optimize the wells as we drill them. That's the image on the lower left there. This is actually what we call ultra-deep resistivity technology. We deploy this on the drilling assembly, and it feeds back information, images like that in real time. The hot colors on there are actually the hydrocarbon-bearing bits of the reservoir. That's what we want to drill through. The colder colors above and below are actually non-reservoir or water-bearing sections. In real time, we can make adjustments to those wells and make sure we drill the sweet spots. It's particularly important for the South Central West and South Central East wells, because as they enter the reservoir, they're actually going to be leveling out and drilling horizontally for a distance of some few thousand feet, actually. Long horizontal wells through the reservoir. We use this technology to optimize those. It's a really exciting period of the redevelopment of Bruce. These wells will be the first wells drilled on the field since 2012, and we're looking forward to moving those into the execute phase. Turning our attention now to the Greater Triton Area and the Kyla development. Kyla is actually a redevelopment of the former Kyle field. We know that the hydrocarbons are there in the subsurface. Production ceased earlier than planned on the Kyla field. Serica is now looking to bring that field back into production as a single well tieback to Triton via the Triton infrastructure. This is a development concept which we know works well in the Triton area with clear parallels to both Evelyn and Belinda, which we delivered in recent years. Planning is progressing on both the engineering and the regulatory fronts. We've already submitted a field development plan and environmental statement to the regulator. Like Belinda and Evelyn, Kyla is a 100% equity field for Serica, with the potential to unlock more than 10 million barrels of 2P reserves and add more than 5,000 bpd of incremental production. Like the Bruce wells, Kyla is already in the define phase of the project, and we're moving that forward to execute likely in 2028. The image on the screen here shows the makeup of the Kyla field. The pink layer at the bottom is a mobile salt layer, which pierces up through the shallow geology and sets up the structure of the Kyla field itself. The actual reservoirs, the younger reservoirs, are lapping up against that salt piercement structure. You can see that the Kyla development itself is relatively simple. It's a manifold on the seabed. We drill down horizontally through the reservoir, and then we tie that back through the Bittern infrastructure. That's the new part of the development, and then everything else back to Triton already exists. You can see that in a bit more detail on the map on the right-hand side here. It's that new part of the infrastructure from Kyla to Bittern is about 12 km. That's a flow line and an umbilical, then the rest of it is already in place. The map on the right-hand side is actually a zoom-in of the structure, top-down view of the reservoir. You can see that concentric structure that I described, and the well is the red line that sits on the southwest flank. Like those two Bruce wells I described, this is actually going to be a horizontal well that's going to skirt around the southwest flank of the field. We believe that's the sweet spot of the reservoir. We're also going to be deploying that same technology I described, the ultra-deep resistivity, so that we can stay as shallow as we possibly can on the reservoir, but also look to our right and avoid that salt wall, which is piercing up to the east of us. Okay. Shifting focus now to the west of Shetland and our Greater Laggan Area. This is a useful image of the area. It's looking northwest, southeast towards the Shetland Gas Plant, which Serica now owns and operates. You can see the subsea infrastructure there linking the four existing fields of Tormore, Laggan, Edradour, and Glenlivet back to the SGP plant. You can also see the Victory field there, operated by Adura, tying into the GLA infrastructure. That's the one that Carla highlighted earlier. Also highlighted here are the approximate locations of the Glendronach development and the Tormore T4 infill well, which I'll touch on now. Glendronach continues this theme of high-value, short-cycle tiebacks to equity infrastructure. One of the attractive features of Glendronach is that we actually don't need to drill a new well. There's already a well in the ground suspended. We'll be recompleting that and tying it back to the existing Edradour infrastructure. The development will require both a Field Development Plan and an environmental statement because this is a new field, and those submissions are planned to be with the regulator later this year. Only minor modifications are expected to be required at Shetland Gas Plant to accommodate the development, including the addition of a gas mercury removal unit. Glendronach has the potential to unlock 5 million BOE of contingent resources and add more than 5,000 bpd of incremental production. Like Bruce and Kyla, it's also passed through the select gate and is now moving into the define phase. On the cartoon cross-section you can see here, Glendronach sits to the right of the Edradour field. It's the middle well, the one that's labeled GD-01 that we'll be recompleting. We'll be exploiting the upper Spinnaker reservoir and the deeper Royal Sovereign reservoir, which is