Good morning, everyone. Welcome to Capricorn's Results Presentation. I'm Simon Thomson, CEO, and with me are James Smith, CFO, Paul Mayland, COO, and Eric Hathon, Exploration Director. As in the usual way, we've got a presentation to run through with you this morning, following which we would be very happy to take questions. Before moving on to the slides, I'd like to take a few moments to update you on our proposed merger with Tullow. The board continues to believe that the proposed merger can deliver significant long-term value for shareholders through creating a leading Africa-focused energy company. The board is also mindful of the impact of external factors and market conditions and is, as always, assessing all options to maximize value for shareholders. The company is exploring a number of expressions of interest relating to alternative transactions and is engaging with those parties expressing interest to evaluate potential outcomes. Now, we will provide you further updates as appropriate, and in the meantime, as I'm sure you'll appreciate, are limited in anything further we can say, and the focus of today's presentation will be on the company's current position and operational performance. Turning to the first slide, and in terms of the underlying business, as a team, we remain focused on the consistent delivery of our long-term strategic goals of sustainability, returns, and growth. In terms of sustainability, our balance sheet strength and continued fiscal discipline affords us the financial flexibility to deliver our growth strategy. We have demonstrable milestones and targets mapping out a clear pathway to net zero by 2040, and Paul will touch on that more in this presentation. Continuing our track record of safe and responsible operations remains at the heart of our business activities. Looking at returns, in the first half of this year, we returned a further $500 million through a tender offer plus additional buybacks, bringing total shareholder returns to in excess of $5 billion over the last 15 years, an amount considerably in excess of any of our peer companies and clearly differentiating our investment proposition. In terms of growth, I've already touched on our proposed merger, which as we have previously outlined, in our view, offers significant organic growth potential alongside further inorganic consolidation opportunities. In the meantime, as the business sits today, we are focused on progressing organic growth in Egypt through a combination of near field and infill production opportunities and an expansive exploration program. Now, like other companies active in the region, we have experienced some delays in securing people and equipment, which has had an impact on the pace of our planned production ramp up. As Paul will outline, we have a redefined plan to target that production growth point forward and into 2023. In summary, therefore, our intention and focus is to ensure that we retain the financial flexibility to balance the responsible delivery of sustainable growth with the generation of further shareholder returns as we seek to create further value for shareholders. With that, I'll hand over to James. Thank you, Simon, and good morning. In the next few slides, I'll take you through the half year cash flows and current balance sheet position, then an overview of the current financial and operational performance and an update on the near-term outlook. The headline numbers in the mid-year financials reflect the major milestone that we reached earlier this year. Receipt of the $1.06 billion tax refund in India marked the conclusion of a long-running chapter in the company's history, and it enabled us to make a further substantial cash return to shareholders of more than half a billion dollars. It also leaves us still in a strong net cash position with the financial flexibility to enable us to continue to deliver value growth for our shareholders. Looking at cash flows over the first half of the year, we started with net cash of $133 million. The India tax refund was received and approximately half of those proceeds were returned to shareholders. Cash inflow from the U.K. North Sea earn out was $77 million, and operating cash inflows in Egypt were $50 million. I'll talk more about both of those in the next couple of slides. Contingent consideration payable to Shell together with working capital adjustments in respect of the Egypt acquisition totaled $35 million. Producing asset CapEx in Egypt was $23 million in cash terms, and total exploration CapEx across the portfolio was $58 million. I'll provide an update of the full-year capital program in a moment. Adjusting for admin and other costs, that took us to a 30 June net cash position of $631 million, being $809 million gross cash and $178 million drawings on the Egyptian Reserve-Based Lending Facility. Looking now at operational performance. Production in the first half averaged 35.5 thousand barrels of oil equivalent a day. This is below expectations for the period, principally due to logistical delays in getting new rigs in the field and operational. However, we have been able to prioritize higher margin liquids targets for those wells drilled to date, and as a consequence, liquids production has grown about 6% from levels at the time of acquiring the asset. Although this has been offset by a decline in gas production of around about 7% over the period due to that slower operational ramp