Good morning, and welcome to Gulf Keystone Petroleum's 2024 half-year results presentation. I will now hand over to Chief Executive Officer, Jon Harris. Please go ahead. Thank you. Welcome to Gulf Keystone's 2024 half-year results. My name is Jon Harris, and I'm the CEO. Today, I'm joined by Gabriel Papineau-Legris, our CFO, who will be taking you through our financial performance, and we're also joined by Gulf Keystone's COO, John Hulme, and also our Head of Investor Relations, Aaron Clark. Over the next few slides, we'll run through our operational and financial performance for the first half of 2024 and the outlook for the remainder of the year. Following that, we will open up the line for questions, and next slide. This is our regular legal disclaimer, and I'll leave for you to review at your leisure. And I'd like to remind you that the presentation slides are available on our website. Next slide, please. We delivered a solid operational and financial performance in the first half of 2024, facilitated by our continued focus on safe operations, with no lost time incidents for over 590 days. Robust local sales volumes, with gross average production of over 41,000 barrels of oil per day in 2024 to date, combined with sustained capital and cost discipline, enable us to return to profitability and free cash flow generation, following a challenging year impacted by the suspension of Kurdistan exports. Cash flow has enabled us to both strengthen our balance sheet and restart shareholder distributions, with $25 million returned to shareholders via dividends and buybacks year- to- date. Looking ahead, we are focused on maximizing shareholder value from the local sales market. We also continue to engage with government stakeholders regarding the ongoing shutdown of the Iraq-Turkey Pipeline, which I will update you on shortly. Turning now to slide five. We've seen robust local sales in the year- to- date, with gross average production of around 41,400 barrels of oil per day, as at the 27th of August. We started the year with weaker volumes in January, caused primarily by seasonal effects and excess supply in the market from competitors. From February, we saw demand pick up for crude to be refined locally into products. Since then, we've seen consistent local sales volumes, aside from some minor fluctuations in April and June, when the Eid holidays reduced truck availability. Prices have also remained reasonably stable. While they continue to be a significant discount to international prices, we have sold crude in the range of between $25 and $28 a barrel so far this year, and we're currently standing at around $27 a barrel. July and August have been particularly strong months for sales, and looking ahead, we see the same strong outlook in the near term. Longer term, the market remains unpredictable, with volumes and prices driven by local supply and demand dynamics. Contracts are only currently renewed on a month-by-month basis. Looking at production, we've been really pleased with the performance of the reservoir and trucking operations, which have responded well to the ramp-up in local market demand. The Shaikan Field is now producing close to its maximum capacity, which is based on our prudent view of our oil and gas capacity in the current constrained investment environment. We continue capitalizing on strong local sales demand. We are focused on two areas. Firstly, we have been able to identify a number of low-cost, quick payback opportunities to optimize production this year, and we see more of those initiatives in the second half of the year. Secondly, we also see some additional opportunities to increase process safety and reliability. That means a slight increase in our average monthly run rate for the full year, which Gabriel will talk about in his section. We don't have production guidance, but we have flagged previously that we're temporarily shutting in PF-1, which is now scheduled to take place in November. During the shutdown, we will execute the safety opportunities I've just talked about. We still expect the shutdown to impact production by around 26,000 barrels of oil per day for three weeks, equating to just over $5 million of sales revenue based on current realized prices. Moving on to slide six, update on Kurdistan exports. I'd like to give you... Excuse me. I'd like to give you a short summary of where we are and remind you of the fantastic potential value opportunity that we have ahead of us from achieving a solution. As you know, the Iraq-Turkey Pipeline remains closed and has been shut in for over 17 months now. The Kurdistan Regional Government continues to publicly state that they want the pipeline open. Turkey have also publicly stated that they are happy for the Turkish side of the ITP to open. I believe the sticking points are reconciling the payment mechanism to the IOCs from selling the oil under our existing economic commercial contracts and settling the arbitration award between Turkey and Iraq. We continue to believe that there is a significant economic value to unlock for Kurdistan and Iraq. The main benefit would be bringing back around 400,000 barrels a day of, barrels of oil per day to the international market, which could then be sold at international prices to fund Kurdistan's