underdeveloped in this part of the West of Shetland. Now, still in GLA, but moving on to the Tormore field, and looking at the T4 infill well. This is a less mature opportunity than Glendronach. Over the coming months, we're looking to progress it from the assess phase into select. Even so, it represents a valuable follow-on opportunity within the Greater Laggan Area and has the advantage of not requiring a Field Development Plan or an environmental statement because it's an infill well in an existing field. Technical work is ongoing, including 3D static and dynamic modeling, which we're moving forward at pace. What we're also using here to condition those models is 4D seismic data. 4D seismic data is actually multiple 3D volumes, but actually the fourth dimension is time. What we do is we acquire 3D data prior to production, and we then acquire 3D data at different steps through the production life of the field, and then we can compare the difference between those data sets and see where fluids are moving within the reservoir. This technique doesn't work for all fields, but it works very well at Tormore. The red and the yellow outlines you can see on the map there represents a 4D seismic signal that we've seen from before production started to now. What that's highlighting to us is that the existing well that's labeled T3 there in the southern part of the field is actually draining the reservoir effectively, but we're seeing less depletion from the segment in the north. That fault that runs through the middle of the field is baffling flow. It means that we've got an undrained segment in the north that we can target with the T4 well. There's a bit more work to do at T4, but it's an exciting opportunity using high-quality data that sets us up nicely to develop that area in the north of the field. Okay. Moving our attention now to a new part of the Serica portfolio, the Southern North Sea and the Cygnus field. Serica is acquiring a 15% interest in Cygnus through the Spirit Energy acquisition. Cygnus is the largest producing gas field in the U.K. It has consistently high uptime. It's an exciting asset to be joining at this stage of its development. There are currently 13 producing wells, with additional wells being drilled as part of the ongoing campaign, at present, C14 is being drilled and C15 is already sanctioned. The joint venture are expecting to take final investment decision in Q2 this year on two further wells, C16 and C17. We're very much looking forward to becoming more involved in Cygnus and supporting the next phase of the development of this world-class asset. Still in the Southern North Sea, a word on Clipper South. This is another non-operated asset that's being acquired through the Spirit transaction, where Serica will hold a 25% interest in the field on completion. It's currently being drained by four existing producers. Those are the red wells you can see on the reservoir map there in the middle of the field. We believe there's an area to the northwest that's potentially underdeveloped, and that's a target for a potential infill well, and we're looking forward to understanding that a bit more and working with the joint venture to bring that opportunity forward. It's another exciting partnership to be part of, and we're looking forward to contributing more to this over the coming months. I'm now going to shift the focus into the Outer Moray Firth area of the North Sea. This sits south of Bruce and north of Triton. This is the Buchan Horst area and the greater Buchan area. Buchan Horst is a potentially material development in the Outer Moray Firth, operated by NEO Energy, and Serica has a 30% equity interest. Buchan is actually a redevelopment of an old field which ceased production back in 2017. It ceased operations due to the removal of the floating production facilities rather than the reservoir being fully depleted of oil. We know that the subsurface opportunity exists. Serica carry more than 20 million barrels oil equivalent 2C or contingent resources on the Buchan Horst field. An FDP has already been submitted to the NSTA. Value engineering studies are ongoing at the moment to optimize the project. With a successful development at Buchan Horst, there are future tiebacks in the area, notably the J2 and the Verbier, which are highlighted in green on the license area there. They're actually on our license as well as discoveries off the license within tieback distance. For example, Avalon, which sits to the south of us there. There's also future exploration prospects on the block, which are labeled Verbier Deep and Cortina Northeast. In the event of a facility being on the location, we'll be able to tie those in at a later date. Finishing with exploration, I'll provide a quick update on our plans for the Skerryvore well in the Central North Sea. Skerryvore has been in the Serica portfolio for some time, but through the Parkmead acquisition in 2025, we assumed operatorship and increased our equity to 70%. The prospect contains two targets, both of which will be evaluated by the exploration well. The primary Mey target, the upper unit, is targeting gross mid case prospective resources of around 20 million BOE, and that carries an attractive chance of success of over 40%, which is a high chance of success. The secondary deeper reservoir target, the Tor, is a higher risk, but also offers a significant upside with mid case resources of over 115 million BOE. You can see in the