up and underlying natural decline rates. As a consequence of that, liquids now represents over 40% of total production, and therefore revenues in the period were $137 million off average realized prices of $111/barrel for liquids and $2.90/Mcf for gas. Gross profits for Egypt in the first half, i.e., that's just revenue less OpEx, were $105 million, while actual operating cash inflows during the period were $50 million due to an increase in receivables of approximately $50 million. The total receivables position in Egypt at mid-year stood at $114 million, of which $61 million was due for payment. We have had good engagement with the state oil company, EGPC, on the receivables issue and plans to stabilize it, and obviously we continue to monitor that very closely. Looking to the full year, that operational delay in being able to accelerate the pace of drilling has led to a revision to the full year production guidance to a range of 33-36 thousand barrels of oil equivalent a day. We expect full year OpEx to be approximately $6 a BOE, partly because of the reduced volumes, but partly because of the increased percentage of liquids production, which has higher processing costs than gas, but obviously also higher margins. This slide is somewhat by way of a reminder and just sets out the value that sits in various contingent payments, both due to us and payable by us. Firstly, in the UK, we completed the sale last year of our 20% stake in the Catcher field and 29.5% stake in the Kraken field to Waldorf Production. As part of the terms of that transaction, further consideration is potentially due to us for each of the years 2021 to 2025 linked to oil price and production levels. The detailed terms of that are set out on the slide. They're already in the public domain, but just by way of reminder. The consideration of $77 million in respect of 2021 was received in the first half of this year. In Senegal, we completed the sale of our interest in the Sangomar project to Woodside in late 2020. Under the terms of that sale, up to $100 million will be payable to us six months following first oil from the project if startup is in 2023, reducing to $50 million if project startup is in 2024. Woodside is currently still targeting first oil within 2023. In Egypt, as part of the acquisition terms, we agreed to pay Shell up to $25 million a year over 2021 to 2024 linked to oil price, with a maximum payout due when Brent averages over $75 a barrel in any year. Further consideration of $0.20 a barrel is also due on any discovered commercial reserves in the first 9 exploration wells. Finally, just an update on CapEx expectations for this year. As I mentioned, our central case production guidance is down about 15% for the year due to a slower ramp-up in drilling activity. As a result, some drilling spend originally scheduled for this year will be deferred into next year, so the producing asset CapEx guidance for 2022 is also reduced by about 15%. Exploration CapEx in aggregate terms remains in line with our prior guidance, with UK drilling now complete, one well remaining in Mexico, and exploration drilling expected to commence in Egypt later this year. On that note, I'll hand over to Paul to provide more detail on the operational update. Thank you, James. Good morning, everyone. We're pleased to report three key elements of our production investment plans in Egypt during the first half of 2022. Firstly, we've fully transitioned the asset base from Shell and started the increased investment in Egypt in our first full year as asset owners. Secondly, we've kept safety and environmental performance at the forefront of our minds. Thirdly, we've refined our investment plans to direct capital to the best value opportunities in light of the prevailing prices and available rig capacity, recognizing some challenges have emerged. On the first point, Cheiron are now firmly in the seat as operator. We both have secondees within the operating company, BAPETCo, and we are working together with Cheiron and BAPETCo, including their new chairperson, to best develop the forward investment plan for the benefit of our companies and EGPC, the national oil company. On oil and condensate working interest production, we are up approximately 6% at 14,600 barrels of oil per day in the first half versus the Q4 of 2021, but we're down around 7% on gas to 117 million standard cubic feet a day. July and August monthly average working interest liquids have grown further to 15,500 barrels of oil per day as we continue to divert capital to our liquids-rich opportunities. Secondly, as you can see, we've had no lost time injuries or tier one process safety events at either of the two main oil and gas processing facilities. Finally, we face some challenges associated with the delivery of the overall investment program, which other operators have also faced in Egypt and reported in some of their earnings calls, most notably Apache. Specifically, we've experienced some delays and inefficiencies as we scale our rig count from two to five or potentially six. These include longer expected times to import staff and commission rigs, extended times for new rigs, particularly rig moves between locations, and increased tie-in times for new well drilling and completion. We believe these are mostly short term, and we should have them overcome by the year-end. The consequence, however, is that we've been unable to deploy capital at the pace