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Operator: Good morning, and welcome to the Harbour Energy 2025 Half Year Results. Today's presentation will be hosted by Linda Cook, CEO; and Alexander Krane, CFO. After the presentation, we will take questions. Linda, please go ahead.
Linda Zarda Cook: Good morning. Welcome to our first half results call. With me today is our CFO, Alexander Krane. Turning to the agenda. I'll walk you through our operational performance. Alexander will cover our financial results, and then it's back to me to wrap up, and we're aiming to leave plenty of time for questions. But first, let me hit the highlights for the first half. Today's strong results reflect the continued execution of our strategy. The Wintershall Dea transaction, which completed 11 months ago, has significantly enhanced the scale, the resilience and the longevity of our business. Perhaps the most obvious evidence of this is our production in the first half at 488,000 barrels per day. It's almost 3x where we were 1 year ago. These results are also supported by excellent underlying operational performance. Production efficiency was strong. Our approved capital projects are on track, and we made progress maturing our substantial 2C resources. At the same time, we demonstrated discipline when it comes to costs and CapEx, taking action to protect cash flow in response to a very volatile commodity price environment earlier in the year. We also strengthened our financial position, addressing near-term maturities and materially reducing net debt. The progress made in the first half enabled us to improve our cash flow outlook for the year to $1 billion. As a result, we're pleased to announce that in addition to our interim dividend, the Board approved a new $100 million share buyback. This will bring our expected total shareholder distributions for 2025 to $550 million. Moving on to operations. Safety remains core to everything we do in Harbour Energy. With respect to occupational safety, while we continue to be better than peer average, our incident rate has increased since completion of the Wintershall Dea transaction in September of last year, reflecting the different levels of performance in some of our new countries. And in process safety, we're running about average so far this year. So clearly, as always, more work to do in both areas. A key part of our integration process that follows each acquisition is to assess the safety processes, systems, competencies and culture in newly acquired locations. This helps us to identify any areas that are not up to Harbour standards and to prioritize actions for improvement. For the Wintershall Dea acquisition, this process is now complete, and we're taking steps to address the identified gaps and strengthen performance, in particular, in new operations in Germany and Mexico. While it will take time to see real results, I am encouraged by the strong commitment demonstrated by our team across the company. In terms of emissions, the Wintershall Dea acquisition actually helped deliver a step change improvement in our greenhouse gas intensity, which is now down by more than 1/3 to 12 kilograms per barrel, taking us below the peer average. Now on to production. As mentioned earlier, we averaged nearly 0.5 million barrels per day in the first half, split roughly 35% Norway, 33% U.K. and 15% Argentina, with the remainder from Germany, North Africa, Mexico and Southeast Asia. The results, of course, reflect the acquisition, but they also reflect the impact of new projects and wells on stream, including in Norway, the U.K. and Argentina, and also improved reliability. In particular, we benefited from strong delivery at our largest operated hubs in the U.K., including from the Talbot project that started up in late 2024 and also from high local gas demand in Argentina. While some of our annual planned maintenance in the U.K. is now behind us this year, the majority is set for the third quarter across both the U.K. and Norway. As a result, second half production is expected to be lower than first half. Also contributing to this is the divestment of Vietnam, which closed on July 9 and which averaged 5,000 barrels per day in the first half. But with a solid 6 months behind us, the uncertainty around our 2025 forecast is now reduced, and this gives us confidence to narrow our full year production guidance upwards for the second time this year, this time to 460,000 to 475,000 barrels per day. Turning to the next slide. Unit operating costs reduced by more than 30% to $12.40 per barrel, reflecting the addition of the Wintershall Dea portfolio, strong production volumes and an increased focus on costs, which more than offset the impact of a weaker U.S. dollar. Notably, our U.K. team has done a great job delivering top quartile unit cost performance. Unfortunately, however, as previously announced, we are again reducing our Aberdeen workforce. This is to align with lower levels of U.K. investment going forward given the ongoing challenging fiscal and regulatory environment in the country. The reorganization will complete later this year and deliver cost savings from 2026. In terms of the acquisition integration, it's going well. We now have the keys to various Wintershall Dea IT systems and are running those ourselves, and we remain on track to exit the transition services agreement by the end of this quarter. And then the second phase begins, the rationalization of these with Harbour's legacy systems, removing duplication and making us more efficient. While most of this effort will lead to savings only over 2026 to '27, I'm pleased that we've already been able to leverage our increased scale with a couple of key contractors to capture supply chain synergies, and there's likely more to come over time as additional contracts come up for renewal. Given the first half performance and outlook and the exit