Gulf Keystone Petroleum Limited

[Audio Gap] 2025. Consistent demand from local sales market in Kurdistan and good reservoir performance enabled an increase in production relative to the same period last year.

Capital and cost discipline continue to underpin free cash flow generation, funding the payment of a $25 million interim dividend in April. We remain focused on safe operations, extending our track record of zero lost time incidents to over 950 days.

We are pleased to have recently ramped up production back towards full well capacity following the temporary shut-in of the field in July after the drone attacks on neighboring oil fields. With the return to stable sales and our robust cash balance, we are pleased to declare another $25 million interim dividend to be paid on September 30, increasing dividends paid and declared in the year to date to $50 million.

We have also taken the investment decision of installing water handling facilities at our production facility 2, which is an important milestone for the company. As we focus on maximizing shareholder value from local sales, we also continue to engage with government stakeholders regarding the restart of exports.

Turning now to our production and local sales performance and outlook. Next slide.

Gross average production increased 12% in the first half of 2025 to 44,100 barrels of oil per day over that of first half 2024. The improvement was driven by consistently strong local market demand between January and May 2025, enabling monthly gross average production above 45,000 barrels oil per day.

Higher volumes were also supported by good reservoir performance with our production optimization program enabling us to offset declines and well maintenance. We saw a reduction in sales in June due to trucking shortages around Eid Al-Adha religious holiday and the conflict between Israel and Iran.

In mid-July, we shut the Shaikan Field as a safety precaution following drone attacks on neighboring oil fields. We acted quickly to move all staff and contractors to safe locations.

At beginning of August, following a security assessment and consultation with the Kurdistan Regional Government, we restarted production and actually ramped up through the month towards full well capacity. We continue to closely monitor the security environment as we operate the plant and we have also introduced increased security protocols.

Average realized prices from local sales in the first half were healthy at $27.80 per barrel, a slight increase relative to last year. We have continued to sell at prices around $27 to $28 a barrel since June.

Looking ahead, we have tightened our 2025 gross average production guidance to between 40,000 and 42,000 barrels of oil per day. The lower range reflects the production losses from June through August disruptions, which amounted to around 1.3 million barrels or around 3,500 barrels of oil per day annualized.

We have additional well optimizations planned in the remainder of the year as we continue to manage natural field decline and certain wells constrained by water and gas. The guidance remains subject to local sales demand and a stable security environment.

Moving on now to field activity. We spent around $13 million of cash net CapEx in the first half of the year, in line with our disciplined guidance for 2025.

Work to date has included implementing the program of safety and upgrades to our production facility 2 with installed equipment expected to be tied in next year during the rescheduled shutdown. We have also been executing a variety of production optimization initiatives on certain wells.

We are really pleased this week to sanction the installation of water handling at production facility 2. This is an important milestone for the company, which we have long envisaged as part of the development of the field and its natural life cycle.

Engineering design work has begun and commissioning is currently expected at the beginning of 2027. The facilities will add an additional wet oil processing capacity of around 17,000 barrels of oil per day to the Shaikan Field's existing dry oil processing capacity of 60,000 barrels of oil per day.

Once operational, the new facilities are expected to unlock an estimated 4,000 to 8,000 barrels of oil per day of incremental gross production above the anticipated field baseline from existing constrained wells. The ability to produce wet oil will also reduce the downside risk to reservoir recovery.

To reduce costs, we are bringing secondhand facilities to production facility 2 and combining them with an existing but unused oil train from the previous expansion program, which was suspended in 2023 with the closure of the pipeline. To minimize upfront capital expenditure and provide flexibility, the facilities will be leased over multiple years following commissioning.

Limited incremental net CapEx is expected in 2025 and the total costs ahead of commissioning are estimated at around $12 million net to GKP. The facilities are expected to generate positive cash flow even in a local sales environment and at the low end of the incremental production forecast I just mentioned.

Looking ahead to the remainder of the year we, are now expecting cash net CapEx of $30 million to $35 million in 2025, a slight increase versus previous guidance of $25 million to $30 million, primarily reflecting the incremental net CapEx associated with the water handling project we've just sanctioned. We continue to expect around $20 million of net capital expenditure on the production facility 2 safety upgrades and the $5 million to $10 million related to the production optimization program.