we had hoped in 2022, and therefore we are revising both our capital and production guidance downwards by approximately 15%, as already outlined by James. However, the Egypt development and production opportunity set remains strong, is growing, and our decarbonization plans remain on track, both of which I will describe in the following slides. In terms of new investments, during the first half, we've drilled 14 new wells, 10 are producing or injecting, two were awaiting hookup, and two were plugged and abandoned. Well results have generally been within expectation, with stronger results on the oil front, particularly at BED and Sitra. This has been offset by a couple of below-expectation gas wells at the Karam and BTE fields and a higher natural decline at the Asil field. The combination of the latter has resulted in a deficit of around 3,000 barrels of oil per day equivalent of gas production versus planned, which we are looking to better understand and address with further investment, possibly re-perforating, fracking, or sidetracking those wells. The outlook remains positive, however. Hookup times are improving, and with the additional rig capacity becoming available in the second half of the year, we expect an increase in well count and total well tie-ins. We are currently drilling several water injectors to improve pressure support and water flood recovery, and the benefit of those wells won't be truly seen in production terms until into 2023. 5 workover rigs remain active on completing new wells and optimizing the existing well stock. The BED additional compression should become operational by year-end, and the Tin gas condensate project is underway. Additional compression is being evaluated for the Obaiyed area as part of a wider enhancement plan for the field, which potentially includes further drilling and deployment of new well technology to access flanks of the field. We've not forgotten about the large gas potential, and we're building an opportunity set in and around the Obaiyed and Tin gas condensate fields with possible execution in 2023. At present, however, the drilling capacity we have is being deployed at BED and Sitra light oil and water flood opportunities, Karam light oil reservoirs, and oil and water flood optimization at Bahga and NEAG. Two opportunities recently executed give an illustration of our field extension well results. The BED 15C2-1 well, shown in the middle plot here, was drilled and completed in approximately 30 days, hooked up within a month at a total cost of around $3.5 million and brought online at rates in excess of 1,000 barrels of oil a day, giving an expected payback of less than 12 months and a rate of return in excess of 50%. The well Sitra C-331 on the right was drilled in 24 days, hooked up within 16 days at a total cost of $3 million and brought online at rates in excess of 10 million standard cu ft a day and 1,000 barrels of condensate, giving an expected payback of less than 18 months and a rate of return in excess of 50%. Our team continues to identify high-grade opportunities in conjunction with Cheiron and BAPETCo. We recognize that we have a role to play in meeting the energy needs in Egypt, and this includes both oil and gas. We will therefore work constructively with EGPC and the ministry to help deliver an investment plan that benefits all stakeholders. We have been particularly encouraged by recent modernization initiatives in Egypt that has seen simplified and consolidated concessions, improved PSC terms, and a recognition that fixed gas prices may not unlock the full potential of the Western Desert basins. Last but not least, our decarbonization plans, which are ongoing in 2022, and wherever possible, we will help contribute towards Egypt's 2030 Vision. We inherited a baseline from 2019 conducted by Shell, but there is further work to do to reflect how the plant is operated today. Consequently, we aim to complete a new and improved baseline survey for greenhouse gas emissions in 2022, our first year as full asset owners. This has not, however, held us back from making immediate improvements and building on the good work that Shell and BAPETCo had already put in place. Energy consumption is forecast to be down slightly year on year across the fields, and our fuel substitution, power centralization, and electrification project has already resulted in change-out of 30 diesel generators. This helps cut operating costs longer term, reduces greenhouse gas emissions, and provides improved power reliability with the likelihood of prolonged ESP run times. We are also looking to integrate solar power into the mix, particularly for remote well sites, where extending the power grid may not be economically viable. With these initiatives underway, we expect to cut current levels of emissions by at least 15% by 2025. Longer term, we remain committed to eliminating routine flaring in our flare gas to power project, and we are also trying to tackle process emissions through CO2 storage. Success on these fronts would take a further 15% out, and potentially more, depending on scale, by 2030 or earlier. For our more difficult to abate emissions, we have and will look to invest in the highest qualified verified carbon offsets, especially where they have a broader societal benefit. On this positive note, and with an exciting set of investment opportunities ahead of us, I'll hand over to Eric to talk through our exploration