from Vietnam, which was the highest unit operating cost country in our portfolio, we're lowering our full year OpEx guidance from $14 per barrel to $13.50. This is despite the not insignificant FX headwinds, which Alexander will talk about in a moment. Turning to the next slide on our capital program. We spent $1.1 billion in the first half and are on track to meet our previously narrowed CapEx guidance of $2.4 billion to $2.5 billion. Looking at CapEx on a per barrel basis, if we compare our full year 2025 outlook to the first half of 2024, which was before the acquisition, it's down 33%. In terms of focus, the money we're investing this year is largely aimed at converting 2P reserves into production, predominantly in Norway, the U.K. and Argentina. In Norway, first half highlights include start-up of the Harbour-operated Maria Phase 2 project in May and solid progress with other subsea developments currently in the execution phase, including Solveig Phase 2, a 3-well tieback to Edvard Grieg due online in the middle of 2026, our Harbour-operated Dvalin North project, where we recently completed installation of the umbilical and pipeline, keeping us on track for first gas late next year. And importantly, after 1 million hours worked, there were no recordable safety events, something our team is rightly proud of. And at Aasta Hansteen, Equinor recently installed a new topsize module in preparation for receiving gas from the Irpa development towards the end of next year as well. In the U.K., we continue to focus on quick payback opportunities around our largest operated hubs, J-Area and Greater Britannia, or GBA. Here, we've significantly improved drilling efficiency. Our 2 J-Area wells online in the first half both delivered best-in-class performance. And in Argentina, at the Aguada Pichana Este or APE concession onshore Vaca Muerta, we drilled 9 3,000-meter lateral wells in the first half with a 10th well drilled since then. And we successfully completed and connected 6 new wells, each with 50 fracs. Here, the operator continues to improve performance and has reduced total well costs compared to the 2024 campaign. We've now paused drilling on the license until early 2026, with sufficient gas from the existing wells to keep the processing plant at capacity and to meet local gas demand. In another success story, we also drilled a CO2 storage appraisal well in Norway. The well was a commitment well entered into by Wintershall Dea when securing the Havstjerne storage license. It was drilled safely and under budget with top quartile performance and was also successful in terms of proving up the license CO2 storage capacity. So we're now moving on to explore various potential commercialization options. Turning to our 2C resource base, which includes a balance of short-cycle near infrastructure investments, the scalable Vaca Muerta shale in Argentina and longer-term conventional offshore growth projects. We're prioritizing efforts to focus on our best projects, enabling the high grading of the portfolio and to underpin long-term cash flow. In Norway, we prioritize the Gjoa Subsea projects, where we target FID in mid-2026, and also development concept studies for the Cuvette, Adriana/Sabina and Storjo discoveries. In the Vaca Muerta, we've booked 600 million barrels of 2C resource, but see the potential to almost triple this. At APE in the gas window, we have 90 producers and 500 million barrels of booked 2C resource, but there's potential to significantly increase this with line of sight to 1,300 locations. What's needed, however, is a market for the gas, and that's why we've entered the Southern LNG -- Southern Energy LNG project. The 2-vessel 6 million tonne per annum project took FID on the first vessel in May, making it the country's first LNG export project. It will provide our Vaca Muerta gas with access to global markets as well as through the new RIGI legislation access to investment incentives and offshore U.S. dollar revenues. Start-up of the first vessel is expected around year-end 2027, while start-up of the second vessel approved by partners yesterday is anticipated around year-end 2028. Our second license in the Vaca Muerta San Roque is in the oil window. Following a successful 4-well pilot, we're preparing to apply for the unconventional license, and once received, it will enable development activities to commence. With around 1,000 potential well locations, we believe there's more than 500 million barrels of net resource to target, of which less than 100 million barrels is on our books today. In Mexico, our stakes in the conventional shallow water Zama and Kan projects together could yield reserves equivalent to more than 2 years' worth of our production, illustrating why these are priorities for us. After the recent successful appraisal drilling at the Harbour-operated Kan discovery, we increased our gross resource estimate by 50% to 150 million barrels. Today, we're focused on development concept selection so we can move into the FEED phase as soon as possible. And at Zama with a 32% interest in gross resources of 750 million barrels, discussions with partners are underway around a potential phase development. Before I hand over to Alexander, it's worth underlining that the Wintershall Dea acquisition not only delivered a step change in scale of our production, but also in the resilience and longevity of our cash flow. Over the next few years, we expect new production in Norway and Argentina to substantially offset the managed decline in the U.K. with additional support from Mexico from 2030. As a result, we're confident in our ability to continue to produce at scale and generate material cash flow well into the next decade. This is supported by our nearly 20-year reserve and resource life with additional potential not captured here in respect of exploration success and M&A. And now let me hand over to Alexander.