allocation from the federal Iraqi budget. The KRG have been receiving their allocation from federal Iraq, but it's been piecemeal, and at the moment, it has to be funded by oil revenues from the rest of Iraq. That's less than the optimal when Kurdistan is sitting on millions of barrels of reserves, not least in the Shaikan Field, and which also has excellent growth potential. We really hope, therefore, that a solution can be found, and we continue to engage with all stakeholders to this effect, with tripartite meetings held between the Kurdistan Regional Government, the Federal Government of Iraq, and the international oil companies. We remain ready to restart exports, but we need clarity on how we will be paid for future exports and past receivables, and we need to see the current economics in our contracts preserved, as we've outlined before. The prize is large for Gulf Keystone. We could see our current realized prices double as we move back to selling at international prices, and we could unlock further significant upside from the repayment of outstanding export sales receivables, which total over $150 million net to Gulf Keystone. Our cash flow would continue to be supported by the recovery of past costs and a continued commitment to capital and cost discipline. We would also be able to reinstate a distributions policy to provide shareholders with greater clarity on returns. With that, I'll now hand you over to Gabriel for the financial review. Thank you, Jon. I'm pleased to present my first set of Gulf Keystone numbers to you today as CFO. Looking at the charts on the slide, you can see that the company is in a fundamentally more positive position than it was a year ago. As Jon outlined, we have had great production and local sales performance so far this year, and we've maintained a high level of discipline on CapEx and costs. This has enabled us to return to profitability and free cash flow generation in the first half. Given our limited capital program, which you can see from the top right chart, we've been able to return a lot of the cash flow generated from local sales back to shareholders, with $25 million distributed so far this year. I will talk about shareholder distribution in more details shortly. Next slide, please. Adjusted EBITDA increased by 6% to $36 million in the first half of the year. The improvement was mainly driven by strong performance of over 39,000 barrels a day in the first half, as well as cost control, as other G&A and share option expense reduced, more than offsetting higher operating costs, primarily related to increased production. We also saw a $5 million benefit from the absence of one-off costs incurred in the first half of 2023 related to the wind down of activity. Higher volumes and lower costs were partially offset by the 49% reduction in realized price associated with the transition from export to discounted local sales, which achieved an average realized price of around $26 per barrel in the period, almost a $60 discount to Brent. Local sales prices are not linked to Brent and continue to be determined by the supply and demand dynamics in the local market, as well as crude quality. Next slide, please. On cash flow, stronger adjusted EBITDA and sharply lower net CapEx enable us to generate $27 million of free cash flow in the first half of the year. Net CapEx reduced 83% from $47 million to just under $8 million in the first half of 2024, reflecting our lean work program compared to a busy expansion program that was in progress prior to the Iraq-Turkey Pipeline closure in March 2023. Free cash flow generation has strengthened our balance sheet, increasing our cash balance from $82 million at the end of last year to $124 million, and has been used to fund shareholder distributions. Our cash balance, as at yesterday, was $98 million. Next slide, please. Looking at our costs, we have continued to exercise tight control over our OpEx and G&A while maintaining full production capacity. This has enabled us to respond to local sales demand and the potential restart of exports. Gross OpEx per barrel reduced by 25% year- on- year to $4.2, primarily reflecting higher production in the first half of the year. Other G&A reduced to $5.4 million. The reduction includes the absence of $2.1 million of non-recurring corporate costs from last year and some cost reductions. Putting OpEx and other G&A together with our capital expenditure, our average run rate for the first half of the year was $6.2 million per month, in line with original guidance. As Jon mentioned, we are now planning to spend a little bit more on production optimization and process safety and reliability, so we can continue to capitalize on the strong local sales demand that we're seeing. That will mean that the average run rate for the full year is now expected to be around $7 million per month. This implies an elevated run rate for the second half of the year. That's due to both the incremental spending described earlier and the phasing of CapEx and OpEx in the second half, which is linked to the implementation of the safety upgrades and maintenance during the PF-1 shutdown in November. Our estimated net CapEx for 2024 remains at around $20 million, as guided previously. Before I move on, I would like to emphasize that