Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the Harbour Energy 2023 Full Year Results Conference. All lines have been placed on mute during the presentation portion of the call, with another opportunity for question and answer at the end. If you'd like to ask a question, please press * followed by 1 on your telephone keypad. I would now like to hand this conference call over to our host, Linda Cook, CEO. Please go ahead. Great. Thanks, Candace. Good morning. Thanks to everyone for joining Harbour's 2023 Full Year Results Call. I'm actually getting quite a bit of feedback on the line, and so maybe if there are others who can mute their lines, that would help. With me this morning is our CFO, Alexander Krane. Turning to our agenda, I'll start by taking you through our 2023 operational performance, and then Alexander will cover the financial results. Then it's back to me to update on the Wintershall Dea acquisition, and we'll leave plenty of time for Q&A. Starting with our highlights, 2023 was a year of significant strategic delivery for the company. We continued to maximize the value of our producing portfolio while generating material free cash flow. Most importantly, we did this while achieving a top quartile safety performance. We also progressed our growth projects that will help to diversify the business over time. We materially grew our international 2C resources and hit key milestones for our UK CCS projects. Our disciplined capital allocation enabled us once again to deliver shareholder returns over and above our base dividend while retaining the flexibility for meaningful M&A, meaning that at the end of last year, we were able to announce the acquisition of the Wintershall Dea asset portfolio for $11.2 billion, marking our fourth major acquisition since 2017 and the most transformational step yet in our journey. Since then, we've made great progress advancing the transaction towards completion, which remains on track for the fourth quarter of this year. More about that later. Critical to our strategy is being a safe and responsible operator. 2023 saw us reduce our total recordable injury rate to 0.7 per million hours worked, which was down from 0.8 in 2022 and from 1.3 in 2021. Across our operated assets, we also achieved two firsts for Harbour, about which I am hugely proud: zero lost-time injuries and zero serious process safety events. This follows the rollout in 2022 of our Back to Basics campaign, which is now embedded across the organization and reflects the strong safety culture we've worked so hard to build over the last three years. Another key aspect of our strategy is the critical role we have to play in the energy transition, producing oil and gas responsibly and utilizing our skills and existing infrastructure to deliver CO2 capture and storage projects, or CCS. Through investments in projects to reduce emissions and improve efficiency, we remain on track to meet our Scope 1 and 2 emissions reductions target, a 50% by 2030, versus our 2018 baseline. In 2023, we were already down 30%. We also continued a steady program of expenditure to decommission wells and infrastructure no longer in service. In 2023, that included the removal of 5,500 tons of subsea infrastructure with a 97% recycle or reuse rate. We made good progress with Viking CCS, which I'll say more about later. Turning to production, we averaged 186,000 barrels per day in 2023. Our U.K. operated hubs continued to perform well, with higher production for the third consecutive year from the J-Area, which was supported by new wells. Both J-Area and Greater Britannia delivered top quartile production efficiency of around 90% in 2023, resulting in production efficiency across our operated assets being materially above the UK average. This strong performance was offset by the deferral of drilling at our partner operated hubs and also by extended shutdowns in the second half of the year, in particular at East Irish Sea. Finally, we continue to have a good balance of oil and gas, and our predominantly operated portfolio enables us to drive efficiencies and cost savings. We do continue to actively manage our cost base, leveraging our scale in the UK and taking action to simplify our organization and systems to help maintain healthy margins and prepare the company for future growth. This included a review of our UK organization in 2023 in response to the Energy Profits Levy, the outcome of which will be to deliver about $50 million in annual cost savings. In addition, we continued to rationalize our UK portfolio of suppliers and contractors, and in key areas, entering into larger strategic supply chain partnerships. These cover key services from drilling and logistics to aviation and operations and maintenance services. This reduces complexity and should lead to further cost savings as we go forward. Testament to our ability to control costs is that we've been able to keep our absolute operating costs broadly stable year-over-year, despite persistent inflationary pressure. As a result, our unit OPEX averaged $16 per barrel in 2023 and continues to rank materially below the UK average. While the impact of the Energy Profits Levy on our cash flow and the ongoing political and fiscal uncertainty in the UK has caused us to scale back investment plans in the country, we have continued to invest selectively in high-return, short-cycle opportunities to support production. We recently completed development drilling at Talbot, a three-well subsea tieback to Judy, which is expected onstream around the end of this year, adding to J-Area production. We also see the opportunity to improve recovery from several of our J-Area fields, including the Judy Chalk, where we've approved plans to drill a well this year and also to add gas lift to three existing wells. At Greater Britannia, we're returning to drilling at Callanish with the F6 well, which spudded last month, while at the AELE Hub, we're preparing to drill the North West Seymour well, which has the potential to extend our modest producing life beyond 2030. This compares to the scheduled decommissioning date of 2018, when we acquired the asset from Shell in 2017. As you can see from the chart on the left, we've invested about $600 million, excluding decommissioning, in the UK in 2023 in support of such opportunities, and have plans to spend slightly more in 2024, which will help underpin future production and cash flow. These capital projects typically have very low break-evens, below $40 per barrel and GBP 0.40 per therm, and high rates of return, well in excess of 50% at today's market prices. Our production guidance for 2024 has been set at 150,000-165,000 barrels per day. This reflects the every 10-year extended shutdowns of the CATS and SAGE pipelines, which impact J-Area and Beryl, among other fields. In addition, we have our regular three-yearly significant maintenance campaign at Greater Britannia. 