Alexander Krane: Great. Thank you, Linda, and good morning to everyone dialing in this August morning. I will start with a few financial highlights. Against a challenging macro environment, we delivered a strong set of financial results, reflecting a full 6 months contribution from the Wintershall Dea portfolio and excellent operational performance. We materially increased the underlying earnings of our business, generated significant free cash flow and we reduced our net debt. We also successfully prefunded all maturities to 2028, further strengthening our financial position, and have increased our full year free cash flow outlook to $1 billion. As a result of all of this, we are well placed to continue to deliver against our capital allocation priorities and have, therefore, announced additional shareholder returns with a new $100 million share buyback program. Let's start with some market context on Slide 13. The first half saw significant oil and gas price volatility driven by geopolitical and economic factors. Brent was 15% lower than that of the same period last year, averaging $72 per barrel. In contrast, European gas prices were 40% higher, averaging $13 per MMBTU or approximately $80 per BOE for those that prefer that. We continue to hedge our commodity price risk and we were able to capture particularly attractive gas hedges during the period, whilst also taking advantage of brief periods of oil price spikes to hedge some crude. We also saw a significant depreciation of the U.S. dollar, which has weakened by almost 15% versus the euro, making it the worst start to the year for the U.S. dollar in more than 20 years. This impacted our financials as we report in U.S. dollars. As such, a weaker U.S. dollar incrementally improves our free cash flow as more of our revenue is in local European currencies than costs. However, the weakening of the U.S. dollar also increases the U.S. dollar value of our euro-denominated debt, which you will see later. In summary, we expect continued volatility and uncertainty. As you can see from the graphs here, July was no exception with U.S. dollar strengthening again. And it is at times like these, a diverse portfolio, a prudent approach to risk management and an investment- grade balance sheet are critical. Turning now to the income statement on Slide 14. For the first time, we are reporting adjusted performance measures, which we believe provide a more meaningful comparison of the underlying performance of our business and brings us more in line with peers. You can read more about these adjustments in our financial statements. Post hedging, we realized prices broadly in line with global benchmarks for our oil and European gas for the first half of 2025. Our realized European gas prices for the same period last year were impacted by lower legacy hedges, the last of which expired in the first quarter of this year at less than GBP 0.50 per therm. Our reported revenue and EBITDAX for the first half more than doubled, reflecting the step-up in production and significantly higher realized gas prices. This was only partially offset by lower realized oil prices. In terms of costs, as Linda mentioned, our unit operating costs have reduced by over 30% year-on-year to $12.4 per BOE, supporting resilient margins. This reflects the addition of the lower cost Wintershall Dea portfolio, strong volumes and good cost control, offsetting the weaker U.S. dollar. Net financial items were impacted by the U.S. dollar movements I mentioned on the previous slide, resulting in foreign exchange losses of $0.5 billion, partly offset by gains on foreign exchange forward contracts to hedge our FX exposures of approximately $0.3 billion. There's a detailed Note 6 to the financial statements for anyone looking for a breakdown of these financial items. Adjusted profit after tax for the period increased to $410 million, while adjusted earnings per share doubled to $0.22 per share compared to the first half last year. Now in terms of adjustments, there are 3 main items to note. First, impairments, which totaled $186 million and are predominantly related to a small number of mature U.K. oilfields, reflecting lower near-term oil price assumptions. Secondly, foreign exchange losses of $193 million due to the revaluation of intercompany balances driven by the weaker U.S. dollar. And to be clear, this is a purely intercompany effect we are adjusting for. And thirdly, we've adjusted for the $300 million charge related to the extension of the Energy Profit Levy in the U.K. So collectively, these 3 adjustments resulted in an adjusted tax rate for the period of 80%. This is more in line with what you would expect given the 78% statutory tax rates in Norway and the U.K. Turning next to cash flow. During the period, we generated $3.8 billion of operating cash flow. We spent $1.1 billion on total capital expenditure, and we paid $1.4 billion of taxes. We also benefited from a $0.2 billion working capital movement. This resulted in a very healthy free cash flow generation of $1.36 billion for the first half, significantly derisking our improved $1 billion full year free cash flow outlook. Further, our dividend is now covered down to prices of $35 per barrel Brent and $8 mscf (sic) [ $8/mscf ]European gas in the second half of the year. The first half weighting of our free cash flow reflects the Q3 planned maintenance programs, higher CapEx in the second half with increased activity in Norway and then expected part reversal of the positive $200 million working capital movement. However, the largest