cross-section there of the prospect itself, and in subsurface terms, Skerryvore looks very much like Kyla, both in terms of structure and reservoir characteristics. Both prospective targets are proven in the area. There are multiple analog fields nearby that produce from these targeted intervals, including the recently developed Talbot Field, which sits just the northeast of us there. There are also multiple potential tieback opportunities in the event of a successful discovery at Skerryvore. One of those actually being back through Talbot and into the Judy facilities. In conclusion, I hope that gives you a clear sense of the scale of the opportunities across our expanding portfolio, which include infill wells at Cygnus and Bruce, redevelopment of Kyla and short tiebacks in the Greater Laggan Area. All of these are underpinned by robust technical work, assured through our opportunity to value framework, and we're very much looking forward to progressing these into the execute phase. With that, Chris, I'll hand back to you. Thank you. What, no music? I don't get any music. I think I'll just leave you with this slide, which is an overview of the key messages we've been hoping to deliver today. I'll just end with a quick summary in my own words. For me, I think we've demonstrated that we have a portfolio with great organic growth potential. In fact, we'll never be able to fund all of the things that we have in our portfolio, some of which we haven't even had time to discuss today. We're in that privileged position where we have a lot of great opportunities, and we just get to choose the best ones to go after. That's kind of where we are right now. We are also in the privileged position of having the balance sheet strength that allows us to fund those good opportunities while also continuing shareholder distributions. I think we've gone some way today to sharing with you why I believe we've got the right team in place to maximize the value from those opportunities. I'm going to end there. We're almost exactly on the 90 mins we were aiming for, which shows we're also quite good at planning, I think. We're going to move into Q&A. I'm going to ask my colleagues to join me up here on the stage, and I think we'll start with questions in the room here. I know that Andrew is monitoring online as well. If we have time, we can go to questions online as necessary. The way this is going to work is if there's a really easy question, I'm going to take it, and if there's difficult ones, I'm going to point at one of these guys. Thank you very much. I'll jump straight in. On Triton, would you like to own 100% of the asset? If so, how possible or doable is it? It's a bit of a double-edged sword. I'd like to have control over Triton operations. I think for fairly obvious reasons. I've spent large part of my two years here apologizing for the performance of Triton. I don't mind doing that if it's our own operations and we're accountable for it, and we've screwed up. I'll hold my hand up and admit to that and tell you what I'm going to do differently tomorrow. Obviously, we can't do that with Triton at the moment. I'd love to find a way that we could operate that. We have the majority of the production that goes through Triton. I think it's about three-quarters of the production is ours today. You can see some logic in that, but we don't have a right to just take the operatorship away from Dana. I think Carla articulated quite well earlier that we're actually quite pleased with what Dana is doing at the moment. They have spent a lot of the last couple of years trying to put things right. They've caught up on quite a lot of the maintenance. For now, the last couple of months, it's been running quite well. They are doing pretty much all the things that we would do if we were operating it today with the same people. Although I'd like to own it, I can't guarantee you that it would actually improve that much. Would I like to have 100%? A bit more production would be nice. I think the only way that comes about realistically is if we do an M&A deal with Dana. I'll leave that there. Thank you. Could you maybe quantify the third-party throughput opportunity at the Shetland gas plant in dollar terms, in monetary terms? Martin, you want to have a go at that? I think it's tricky for us to do that, not least because the, I mean, I think we indicated for Tornado, the discussions are still going on, right? There's ongoing discussions with Adura and Ithaca. Really, I don't think it's appropriate to put a number on it, but I can quantify, I can further recalibrate, if you like, where it comes from. The value to us is clear. I think hopefully that the cost base is essentially fixed, and so any more throughput that comes through, everything is going to have a degree of cost share and probably some component of tariff potentially as well. We're not going to be in the business, and we don't intend to really be in the business of just becoming a third-party infrastructure owner. It brings good value to our own existing assets. If we can lower that cost base, it improves the economics overall of GLA, which improves the life of the fields and gives the potential for more stuff to come into the plant. It's all good news if we can. You've seen that plant. It's virtually brand new, I mean, by U.K. standards and it's got loads of ullage in it. Not really going to help you, Valerie, because it's not a number, but I don't think we can give