Next slide, please. Update on Kurdistan exports.

We are continuing to engage with the government stakeholders regarding a solution to restart Kurdistan exports through the Iraq-Turkey pipeline. We have seen increased momentum towards a solution in recent weeks as we remain focused on securing written agreements on paying surety for past and future oil sales and the preservation of our contractual rights.

We are ready to restart exports quickly provided we have right agreements in place. We continue to see a number of sources of potential value to Gulf Keystone from the restart, including operational leverage to higher realized prices, the full repayment of outstanding receivables, a stable commercial environment enabling us to develop the rich Shaikan Field's significant estimated 2P reserves base of around 440 million barrels of oil and recognition by Iraq for Kurdistan's oil and gas industry, potentially reducing our cost of capital.

The restart of exports would also be a significant positive for Kurdistan and Iraq by unlocking additional revenue from a vital source of global oil supply. With that, I'll now hand over to Gabriel for the financial review.

Great. Thank you, Jon.

In the first half of 2025, we delivered a resilient financial performance. Increased EBITDA from stronger production, combined with capital and cost discipline, enabled continued free cash flow generation, in turn, funding a $25 million dividend and reinforcing our robust balance sheet.

Next slide, please. Adjusted EBITDA increased 13% to $41 million in the first half of 2025.

The improvement was primarily driven by the 12% increase in gross average production to over 44,000 barrels a day and a higher average realized price of $27.8 per barrel. Stronger volumes and prices combined with lower G&A expenses more than offset the increase in operating costs and share option expense.

Turning now to operating costs and G&A. We continue to exercise tight control of our cost base while safely maintaining the production capacity of the Shaikan Field.

Gross OpEx per barrel was flat at $4.2 per barrel versus last year first half as we maintain our leading industry cost position. The 13% increase in operating cost to $27 million reflected a higher production and increased well service costs spent on bringing 2 wells back on to production.

Other G&A expenses decreased 15% to $4.6 million in the first half. The performance so far this year means that we are pleased to report today that we are on track to meet our 2025 guidance for operating costs between $50 million and $55 million and for other G&A expenses under $10 million.

Next slide, please. On cash flow, we generated $25 million of free cash flow in the first half of the year relative to $27 million a year ago.

Stronger adjusted EBITDA more than offset the increase in net capital expenditures, working capital and other cash outflows. Net CapEx in the first half of the year was $18 million or $13 million on a cash basis after excluding a $5 million noncash charge associated with reclassification of drilling inventory purchased and paid in 2022 and 2023.

Free cash flow funded the payment of the $25 million interim dividend paid in April, while $4 million were also used to fund share repurchases by the Employee Benefit Trust to satisfy the 2022 LTIP vesting. Our cash balance was broadly flat at $99 million at the end of June.

And since then, liquidity has improved to $106 million as at yesterday. Moving on to capital allocation and shareholder distributions.

We have a consistent track record of balancing investment with shareholder returns while maintaining a robust balance sheet. We've delivered against this strategy for many years now and it is the cornerstone of our investment case.

In the current total sales environment, we are taking a specific approach to capital allocation. In terms of field development, our focus is on safely maintaining our existing production capacity and reliability as evidenced by the recent sanctioning of the water handling project.

Looking at our balance sheet, we are focused on preserving a certain level of minimum cash to fund this essential investment while managing the operating environment. We are committed to returning excess cash to shareholders in line with our clear shareholder distribution framework, which includes semiannual dividend reviews and the opportunistic consideration of share buybacks.

Given the recent return to stable sales and current liquidity position, the Board has approved the declaration of an additional $25 million interim dividend to be paid on 30th of September, bringing total dividends this year to $50 million. The dividend decision has been taken recognizing the potential liquidity required to transition from prepaid local sales to exports.

In an exports restart scenario, we plan to review our approach to investment at broader field development. Higher realized prices from exports will make growth investment more attractive, in particular, as the recovery of the cost pool is accelerated.