2024 production also reflects the decision by other operators to divert some drilling and the fact that many of the wells coming onstream this year only do so in the second half of the year. We'll see the benefit of this investment then in 2025, with the volumes from new wells coming onstream almost double that compared to 2024. This, along with a more normal maintenance schedule, means that 2025 production is expected to be similar to 2024. As a result, over the years 2023 to 2025, we're seeing an approximately 10% managed average annual decline rate, in line with what we would expect, given our level of investment. The next page summarizes our reserves and resources. Starting with the chart on the left, reserve additions at our largest U.K. operated hubs offset almost a third of our production during the year. This continues our track record of adding reserves to the assets acquired. As shown in the top right-hand chart, we have increased the reserves that came through the Shell, Conoco, and Premier acquisitions by more than 25%. We've also materially grown our international 2C resource base with exploration success in both Mexico and Indonesia. As a result, our international 2C resource base now accounts for over 60% of the total, underpinning future potential reserve replacement and diversification. Ultimately, however, it's through M&A that we look to grow reserves, and the Wintershall Dea acquisition does that, almost tripling our reserves and lengthening our reserves life. It will also transform the geographic diversity of our asset base, with the UK accounting for a quarter of the pro forma company's 2P reserves, compared to 95% of Harbour standalone today. Before I turn it over to Alexander, maybe a few words about our organic growth projects. In Mexico, our Zama project reached a major milestone, with the Unit Development Plan being approved by the regulator in June. FEED is planned to begin shortly and marks the last phase before a potential final investment decision. A positive decision would result in about 75 million barrels of 2C resources moving into proved reserves, replacing the equivalent of over a year's worth of Harbour's current production. Southwest of Zama and Block 30, we made a significant oil discovery with the Kan-1 well in April, with appraisal planned for the second half of this year. As a result of the Wintershall Dea acquisition, Harbour's interest in both Zama and Kan will increase and will become the operator at Kan. In Norway, we made a small gas discovery at our operated Amethyst well, and drilling at Ringhorne is ongoing. We look forward to adding these to the substantial Wintershall Dea position in the country. With its low unit operating costs, low emissions intensity, stable fiscal regime, and supportive business environment, we're excited about entering Norway in a material way. Moving to Indonesia, progress on our Tuna project continues to be impacted by sanctions, which affect our ability to work with the Russian partner. But we're hopeful that a solution will be found shortly so that work can restart at that important project. And finally, turning to the Andaman Sea in Indonesia, following the discovery at Timpan on the Andaman II license, we initiated a multi-well exploration campaign in 2023 and late in the year announced another significant gas discovery at the Layaran-1 well on the Mubadala operated South Andaman license. The rig then moved back to the Andaman II license, where Timpan is located, at the turn of the year for the next two wells, where we're just wrapping up operations. The Halwa-1 well was unsuccessful, while a small gas discovery was made at Gayo. Next, the rig returns to South Andaman to drill the shallower Tangkulo prospect to the south of Layaran and a possible fifth well, as we look to continue to test the numerous large prospects across these licenses. Once this campaign is complete, we'll work to incorporate the new data into our regional models. Based on what we've seen so far, we remain optimistic about the potential for a new gas development in the region, which is so close to multiple growing natural gas markets. Finally, on CCS, tremendous progress was made on our two UK projects during 2023, with both the Harbour-led Viking project and Acorn being awarded Track 2 status by the UK government. This marked a significant milestone, enabling the projects to mature into the FEED phase and to start government due diligence and discussions over the terms of the economic license ahead of a potential final investment decision. Viking is targeting CO2 transportation and storage of up to 10 million tons per annum by 2030, subject to government progress on discussions with emitters. The project allows for scalable transportation and storage of CO2 emissions from the Humber, the UK's most industrial region, and also for shipped CO2 emissions from emitters both in the UK and in continental Europe, providing the potential for additional revenue and improved returns. And now over to Alexander for the financials. Great. Thank you, Linda. And good morning to everyone that has dialed in this morning. Now, before I talk about our 2023 financials, a few points for me first around how. Since becoming a public company in 2021, we've continued to deliver against our three capital allocation priorities of maintaining a robust balance sheet, ensuring a robust and resilient portfolio, and delivering competitive shareholder returns. Now, of course, it's the operational delivery that you just heard about from Linda, along with prudent risk management and a disciplined approach to capital allocation that underpins our strong cash flow generation and has enabled us to deliver against these priorities. 