a number right now. I think that one of the biggest sources of value in all of that is pushing out the decommissioning costs as well. Yeah. Even if you just factored in the time value of money of pushing that out by who knows, 10, 15, 20 years potentially, that's quite valuable to us in and of itself. Yeah. Hi. Can I just ask a couple of different ones quickly? On Southeast Asia, give us a flavor of the fiscal environment, which I imagine it's impossible to be any worse than the U.K., and also, importantly, the regulatory environment and how robust it is there. Secondly, just talking about the sort of the U.K. PCS, and you talked about how Belinda was in 2024, quick approval, et cetera. It looked a bit different to a lot of the stuff that's being talked about in the press and at government at the moment. Can you just give us a little bit more of a flavor about what looked different about that and what might we see going forward from- This is going to be a three-part answer. I'll make a quick comment. I'm going to ask Martin to talk about the kind of government takes that they have in Southeast Asia, typically, maybe over to Fran. I think one thing we can say about Southeast Asia in general, and of course, it's not one country. There's multiple countries that we're looking at. In general, the governments tend to like the oil and gas industry in that part of the world. In general, the populations seem to be quite positive towards our industry as well. That, in and of itself, is a good thing. The fiscal regimes tend mainly to be production sharing contracts, which you'd almost be forgiven for thinking the government here was trying to put in place a production sharing contract through the back door, they won't call it that. Production sharing contracts actually protect the producer on the downside, but it caps you on the upside, and that's one of the benefits of them. In terms of the average government take. Yeah, I think the average take probably some of it may not be that dissimilar to where we are. It might be sort of 60% to 70%. It's not the same in every single country. The point is, in all these things, what's key, and we did spend time looking at Norway, as people will know. What's key is that if you know what it is when you go in, and you know that it's consistently going to be that, and it's always stayed like that's what matters. That's what kills the U.K. As long as you know what you're getting when you come in, and you buy it on that basis, and therefore that's the economics, then you can live with it. As Chris said, they're virtually all PSCs, which is a good thing really. It gives you this kind of S-curve exposure to prices. It has a bit of inbuilt hedging, if you like, embedded within it. Fran, do you want to kind of contrast what we might expect for something like a Kyla or a Glendronach compared with, say, a Rosebank or a Jackdaw? Yeah. What's different about them? I think the first thing to learn on Belinda, a lot of this comes down to size. How much volume is sitting within that? What's the opportunity on it? Belinda is much smaller than something like a Kyla or a Glendronach, and it's significantly smaller than something like a Rosebank or a Jackdaw. That's the first bit. What size is it, and how does it go through? That doesn't mean that there isn't a regulatory consenting process. I should be clear on that. As we said earlier, we're really committed to making sure we're producing these at the lowest emissions, and that doesn't mean that we're not taking our eye off that. A Rosebank and Jackdaw is a significant flagship project. Lots of volumes, lots of new infrastructure in it. Lots of the things that Rich outlined are tie-back opportunities to existing hosts, and that's where the difference is. They still have to go through a process, absolutely, but it's a different sort of process, and it's a different pace of time. If you look at Jackdaw, it went in in 2021. That's when it started its journey. I listed Belinda as an example. There's plenty of other things, like BP's Murlach that's out there, Adura's Victory. They've all gone through in different levels of times in this process. Before we take another question in the room, we will take one from online. It is a follow-up to what Martin was just talking about, actually, which is that given the scale of opportunity in the U.K. and your excitement about it, is there a risk that buying assets outside the U.K. creates a distraction? Yeah, no. It's a short answer to that. I think we can manage. Hopefully, we've demonstrated that we're able to manage the acquisitions we've made in the U.K. When we do that, we're actually getting people that come with it. We've deepened the bench strength, basically, of the company overall. If we were to buy something in Southeast Asia, it's exceedingly likely that we would buy something that probably comes with a team that has been operating it. If it's buying an asset from a major, for instance, it would almost certainly come with the people that do that. To us, and actually managing that, people who've known Serica for a long time will know that Serica used to be in Southeast Asia. We're talking like 20 years ago. Really a long time ago. I'm told that at that time, it was a bit trickier managing a business that far away. I think nowadays that's much easier, right, from a comms perspective. I'd just add. Martin's absolutely right. The kind of things that we're considering and that we've