driver is timing of U.K. tax payments, with first half tax payments equating to around 40% of the total expected payments for the group for the year. We've also been proactive with our debt refinancing, with net bond issuances amounting to $1 billion during the period and repayment of our RCF such that we were undrawn at the period end. I will now turn to the bond issuances in more detail on Slide 16. During the first half, we issued $0.9 billion of senior notes and EUR 0.9 billion of subordinated notes, concurrently repaying $0.3 billion of legacy high-yield bonds and EUR 0.6 billion of the subordinated notes. This means we were able to effectively prefund all our senior debt and subordinated note maturities to 2028 and strengthening our balance sheet with an additional layer of subordinated notes. Thanks to the very strong free cash flow generation in the first half, we reduced net debt by $0.9 billion to $3.8 billion and leverage to 0.5x, comfortably below our internal 1x target. The impact of the weaker U.S. dollar, which increased the value of our pre-swap euro- denominated bonds by $0.7 billion, was partially offset by the net addition to cash balances of $0.4 billion from the subordinated notes issuance and repayments. Now further, at June 30, we benefited from a $0.2 billion mark-to-market gain on our cross-currency interest rate swaps. This offsetting gain is not included here in the net debt calculation. Whilst we only have about 20% of our debt denominated in U.S. dollars, on a post-swap basis, our debt exposure to U.S. dollar is now around 60%. This mimics our U.S. dollar versus euro and British pound revenue with approximately 40% of our production being European and U.K. gas. We ended the first half with over $5 billion of liquidity. And having prefinanced all maturities to 2028, we're in a strong financial position. Moving to our free cash flow outlook for the rest of the year on Slide 17. We've increased our free cash flow outlook to $1 billion, driven by our continued strong operational delivery across the board, further offsetting the impact of lower commodity prices. As a result of this and our strengthened financial position, we are pleased to announce a new $100 million buyback. Along with our $455 million annual dividend, this means that roughly half of our free cash flow in 2025 is expected to go towards reducing our net debt and the other half to our shareholders. And our sensitivity to movements in Brent and European gas prices for the year remains the same. Before I move to our guidance, a quick look at our commodity hedging on Slide 18. Our strong financial position and balance sheet is supported by the diversity of our revenue mix. In addition, we aim to hedge approximately 50% of our economic exposure to commodity prices in year 1 and 30% in year 2. We use both swaps and nonlinear structures. This helps to protect our cash flow through the commodity price cycle whilst maintaining upside participation. For the 18 months through to the end of 2026, we've hedged approximately 40% of our economic exposure to Brent and 50% of our economic exposure to European gas prices. As you can see from the graphs on the right here, we've locked in some good pricing above the forward curve, leaving us with a pretax mark-to-market position of around $0.4 billion as of June 30. So what does this mean for our guidance and outlook? Well, we've lifted the lower end of production guidance for the second time this year, now set at a range of 460,000 to 475,000 barrels of oil equivalent per day. This reflects continued high reliability across the portfolio, increased production from our operated U.K. portfolio and strong volumes from Argentina, collectively more than offsetting the impact of the Vietnam divestment. OpEx guidance has been lowered to $13.5 per BOE despite a weaker U.S. dollar. This reflects strong cost control year-to-date and the sale of the higher cost Vietnam business post period end, as mentioned by Linda. We are reiterating our previously narrowed total CapEx guidance of $2.4 billion to $2.5 billion as we continue to challenge our portfolio and high grade it. And as mentioned a couple of times already, we have increased our full year outlook for free cash flow by $100 million to $1 billion, enabling us to increase expected shareholder distributions to $555 million for 2025. Now my last slide is just a reminder of our capital allocation priorities, all unchanged from our update earlier this year. We will continue to invest in our business to improve our portfolio, prioritizing our best and most competitive projects. We will deliver attractive through-cycle shareholder returns as further evidenced by today's $100 million buyback announcement, meaning we will have returned $1.8 billion since listing in 2021, and all of this while maintaining financial discipline. So thank you. That's all for me, and I will now hand you back to Linda.
Linda Zarda Cook: Thank you, Alexander. So we've had an excellent start to the year, both operationally and financially and enter the second half in a strong position. We're seeing the benefits of the execution of our strategy, the expanded portfolio and the additions made to strengthen our team globally over the past year. This progress gives us continued confidence in our asset base and in our ability to meet our capital allocation priorities, including maintaining our investment-grade balance sheet and delivering additional shareholder returns through buybacks. With that, I'm going to hand it back to Matt, and we'll open the call for questions.