activity and results. Thank you, Paul. Good morning, everyone. In exploration, we're focused on high grading and maturing our portfolio through seismic acquisition and reprocessing, drilling, and other technical workflows. First to Egypt, where we're assessing our operated exploration drilling schedule while we focus on near-term production, as Paul noted, and in conjunction with the late arrival of additions to our rig fleet as already discussed. We've emphasized the acquisition of our broadband 3D seismic programs in order to further enhance the exploration opportunity set. You can see those 3D areas are shown on the map in pink in each concession area. The 3D acquisition in North Um Baraka to the far upper left was completed in Q2, and we expect interpretable products in Q1 2023. We have entered into the second exploration phase here with a two-well commitment. In our operated 3D acquisition programs, the first will be in Southeast Horus starting this month, and you can see that on the map. Upon completion of that, the seismic crew will move to West Al- Fayoum for our final acquisition program around the beginning of November. We expect products from both towards the latter half of 2023. Now if we move on to the UK, the Cairn-operated Diadem well was completed at the end of August. Jurassic Fulmar sands, which were the target, were penetrated but are found to be water wet, and the well is currently being P&A'd. Now in our acreage in the southern North Sea basin, we received the final products from our 2021 3D acquisition and are in the midst of interpretation. Now if you look to the right of the slide in offshore Mexico, the Eni-operated Yatzil well in Block seven is expected to spud in the Q4. This is our last commitment well in Mexico, targeting upper Miocene turbidites, the same stratigraphy which was hydrocarbon-bearing in both the Saasken and Sayulita wells. Elsewhere in our portfolio, in Mauritania, we've completed our environmental baseline survey and are in discussion with potential partners. We have a drill decision there in Q2 of next year. In the Eastern Mediterranean, we're relinquishing our eight concessions offshore Israel and have completed our review utilizing the newly reprocessed 3D data. The opportunities identified did not meet our investment criteria. Finally, in Block 61 offshore Suriname, we continue to discuss our plans for 3D seismic acquisition with interested parties in an area where Shell, PETRONAS, Apache, and others are planning additional exploration and appraisal drilling. On that, I'll hand back to you, Simon. Okay, thank you, Eric. So in summary, our long-term strategy consistently delivered utilizes our financial flexibility to balance the responsible delivery of sustainable growth and further shareholder returns. As I noted at the start of this presentation, we are working hard to ensure that we can deliver best value for shareholders, and we look forward to updating you on our progress in due course. In the meantime, having moved forward from initial equipment and people delays in Egypt, we are focused on delivering production ramp up and, as Eric has just outlined, an expansive forward exploration plan in an area of strong local and regional demand growth. Thank you. That concludes today's presentation, and I'd like to hand back to the operator for questions. Thank you. If you would like to ask a telephone question, please signal by pressing star one on your telephone keypad. Please ensure that your mute function is turned off to allow your signal to reach our equipment. Again, that is star one to pose a question. Our first question today will come from Matt Smith from Bank of America. Please go ahead. Hi there. Morning. Thanks for the presentation, and thanks for taking my questions this morning. First one would be touching upon the fiscal modernization process in Egypt. Of course, a lot of your peers there have been successful in the Western Desert, specifically, secure and improved terms. I just wanted to double-check if there's any reason, you know, I appreciate these things sort of take time, and the exact details might be somewhat uncertain, but, you know, is there any reason for us to not expect that you might be able to achieve a positive outcome there in future? I did wanna sort of link that into your comment on the gas side as well, which I appreciate is somewhat separate but somewhat related, in that I appreciate, of course, it's much more economical for you to prioritize the oil volumes at the moment, but I guess Egypt as a country is quite desperate for gas. So just interested if there could be any changes on the gas side as you alluded to. Then the second question would be around. I appreciate you perhaps you're not gonna go into the sort of the details of the alternative transactions that you're exploring at the moment, but just in principle, based upon the sort of interaction and engagement you've had with shareholders, could you outline Sort of in principle, what these transactions, what these alternatives might be able to deliver for shareholders, which perhaps the sort of Tullow transaction does not, in the opinion of I guess some of those shareholders that have publicly sort of came out against the deal. Thanks very much. Okay. Thanks for that, Matt. I'll let Paul answer the first part of your question about the fiscal modernization and gas. Just on the second part, you're right. I mean, obviously we can't go