evaluated so far would all come with a team on the ground, in country, that are running assets. You should not expect to see us go and try and pick up an exploration license, for example, and then build a team in country to go and run that. We will look at buying assets that come with a team. The other thing that we've been doing over the course of the last year or so, as we've been integrating the M&A that we've executed, is we've set up our organization such that adding another country is really straightforward. It's like adding another asset within the U.K. Here's the person at the head of that asset team. There's the team underneath them. That person probably reports into me or into the COO, and the organization is set up to support that. We weren't that way 12 months ago. Now we have an organizational design that allows us to plug in additional assets as we buy them and do it in a seamless way. Thanks, guys. Can I start with the development portfolio? Just, you gave a 40% IRR number there, which obviously is an average across those projects. Are you able to break that down at all in terms of giving us a bit of a steer on what the range of returns are across the projects? The second one on the dividend, I appreciate we've got a load of information there. The bit that I'm not fully clear on is M&A, and how much you may want to retain for M&A. Is there a rule of thumb as to what kind of cash balance you would like to retain for M&A, just to give us a bit of a steer on what the dividend would be? Yeah. I don't think we're in a position to share economics of individual projects at the moment. We will do that as we mature those. Rich was showing as we were going through the presentation there, the stage that we're at in each of those. Some of them, frankly, the economics are fairly early on and it's quite high level and there's a wide range of outcomes. As we get closer to sanctioning individual projects, I think that's the point at which we'll have the confidence to share the data more widely. Apologies, I don't think we'll be sharing individual asset project economics at this point, but it will come. Martin, do you want to take that? Yeah. The M&A one's an interesting point, obviously. As you've seen, we've got, based on that plan and the consensus price decks that we're using, we would have essentially the full liquidity that we've got right now, which is GBP 684 million, and even after we've done our refi. I think I hopefully indicated it. We don't expect that to change much, right? That's a lot of liquidity. You might look at it and think, "Well, what are you going to do with that?" Obviously, that does give us, in a way that part of the reason we want that is because those who've been following us for a while will know that, and it was up on the chart, we did last September, October, we announced a deal to buy BP's Culzean in the Killaloe field, which was relatively sizable. I think it was GBP 200 million odd acquisition price. Unfortunately, it got preempted, so we don't own it. The point I would like to make on that is in order for us to do that, we and some of the banks are in the room, so thank you to them. We had to go to our banks and get a special, basically bridge financing to enable us to be able to demonstrate that we could actually complete that financing, that deal had it got to completion. With the level of liquidity we've now got, we have the ability that if that sort of situation were to crop up again, we could just do it like that. That is really important in M&A because you've got to be very clear that the seller knows that you absolutely are deliverable. I think the ability to have committed funding that we can draw down at a moment's notice is key. The other thing that makes it tricky with M&A is that the kinds of things we're going to buy will themselves bring debt capacity or cash flow as well. As long as they're credit accretive, i.e. they just basically add to our financing capability, and hopefully they'll be equity accretive as well. They shouldn't hinder our ability to continue on the same distributions policy that we've laid out as well. Clearly, that was a plan based on what we own currently. Right? Morning. Thanks, guys. Just thinking about the U.K., I guess historically, access to infrastructure has been a problem in terms of some projects moving forward, Columbus being one. As operator of the GLA now and obviously the gas plant, how are you sort of approaching discussions with partners to make sure that that doesn't happen? Obviously, I guess you're incentivized to push the life out, but you mentioned that discussions are still ongoing with Tornado. Maybe if there's any sort of context you can put around it, maybe not in dollar terms, but any sort of the volumetrics or something you can say around that longer-term third-party opportunity. Just secondly on the dividend. If consensus price expectations change, for example, and CFFO comes in below where you're currently thinking about it, should we think about that GBP 0.16 as a floor, assuming that the other guardrails in terms of leverage and liquidity stay in place? Thanks. On the infrastructure question, it is a live debate at the moment. Specifically around Tornado, and I think that's why Martin was reluctant to say anything about the scale of what the value that might bring to us, frankly. That is ongoing. We're in conversation. The conversations had started before we bought those assets, so Total