while we see good local sales demand in the near term, we retain flexibility to rapidly and significantly reduce our capital expenditures and costs in a downside scenario. The $7 million run rate implies a free cash flow breakeven at around 24,000 barrels of oil of production, which is about half of current production levels. We have identified actions to sharply reduce the run rate if required, although we would have to balance them against potentially delaying a return to full production capacity. Next slide, please. Our shareholders will be well aware that by now we have a strong commitment of returning excess cash, provided that we have sufficient cash available to manage the operating environment and the liquidity needs of the business. That's evident by our track record over the years, and you can see from the chart that we've distributed over $460 million since 2019. Throughout, we have balanced shareholder returns with investment in profitable production growth and maintaining an appropriate balance sheet to navigate the operating environment in Kurdistan and the commodity cycle. This year, we're pleased, we are actually really pleased to restart shareholder distributions following the decision in 2023 to suspend our ordinary dividend policy in response to the closure of the Iraq-Turkey Pipeline. To date, in 2024, we have completed a $10 million share buyback, which was an effective way to capitalize on the attractive valuation of our shares while reducing our share capital with surplus cash. We have also paid a $15 million interim dividend last month. Looking ahead, we are continuing to keep a very close eye on our liquidity levels and our capacity to return further cash to shareholders, either via dividend or share buybacks. With improvements in the environment, operationally, it is our ambition to reinstate an appropriate distribution policy to provide shareholders with greater clarity on returns in terms of timing and quantum. With that, I will now hand it back to you, Jon, to wrap up. Thanks, Gabriel. Next slide, please. Outlook. To summarize, we are pleased with our performance in the first half of 2024. Looking ahead to the remainder of the year, we have two priorities. Firstly, we are focused on maximizing shareholder value from local sales. This means balancing a focus of capital and cost discipline with incremental expenditures on production optimization, process safety and reliability, so we can continue to meet the strong local sales demand we are seeing in the near term. As we generate cash flow, we will continue to review the company's capacity for additional shareholder returns via dividends or buybacks. Secondly, we are continuing to work towards unlocking significant potential upside from the restart of exports and repayment of receivables. While there remains no timeline, we have seen some traction this year through tripartite and other discussions, and we are hoping for a conclusion. With that, I will now hand you back to the operator for Q&A. Thank you. If you would like to ask a question, please press star one on your telephone keypad. Please ensure your line is unmuted locally, as you will be advised when to ask your question. So once again, that's star one if you would like to ask a question. Our first question comes from the line of David Round from Stifel. Please go ahead. Thank you. Morning, guys. One and a follow-up from me, please. The first, just you talked about producing at max capacity or towards max capacity. Obviously, that's not sustainable forever. So assuming this situation persists and that the pipeline remains shut, at what point should we expect that CapEx might have to trend up, as you have to drill new wells? And then the follow-up, I suppose, is: Is there a scenario where you could get some better pricing power if production elsewhere drops away? I mean, you guys don't have the highest declines in the region. If domestic production from your peers fell away all of a sudden, do you get better pricing power? Thank you. David, thanks. Thanks for your questions. In terms of max capacity, so there are. I think we've alluded to it or we've said it in this morning's presentation. There are opportunities to sort of increase our some of our oil production from a couple of wells, which have previously we've seen hints of a salt production, which is usually a kind of hint of water production, and we've kind of closed those in. And see, previously, we've been successful in bringing those back online and actually producing those as black oil, without the salt goes away, the water goes away, and because it's been shut in. This time, we're also looking at the possible capacity of producing and selling the oil with the salt in it, probably at a discount, depending on how the local refineries can deal with it. But that's we we're unsure about success of that, so we're gonna it's a small amount of money to do to carry this out and see if we can get it to work. Another issue for us is that, as part of the safety shutdowns that we're doing in November, we'll increase our gas handling capacity, which at the moment, we're kind of pushing up against. So with potential a lot more oil, which brings with it more gas, that will also alleviate the capacity constraint. So that allows us to