Operator: [Operator Instructions] Our first question comes from Lydia Rainforth from Barclays.
Lydia Rose Emma Rainforth: Two questions, if I could. The first one, just Linda, when you think about the integration with the Wintershall Dea assets, that's clearly been going very well. I'm just wondering if you can talk about things that -- about how far you think you are through that integration process now in terms of getting the best out of the assets. Are we all the way done? Are we 50% of the way done? So just that sense of how much more you think the portfolio can give you relative to what you were hoping? And then secondly, if I can come back to the free cash flow guidance. So this is the second improvement that we -- that you've given us over the last couple of updates. And I think the underlying improvement is about $300 million, which is significant. Should we think about that rolling into next year and into '27 versus where the plan was? And what I'm thinking about there is like the buyback for today, does that actually -- is that something you think about, that level should be what we should be thinking about going forward subject to where prices are? And then sorry, one final one. Just on Argentina, we did see TotalEnergies yesterday sell part of their exposure for about $10,000 an acre. When you think about the potential of the Argentina business, is that something that you would think about in terms of the valuations that you would look at – or, effectively, would you -- is that a fair valuation from your side?
Linda Zarda Cook: I'll take the first and the last one and then turn it over to Alexander for your second question. So the first question was how do we think about how far along the integration journey we are following completion of the Wintershall Dea transaction, which was just 11 months ago as we think about it. I would say we're on track with where we thought we'd be. And the biggest milestone is getting off the transition services agreement, which I said we're on track to do here in the coming weeks. And that means that we already have the keys to the IT systems. That's all gone very well. That just happened less than a week ago, I think. So far, no issues with that. And have taken that time to hire the people we need to support us going forward and replace those in the old Wintershall Dea RemainCo that sort of still exists in Germany. So that's all going well and on track. I think the -- and operationally, everything is going well. If we think around the business units we've acquired, no surprises technically or operationally other than probably we're a bit more excited about Argentina than we had anticipated pre-acquisition. And I think all of that's demonstrated and comes through in our first half results with what we've seen with production, operating costs, emissions, et cetera. I think where we're in the really early stages, though, is in driving the cost efficiencies through the expanded company. So we have to wait for a lot of contracts that we've assumed to come up for renewal. At that point, we can consolidate them with existing contracts we may have with the same suppliers. We need to rationalize systems. So we've taken on hundreds of new, for example, IT applications, and we're going through those and trying to rationalize and decide which ones we really need, because once we add them together with the applications we already had in Harbour Energy, there is duplication. And all of that just takes time. So I think we'll finally get to a run rate on all of that or where we need to be probably over the course of the next couple of years, is how we think about it. And that's similar to the experience we've had with other acquisitions in the past. So early days from a rationalization and driving improvement standpoint, but so far, so good. The Argentina question, Lydia, yes, we saw the news just yesterday, and I honestly haven't seen all of the details yet, but maybe just note a couple of things. The license that Total sold was in the volatile oil wet gas window of the Vaca Muerta. So if we think about how that might relate to our position in that play, our San Roque license, which is also operated by Total and is not a license that they've marketed, which I think is probably telling. So they're keeping that. It's in the -- solidly in the oil window in the Vaca Muerta. So better position from a hydrocarbon phase standpoint. And we're actively working with Total and the other partners on what a development plan might look like. And we're anxious to start development once we get access to the unconventional license, which we're in the process of applying for.
Alexander Krane: Yes. I'll take the free cash flow guidance one, Lydia. Yes, I think it's fair to say that we're happy with performance in the first half of the year, and, of course, we're happy to be able to increase the free cash flow guidance again here. I mean it's only 4 months or so since we had the Capital Markets update, where we laid out our expectations over the 3-year period. And yes, of course, it's a good start to that 3-year period, and it does give us confidence in delivering those targets that we set out, whether it's production or it's on the spending side. And the free cash flow guidance we gave at that point still holds true for us. So yes, I think it's been a strong first half. We've sort of tried to control the things we can control, whether it's taking care of the balance sheet or whether it's hedging or revisiting costs here. So yes, there's really no change here, Lydia, from what we said earlier in the year.
Operator: Our next question comes from James Carmichael of Berenberg.