2023 marks our third consecutive year of delivering significant free cash flow. Since 2021, we have generated just shy of $4 billion of free cash flow, and this is after a material capital program targeting good, high-return organic opportunities, both in the UK and internationally to support future production. This strong free cash flow generation has enabled us to repay $2.7 billion of debt, leaving us with only $0.2 billion of debt at year-end. We've also returned $1 billion to our shareholders through dividends and buybacks, and this year again, we are able to deliver annual dividend per share growth of 9% thanks to our buyback program. Now, in fact, over the last few years, we've bought back 17% of our share capital. We have done all of this while retaining the financial flexibility to, at the end of last year, agree the transformational acquisition of the Wintershall Dea asset portfolio. Now, with that context, let's move to the next slide and to our income statement for 2023. We delivered strong operating margins in 2023, albeit a significant reduction from last year. This reduction was primarily driven by lower revenue of $3.8 billion, reflecting lower realised UK gas prices of 0.54 GBP per therm and also lower production. Costs of operations were up slightly, reflecting the inclusion of redundancy costs from our UK reorganization. Otherwise, absolute operating costs were broadly flat year-over-year, demonstrating good cost control in an inflationary environment. On a unit of production basis, operating costs were higher at $16 per BOE due to lower production. Our cost of sales included a net movement in underlift position of $0.2 billion as a result of lower invoiced liftings sitting up in revenue. Our EBITDA was $2.7 billion compared to $4 billion in 2022, with this reduction driven by changes in revenue, as I just described. There are a few one-off items from this period I would just like to note. First, we had a total impairment charge of $239 million. Approximately half of this is due to an increase in our estimates for decommissioning costs associated with certain non-producing assets. This increase reflects higher non-rig-related costs, including increased duration of activities and subsea well rates. Since there is no asset to book the increased decommissioning estimate against, this flows immediately into the P&L, causing an impairment charge. In addition, there were two UK North Sea producing assets which had asset impairments. One was due to the lower forward gas price curve and another, as we flagged at half-year, due to a revised estimate in decommissioning costs. And finally, we have an impairment in respect of the Vietnam assets and goodwill as a result of the divestment agreement signed in Q3 2023. Exploration write-off expense includes the Ix well on Block 30 in Mexico and the Joe well in Norway, which have both been plugged and abandoned. We also had some expenses here related to license relinquishments as part of regular portfolio reviews and management. Other charges here include our pre-development UK CCS costs on our Viking and Acorn projects. Following the award of FEED contract for Viking earlier this year, associated costs will from now on be capitalized rather than expensed. G&A costs of $149 million include base and corporate overheads of approximately $75 million and non-cash depreciation of non-oil and gas assets of $35 million. We also incurred fees of approximately $33 million related to M&A activities, both in relation to the Wintershall Dea transaction and other opportunities we were evaluating. In addition, we have some period-specific items making up the balance, including net redundancy costs after allocations. As a result of these items, our operating profit was $0.9 billion compared to $2.5 billion in 2022. Net financing costs were relatively flat at $0.3 billion. Here, higher interest rates led to a higher interest charge for the unwinding expense of decommissioning provisions, but this was offset by lower interest payable as a result of repaying our RBL facility. Our RBL was undrawn at year-end. Our tax charge was $0.6 billion, reflecting a continued high effective tax rate of 95% above the U.K. statutory tax rate of 75%. This was due to the value of costs which are not fully deductible at U.K. oil tax rates, which outweighs the benefits of investment allowances and favorable remeasurements in deferred tax in the period. Earnings per share were $0.04 per share, supported by a share buyback program resulting in a lower number of shares in issue. Now, let's move to the balance sheets on slide 18. The first thing to notice on the balance sheet is the significant reduction in total assets. Perhaps unsurprisingly, the biggest contributor to this is in tax. We have moved from a net deferred tax asset position of $1 billion to a net deferred tax liability position of $1.3 billion, driven in large part by the associated movement in our derivative position. We saw a significant reduction in the net financial liabilities we carry on our balance sheet for commodity hedges. We have moved from $3.3 billion at year-end 2022 to almost nil at 31 December 2023, reflecting a significant unwinding of our hedge positions and a reduction in forward U.K. gas price curve. Our property, plant, and equipment balances reduced to $4.7 billion from $5.7 billion at the end of 2022. This reflects the fact that total DD&A and impairments were higher than the capital investment additions. The lower balance also takes into account a $0.1 billion reclassification of the Vietnam asset from fixed assets to a current asset held for sale. We have continued deleveraging, with net debt of $0.2 billion at year-end. The net debt balance consists of our bond of $0.5 billion, netted by cash of $0.3 billion. Our RBL facility was fully repaid in the year and undrawn at year-end. The final point I will touch on is total equity. Shareholders' equity has increased to $1.5 billion from $1 billion, mainly because of the favorable substantial movement on unrealised commodity derivatives reflected in other comprehensive income. This was just partly offset by shareholder returns from the share buybacks and dividends. We continue to have significant distributable reserves on the balance sheet, which supports our annual dividend policy of $200 million. Next, on slide 19, we have illustrated the cash flow generation throughout the year. On