were as host, were having conversations with them before that. We are in a live debate about it right now, trying to close a deal, and there's a gap at the moment, and it's edging closer. I'm pretty sure we'll end up with a deal, but I'm not sure we can give. No, I don't think we. Once we have a deal and they announce that they're sanctioning Tornado and it's coming to us, I think we can be quite open at that point. It's just at that point where it's not appropriate to go into it in more detail, I'm afraid not in this forum. I would say generally on that point of infrastructure, to us, and not just us, to NSTA. You might be surprised that there's a huge amount of drive for NSTA to maximize the amount of resource that comes into that Shetland gas plant. They can see, like us, that it's virtually brand new. There's a whole load of gas out there. The U.K. funnily enough needs it. There's a lot of desire to have that all come together, and we're actually working pretty collaboratively with the partnership because they'll become long-term partners of ours in the plant as well. I think that's all I can say on that. On the dividend, you asked about that. Look, I think the way we've framed it, yes, we want the GBP 0.16 to be viewed of as a floor. They're obviously pure math says that there is a circumstance, because what we won't do is go over the 30% of post-tax CFFO. You can kind of back solve that if our post-tax CFFO were to go to below GBP 280, I think is the number. We would be breaching the 30%. That's the point of having the 30% as the max, if you like. We can flex that percentage to keep with the aim of essentially keeping the GBP 0.16 as a minimum. We'll take another quick question online, which is, once you're in the FTSE 250, do you expect a lot of new institutional investors? What impacts do you think that will have on the share price? We should say that it's not absolutely guaranteed we'll make the FTSE 250, by the way. There is actually an index process that you have to go through, but we're saying it as if it was certain because by our current size, we're comfortably at that level. I think it's fairly plausible. More than plausible. What you will get is trackers. That means that one of the benefits of being in the index is you get a lot of funds, passive money that basically tracks the index. That, we don't have today, there's none of that that's tracking us in AIM. I don't want to sit here and say it's a kind of silver bullet, but I think it just gets a lot more focus and attention. There are some international funds, there are some U.K. funds who just only invest in main board-listed companies. Yes, I think we'd expect to see wider shareholder interest. Frankly, we're pleased we get quite a lot of good shareholder interest now as it is, but the more we get, the better. I think it's in everyone's interest to do that, and that's the main reason we're looking to move up. A question on Bruce first. This is a very large project, very large contingent resources well beyond the current 2P reserve. I was wondering whether you could talk about Phase 2 of those infill wells. I think we talk about 17 additional wells. What's the timing? What needs to happen? Does the result of the three wells of Phase 1 impact Phase 2? Maybe related to that and thinking about tax and the new OGPM. How does the capital allowance work? What's your understanding on this OGPM? I guess given the cost of those Bruce wells, surely, and the timing, that must be something that should be quite important for investment decision for those wells. Yeah. I'll get Rich to talk about the potential follow-on wells and are they impacted by the first three. Okay. Fran, do you want to talk about the. Yeah CapEx? Yeah. Okay. Yeah. You mentioned the 17 follow-on wells. I want to be clear that although there were 20 highlighted opportunities on Bruce, in terms of our contingent resource, the volumes we carry within there are five additional wells, not 17. Those are on top of the three that we've actually got sat within our reserves category. The activity that we would need to undertake to bring those forward, those follow-on wells, would probably involve some sort of appraisal in the northeast to make sure that our models are correct. We model these as being undepleted, and we think that there's a large volume there. Actually, in terms of contingent resources, around about 30 million BOE of contingent resource in that northeast area. Once we've demonstrated that, then to actually develop them, we'll have to put new seabed infrastructure in place because we can't tie it back through the existing WAD area like we're doing with these first wells. Those first three wells I showed today, they're first because we can develop them quickly. They're also high value. They are independent of the North. Whatever result we get in these first wells, it doesn't impact what we do in the north. I'd say the one area where these wells do impact it is it keeps Bruce going for longer. The additional volumes from the first three wells mean that we're economic for longer, and therefore you've got longer to get those wells drilled and get the reserves from those. Yeah. Do you want to- Your OGPM question is a really important one. Actually, if you think about it, the timing of OGPM, when that comes in is critical. Actually, the style of OGPM, so it's not on all the time. It's not taking all of the profit, only applying in certain scenarios on that top