James Carmichael: You talked about sort of a payout ratio of 55% this year based on current free cash flow guidance. Just wondering if you're sort of thinking about introducing some form of cash flow-linked payout in the future? Or are you going to stick with the flat dividends topped up by the buyback? And then maybe just a clarification on the buyback. I appreciate you giving yourselves until 31st of March, but a lot of the footnotes referenced are assuming it's completed by the end of the year. So what should we think about on timing there? Just a quick one also on the transitional services agreement. Just wondering what that sort of means day-to-day when you exit that and whether there are any cost savings? If I could just sneak in a last one on Argentina, just the sort of steps and timing to getting that unconventional license would be helpful.
Linda Zarda Cook: I'm going to take #3 and #1 in that order and then turn it – or, no, 3 and -- sorry, I've lost track. I'll take Argentina, then I'll turn it to Alexander. On Argentina, yes, it's -- the partners are in discussions with the provincial government around the unconventional license. So we had received approval for the 4-well pilot program a few years ago. That pilot program has now been completed. That means we move into the next stage where we apply for the actual license. Hopefully, we'll make that submission sometime in the coming months and get the license awarded not too long afterwards. It should be a pretty straightforward process. And then Alexander, on the financial question.
Alexander Krane: Yes. So I'll take the one on cash flow and timing of buybacks and – yes, so when we introduced our capital allocation framework a bit earlier this year, you probably recognized quite a bit of it, James, from some work we had in the past, except some tweaks here and there. And I recognize that a lot of companies, they have more CFFO-linked dividend policies, but we thought it made sense to have a more fixed amount at that point in time. We're quite pleased with sticking with that somewhat more simplistic policy, if you will, and rather seeing how does this compare on a ratio at least for now. And again, it's only been less than 6 months, 4 or 5 months since the capital markets update. So we're not really revisiting that at this point. But yes, we'll assess in the future -- in future periods if we get the mix of dividends and buybacks right or if it does indeed make sense to have fixed plus some more variable elements. But for now, there's no plans on changing that point. So on the buyback timing, yes, I mean, there's a backstop date of March 31, which obviously feels like a long time from now. The numbers we gave, James, that was, yes, just simple math, saying that, that does assume that we managed to wrap this up by New Year's Eve, and that's how you get to the 55%. But the backstop date is end of March.
Linda Zarda Cook: And James, your second question was on the TSA. So maybe just let me explain that a little bit. So if you think back to the Wintershall Dea transaction, we didn't buy the whole company. We bought assets, so business units owning and producing assets in a variety of countries around the world. We didn't buy the corporate center, and the corporate center was supporting all of those business units in Wintershall Dea. So that corporate center still exists, if you will. We refer to it as Wintershall Dea RemainCo sometimes. And that corporate center, we had an agreement with them that they would continue to provide certain services to us, and we've been paying for that on a monthly basis so long as we needed them, and it expires in about a year, so in early September or by the end of September. There were, I think, maybe 11 components of that TSA. We've already completed 7 of them. So they cover things like HR support. An example is German payroll. We don't have -- I didn't have a business in Germany before the transaction. So we didn't have a group able to do payroll or help us file German tax returns, for example. So those things continue to be provided for by the RemainCo. And then the biggest thing are all of their IT systems. So they've been providing those for us, so e- mails, technical applications, et cetera. So during the past 11 months, we've slowly worked through all of those to be able to be in a position to run and operate all of those things ourselves and take over the administration of the contracts. I think we're through 7 or 8 of the 11 components already, have 2 or 3 to go. Everything is on track for complete handover, like I said, by -- during the third quarter, I think, by the end of September. And the biggest one, as I said, was the IT services. So as of last week, we're now running all of those systems ourselves. We're in a period of hypercare in case we need it. So the Wintershall Dea RemainCo people are there and available for us should we need it. But so far, everything is going really well, and we're actually running and operating those systems and we have control of the contracts and are administering all of that ourselves. So it's a process we've gone through before. I think with both the Shell and Conoco acquisitions, we did the same thing. This process, even though it was a much larger acquisition, we've done it faster than we did for those others. One of them, I think, took 18 months. So we're really proud of the capability we've built in-house to be able to understand and sort of methodically plan and then work through the integration transition process as we complete acquisitions. And that remains part of our skill set and strategy going forward. What does it mean financially? That by the end of September, we'll stop having the cost of that transition services agreement. It doesn't completely go away, because if you think about it, we're now running those systems ourselves, so some of those costs are still going to be with us instead of them charging us for it. And we've also had to hire people to do things like German tax returns or payroll, et cetera. So we've been replacing those costs over time with our own overhead or G&A or other support. So now that important phase is behind us. We've executed it well. But I think the really hard work begins. And I always hate to remind the team about this, but now the hard work begins, and that's rationalizing all of these systems with what we have today in Harbour. So do we need system X from Wintershall Dea and our system Y or can we consolidate those? Is one or the other the right choice for us? Or do we have to go to system Z, et cetera. So all of that work begins, and that's where we'll get real cost savings, and that will happen over the course of a couple of years. But like I already said, we already have had a couple of good, I think, wins for us when it comes to supply chain things. So we renegotiated, for example, technical -- it was in geo modeling area -- so technical licenses with a global supplier that led us to have significant savings. We negotiated better rates on subscriptions with Microsoft, for example, so leveraging our scale, as well as subscriptions with things like WoodMac. So we're already starting to realize some of it, but much more to come. Again, we will take a bit of time.