We would also expect to review the current distribution policy with the objective of providing investors with additional predictability of future returns. With that, I will now hand back to Jon to wrap up.

Thanks, Gabriel. To summarize, we have delivered a good performance in the first half of the year with higher production, prices and capital discipline and cost control generating free cash flow.

We have continued to execute our disciplined work program to safely maintain the well capacity and the reliability of the Shaikan Field and have taken an important step towards unlocking incremental production and reducing reservoir risk through the sanction of water handling facilities at production facility 2. Looking ahead to the remainder of the year, we are now focused on delivering a tightened gross average production guidance range for 2025 of between 40,000 to 42,000 barrels of oil per day, subject, of course, to stable local sales demand and the security environment.

We have increased annual net CapEx guidance slightly to $30 million to $35 million, reflecting the incremental investment in the water handling. OpEx and G&A guidance remains unchanged.

Following the return to stable sales and further improvement in our cash position since the end of June, we are pleased to declare an additional $25 million interim dividend to be paid on the 30th of September, increasing total dividends paid and declared in 2025 to $50 million. Finally, we are continuing to make progress towards unlocking the restart of exports.

We continue to push hard and we are hopeful of nearing a solution. With that, I will now hand you back to the operator for Q&A.

Thank you.

Just a question to sort of understand a bit more about CapEx and what the total gross water handling CapEx is between now and commissioning in 2027, that's the first part.

All right. Okay.

Thanks, Werner.

Sorry, I thought I'd give you a pause rather than just ask them all in one go.

Right. Okay.

Fair enough. That's fine.

Yes. So the total CapEx between now and the start of commissioning in '27 is $12 million.

Okay. Perfect.

And just following on from that, can you perhaps give a feel for what you'd expect your -- I guess CapEx at the moment is relatively modest, what that would increase to above and beyond the water handling when the pipeline restarts and you accelerate investment in drilling and other related spend again?

Sure. Yes.

I mean, I think, obviously, we would look to restart our drilling campaign. That will take some time.

Following the opening of the pipeline and surety of payments, then we would look to restart drilling. That will take a little bit of time.

So depending on when that speed or when that occurs, will depend on that. If you're looking at annual spend budget next year, a bit difficult to predict other than say we were to drill 2 wells.

Two wells would be notionally $40 million net to GKP on top of existing budget. And there may be a few other bits and pieces that we would look to do, improvements around that we've been delaying as a result of our cash position currently.

Can I ask, if I may, a sort of three-part question? I know it's a bit of a naughty thing but analysts always do that.

The first thing is just a reminder of what the current throughput is at PF-1 and PF-2. Secondly, do you see the water handling project at PF-2 kind of being rolled over, if you like, into PF-1 additionally next year?

In other words, maybe PF-1 might be sanctioned, yes, next year and lag 12 months for PF-2 water handling. And following your comments about drilling, perhaps next year if there are exports, do you think that they may be drilling even if there are continued local sales?

Okay. Right.

So first question was throughput PF-1 and PF-2. I think we already said the capacity of PF-1 and 2 are about 30,000, 31,000 barrels a day of dry oil each.

Current throughput is rounding 26,000 barrels a day through PF-1 and 19,000 through PF-2. Will we put water handling next year at PF-1 following PF-2's installation next year?

The answer is the wells that feed PF-2 are lower in the structure and, therefore, the whole structure is slightly tilted to the east. So the wells are slightly lower and therefore closer to the aquifer.

And what we've seen is a number of wells are constrained at PF-2. And we don't have similar problems, similar issues at PF-1 at the moment.

Now in the life cycle of the field, we would expect the water to encroach on PF-1, but it isn't a next year problem. It's later in the development cycle.

And I'm not going to hazard a guess of when that will be, but it's -- there are plans to put it in but it's not soon. And would we consider drilling in local sales?

I think if there was a stability around that, around the kind of geopolitical solution, and we thought that, that was going to be the remaining -- that was the intent going forward, but that isn't the intent. Of course, the intent is to export.

If that were, we may well consider drilling. But it's not something we are contemplating at this moment in time.