the left-hand side of this slide, we've illustrated the cash flow generation in the year. Gross operating cash flow for the year was $2.9 billion. Then during the year, we spent $1 billion on capital expenditure, comprising $0.7 billion of capital investment and $0.3 billion of decommissioning spent. Financing costs included interest and lease payments amounted to $0.4 billion, while tax payments were $0.4 billion, and shareholders were also returned a total of $0.4 billion. During the year, we successfully amended and extended our RBL, extending the maturity to 2029. As at year-end, we had available liquidity of $1.6 billion, comprising the $1.3 billion undrawn RBL facility and $0.3 billion of cash. Finally, let's have a look at our guidance for the year. We are not making any changes to the guidance we issued in January. For 2024, we expect production to average between 150,000 and 165,000 barrels of oil equivalent per day. This reduction in production compared to 2023 reflects a number of things, as Linda has already outlined, namely unusually high level of plant shutdowns coinciding with third-party pipeline outages, the impact of deferred partner-operated wells, and the sale of our Vietnam business. While absolute operating costs will be broadly flat year on year, lower volumes mean we are guiding to a higher unit operating cost of approximately $18 per BOE. After both the higher plant capital investment program in 2023 and 2024, which will support our future production, and approximately $1 billion of cash tax payments, we expect to be marginally free cash flow positive for the year, using commodity price assumptions of $85 per barrel and $0.70 per therm. The previous sensitivity we provided in our January trading and operations update reflected $85 per barrel and $0.100 per therm. As such, we see a $0.20 per therm change in gas price, resulting in approximately $100 million change in our free cash flow, and an approximate $10 per barrel change in oil prices, resulting in $110 million change in free cash flow, as set out in a slide in the appendix. Higher tax payments reflect the anticipated full utilization of our available UK corporate tax losses during 2024, as well as the resulting change in the phasing of our EPL payments. Now, specifically, the residual 2023 EPL liability to be paid in 2024 amounts to just over $400 million, the majority of which relates to EPL not payable by installments. There's a slide in the appendix that covers this topic as well. Looking further ahead to 2025, we anticipate production remaining broadly stable, with fewer plant shutdowns and increased volumes from new wells and projects substantially offsetting the natural decline. Our total capital expenditure is forecast to be materially lower. As a result, along with a more attractive hedge book, we expect to generate significantly higher free cash flow in 2025 compared to 2024 and to build a net cash position over the year. In the upper right-hand corner, we've illustrated our hedged volumes. Now, I talked about the very significant effects we've seen in our financial statements on the unrealized mark-to-market position. We are now back closer to zero in terms of unrealized hedges. For 2024, we've hedged just over one-third of our production using swaps for both oil and gas, helping provide some certainty around forward cash flows. For 2025, we are significantly less hedged and we're using a mix of swaps and collars for gas. Our gas collars have an average floor price of $0.112 and a ceiling of $0.263. For 2026, we are currently putting more hedges in place. As you can see, we had only a small portion of gas hedges in place at the beginning of the year, something we are now actively adding more to. We are also adding some oil swaps to 2026 now. Now, finally, just a reminder that the guidance provided on this slide relates to Harbour on a standalone basis before any contribution from the Wintershall Dea acquisition. I will now hand over to Linda to take you through the details and impact of the acquisition and to give some closing remarks. Thank you. Thanks, Alexander. As he said, while we haven't included the impact of the Wintershall Dea acquisition in our guidance, it will have quite a material effect on the business from its expected close in the fourth quarter. The acquisition will transform Harbour into one of the world's largest, most geographically diverse independent oil and gas companies, with material positions in Norway, Germany, Argentina, and Mexico. As a reminder, the $11.2 billion consideration will be funded through: first, the porting of about $4.9 billion of low-cost investment-grade bonds; $2.15 billion of cash, a significant proportion of which will be met from cash generated from the target portfolio being acquired during the period between the effective date of mid-2023 and completion; and finally, $4.15 billion of equity, which was valued at $0.360 per share. The quality of the portfolio, together with the way we've structured the acquisition, means that we expect to receive investment-grade credit ratings upon completion. The acquisition takes our production to nearing 500,000 barrels per day, adds about 1 billion barrels to our 2P resources, and increases our reserves life to eight years, an important priority for us. The acquisition enhances our margins, reducing unit operating costs by over 25%. It also advances our energy transition goals, significantly lowering our greenhouse gas emissions and expanding our already strong CCS portfolio. Importantly, the acquisition is expected to be accretive across all key metrics, including free cash flow, which was another important criteria for us. All of this supports an increase in our dividend and underpins our commitment to competitive and sustainable shareholder returns over the long run. We've already committed to a 5% increase in our dividend per share following completion, signaling our confidence in the future cash flow generation of the business. We showed this next slide in December, so I won't dwell on it here other than just to say that with the acquisition, we move significantly to the left, placing ourselves in a new peer group which, in addition to the large Norwegians, will include some large U.S.