Operator: Our next question comes from Mark Wilson of Jefferies. We seem to be having an issue with Mark, so we're now going to hand over to Teodor Sveen-Nilsen from SB1 Markets.
Teodor Sveen-Nilsen: A few questions for me. First, you mentioned you do see strong local gas demand in Argentina. I just want to know if that impacts the realized gas prices or if there was something you can do to capture that strong demand in terms of prices? Second question that is on general cost inflation. One of your peers were recently pretty clear on that they see cost inflation across the industry. Could you just update us on what you are seeing on that front? And my final question, that is on the new buyback. Did you consider to increase the cash dividend instead of announcing a buyback? And if so, what kind of consideration was made behind that decision?
Linda Zarda Cook: I'll take, I think, the first and maybe the third one and hand it over to Alexander to talk a bit about inflation. On Argentina, we did see strong gas demand in Argentina, mainly weather-related, a little bit economy, but also largely weather-related. Pricing, our domestic gas is sold under contracts, so about half of it under long-term contracts at around $3.50 per million standard cubic feet, and the rest of it is sold into the domestic market on 1-year contracts and typically at fixed prices and generally between $3 and $4 per scf. On the buybacks, yes, of course, we debate capital allocation and if we have excess cash flow, what to do. But as we said at our Capital Markets Day, because we view our current base dividend as relatively competitive in the market, more or less, compared to a wide group of our peers, our priority has been after focusing, of course, on debt reduction, is to return excess cash flow via buybacks, and that remains unchanged. Alexander, a bit on inflation maybe.
Alexander Krane: Yes. No, thanks for that. And yes, just on the buyback versus dividend. I mean, we're mindful of what our peer group and others are doing as well and on our shareholder register. So it seems to be, we think, hopefully, a good balance here between the 2. I mean on cost inflation, I mean, we're seeing some of it. But to be honest, I think the performance has been pretty good in the first half and we're able to offset much of what we've seen there with operational efficiency here. I think also for some of the bigger projects we have, they are pretty well advanced. So the cost move hasn't been -- we haven't really seen that much there. So I'm actually quite happy with the cost control that we've seen through the business. We're somewhat -- I mean, we're somewhat exposed to FX, of course. FX for us in this business is a bit complex. So we, of course, try to look at this as holistically as we can, trying to mimic a bit of revenues coming from different currencies and where do we have costs and then, of course, balancing that with the financing. So yes, I mean, when the dollar weakens, any costs coming through in NOK, euro or pounds will, of course, be somewhat higher. But given that our revenues are significantly higher than the cost base, incrementally, that's good for our cash flow.
Operator: Our next question comes from Matt Smith at Bank of America.
Matthew Smith: A couple of questions, please, left. I think the first one, I think, clearly, the quantum and resilience of your near-term cash flow, free cash flow, is showing through very brightly by now. And I think perhaps that turns attention towards the sustainability of your production base and, more importantly, your cash projection into the next decade, as you already referenced. So I guess on that topic, would you be able to give us a bit of an update on your key major projects, potential projects? You touched upon Kan and Zama in Mexico and also your gas discoveries in Indonesia. It sounds as though Tangkulo, in particular, the operator is moving things forward at a pace there. So any updates on those major projects would be useful. And then the second question, please, would be on the U.K. portfolio, which is a very diversified business now, but U.K. volumes still remain very material for the group. I think at the very least, it's fair to say we're hoping to have better clarity and visibility on the U.K. sort of fiscal and regulatory framework later in the year, whatever form that may take. But do you think that will facilitate any further options to create value in that U.K. business from an M&A perspective, whether that's Harbour actually acquiring U.K. assets or potentially disposing some of them?
