Thank you. Welcome to Gulf Keystone's 2026 Half Year Results Presentation.

I'm Jon Harris, the CEO, and I'm joined by Gabriel Papineau-Legris, our CFO. Over the next few slides, we will discuss our operational and financial performance in the first half of 2026 and the current outlook for the business.

We will then open the line for questions. Next slide, please.

This is our regular legal disclaimer, and I'll leave you to review at your leisure. Presentation slides are available to view on our website.

Next slide, please. Gulf Keystone delivered a resilient operational and financial performance in the first half of 2026 during a period of significant regional disruption caused by the conflict between the U.S.A.

and Iran. Our priority throughout has been the safety of our people.

Despite the challenging circumstances, we are pleased to have extended our track record of 0 lost time incidents to over 3.5 years. Decisive action to reduce expenditures following the production shut-in enabled us to minimize cash outflow, maintain a robust balance sheet and pay a $12.5 million dividend to shareholders.

We are pleased to have recently restarted production and exports with volumes continuing to ramp to prior levels. Looking ahead, we are focused on unlocking full production sharing contract entitlement or export sales at international prices, which could bolster cash flow generation in the second half of the year and support a return to production growth in 2027.

Turning now to the operational review. Next slide, please.

Production in 2026 year-to-date has been impacted by 2 precautionary shut-ins related to the regional security environment, totaling almost 5 months. Gross average production in the first half of 2026 was 14,600 barrels of oil per day compared with 44,100 barrels per day in the first half of 2025, reflecting the shut-in from the 28th of February to the 23rd of June.

Shaikan Field and the team on the ground responded exceptionally well to these disruptions. Prior to the first shut-in, production had exceeded 44,000 barrels of oil per day on several days in late February, thanks to the completion of several well workovers.

Following the restart on the 24th of June, the field ramped up quickly to exceed 45,000 barrels of oil per day before the second shut-in on the 19th of July. On August 16, we were able to restart production again following the extension of the tripartite interim export agreements and our view of the regional security environment.

Gross volumes are currently approaching 40,000 barrels of oil per day and well activities are underway to increase production to prior levels soon. Our focus for the remainder of 2026 is completing the ongoing ramp-up and maintaining stable export sales, subject to the stable security environment continuing.

Next slide, please. Investment and activity in the first half of 2026 is focused on the enhanced production and -- enhancing production and improving safety and reliability of our facilities.

Almost half of the $18 million net CapEx in the period was spent prior to the shut-in on 28th of February. Subsequently, we moved quickly to moderate expenditures and preserve cash.

Nonetheless, we have actively continued to progress safety critical and strategic projects during that period, in particular, the installation of water handling facilities at PF-2. We're making good progress and remain on track for full start-up in Q1 2027.

Once operational, the project is expected to unlock 4,000 to 8,000 barrels of oil per day of incremental gross production above the baseline, expand total capacity to around 77,000 barrels of oil per day and reduce reservoir risk. Looking ahead to the remainder of the year, we will continue to further progress the work program provided production remains online.

We are also positioning for a return to field development and drilling in 2027 once we have unlocked full production sharing contract entitlement for export sales at international prices. Next slide, please.

Despite the disruption to production this year, the tripartite interim export agreements signed in September '25 between the IOCs, Kurdistan Regional Government and Federal Government of Iraq have worked effectively. IOC remuneration has improved relative to local sales and payments have been consistent without delay following crude liftings.

Realized prices in entitlement invoices have been very robust with the Shaikan discount to Brent in the first half of the year at around $9 a barrel. The decrease in discount relative to Q4 2025 has been driven by strong demand for the Kirkuk blend of crude marketed at Ceyhan from the Iraq-Turkey Pipeline.

Due to the market disruptions caused by the U.S. Iran conflict, some cargoes of Kurdistan crude were sold at a netback price, which included a premium to the Kirkuk blend official selling price.

We will keep a close eye on how the discount evolves going forward, but it's too early at this stage to provide long-term guidance. In June, the independent consultants review of IOC invoices and contractual costs were submitted to the government of Iraq.

Gulf Keystone and other IOCs are now focused on reconciling export sales since September '25 to international prices. As you can see from the chart, we have a top-up receivable on our balance sheet of around $80 million net to Gulf Keystone.

This is estimated value for the differential between cash received to date of $30 a barrel and international prices in the entitlement invoices. It remains subject to the implementation of the independent consultants review.

We are seeking to recover the receivable through the commencement of additional liftings in September 2026. The interim export agreements have also been extended for 6 months to the end of January 2027.

This was the final step, enabling the recent restart of exports and followed the 1-year extension of the Iraq-Turkey pipeline agreement earlier this month. Our focus is now on replacing the interim arrangements with longer-term agreements at international prices.

Next slide, please. Shaikan remains a large long-life asset with significant growth potential.

As of the end of 2025, the Jurassic reservoir had 416 million barrels of internally estimated gross 2P reserves, implying a reserve life of 27 years at 2025 production levels. The field also contained 311 million barrels of estimated gross contingent resources, including 157 million barrels in the Triassic reservoir based on the latest CPR from 2022.

Returning to stable exports and payments of international prices will provide the foundation for renewed investment in production growth. In preparation, we are discussing a revised field development plan with the MNR and positioning for a potential return to field development and drilling in 2027.