slice. Although it doesn't come with capital allowances and investment allowances, it is a very different tax. It's a revenue tax. Your baseline is much lower because you're planning that you're at 40%, 46.25% on relief for that whole period of time and only up. Obviously we're using lower decks than 90/90 anyway, so you're not forecasting OGPM into that space. That's the really important piece of it. The other thing that we should say, though, is whilst projects might look slightly different, the sentiment of a move away from the Energy Profits Levy, which this Treasury has been clear that it's not working, to OGPM would be significant. Significant for supply chain and keeping infrastructure in the U.K. It's an important factor to think about. It is possibly worth saying that the whole genesis of OGPM was because Treasury understood that it wasn't helpful to have a tax that actually disincentivized people to make investments. At least they felt it was doing that, and people were saying that. We still think we can make money with the regime as it currently is on the things that we've talked through. That's why their thinking was setting the 90 in the 90, and it inflates up. By the time we would get there, it would be higher numbers, was so that it didn't distort investment decisions. Hopefully, we wouldn't be taking decisions if they only worked at 90 and 90, right? I do really like the idea, though, of spending our capital under the EPL regime and getting the 84.25, and then getting most of the production under an OGPM regime. That would work out really well. Okay, thanks. Mark Wilson at Jefferies. First thing, I just think it's nice to see a CMD balance between the clear financial strategy and the assets. Your own recent history has shown the uncertainty that assets can have, certainly on the facility side. The financial position you're in and with the deals you've done, I think is a credit to you. One thing that's really new in this presentation, certainly for me, Fran, was this Energy Forward bill in the U.K. Could I ask firstly, is there a link within that to the fiscal rules such as OGPM? Is there anything investors should be aware of? Does it change anything about a timeline of a change of fiscal regime? Is there any expectation from yourselves on who's in charge of that change when it comes Treasury or Energy Department? Let me think about that while I say a second. The second point is on the asset side, because this is where history and risk comes into play. The size of resource at Bruce has just been highlighted, clearly you're going to exploit that. We started this presentation, as Carla said, with a still quite new and shiny Shetland gas plant. The former operator clearly spent a lot building those facilities, your own low level of 2C resource against that shows it doesn't look like something delivered against them. It'd be nice to have a history lesson against maybe what didn't come through in those GLA assets. Second point. Okay. So the- Do you want to talk about the tax? The Energy Independence Bill is very much a Department of Energy Security-led bill. The Finance Bill, which is the bill that we expect, I'm not going to guess when the budget is, but sometime in the autumn, there will be another budget. The Finance Bill that would come with that budget is what the Oil and Gas Price Mechanism will be legislated in. Two separate bills. Obviously, all bills are related because they have to go around Cabinet right around. When a Finance Bill comes forward, they'll debate it in the room, and many people can. A Defense Minister could say something. An Energy Secretary could say something. There's lots of different values for that. That Energy Independence Bill, I think the other really important piece to reflect is it didn't come out of nowhere. They've been thinking about that since 2024. Whilst that's an Energy Department bill, many of the people who were on the campaign in 2024, many of the ministers that are around the table, they all have a recognition for that. It's a big bill. It's got lots of stuff in it. We talk about it as a Christmas tree because it's got so many different parts to it, which means by default, lots of different people will have an interest in it. The key date on Finance Bill is after the autumn, where we'll see OGPM legislated. I'm going to answer the easy part of the second question, and then I'll give the tough part to Carla. Total were disappointed, right, by what they drilled west of the Shetlands. They spent over $1 billion on the gas plant, expecting it to be full. It's never been full. When they drilled a couple of things, they didn't find what they expected. Even Glendronach, most companies, after drilling the Glendronach well, would've tied that in and produced it. It was almost like they were fed up with the U.K. in general and wanted to walk away, was kind of the impression you get about it. It was a bonkers decision after they drilled it. Carla, do you have any more information about the things that they drilled and what they expected? Yeah, I think the history lesson here is around understanding subsurface uncertainty and being disappointed if you don't get what you expect. For GLA, in terms of where we're focusing at the moment, we're focusing on what we know is there, the simple and quick. Glendronach, there's a well in the ground waiting to be completed and tied in. We're taking a conservative approach to how much might be there. There's