Gulf Keystone Pet Ord New

Good morning and welcome to Gulf Keystone Petroleum's 2024 Half Year Results presentation. I will now hand over to Chief Executive Officer John Harris. Please go ahead.

Thank you. Welcome to Gulf Keystone's 2024 Half Year Results. My name is John Harris and I'm the CEO. Today I'm joined by Gabrielle Papanoligri, 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. Cashflow 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 shut-in of the Iraq-Turkey pipeline, which I will update you on shortly. Turning now to slide five, we have 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 selling 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 Shikamp 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 capitalising on strong local sales demands 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 PF1, 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 shut-in to impact production by around 26,000 barrels of oil per day, per 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 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 SOMO 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 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 has to be funded by all revenues from the rest of Iraq. That's less than optimal when Kurdistan is sitting on millions of barrels of reserves, not least in Shaikhan 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 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 price is large for Gulf Keystep. 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 now hand you over to Gabriel for the financial review.

Thank you, John. 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 John 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 cost. 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 GNA and share option expense reduce 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 price 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. Pre-cash flow generation has strengthened our balance sheet, increasing our cash balance from $82 million at the end of the last year to 124 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 GNA 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 GNA 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 John 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 PF1 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 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 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, John, to wrap up.

Thank you, 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 maximising shareholder value from local sales. This means balancing a focus on capital and cost discipline with incremental expenditures on production optimisation, 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 1 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 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. 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 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 decline in the region. domestic production from your peers fell away. All of a sudden, do you get better pricing power? Thank you.

David, 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 some of our oil production from a couple of wells, which previously we've seen hints of salt production, which is usually a kind of hint of water production, and we've kind of closed those in. And 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 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 refiners can deal with it. But we're unsure about success of that, so we're going to It's a small amount of money to carry this out and see if we can get it to work. Another issue for us is that part of the safety shutdowns that we're doing in November will increase our gas handling capacity, which at the moment we're kind of pushing up against. So with potential more oil, which brings with it more gas, that will also alleviate that. capacity constraint will be alleviated. 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 gagged back previously to allow us to produce at the current rate, which is 48,000 and maintain 48,000 for the last few months. So when would we decide to, or to potentially think about drilling new wells? I guess we were always thinking about it and it kind of, it kind of depends on A our capacity constraints and alleviating those and B the local market and being able to make sure that we could, we could sell that additional production. Otherwise it's very little value in doing it other than maintaining production, but certainly not increasing. So we are, we are thinking about that, but we haven't made a commitment to enhancement, I'm going to 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 has not been taken yet. I think on price, I'll let Gabriel.

yeah so to your question on uh on price um you you will see the prices tend to be relatively sticky um absolutely i would expect that with lower volumes available in market we'd be able to to to push uh the price a little bit um one of the key differentiator with the other crudists ours as you really 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. 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?

Yes. So as John mentions, the contracts are on a monthly renewal. So I'd be tempted to say that, yes, we do have flexibility, but there will still be a question that we'll ask ourselves in terms of the payment cycle, the export and the trade-off between getting payment at a discounted price versus production. So maybe in transition, but we're not there yet, but we do have the flexibility.

But that would be voluntary. decision. There's not an obligation to keep supplying the local market.

Okay, brilliant. Great, thank you.

Thanks, David. 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 enhancement as you put it and all that sounds good in terms of keeping production up around the sort of 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 uh 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. This year, we've recently gone out for additional boats 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 going to 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, some way in the future, the need for water handling. And we recognise 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. Sort of translated, what does that mean? Is that gas injection? I didn't think you were doing that, or perhaps you are. Is it more flaring and are there limits on flaring?

Effectively it allows us to, what we've seen over time is slightly more gas being produced and also we've re-completed one of our wells into a gassier area and that means that we've had to kind of, because it's a pressure constraint, we're pressure constrained with the existing equipment so we're going to alleviate that by putting pressure, in which case we could handle that particular well, which you've had to constrain. So it's a, it's a, if you like, it's a subtle, 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. So that that's the kind of capacity enhancement is 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, 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. 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 theodore nielsen from sb1 markets please go ahead good morning guys so thanks for taking my my questions um first i want to discuss the scenario where actually the pipeline is reopened and you're able to to export oil at international oil prices. In that kind of scenario, what kind of capex and production should we expect? Should we then expect to return to a scenario where you invest a lot more and ramp up production towards the last 70,000-80,000 barrels per day, as we previously have indicated? That's my first question. And the second question is, I'm just curious on the dialogue and meetings you have with the KRG and representatives from Baghdad. What's the most recent updates from those meetings? Are those meetings on a regular basis or more ad hoc basis? My final question is on your balance sheet and balance sheet priorities. You've been running the company with a net cash position for many years and going forward, is that also something we we should expect you to do, or will you take on some more debt and maybe save around the company with a net debt position in a more stabilized environment with international sales?

Thank you. 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 pounds a day. I think in terms of looking at drilling more wells, we have to see an establishment of a certain cadence with regards to payment regularity and production performance. I'm not worried about production performance, I have to say, but we'd have to see payment cadence that we were comfortable with. And also there's a question of the 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 wrote 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 we would we would look at potentially recommending some further development of the field. What that further development looks like is too early to say. We're looking at a further optimisation from the previous field development plan and that's work that's ongoing as we speak. So you 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, over the summer, there's been a little bit of a hiatus on that 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 Gabrielle to answer.

Thanks, Theodore. 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 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 kind of capitalizing on the local sales market, strict control on costs, and eventually returning excess capital to shareholder as we've been doing recently. But we are aware that high yield has been a way for security players to fund some of their activity over the years.

And we'll continue to speak to investors in that market as well, because maybe in the future, once things normalize and more activities are required, it makes sense to bring external capital, but not in the foreseeable future stage.

Okay, thank you. Understood. That's all from me.

Okay. As there are no more questions at this time, that concludes the presentation from Gulf Geese and Petroleum. Thank you for your time. You may now disconnect your lines.