certainly continue to produce at or similar to current levels. We've previously stated that the decline is between 6% to 10%, and what we've seen this year is we've managed to bring back some wells, which have been sort of choked back previously, to allow us to produce at the current rate, which is 48,000, maintain 48,000 for the last few months. So when would we decide or potentially think about drilling new wells? I guess we're always thinking about it, and it kind of depends on, A, our capacity constraints and alleviating those, and B, the local market being able to make sure that we could sell that additional production. Otherwise, there's very little value in doing it, other than maintaining production, but certainly not increasing. So we are thinking about that, but we haven't made a commitment to that, and we're kind of looking at the success of this capacity enhancement, I'm gonna call it, in November. And then we might come back to the market and kind of indicate what we might do next year, but that decision's not been taken yet. I think on price, I'll let Gabriel handle that. Hey, David. So yeah, to. Hey. ... to your question on price, you will see the prices tend to be relatively sticky. Absolutely, I would expect that with lower volumes available in the market, we'd be able to to push the price a little bit. One of the key differentiator with the other crudes, ours, as you will recall, is quite heavy and sour. And some of the larger refineries are struggling to accommodate for sulfur. So ideally, we'd like to see a rebound in us taking more market share or at least improvement of the price. But at the end, we're currently kind of limited to the kind of small topping plant units that aren't really sophisticated. So, definitely we're doing what we can to increase competition and increase price, but it's fairly sticky, as you can see. Okay. Both really helpful. Thank you for that. The final follow-up, maybe I just had, and it's clarification, but if the pipeline did reopen, would you have any remaining obligation to the domestic buyers? I mean, I assume not. These are all just short-term contracts, are they? Yeah. So as Jon mentioned, the contracts are on a monthly renewal. So I'd be tempted to say that, yes, we do have flexibility, but there would still be a question that we'll ask ourselves in terms of the payment cycle, the export, and the trade-off between getting payment up front at a discounted price versus production, so maybe in transition. But we're not there yet. And but we do have the flexibility. But that would be a voluntary decision. There's no obligation to keep supplying the local market. Okay, brilliant. Great. Thank you. Thanks, David. The next question- Next question. The next question comes from the line of Charlie Sharp from Canaccord. Please go ahead. Yes. Good morning, gentlemen. Thank you for taking my call. Hopefully, you can hear me okay. It's just a follow-on, a little bit from David's question regarding production, and I understand that the November downtime will lead to capacity enhancement, as you put it. And all that sounds good in terms of keeping production up around the sort of or capability of delivering 48,000 or so, I guess, for the near term. Could you talk a little bit about. I mean, you have indicated in the past that you need water handling. Are there any signs that that may need to be done sooner rather than later? And if so, what are the costs associated with that? If you could remind me of what would need to be done and how much that would cost, if you think that that might have to happen in the next year or so? Yeah. Thanks, Charlie. A very timely question. Prior to us ramping down all our construction activity, we had a number of water handling trains planned, and they were costed at the time for that. This year, we've recently gone out for additional quotes for new equipment and also potentially using second-hand equipment. Sorry, I don't know if you can mute your line. We're getting some feedback. I think in terms of costing, we're going through that at the moment. We're waiting for pricing. So I don't want to second-guess that by saying that, other than we are looking at water handling. We are looking at doing water handling within the current local sales environment. But again, we haven't seen the actual cost, and we haven't seen the commercial arrangements that we're gonna need to put in place to be able to deliver that when we need it. Now what we've seen, the reservoir model continues to kind of predict in the future, somewhere in the future, the need for water handling, and we recognize that we do need to put it in, but it's not in the near term. So I hope that answers your question. That's great. Thank you. And if I may follow up then with one sort of additional bit, which is, I think you said that the November activities will enable you to handle more gas. It sort of translated, what does that mean? Is that in gas injection? I didn't think you were doing that, but perhaps you are. Is it more flaring, and are there limits on flaring? It effectively allows us to. What we've seen over time is slightly more gas, which is being produced, and also we recompleted one of our wells into a gassier area. And that means that we've had to, kind of, because we're. It's