Can I start with just a follow-up on Charlie's question there on the water handling, please, and on the PF-2? Just I remember we talked about it years ago, but would you mind just reminding us how many wells are constrained by water, what the handling is there at the moment and where you hope to get to?

Just I'm sort of -- I don't have those numbers at hand. I'd appreciate just a bit of color around sort of what you're producing at the moment.

Second question, just on the export pipeline and, I guess, it's probably another way to ask about the drilling. But I mean, if it was to reopen tomorrow, to what extent could you ramp up production?

I suppose I'm taking a baseline from maybe your 47,000, 48,000 you were doing at the start of this year. Could you go much higher than that?

And finally, I'll call it a third part, on the pipeline again. Just you talked about the progress, terms are being discussed.

What compromises around terms are you prepared to accept, if any, to access better prices?

David, thank you for your questions. I think your first question was around what's our current capacity at PF-2.

So the current production I think I just said to Charlie was 19,000 barrels a day today we're currently producing. I think a handful of wells are constrained.

They're not shut in. But we have a number of wells which -- how water production manifests itself is we see the salt content increase at the wellhead.

And then what we have to do is we kind of choke the well back slightly to limit production from that well. And so it stops and so we can produce what we say is water-free oil.

So that's the kind of mechanism. And the third train that we're installing at PF-2 will allow us to take the water out and salt out because there's a salt limit, quite a low salt limit on the export pipeline.

So that's why we need it. In fact, local sales is the same as well, to be honest.

I think the other thing was about once we start exporting, what can we ramp production up to? I mean, to be clear, we are at our maximum deliverability from our existing wells.

So opening export pipeline doesn't give us any additional well deliverability because that's the choke. It's wells.

It's not exports, it's not local sales. It is the well deliverability.

And by installing PF-2, we would hope to see somewhere between 4,000 and 8,000 barrels a day of additional dry oil production. So that's what we're expecting to get at the end of 2026 when we commission it early '27.

So I hope that answers that question. On the pipeline, in terms of compromises, I think you'll understand, now I think we've been clear about what we expect to get in order to put oil in the export pipeline.

We've been very clear actually in terms of public statements. And we are -- what I will say is that we are having discussions and negotiations, but really I'm not prepared to discuss that until we've kind of landed those.

So I'm not going to give you any details, I'm afraid.

First one, just following up on the export pipeline. Of course, I understand it's extremely hard to have any good visibility here.

But still do you have any sense of timing here? What do you plan for in terms of timing for the reopening?

Second question, that is on dividends. Let's assume that the export pipeline reopens before year-end and that you're able to export oil in 2026 at global oil prices.

How should we think around dividend in that scenario? I would assume that, that would maybe increase.

And final question, that is on the M&A landscape in Kurdistan. Of course, hard to do deals in Kurdistan now.

But conceptually, would you look for more assets in Kurdistan? Or it's still your main strategy to produce as much as possible from Shaikan and then distribute any excess cash to shareholders?

Okay. Teodor, thank you.

No, I don't want to hazard a guess on export timing, when they will restart, other than obviously I've become more optimistic recently as we started to have negotiations. But I don't want to hazard a guess to when they might resolve satisfactory.

So sorry about that. Gabriel?

Yes. Teodor, on your question on the dividends, when the pipeline comes in and the realized price is coming to international levels.

As I mentioned earlier, once we go back to the export pipeline, we're also going to revisit our investment and the timing of those, so as Jon mentioned, around, for example, returning to drilling, other facilities increase. Obviously, there's going to be a time line as to when that actually turns into cash going out the door.

And so absolutely, the dividend side and capital distribution as a whole remains a very important part of our strategy. So we're not at a moment to think that we're just going to stop distribution to focus solely on CapEx.

The other bit, to just be very minded, and I'm very cautious on this, is whenever we get into the pipeline going is actually the cycle of the payments. Now it's very straightforward because local sales, we get paid upfront.

Payment surety is probably on all the IOCs mind on when we put the oil back in, what's going to be the cycle of the money coming back to us. And that's also going to be an important factor as we deal with capital allocation, whether it's CapEx or distribution.

