Capricorn Energy PLC

Good morning, everyone. Welcome to Capricorn's results presentation. I'm Simon Thompson, CEO, and with me are James Smith, CFO, Paul Malin, COO, and Eric Hatham, Exploration Director. As an 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 maximise 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. So 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. And 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. And 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. But 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. So 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. And 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 UK North Sea earn out was $77 million, and operating cash inflows in Egypt were $50 million. And 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 expiration capex across the portfolio was $58 million. And I'll provide an update of the full year capital program in a moment. So 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 35,500 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 prioritise 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 assets. 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. So 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 a barrel for liquids and $2.90 in MCF for gas. Gross profits for Egypt in the first half, i.e. that's just revenue, less OPEX, were $105 million, whilst 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, EGBC, 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 33,000 to 36,000 barrels of oil equivalent a day. And 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. So firstly, in the UK, we completed the sale last year of our 20% stake in the capture field and 29.5% stake in the Kraken field toward our 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. And 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 Sangamar project to Woodside in late 2020, and 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. And then 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. And further consideration of $0.20 a barrel is also due on any discovered commercial reserves in the first nine exploration wells. So then 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%. Expiration 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. And 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. And 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, recognising some challenges have emerged. On the first point, Chiron are now firmly in the seat as operator. We both have secondees within the operating company, Bepetco, and we are working together with Chiron and Bepetco, 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 fourth quarter 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 1 process safety events at either of the two main oil and gas processing facilities. And 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 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 decarbonisation 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, 2 were awaiting hook-up and 2 were plugged and abandoned. Well results have generally been within expectation, with stronger results on the oil front, particularly at Bed and Citra. This has been offset by a couple of below-expectation gas wells at the CARAM and BTE fields and the higher natural decline at the ASEAL 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. Hook-up 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. Five work-over rigs remain active on completing new wells and optimising the existing well stock. And the bed additional compression should become operational by year end, and the teen gas condensate project is underway. Additional compression is being evaluated for the Obead 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 Obeid and Tin gas condensate fields with possible execution in 2023. At present, however, the drilling capacity we have is being deployed at Bed and Citra light oil and water flood opportunities, Karim light oil reservoirs, and oil and water flood optimization at Baga and Niag. and two opportunities recently executed give an illustration of our field extension well results. The Bed 15C21 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, Citra C33-1 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 cubic feet 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%. And our team continues to identify in high-grade opportunities in conjunction with Chiron and Bepetco. We recognise that we have a role to play in meeting the energy needs in Egypt, and this includes both oil and gas, and 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 modernisation initiatives in Egypt that has seen simplified and consolidated concessions, improved PSE terms and a recognition that fixed gas prices may not unlock the full potential of the western desert basins. Last but not least are decarbonisation 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. And 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 Bepetco had already put in place. Energy consumption is forecast to be down slightly year on year across the fields and our fuel substitution, power centralisation 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. And 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. And 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. And on this positive note, 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 expiration, 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 expiration 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. And you can see those 3D areas are shown on the map in pink in each concession area. The 3D acquisition in North Umbarica to the far upper left was completed in Q2, and we expect interpretable products in Q1 2023. We have entered into the second expiration phase here with a two-well commitment. And in our operated 3D acquisition programs, the first will be in Southeast Horus starting this month. And you can see that on the map. And upon completion of that, the seismic crew will move to West El Fayoum for our final acquisition program around the beginning of November. And 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 Yatzo well in block seven is expected to spud in the fourth quarter. This is our last commitment well in Mexico targeting upper Miocene turbidites, the same stratigraphy which was hydrocarbon bearing in both the Saskin and Sayulita wells. And 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. And in the Eastern Mediterranean, we're relinquishing our eight concessions offshore Israel, have been completed our review utilizing the newly reprocessed 3D data. The opportunities identified did not meet our investment criteria. And finally, in Block 61 offshore Suriname, we continue to discuss our plans for 3D seismic acquisition within arrested parties in an area where Shell, Petronas, Apache, and others are planning additional exploration and appraisal drilling. And 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're 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 1 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 1 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 so 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 and I did want to sort of link that into your comment on the gas side as well which I appreciate it's somewhat separate but somewhat related and 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. And then the second question would be around And I appreciate you, perhaps you're not going to go into 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. So 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 kind of limitations on public disclosure in terms of confidentiality agreements. But we are looking at various alternative transactions. We're, of course, evaluating them all on a relative and absolute basis. And ultimately, we're looking to create best value for shareholders. So, 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 PSE terms, which has been encouraging. That has taken time. I think we have to recognise that, you know, for a change in terms, there has to be value seen on both sides of the equations by the respective parties. And therefore, that's a negotiation that we'll need to look at carefully to see what the benefits potentially are across the concessions that we hold. And I guess it's a sort of similar story on gas. Obviously, some of the gas is commercially viable today. Others, we'll need to make the economic case for some of the other gas resources that we hold in the contingent resources and development unclarified category. So that's very much sort of work in progress, I would say. And 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. So the first is on the lower production guidance. You've revised your four-year production guidance to £33,000 to £36,000 today. 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 50,000 spousable equivalent per day? I think that's by 2026. So that's my first question. And 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 first quarter due to global issues. circumstances. And 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. And we'll see where we turn out in the end of 2022. And obviously, we'll issue our normal guidance in January.