a pressure constraint. We're pressure constrained with the existing equipment, so we're gonna alleviate that by putting in some additional equipment, which will allow us to go to a higher pressure, in which case, we could handle that particular well, which you've had to constrain. So it's a, if you like, it's a subtlety, but it's more around process safety, because the existing equipment, we have to operate at a lower pressure to be maintained within sort of safety limits. We'll be able to go past that with this new equipment. That, that's the kind of capacity enhancement. It allows us to produce, probably one or two wells slightly harder, so. More, more flaring? ... a small amount of more flaring, yes. But again, in parallel to that, you know, we were in the process of going to a gas management plan, and we tendered that, and we had pricing, but we didn't progress it. Sorry, I'm getting some feedback. We'd like-- Thank you. Thank you, Charlie. So we are, there is a small increase in flaring, but we are working on a solution to that in parallel. Thank you. Okay. The next question comes from the line of Teodor Sveen-Nilsen from SB 1 Markets. Please go ahead. Good morning, guys, and thanks for taking my questions. First, I want to discuss the scenario where actually the pipeline is reopened, and you're able to export oil at international oil prices. In that kind of scenario, what kind of CapEx and production should we expect you then expected to return to a scenario where you invest a lot more and ramp up production towards the, like, 70,000-80,000 barrels per day, as you previously have indicated? So that's my first question. And a second question is on, I'm just curious on the dialogue and meetings you had with the KRG and the representatives from Baghdad. What's the most recent update from those meetings? And are those meetings on a regular basis or more ad hoc basis? My final question that is on your balance sheet and balance sheet priorities. You've been running the company with a net cash position now for many years. Going forward, is that also something we should expect you to do, or will you take on some more debt and maybe run the company with a net debt position in a more stabilized environment with the international sales? Thanks. I think your question is, what could we expect for export? The first question was, I'm not sure we caught the second question, but the first question was around... I mean, if the pipeline opened tomorrow, then the production level would be what we're currently producing, around 48,000 barrels a day. I think in terms of, looking at doing more wells, we'd have to see an establishment of, you know, a certain cadence with regards to payment regularity and production performance. I'm not worried about the production performance, I have to say, but we'd have to see payment cadence that, we were comfortable with. There's also a question of the late receivables, which is $150 million, and we would expect with the reopening of the pipeline, that there would be some mechanism, like there was previously when we were owed four months of arrears, where that was paid off over, like, a year and a half. So something perhaps like that. I mean, I'm hoping it would be faster, but I'm trying to be realistic about this. So if we saw very strong positive cash flows, then absolutely, we would look at potentially recommencing some further development of the field. But what that further development looks like, it's too early to say. We're looking at a further optimization from the previous field development plan, and that's work that's ongoing as we speak, so you'll have to wait for further updates on that. I think also you were talking about, sorry, your second question was around possible the meetings that are ongoing. Those are continuing. Obviously, there's been a little bit of a hiatus over the summer as people have been away. Various people, decision-makers have been away. But I think now we're kind of talking about solutions. And I'm looking forward to basically trying to progress that in the autumn period, essentially. And for your last question around net cash position, I'll hand over to Gabriel to answer. Yeah. Thanks. Thanks, Teodor. So, yeah, so you're right. We've been the last couple of years running the business without debt. The business at this stage is generating good free cash flow. There is no real need to, at this stage, to bring in more capital into the business. Maybe in the future, as we go into some development, but it's too early. At this stage, our real focus is kinda capitalizing on the local sales market, strict control on costs, and eventually returning excess capital to shareholders, as we've been doing recently. But we are aware that high yield has been a way for junior players to fund some of their activity over the years. And we'll continue to speak to investors in that market as well, 'cause maybe in the future, once things normalize and more activities are required, it would make sense to bring external capital, but in the foreseeable future stage. Okay. Thank you. Understood. That's all for me. Okay. As there are no more questions at this time, that concludes the presentation from Gulf Keystone Petroleum. Thank you for your time. You may now disconnect your line.