So I would just perhaps bear that in mind in terms of the cycle of the future of oil sales in the export. And on the M&A landscape, as we said in the past, we don't have any rush or requirements to deal with M&A.

We have a fantastic asset with a lot of upside, and we could definitely grow production from here. But absolutely, if we see some opportunities to increase value for our shareholders with opportunities in Kurdistan and reduce costs, improve cash flows and overall distribution capacity, absolutely, we'll look at this.

But this is not one of our priorities at the moment.

Understood. Just on M&A, has it been on the agenda to expand outside Kurdistan?

Or will it still remain a pure-play Kurdistan company?

Yes. At the moment, our focus is Kurdistan.

Congrats on the first half of the year, a strong first half. Most of my questions have already been answered, but I have one last question on shareholder distributions.

How do you think about the balance between buybacks and dividends going forward? And also looking ahead, do you have any minimum cash buffer, above which you would target to return excess cash to shareholders?

I know you had touched upon this already but a bit more color would be appreciated.

Yes. No problem, Christoffer.

So I'll just kind of take this in turn. In terms of the minimum cash, we've always kind of been focused on ensuring that we have enough liquidity for about more or less a year of spend, just getting us sufficient headroom to navigate the transition back into the pipeline, any payment side of it.

This is obviously going to evolve over time, as I mentioned, with the pipeline or not. But at the moment, we got like around $105 million, $106 million, $25 million.

We think that $80 million is still a level that we're still comfortable at kind of minimum cash to get us going in local sales. But we're going to revisit this in due course.

But for the time being, we feel that it's the right level for the company. And in terms of shareholder distribution between buyback and dividend, on this one, we take an approach and getting the feedback from shareholders.

Some shareholders have clear preference on dividends but also to a point that it comes at the level of the share price. We've seen the share price very strong over the last few months.

So for the time being, we're focusing on ensuring that twice a year, we're delivering some distribution on dividend side of it. But if we see opportunistically value for shareholders throughout the year, we want to remain agile and be able to act quickly on this if we see an opportunity.

Thanks, George. We have a number of questions that have been submitted on the webcast.

First is, Morten, please can you tell us the difference in production volumes from investing in water handling at PF-2 versus drilling 2 new wells? A great set of results today.

Well done.

Thank you very much. Yes, certainly.

So I think the question was asked already, but the CapEx to install this water handling is $12 million, and the cost to drill 2 new wells is between $35 million and $40 million. The production from 2 wells would be somewhere between 6,000 and 8,000, and we're expecting somewhere between 4,000 and 8,000 from already constrained wells that we've already drilled.

So I think looking at that, you will understand that the kind of return is much better on water handling. But there's not really a subtlety.

With the production of oil fields, oil from oil fields which are underlying by water, over time, as you take the oil out, the water encroaches on your wells and therefore you get to plan where you have to deal with the water or you have to shut your wells in if you can't deal with the water. So this is a situation where, at the moment, we have a number of wells that are constrained but not shut in.

But it might become to the point where if the water production increases, we can't deal with it by choking the wells back. We'll have to shut them in.

So this is a kind of downside risk mitigation that we're also installing. So it's kind of -- it's not just a straight investment decision of one versus the other between wells or water handling, although in this case water handling is actually better.

But it is also a downside risk mitigation as well.

Our next question. Is it the intention of the company to increase the number of wells/barrels per day when exports recommence and the cash flow situation improves?

The simple answer is yes. We would look to increase the number of wells.

And that's underlined by the 2P oil reserves. Our estimate is in the region of 440 million barrels.

And if you look, I think, in the presentation, I said stated this, that using last year's production as the target -- as a production level, if you divide one by the other, you get something approaching 30 years, which actually says that the field isn't producing at its kind of classic optimum rate. So we would absolutely seek to increase drilling once production -- once we continue to export and look to raise the daily production rate.

Thanks.

Our next question. They say, congratulations on our resilient half year performance and your continued prudence in managing the business.

Could management provide greater specificity on the settlement mechanics discussed to date and timing for overdue receivables?

Yes. I think as I've said, we've been clear about what we seek in order to restart exports and the fact that we are in negotiations.