-listed independents, well-known companies like Apache and Murphy, who are mainly focused in North America. I think this page makes the point about the unique investment opportunity Harbour presents: a new large-scale global independent with a diverse and high-quality portfolio of mostly conventional offshore assets, with very competitive margins and low emissions intensity. It also makes clear the progress we made since founding Harbour a few years ago and the opportunity we have to continue playing a material role in the world's energy sector going forward. Since the announcement only a couple of months ago, we've made good progress on the various approvals and workstreams required for completion of the acquisition. Last month, we successfully completed a bondholder vote to amend certain terms and conditions of Wintershall Dea's $4.9 billion investment-grade bonds, for which we received significant bondholder support. We also successfully completed the syndication of the $3 billion revolving credit facility and $1.5 billion bridge facility, which were both oversubscribed. The margin on the new RCF facility will be approximately half that of our existing RBL facility, further evidence of the material financial synergies this transaction delivers. We're on track to publish the circular and prospectus and to hold the Harbour shareholder vote in the second quarter, where a simple majority of those voting is required to approve the acquisition. Typically, about 70% of our share register votes, so with 35% of our issued share capital already subject to irrevocable undertakings to vote in favor of the transaction, we're feeling good about this important approval. We've also made really good progress on all the regulatory, antitrust, and foreign direct investment approval processes, with substantially all necessary filings required having been submitted, including those in the UK and Germany. These are all progressing as expected, and in fact, we've already received the approvals required in a couple of countries. Given this progress, we're confident that we're on track to complete the acquisition during the fourth quarter of this year. Moving to our final slide, and just to sum up before we open the call to questions, 2023 has been a year in which we have materially advanced our strategy. We continue to invest in attractive organic opportunities to support production and cash flow, and at the same time, progressed our international growth and CCS projects. Our strong financial position, cash flow generation, and capital discipline has enabled us to deliver the shareholder returns over and above our base dividend while allowing the flexibility to pursue the Wintershall Dea transaction. In the two months since the deal's announcement, we've made great progress and look forward to completing the transaction before the end of this year. We'll now open the call for questions. Thank you, Linda. If you'd like to ask a question, please press star followed by one on your telephone keypad, ensuring you are unmuted locally. If you'd like to withdraw your question at any time, please press star followed by two on your telephone keypad. We will pause here momentarily just to compile the Q&A roster. Our first question comes from the line of Mark Wilson of Jefferies. Your line is now open. Please go ahead. Hi. Thank you for taking my questions. The first question I have is actually on the Wintershall Dea. We've seen various headlines regarding regulatory oversight going on in certain countries, certainly in Germany. Is there anything you can say specific to give people comfort on that? You've been very clear that you still expect all the approvals to come through. Is there any just more color you can give on that, please? Thank you. Hi, Mark. It's Linda. Thanks for the question, and it's a good one. I think we've tried to be very clear in the presentation about our confidence in getting to completion and the fact that everything is on track. We're making good progress exactly as we had expected that we would, so no unusual or new concerns in that regard. I think in Germany, in particular, in terms of the concerns raised in various press articles, I mean, I think just a few key facts and figures. Wintershall Dea's production in Germany accounts for less than 1% of Germany's total gas consumption, so not a big supplier of domestic oil and gas. And some of the articles were about CCS capabilities. Actually, none of the CCS licenses in Wintershall Dea are actually in Germany. They're in other countries, so they're in Norway, Denmark, UK. Wintershall Dea's CCS projects are around transportation and storage, and they don't involve the technology required to separate CO2 from various industrial processes. So that sort of technology relies on other companies, the actual emitters. So from our standpoint, with respect to some of the concerns raised, we don't see any issues that would have any impact on our ability to get the transaction approved. Okay. Thank you very much. And then one other follow-up. You're moving towards, well, certainly FEED stage at your U.K. CCS projects. Yesterday, we saw another 1 year of EPL put on the oil and gas side of things. Could you remind us of, if there is indeed such a thing, a connection between the two sides of the industry, oil and gas, and energy transition or CCS, in terms of the UK fiscal framework as it is, or in terms of how discussions are with the government on such things? Yeah. Thanks, Mark. A bit harder to answer given the fact that we're still progressing the project through all of its various approvals and the regulatory process. It may take different parts of it, maybe. The CCS expenditures aren't really allowed as deductions against the EPL, so from that standpoint, no real change to the situation when it comes to CCS economics or investment. I think the other link that we make, and we do make this point in our engagements with the U.K. government, is that companies like ourselves need cash flow and a supportive general investment climate if we're going to participate in these kinds of projects. So there is a link, sort of at least in that regard, to how companies like ourselves look at investing in CCS in the U.K. And you will have seen, once again, the impact of the EPL on our earnings with the results we put out today. So from that sort of higher-level standpoint, there's a linkage. I don't know if that answered your questions or not. That's