into details given the kinda limitations on public disclosure in terms of confidentiality agreements. You know, we are looking at various alternative transactions. We're of course evaluating them all on a relative and an absolute basis and ultimately we're looking to create best value for shareholders. You know, that will be the focus in relation to these ongoing discussions and of course, yes, we do listen to the views of all shareholders in relation to our strategy and we do obviously take that into consideration as we consider the best value route that we're trying to create. Paul. Yes, good morning. Yeah, Egypt's obviously a new journey for us and we're just understanding what the opportunities are there. I think it's fair to say we've seen changes obviously in the PSC terms, which has been encouraging. That has taken time. I think we have to recognize that, you know, for a change in terms, there has to be value seen on both sides of the equations by the respective parties. Therefore that's a negotiation that we all need to look at carefully to see, you know, what the benefits potentially are across the concessions that we hold. I guess it's a sort of similar story on gas. Obviously, some of the gas is, you know, commercially viable today. Others we will need to make the economic case for some of the other gas resources that we hold in the contingent resources development unclarified category. That's very much sort of work in progress, I would say. It's difficult to put a timetable on it other than it will take time. Perfect. Okay. Well, thanks for your answers, guys. Much appreciated. I'll pass it on. Thanks. We will take our next question from Rachel Fletcher of Morgan Stanley. Please go ahead. Good morning. Thanks for taking my questions. I have two, please. The first is on the lower production guidance. You revised your full year production guidance to 33-36 thousand barrels a day. I was wondering how this impacts production growth in 2023 and beyond. Does it affect your longer term target of working interest production growing to 50 thousand barrels of oil equivalent a day? I think that's by 2026. That's my first question. The second question is on the merger with Tullow. The documentation is expected to be issued in Q4, and you're targeting completion before year end. I was hoping you could give a brief overview of the steps that would be needed to be taken before we get to completion. For example, what regulatory approvals would be needed and when we can expect these to happen, please. Thanks. Okay, thanks. I'll let Paul deal with the first one and James the second. Yeah, I mean, I think on the production ramp up, I mean a lot of it is naturally anchored to the performance of the units in terms of how effectively and efficiently we can drill and tie in new wells. Obviously we're making improvements on that front, and as I said, we've had some issues like some other operators, particularly from sort of the end of the Q1 due to global circumstances. I think we just have to see how the performance goes for the rest of this year. Obviously we're striving to make improvements and drive performance. We'll see where we turn out in the end of 2022 and obviously we'll issue our normal guidance in January. Yeah. On the timetable for the merger, I think as we said at the time of the announcement, we would go through the regulatory or the government consent process first, and then issue the documentation for shareholder vote and the UK completion process. We're still in the process of obtaining government consents in key jurisdictions. I would say that we've made very good progress on that. The reception has been positive, but it's not yet concluded. When that is concluded, we'll issue the relevant documentation, which is a prospectus for the combined entity and the court scheme documentation and shareholder documentation, shareholder vote documentation on both sides. If we're on track with government consents, that would happen in the October, November timeframe for that documentation and shareholder vote process. The final step is the court sanction. Given it's a scheme of arrangement in our case, which should happen pretty swiftly after shareholder votes. Very clear. Thank you. We will take our next question from Mark Wilson of Jefferies. Please go ahead. Okay, thank you. Good morning, gents. First is a housekeeping point. The payment from the U.K. North Sea earn-out, just to confirm, is that subject to EPL taxation or not? Hi, Mark. It's James. I can take that first. No, it's not. The earn-out terms are purely on a revenue basis. As we set out on the slide, they're just calculated as being production from those assets multiplied by the oil price in excess of $52 Brent for the average in each year, multiplied by a percentage, which, you know, on a sliding scale over that period. That's it. Got it. Okay. Thanks, James. The second question is regarding the Egypt operating cash flow. The slide seven and the $50 million you talked about. You said how that there's receivables of another $50 million as well we should consider. I'm just trying to understand on a like-for-like basis, full-year results, you talked about Egypt having the potential for $150 million of operating cash flow a year at $60 a barrel. Are we looking at a like-for-like therefore with that $50 million, or do we have to add the receivables? How does that compare? The $50 million was the actual cash