Linda Zarda Cook: On the first one around key projects, yes, I touched on most of them already. So let me maybe start with Mexico. So Zama alone biggest undeveloped discovery in Mexico, extremely important not just to us, but also to the government and to Pemex. So it's getting a lot of focus and attention. Unfortunately, we're not completely in the driver's seat on this one with Pemex owning 51%. So it does involve a lot of collaboration not just with Pemex, but also with the Energy Ministry and the Finance Ministry about how we bring that forward. We're mindful of Pemex's financial challenges, so that comes into play as well. So as you can imagine, a lot of discussion ongoing now around the design for the development, how to get to first oil as soon as we can. So thinking about things like phase developments and then trying to make sure that all partners are going to be in a position to pay their own way, if you will. So a lot of things to solve for there. But the really -- the good news is from a subsurface standpoint, it's in shallow water. The reservoir is fantastic. Development itself and then ensuing production should be very straightforward. So we're all anxious to get to FID as soon as we can. But unfortunately, given the complexity of some of the discussions, I don't have a real clear line of sight to that. But hopefully, not in the too far distant future. Kan, on the other hand, is a different story. We are the operator. We have 70% of the project. Total has the other 30%. Again, another high-quality discovery. Shallow water should be a straightforward development. So we're working as efficiently as we can through concept select and hoping to drive that to FID in the not-too-distant future, so possibly as early as next year, and then get it into production as soon as we can. So that one -- we're moving both forward as fast as we can and we'll see which one gets to the finish line sooner than the other. Argentina, another big part of our 2C resources, already drilling away on the gas side on the APE lease. We'll pick a rig back up. As I said, we've taken a pause now given the increase in production. And we're at the capacity on the existing gas processing facility. So it took a pause on drilling, but we'll start back up next year on the gas license. And then at San Roque, as I've already talked about, applying for the unconventional license. But lots of potential there, and we're really excited about how we're positioned there and also our interest in the LNG project, which --I think we're probably amongst independent oil and gas companies around the world, best positioned in the country, sitting there alongside major oil companies and, of course, the big domestic players. In Norway, there's not a -- it doesn't get as much airtime as maybe it should because it's not a single big discovery or development going on. Instead it's this sort of steady pipeline of projects that are already in execution phase and moving towards FID over the next couple of years. And that's going to continue to be important for us as well. And then the Andaman in Indonesia, you're absolutely right, really good gas discoveries there, multi-TCF play and a great geographic ZIP code given the growing demand for natural gas in the region. And now it's just working with our partners, Mubadala, who operate one of the big discoveries, and then ourselves, who operate the other license with a couple of discoveries on it, just working together in collaboration to find the best way forward. Tangkulo, the discovery on Andaman South, the license operated by Mubadala, actually has the best reservoir quality. So it makes sense that, that one may be first out of the chute. So we're just working with them on how then we phase the development that also takes advantage of the discoveries over the entire area in which we're both partners to maximize value for both of us. So some movement forward there. But again, it will take some time. So those are, I think, the big ones, Matt. Then in the U.K., yes, the consultation period on the EPL has ended. We're now waiting to hear from the government on what the outcome will be, and that probably won't be until later this year. Maybe at the autumn budget, we'll hear what the EPL will be replaced with once it expires in 2030. I think in the meantime, what we've done is make the most of what has been a challenging situation, and our team has done a great job driving down unit costs, executing the high payback or high-return quick payback opportunities we had in the portfolio. We just successfully completed the maintenance on the J-Area in the first half of this year. So they're really firing on all cylinders in what's a challenging environment and in the midst of a redundancy program. So I give them a lot of credit for delivering what they have for us, and we really appreciate all the effort going on in Aberdeen. Going forward, as we said, we do expect investment to decline in the country given the fiscal and regulatory conditions. That doesn't mean we don't still have some high-return opportunities. But overall, investment likely to decline and will be replaced by investment in Norway, Argentina over time, Mexico. And that in and of itself will transform our portfolio and overall give us lower unit operating costs as we replace the U.K., which is one of our highest unit operating cost countries even with the progress that's been made, and it's one of our highest tax environments as well. So that production will get replaced over time with production from other countries, and that's a good thing for us overall in the portfolio. That was the last question. I guess, Mark Wilson, we've lost, he hasn't come back online. So we're going to close it there. Thanks to everyone for dialing in. We do know it's holiday time for some of you. So we appreciate the interest. And again, we're excited about what we've done in the first half and looking forward to continuing the delivery throughout the second half of this year and beyond. Thanks again.