fine. Thank you. I'll hand it over. Thanks, Mark. Our next question comes from the line of Lydia Rainforth of Barclays. Your line is now open. Please go ahead. Thanks, and good morning. Two questions, if I could. First, just going back to the Wintershall Dea deal, so it's a transformative deal for you. Within the existing Harbour business, are there things that you can do today to kind of get ready to basically have the biggest impact as soon as that deal closes within it? And then just secondly, we talked a little bit about it earlier, but that whole idea around natural gas prices and just kind of a little bit about your thoughts on that market as well, please. Thank you. Thanks, Lydia. On the first question, are there things we can do to get ready for completion? As you might imagine, a lot of work is ongoing at the time to do just that. We put them sort of in three buckets, if you will. The first bucket is all of the work that needs to get done to execute the completion of the transaction, and I talked about that in my remarks already between the bonds and syndication of the debt, the Harbour shareholder vote, getting the irrevocable signed up, which was really great progress for us. And then actually having the vote issuing the prospectus and circular, etc., all that going really, really well. Second bucket I would put in is around people. As you can imagine, we'll need a somewhat different organization. We'll be bringing on board five business units from Wintershall Dea, so we'll need some changes to leadership team, etc. So that's well in train. We have a process going through which we're offering opportunities for Wintershall Dea staff to apply for vacancies we have in the Harbour organization. That is now a live process, so we're looking forward. We're hoping to welcome in a number of Wintershall Dea staff from their corporate organization, which isn't part of the transaction, into Harbour Energy and also preparing our own organization for the changes to come. And then the third bucket is around systems and processes, so IT systems, etc. And absolutely a ton of work going on related to discovery around Wintershall Dea systems, how they relate to ours, selecting the best of both, deciding where we may or may not need a temporary transition services agreement, and all of the planning that needs to go into that side of its supply chain, you can imagine. Our priority will be on the safe transfer of the assets, in particular where there are operated assets. So we're just making sure we're doing nothing to jeopardize our ability to do that first and foremost. So a lot going on there. European gas prices, I think, was your other question, Lydia. And yeah, I mean, I've been in the business now for a very long time, and so we see these cycles all of the time. If there's anything I've learned, it's that I don't know what oil and gas prices are going to be in the future, and so we're very careful to stress-test everything we do against a wide range of oil and gas prices in the future. Alexander touched on hedging. That, of course, plays into this as well. We understand the fact that there's price risk out there, and that's why with each of our prior 3 transactions, and we're doing it again today, as he mentioned, how we think about when we're entering a period where we're increasing our debt, how we think about commodity price risk and hedging sort of is influenced by that. So we're already taking steps in that direction, and actually quite a good part of this year's European gas production across both companies is hedged, and a lot of it at some pretty favorable prices, so we're feeling okay about that. I think the other thing we keep in mind is that on a pro forma basis, our operating costs are going to be $11 per barrel, so that still gives pretty strong margins even at today's gas prices. Yeah, so I think I'll leave it. Maybe the other point is on a pro forma basis, if we look at how the production is split in 2024, maybe just around 35%-40% of it is European gas, and so a large part of that is hedged. And then we have the rest are split almost equally between liquids and then gas and other markets. Thanks, Lydia. And thank you. Our next question comes from the line of Matt Smith of Bank of America. Your line is now open. Please go ahead. Hey, good morning, everybody. Thanks very much. Just one question, please, really, around the, I guess, post-transaction. I think it's clear that there's many benefits to the Wintershall asset acquisition, but I think perhaps key one of them is probably the sustainability and visibility on cash flows that it gives you versus Harbour standalone, whether that relates to reserve life and decline rates and whatever else. So therefore, I'm just wondering how might that improved visibility feed back into your philosophy on shareholder distributions? Might there be any sort of changes in the philosophy itself or perhaps just a communication on the policy going forward once the deal is completed, please? Yeah. Thanks, Matt, for the question. We do get that one as well. As you can imagine, we're thinking about it. Why don't I let Alexander say a few words about how we might be thinking about that and the timing for when we might provide more insight? Yeah. Thanks, Linda, and thanks, Matt, for the question. I think, as we said when we announced the transaction back just before Christmas, that the capital allocation priorities that we think we've quite successfully had over the last three years, they would continue to be the ones going forward. We did sort of make the slight tweak in reinforcing our commitment to keeping an investment-grade credit rating. Now, when it comes to shareholder distributions, it's been a fairly simple policy up until this point, and that's what we'll have while the companies are operating as two independent companies through 2024. Now, once this transaction then completes in the latter part of this year, we do see that, as Linda said, it will put us in a different bracket in terms of peer group who have slightly different approaches when it comes to shareholder distribution. So we will use the time wisely over the next few months, not just transition integration, as Linda talked about in Lydia's question, but also firming up a bit more in terms of capital allocation framework. So there's, as you would expect, Matt, there's