received in the half year. The gross profit number I gave, which is, you know, just revenue from production, i.e. the realized production times realized prices in the period, less OpEx. If you like, that's the kind of cash flow from on a produced barrels basis of $105 million in the half year. It's just that only $50 million of cash was received because of an increase in the working capital position. If you're thinking of it purely on a producing basis, the gross profit was $105 million for the half year. You know, with similar production in the second half and similar realized prices you'd expect about the same in the second half. The actual cash received is obviously dependent on the development of that working capital receivables position. Got it. Okay. We look at the gross profit number as being equivalent to that $60 guidance at the beginning of the year? Yeah. That's the right comparison. Yeah. Okay. Thank you. I'm not sure I heard that, but maybe my line's not very good. Just last point then. You spoke about the country approvals. Just to check if any of the countries have given their approval yet. The final point is, simply put the Cairn shares are trading at quite a premium to the implied transaction price with Tullow. I'm just wondering if you could speak to that, Simon, at all. Thank you. Yeah. I'll speak to that. I mean, basically we're obviously aware of where the shares are currently trading and, you know, as we've indicated today, you know, we're very much focused on, you know, establishing the best route for to value creation for shareholders. We take that into consideration as we consider obviously the transaction with Tullow and also the other expressions of interest that we've received. You know, as I said, we're working hard to create the best possible outcome for shareholders. James. Yeah. On the country approvals, I wouldn't wanna say more than the fact that, as you know, my comment earlier that we're making good progress. We'll announce when they're concluded in aggregate rather than individually. Mark, sorry, the other thing is that you didn't hear, James, the answer was yes to your point in earlier question in relation to the comparison with the full year results. Okay. No, thanks for that clarity, yeah, I'll hand it over. Thank you. Thanks. We will take our next question from James Thompson of JP Morgan. Please go ahead. Great. Good morning, gents. Thanks very much for the presentation so far. Just a few questions on Egypt, if I may. You know, obviously there's some delay in getting the assets to location, and you kind of articulated a number of, I guess, smaller bottlenecks which have caused the production downgrades. You know, what gives you the confidence that these are really going to ease? To go back to kind of an earlier question, maybe not necessarily in the medium term, but, you know, can you talk about your ability to kind of ramp up production as we head into 2023? I know you've obviously brought down guidance for this year, but just thinking about the delivery of wells, you know, how many wells do you need to be drilling to get back up to the sort of 40s or, you know, mid-40s type level in the relatively near term? Yeah. Paul. Yeah. Just, I mean, just on the drilling. I think I explained, you know, we've only drilled 14 wells in the first half of this year. We were hoping to outturn, you know, over 20. I think we previously guided for full year over 40. Clearly that's where we're trying to get to, not just this year, but obviously in subsequent years. That may well, you know, include adding to the current rig capacity to do that. Just in terms of the other bottlenecks, you know, you talked about tying wells in, moving people around, just generally getting through things through customs, for example. What gives you the confidence that these are really gonna ease? Yeah, on the specifics of importing the two rigs, they're obviously both now in country. One is commissioned, accepted, and operating on its first well, and the second one is undergoing final acceptance. Both of those rigs should be operating on wells during this quarter, and we'd certainly expect by the end of the year that they'll be performing, you know, fully to our satisfaction in terms of delivering performance on a par with the other three units that are operating. The third one, you know, has had some issues in terms of just basically performance between moves. It doesn't actually add to the cost 'cause most of the rig moves are fixed price. Actually it does, it's a sort of opportunity loss, so it basically drills fewer wells than you would expect in the period. We're making, you know, we're making progress on that as the crew is more familiar in terms of obviously, demobilizing and rebuilding the rig and putting it back into operation between locations. Okay. Thanks, Paul. Just one more on Egypt. You talked about one well, one field, experienced slightly faster natural decline. I missed the name. Was it AF- Yeah. AESW? It's the Bahga field, which, yeah, basically is within that AESW concession. Obviously that field, but particularly the Karam-11 well that was drilled just as a back end of Shell's tenure. You know, they're the two main contributors along with our suspended well, BTE-4, which is in the NEAG concession, which has resulted in that deficit of gas production, which I mentioned earlier in the presentation. Okay. Thanks, Paul. Just shifting to