But I think people will understand that I'm not going to disclose anything that we're talking about until it is finalized. And then once it's finalized, we will obviously share it with the market and what mechanics are of that settlement.

But I'm afraid I can't do that now. I think -- yes, so okay.

I think also, yes, but I would say that the arrears, we would expect to recover over a period of time. And again, that's part of the negotiation that's going to take place.

So I'm not going to give us anything more than that, I'm afraid.

Next question. Why was the $10 million share buyback never utilized?

Yes. So I'll take that one.

So we only had very limited purchases that were made primarily because of the steady increase in the share price following the launch in October 2024. The buybacks make sense as a way to return capital to shareholders, as mentioned earlier, if we are increasing value.

We'll continue to do it to review opportunistically throughout the year. And as mentioned earlier, we try to take as broad feedback from shareholders.

Some have a clearer view on preference on dividend as we make our decision. So we're monitoring this throughout the year.

Thanks.

Our next question is on whether GKP and/or other IOCs in Kurdistan have signed in recent weeks lifting agreements to facilitate oil handover after ITP resumption that have included the Federal Government of Iraq. Or were those signed with the KRG?

If no such agreements were signed, was there a template circulated with the firms/KRG?

Okay. So yes, thanks for that question.

But I think as I've answered two similar questions already, I think you'll understand that I'm -- we've made it clear of what we seek in order to put oil back in the pipeline. And we are having discussions and negotiations with the KRG and the Ministry of Oil, and I'm not really at liberty to disclose those negotiations at this point in time other than we are having them.

So we'll give full disclosure once we've signed the agreements. So thank you.

Next question. What is the cost of water handling solution, namely higher CapEx through 2027, and increased OpEx thereafter via leasing?

Okay. So because we're utilizing existing equipment, we're going to install this and have it operational by the start of '27.

So the increased CapEx will be between now and the start of '27. So it would be through '26 and a little bit in '25.

That amount is $12 million. And I think also from our presentation, we said that the leasing cost will be covered by the low-end production increase that we're expecting, which is 4,000 gross at the local sales price, which we said it's, again, it's $27 to $28.

So you can work out that to a maximum of operating. And actually, it's slightly lower than that.

Okay.

What are the expected lease costs of the PF2 water handling facilities?

No, sorry, I think I've just answered that with the previous question.

Apologies.

No worries.

In an export restart scenario, would GKP intend to export 100% of Shaikan output? Or is there a specific benefit to retaining the local market offtake route?

We're currently expecting to export all of our oil under the agreement. 50,000 barrels might be retained in the local market, but I don't expect it to be our oil.

And that's a government thing rather than an IOC thing. Thanks.

Our next question. It will take considerable capital to fully develop a resource the size of Shaikan.

Are you open to third-party farm-in to accelerate development? Or are you still committed to a self-funding but slower path?

Yes. Good question.

So at this time, we're not considering in the near term or long term any farm-in. As we revisit the development plan following the export, we'll assess the capital phasing and requirements at the time, and we'll seek to get the best use of capital to fund this.

But I think it's fair to say that there is definitely a lot of growth here. And our intention is not to keep capital out of the CapEx.

If it's a good project, we'll find capital to make sure that we can deliver a good production growth outlook of this.

And finally, what is the ultimate production plan?

Okay. Basically, previously, we had a field development plan, which basically took our production to 80,000, 85,000 barrels a day from the Jurassic and somewhere between 10,000 and 20,000 barrels a day from the Triassic depending on the appraisal of that reservoir.

And that's kind of the levels that we would expect to get back to if we resumed our drilling plans basically.

Thank you very much. There are no further questions from the webcast, so I would like to hand back to Jon for any additional or closing remarks.

Thank you for everyone's questions and the time today, time this morning for listening to our presentation. I hope it gave you an insightful view as to how we've done this year and how we're going to do for the rest of the year and also an insight into maybe what's going to happen in future years if we get to restart exports in the near future.

So I would say thank you very much for your time today. Thanks for George and Rosie for managing this.

And thank you, team, also for a great job. So thanks, guys and girls.

And thanks for your continued support as investors. Thank you.