a big upside, but there's enough to carry that project. Same with Tormore, low subsurface uncertainty, within proven well control, and a model that works in terms of matching the data. There's also a lot more opportunity West of Shetland. You can see that in terms of the prospectivity of the basin. There's some acreage that we sit on that has some opportunities that are really immature at the moment, and we'll need to take some decisions around that as we mature them. Throwing technology, for example, seismic amplitudes work very well West of Shetland, and really trying to use that with the data we have. There's lots of well control. As are many others in the basin as well, and that's where the importance of the strategic infrastructure comes in. If we can have sight of what that looks like for gas in the future, it gives us more confidence for some of the longer-term pieces as well. I guess, in general, not just West of Shetland, but in everything that we're looking at in the tranches at the moment of our opportunities, we're opportunity-rich, and it means that we can take some decisions. What we're looking at are the areas with the greatest well control, where we have the most information, proven accumulations with low subsurface risk. That's why we can confidently talk about short cycle and quick to develop. We've got time for just a couple more questions. I think we'll take a couple more in the room and deal with a couple offline. As we say quite consistently, but if we don't get around to your question that you've asked online, then do please drop the head of IR a line. We'll make sure we do answer all questions that we get in that forum. I'll take one very quickly before I pass the microphone over, which is, "What is the consensus share price target from your analysts?" I can say that as of now, it's £3.11 at present. With that, I'll hand over to Dan. Yeah. Thanks very much. I just wanted to ask where your thoughts have got to on Buchan at the moment. The program that you've laid out is obviously very well thought through. It feels like it focuses on sort of doability and your ability to deliver that over the next few years. Your financial framework, got an awful lot of flexibility in it, gives you a lot of options around various different bits and pieces. Buchan does make up quite a bit of your 2C resource as well. What I was kind of wondering is, what do you need to see in order for Buchan to get kind of promoted up the slide deck? If you see what I mean. What do you need to see? How does that come about? At the moment, the reason it didn't feature earlier in the slide deck is exactly to your point. We're focusing on the things that we have control over, that we're pretty confident we'll get the approvals that we need in a quick timeframe. We don't have a partner group that we need to get aligned on some of the stuff that's in the portfolio that we want to do very quickly. A lot of it's just around that doability. I think it's fair to say that the partnership on Buchan, and there is a new operator there, by the way. NeoNext Plus is now the operator. Used to be Neo, then it was NeoNext, and now it's NeoNext Plus, since it's got the TotalEnergies business in there. I think it's fair to say that they're taking another look at it. They want to form their own view of Buchan before going to sanction a project. It's just a little bit behind some of the other things in the portfolio, just in terms of its maturity. I think that's probably the main reason it didn't feature more strongly. Thank you. I'll pass over for the last question now. Thanks very much. Yeah, frankly, it's remarkable given U.K. politics that you've managed to reach this position where you're presenting such self-funded organic growth plus sustaining a dividend. I guess my blunt question would be just, how could the politicians spoil this from here? Wow. I'll make one comment. Seeing as it's about politics, I might let Fran have a go at this. I've been thinking about this a bit lately, how could they screw it up any more for us? It's difficult to see. Look, I maybe would've said that a few years ago, but 78%. I don't see them going any higher than 78%. Is it possible that they just decide to keep that EPL regime forever? I think that's possibly, but everybody has been saying, no, it goes away in 2030 at the latest and gets replaced by OGPM, which would be much friendly to us. I think the best thing that protects us is the fact that we do have these short-cycle things where we get quick returns, everything that we've shown you up there is pretty much within our control, and we don't need much from the government in order to get the approvals to go ahead. We're almost immunized against Miliband in that regard. Not completely, we feel like we're in a fairly strong position to kind of ride the wave regardless of what happens. You want to- Leave that out? She thinks I've said too much already, I think. With that, Chris, I just wanted to ask have you got any final remarks? Thank you everyone for coming. No, really, just to thank everybody. It's great to see such a good turnout on a day like this with a tube strike, and I had my own adventures in getting here this morning, so I'm sure others did too. Brilliant questions, and apologies to those online, but we will be hanging around for coffee afterwards. Any other questions from the group that are here, we're happy to take them out in the lobby afterwards. Thank you very much