exploration. Obviously, U.K.'s been a bit of a disappointment this year. Just generally reading you know, your commentary on exploration, seems like a little bit of a risk off the table. Simon, could you maybe talk about what's in the hopper as you head into 2023 or should we expect it to be a relatively less active year, all else being equal? Yeah, sure. Let me hand you over to Eric for that. Yeah. Thank you. Good morning. Our focus for 2023 will be Egypt, obviously. We'll have three new 500 square kilometer 3D surveys to evaluate and then a rig program to get started. That'll be our focus for 2023. The other things we have are optionality. Obviously in Mauritania, where we're coming up on a drill decision early part of next year, and we're talking to potential partners. The same in Suriname, where we're talking to partners with the idea of acquiring 3D over our Block 61. While those aren't firm commitments, they're options that we have in front of us. Of course, we continue to look at other opportunities across the spectrum, primarily in our current areas of Eastern Med and Africa. Okay. Thanks, Eric. I'll hand over. We will take our last question today from Chris Wheaton of Stifel. Please go ahead. Thanks so much indeed. Two questions from me, if I may, guys. Firstly, can I come back to Mark's question on working capital, please? I'm slightly unclear about your answer, James. Are you saying that you think the $50 million working capital build in Egypt you can see in note 3.3 in the results reverses in the second half? Or should we think about that as actually more like the ongoing natural delay in getting paid within Egypt? That actually there is a sort of $50 million effectively working capital float now in the business that we should just assume doesn't reverse, but it doesn't get any worse from this point. Notwithstanding you will be growing production hopefully a bit in the future. That's my first question. I think the specific question that Mark was asking is if we just think about operating cash flow on a kind of production basis aside from working capital, where we'd kind of guided to a steady state, what's the right comparator to that? I was sort of drawing attention to the gross profit number, revenue less OpEx, of $105 million for the first half. Obviously, as you've noted, cash inflow in the period was only $50 million as a result of a roughly $50 million build in the receivables position. I think, you know, I would say in terms of the near-term outlook, we've had good engagement with EGPC and other stakeholders to try to ensure that we stabilize that. I wouldn't necessarily forecast a significant reduction in that receivables position over the rest of this year. Clearly it's a focus for us to look to ways to bring that down over time. Okay. Brilliant. That's very clear, James. Thank you very much indeed. Apologies for mixing up the topic of the question. My next question was just going back to the production guidance change. Just trying to understand what rigs and what field performance. I noted Paul's comments earlier of about 3 kboe/d of gas versus lower production versus plan. That would. Given the oil is up, I would have thought therefore that means something like a 1-1.5 kboe/d net impact from fewer, you know, from worse performance from the fields. That suggests the rig delay is about another 1.5-2 kboe/d. Is that a reasonable split of that guidance change between the rigs and the actual field performance? I think I followed that, Chris. The 3,000 I mentioned is sort of on a working interest basis. If those, particularly those two wells had performed as per expectation, we would be probably closer up to sort of 37,000-38,000 barrels of oil equivalent per day. You know, with an increase obviously production on gas in the first half. Then the further delay is probably about where you suggested. Okay. It's about 2 kboe/d of field performance, right? Either 35 versus your sort of 37, 38. Then the other one, 1 to 1.5 kboe/d have gone. That's rigs. Yeah. That's kind of the implication from Yeah. That's reasonable, isn't it, Paul? That's probably reasonable. Just to clarify though. Cool It's not actually field performance. There's two wells. There's the Karam-11 well, which we think was a very good well that we've drilled. For some reason it hasn't produced at the levels we had hoped. As I've said, we are considering options to remediate that. It's a similar story at BTE-4, which was a suspended gas well that was drilled by Shell. You know, the offset well came on pretty strong and had produced for a number of years. We reactivated BTE-4 with an expectation that we'd get similar performance, and that hasn't happened. Again, we're looking at it to see what we can do to, you know, remediate that deficit in production performance. It's not a sort of underlying field performance. It's very much those two specific wells. Okay. That is helpful clarification. Brilliant, Paul. Thank you very much indeed. Thanks. That's it for me, guys. Thank you. Thank you. This will conclude today's question and answer session. I would now like to hand the conference back to our speakers for any additional or closing remarks. We'll just say thanks very much indeed for your time and for your questions. As ever, we're available for any further questions that might come up. In the meantime, we look forward to coming back and reporting further progress to you in due course. Thanks for your time.