quite a bit of work to do in looking at the combined portfolio, determining investment plans going forward, capital spending, and so on, high-grading the best project, and so on. So we do want to just take some time through 2024 to look at that as we're firming up a more definite shareholder return policy, if you will. So that will come a bit later in the year. Perfect. Well, thanks very much. I'll pass it on. Our next question comes from the line of Chris Wheaton of Stifel. Your line is now open. Please go ahead. Brilliant. Thank you very much indeed. Good morning, Linda and Alexander. Three questions, if I may try and chance my arm. Firstly, on tax. Alexander, you've guided in that presentation to about $1 billion of tax. Can I just clarify that? It's actual cash tax being paid in 2024 at your scenario of $85 oil and 70p/therm gas. That's the first point I wanted to clarify. Secondly was the impact of tax on CapEx and investment plans. Obviously, you've talked about tax, sorry, CapEx, being materially lower in 2025 versus 2024. And I just wondered, my industry contacts are saying 20%-30% decline in spend next year on this year is quite likely. I wondered if you felt that was a reasonable estimate for where you thought activity or spend might be going. Those would be my first two questions, please. Sure. Alexander? Yeah. Thanks, Chris. On the first question, the very short answer is yes. The bit lengthier answer would be, well, we tried. We didn't go through it in the main presentation, Chris, but in the appendix there, there's a slide that details a bit just on which of the years the liability versus the cash effect is coming. But yes, that estimate is the cash tax we're expecting to go out the door in 2024. The second question, just on the impact of tax, EPL, others on CapEx plans. Well, I think for now, we've tried to guide directionally on how we see our spending in 2025 versus 2024. I think I would just add to that graphics on my ending slide, Chris, is that this is where we're seeing a benefit of being the operator here in the UK to a large part of the production. That does give us more flexibility when it comes to determining spending plans, high-grading, ensuring we are prioritizing the best projects on the backdrop of some fiscal uncertainty here in the UK. That's great. Thank you very much. Linda, if I may, one question for you and picking up on the theme of capital allocation. You've had a very strong capital return story over the last three years, as you said, returning a substantial amount of money to investors through buyback and through the dividend. If you look at the Wintershall Dea transaction and the free cash flow guidance from them for 2024, if you assume that rolls forward to 2025, given the business is roughly in steady state, plus the free cash flow generation from the core Harbour business, you're looking at free cash flow numbers of well in excess of $1 billion, it appears. How do you think about the ability to return that through buyback versus dividend, particularly when you now have some other big shareholders in place now with LetterOne and BASF post-transaction versus the dividend? Because obviously, you've given a steer on the dividend already. You've increased it by that 5%. I'm interested in the other bit of capital return we could see with that substantially enhanced free cash flow, which is the buyback. Yeah. Thanks, Chris. First, just to supplement maybe Alexander's answer to your second question, he's absolutely right that we're guiding to lower CapEx spend in 2025, and a large part of that is related to fiscal uncertainty in the UK. The other part of that is that we'll have lower international CapEx in 2025. I talked about the exploration campaign in Indonesia that's ongoing right now, so that will conclude here in the next couple of months. And at this time, don't anticipate spending that much at all next year in that area because it will take us some time to evaluate the results, decide where to drill next, etc. And then going to your third question, yeah, you're right. We have said acquisition is considerably cash flow accretive for Harbour. What will we do with the extra cash? I think just at the highest level, we'll probably do what we've done in the past. We have announced kind of a stable dividend that we think provides fairly competitive returns kind of as the foundation for our capital allocation framework. And then as we've had excess cash flow over the past several years, we have decided to use it for buybacks. Going forward at the highest and simplest level, I imagine it's going to be about the same. What we'll have that will be sort of new in the equation following completion will be, as you referred to, the large BASF shareholding. LetterOne as well, but BASF, as we all know, has stated their intention to exit oil and gas over time. They have come out and said that they believe that the investment in Harbour Energy is of good value for them, and there's value creation potential, so that should allow them to take their time in executing their exit. We're, of course, very mindful of that. We've dealt with high levels of overhang in the past with the Premier transaction in particular, so it's not a new situation for us. But we are mindful of that position of BASF's intention and the important role that buybacks may play given all of that. So that will definitely be part of how we think about the framework going forward. Thanks, Chris. That's brilliant. Thank you very much indeed. Thank you. Our last question comes from the line of James Carmichael of Berenberg. Your line is now open. Please go ahead. Hi. Morning, guys. Thanks for taking my questions. I might try and sneak in three as well if possible. Just thinking about the CCS portfolio, just wondering what you're thinking about returns on that business. We hear different numbers from different companies, so just wondering what your sort of assumptions are of what you could achieve or at least what you need to get clarity on that. And then just looking at sort of the 2C resources and timing of conversion of those into 2P reserves. I guess Indonesia's probably quite a long lead, but how do you think about converting the Mexico, UK, etc., resources into reserves? And then just lastly, our impairment pricing. I think if I'm reading it right, your UK gas price