On the timetable for the merger, 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. So 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 and 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 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. And then the final step is the court sanction, given it's a scheme of arrangement in our case, which had happened 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 The payment from the UK North Sea and 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. So as was 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 on a sliding scale over that period, and that's it.

Okay, thanks, James. Then the second question is regarding the Egypt operating cash flow, the slide seven and the 50 million you talked to. You said how there's receivables of another 50 million as well we should consider. So I'm just trying to understand on a like-for-like basis, four-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 have the receivables? How does that compare?

So the 50 million was the actual cash received in the half year. The gross profit number I gave, which is just revenue from production, i.e. production times realized prices in the period, less OPEX. So if you like, that's the kind of cash flow on a produced barrels basis of 105 in the half year. It's just that only 50 of cash was received because of an increase in the working capital position. So if you're thinking of it purely on a producing basis, the gross profit was 105 for the half year. So with similar production in the second half and similar realized prices, you'd expect about the same in the second half. But the actual cash received is obviously dependent on the development of that working capital receivables position.

Okay, and so 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. But just last point then, you spoke about the country approvals, just to check if any of the countries have given their approval yet. And then the final point is, simply put, the Cairn shares are trading at quite a premium to the implied transaction price with Tullow. So I just wondered 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 as we've indicated today, we're very much focused on establishing the best route to value creation for shareholders. We take that into consideration as we consider, obviously, the transaction with Telo. 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.

And on the country approvals, I wouldn't want to say more than the fact that, you know, my comment earlier that we're making good progress. We'll announce when they're concluded in aggregate rather than individually.

And Mark, sorry, the other thing is that you didn't hear James, the answer was yes to your point in an earlier question in relation to the comparison with the full year results.

Okay, no, thanks for that clarity, both, and yeah, I'll hand it over.

Thanks.

We will take our next question from James Thompson of JP Morgan. Please go ahead.

Great. Good morning, Jens. 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? And 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, you know, mid 40s type level in the relatively near term?

Yeah, Paul.

Yeah, just on the drilling, I think I explained we've only drilled 14 wells in the first half of this year. We were hoping to outturn 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. And that may well include adding to the current rig capacity to do that.

And 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 going to ease?

Well, so, 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. So both of those rigs should be operating now. on Wales during this quarter, and we'd certainly expect by the end of the year that they'll be performing 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, it's had some issues in terms of just basically performance between moves. It doesn't actually add to the cost because most of the rig moves are fixed price, but actually it does. It's a sort of opportunity loss. So it basically drills fewer wells than you would expect in the period. But we're making progress on that as the crew is more familiar in terms of demobilising and rebuilding the rig and putting it back into operation between locations.

Okay, thanks Paul. Just one more, you talked about one field experiencing slightly faster natural decline, I missed the name of it, was it ASW?

It's the ASEAL field, which basically is within that AESW concession. Obviously that field, but particularly the Karamat field. Carrum 11 well that was drilled just at the back end of Shell's tenure. They're the two main contributors along with our suspended well, BTE4, which is an ANACE 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 the UK has been a bit of a disappointment this year. Just generally reading 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 let me let me hand you over to Eric for that.

Yeah, thank you. Good morning. Well, our focus for 2023 will be Egypt, obviously, with our new we'll have three new 500 square kilometer 3D surveys to evaluate. and then a rig program to get started. So that'll be our focus for 2023. And then 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 and the same in Suriname where we're talking to partners with the idea of acquiring 3D over our Block 61. So while those aren't firm commitments, they're options that we have in front of us. And then, of course, we continue to look at other opportunities across the spectrum, primarily in our current areas of Eastern Med in Africa.

Okay, thanks, Eric. I'll hand over.

We will take our last question today from Chris Wheaton of Stiefel. Please go ahead.

Thanks very 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 bill 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.

Yeah, hi. Sorry, 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 guide it to a steady state, what's the right comparator to that? And I was drawing attention to the gross profit number, revenue less OPEX, of 105 for the first half. Obviously, as you've noted, cash inflow in the period was only 50 as a result of a roughly $50 million build in the receivables position. 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, but 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, and dear 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's rigs and what's field performance. I noted Paul's comments earlier that about 3k BOE a day of gas versus, or with lower production versus planned, that would, given the oil is up, I would have thought that, therefore, that means something like a one to one and a half kBAD net impact from fewer, you know, from worse performance in the field. So that suggests the rig delays about another one and a half to two kBAD. It's not a reasonable split of that guidance change between the rigs and the actual field performance.

I think I followed that, Chris, but the 3,000 I mentioned is sort of on a working interest basis. So 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. And then the further delay is probably about where you suggested.

Okay, so it's about 2 kBAD of field performance, either 35 versus your 37, 38, and then the other 1 to 1.5 kBAD of DAS rigs. That's kind of the implication from the answer. That's reasonable, isn't it?

That's probably reasonable. Just to clarify, though, it's not actually field performance. So 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'd hoped. And as I've said, we are considering options to remediate that. And it's a similar story at BTE4, 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 BTE4 with an expectation that we'd get similar performance and that hasn't happened. So again, we're looking at it to see what can we do to remediate that deficit in production performance. but it's not a sort of underlying field performance. It's very much those two specific wells.

Okay, that's helpful clarification. Brilliant, Paul. Thank you very much indeed. And 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.

Well, just to 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. And in the meantime, we look forward to coming back and reporting further progress to you in due course. Thanks for your time.