assumption and the impairment calculation's gone from sort of GBP 0.65 to GBP 0.90 over the long term, so about up 40% year-on-year. So just wondering what's driving that renewed confidence in the UK gas price outlook. Thanks. Great, James. Thanks. I'll take the first two and then turn it over to Alexander for your last one. On CCS returns, I mean, the honest answer is we don't know yet. The good news is we're now in that phase of the Viking discussions with the government where we're negotiating the economic terms of the license, so we should know sooner rather than later. What I can say is that we're not doing the project for free or for charity, that we will require an attractive return for the Harbour investors if we're going to invest in it. Comes back to our messaging around the EPL where we continue to make the point to the government that we need a stable and fair and attractive fiscal environment for us to invest in the country, and that includes in CCS. So we'll have to look at it as we learn more. We're also going through the FEED process, as I mentioned, which will give us a much better idea of the actual capital costs required to execute the project. So we'll know more at the end of all of that. And we'll look at, I think, a couple of things. We'll look at the base return we get from the regulated component of the project, which will be, as we think about it, phase one. And as you can expect, because it is regulated, that typically is code, at least for me, for relatively low returns. On the other hand, should be relatively low risk. We'll have long-term offtake agreements, if you will, speaking in LNG speak, with CO2 emitters who will be committing to deliver to us for transportation and storage their CO2 volumes for long periods of time. We'll have certain guarantees from the government. So from that sort of standpoint, it can be deemed lower risk than other things we might invest in, in upstream oil and gas, so we'll take that into account as well. The next thing to think about is there may very well be. We have good indications that there may very well be very attractive opportunities for project financing for a project like this. The number of banks are very interested in becoming involved and have their own drivers to help support projects like this. So that could help boost returns as well if we decide to get third-party financing. Then finally, I referred to the shipping component of the project. We are reserving some of the capacity for shipped emissions and expect a lot of those may actually be coming from continental Europe, and in that regard may fall outside of the regulated part of the project. We're strong believers, have a good degree of confidence in the low-cost nature of Viking relative to other potential projects being developed. And so we feel well positioned, hopefully, to be able to boost returns by supplementing the project with imported volumes. So sorry, a fairly long answer to your CCS question. On converting 2C to 2P, I think you have it right. The first one's probably to make that transfer could be in Mexico. As I said, we should be starting FEED soon on the Zama project. That notionally, I typically think about FEED processes as lasting about a year. There'll be some other agreements we'll need to reach around commercial and other things in the country, but hopefully, those can be done simultaneously. And so that may be the first one. And then if FEED starts pretty soon, should end sometime next year. Whether or not we get to an FID decision next year or not, still no certainty around that, but it could be possibly in the second half of next year kind of timing. But I'm not committing to that, to be clear. We have the Kan discovery in Mexico. That could be, if the appraisal well goes well this year, that could be a relatively short time to a development decision, so not too much longer than a Zama decision possibly. Then in Indonesia, the Tuna project, I said it's a bit blocked right now with the sanctions impact on our partner. If we can unblock that, which we're working to do, that project could go into nearly a FEED phase sort of soon too. So those three could move, relatively speaking, more quickly than Andaman. As you mentioned, that one will be a longer timeframe. We're getting a lot of data. We've drilled four wells so far, two major discoveries, one small one, pretty good track record for exploration so far. We have one or probably two more wells to drill with this rig. Then we'll have a lot of data. We just have to incorporate it into the model and decide what we do next in terms of appraisal, drilling a well to long-term production test. Do we need to test more prospects, etc., etc.? So that one will take much longer time. And let me now turn it to Alexander to answer the last question, and then I see we're past the end of past the beginning of the hour, and so I'll wrap it up after he answers that question, James. Thank you. Yeah, thanks, Linda. So yeah, quickly on your impairment question, James, and around the assumptions. Now, as you would expect, there's quite a bit of assumptions going into all of these impairment assessments where oil and gas prices are one of them. I think what we're trying to do is, and all companies do this, is to benchmark against market data, against other companies, and so on. So when setting this, we did benchmark and see that using an assumption of GBP 0.90, we're actually at the very low end of others. So we feel that that's an okay place to be. And do just keep in mind that these assumptions, they are set as of the end of the year. So you look at forward curves and you look at other things at the end of the year. I think looking back, when we did the same testing in the middle of the year, we used closer to 100, closer in time, and then it was dropping off at the far end of the curve. So it's an exercise at that point in time, looking at benchmark data and then setting those assumptions. So thanks, James. I'll put it back to Linda for a closing comment. Thanks. Great. Thanks, everyone, once again, for dialing in, and thanks for the good questions. We appreciate the time you're taking to consider Harbour Energy and your support and wish you a good rest of your day. Thank you. Ladies and gentlemen, I would like to thank you for joining today's call. You may now disconnect your line.