The draft field development plan targets a more than doubling of current production from the Jurassic, a test of the Triassic reservoir up to 10,000 barrels a day and the elimination of routine gas flaring through a gas management plan. We will provide further updates as we firm up our plans.

With that, I will now hand over to Gabriel for the financial review.

Thank you, Jon. We delivered a resilient financial performance in the first half of 2026.

By reducing expenditures, we were able to minimize the free cash outflow, protect our balance sheet and return cash to shareholders while continuing to progress safety critical and strategic projects. Next slide, please.

Adjusted EBITDA increased 26% to $52 million in H1 2026 compared with $41 million in the first half of 2025. The increase was driven primarily by considerably higher realized prices reflected in entitlement invoice for export sales and as well as lower operating costs.

This more than offset the impact of lower production from the temporary shut-in of the Shaikan Field. Next slide, please.

By taking decisive actions to reduce costs, we have been able to protect our balance sheet through the shut-in while maintaining our ability to quickly restart production at full capacity. Operating costs reduced by 25% to $20 million in the first half of the year relative to H1 2025, while other G&A expenses were 6% lower at $4.3 million.

OpEx per barrel, while elevated over the entire period due to the lower production denominator was around $4.4 per barrel prior to the February shut-in, in line with prior years. G&A expenses were also down in H1 despite incurring the one-off costs related to the Oslo dual listing.

Looking ahead, we remain focused on exercising strict cost control following the recent restart of production and exports. Next slide, please.

The reduction in CapEx and costs during the period enabled us to limit the free cash outflow to $2 million. The working capital outflow primarily reflects the difference between cash received at around $30 per barrel and the international prices reflected in the entitlement invoices.

As Jon mentioned, the difference is accrued as a top-up receivable, which increased to around $80 million net to GKP at the end of the period. To begin recovering the receivable, we are seeking the allocation by SOMO of additional liftings of crude in September 2026 with payment expected no later than 30 days after scheduled cargoes.

GKP's net entitlement of Shaikan Field sales was approximately 36% in the first half of the year, in line with prior periods. Future net entitlement will depend on realized prices, production levels and the outcome of the ongoing commercial negotiations with the Ministry of Natural Resources.

A return to international prices would quickly deplete the current reported cost pool, incentivizing future investment. Next slide, please.

GKP's robust balance sheet and ability to moderate expenditure enabled us to weather the disruptions in the first half of the year while paying a $12.5 million semiannual dividend in April. We remain committed to return excess cash to shareholders.

We are, therefore, pleased today to announce an interim semiannual dividend of $10 million for payment in September 2026. The dividend decision follows a careful consideration by the Board of GKP's operating environment, outlook and cash balance.

Achieving full PSC entitlement for export sales could strengthen cash flow generation in the second half of the year, while the company maintains significant flexibility to reduce CapEx and costs if required. As Jon mentioned, export sales at international prices would also support a return to field development and drilling in 2027 as we firm up our plan with the Ministry of Natural Resources.

Looking ahead, we will remain true to our strategy, balancing disciplined investment in production growth while shareholder distributions and a robust balance sheet. With that, I will hand out to Jon for closing remarks.

Thanks, Gabriel. To summarize, our performance in the first half of 2026 demonstrated the resilience of our business during challenging conditions.

By acting quickly and decisively, we've been able to protect our people, our assets and our balance sheet while continuing to progress strategic projects and returning cash to shareholders. Following the recent restart of production and exports, we are focused on completing the current ramp-up to prior levels and unlocking full production sharing contract entitlement for past and present export sales.

Achieving the latter would bolster cash flow generation, supporting our decision today to announce a semiannual dividend of $10 million and provide the foundations for a return to production growth in 2027. As I conclude, I would like to say a big thank you to our staff, shareholders and wider stakeholders for your continued support.

With that, I will now open the line for questions.

Just a question on reserves. You mentioned that your estimate of 2P reserves shows 27 years of productive life based on last year's production.

When I look at the license expiry and including the two 5-year extensions, the license expires well before this. So I'm thinking -- well, I would like to kind of hear your thoughts.

Do the revised discussions you're having on the new FDP with the MNR, do they factor in a development period that will allow you to produce all of those reserves? Or how do those 2 things marry together?

Werner, thank you. Thanks for your question.

The simple answer is yes. Those are reserves and they are the reserves produced within the license period.

Essentially, I think during the presentation, I mentioned that we were looking to ramp up production to some 85,000 barrels a day, which is nearly double what we're producing now. Clearly, that would shorten the 27 years life based on last year's production considerably, not quite sure it halves it, but nearly basically.

Yes, they are the reserves. They are produced within the period, and it does assume a production ramp-up.

Okay. And so with the revised FDP, it's possible that we'll see an extended license period as well to kind of enable you to do that?

We are not -- that's not part of the field development plan. At the moment, of course, it might become part of future negotiations.

Okay. All right.

Maybe one for Gabriel. Just wondering how much of the H1 operating cost reduction reflects the temporary shut-in versus, I guess, more sustainable structural efficiencies?

Because you're producing less...

Exactly. I would say the majority is related to the fact that we were shut in.

We were spending less on diesel, on chemicals. Obviously, we had to implement some other staff-related savings.

But as you can see in the first half -- in the first 2 months, we were bang in line with historical costs. We always look for opportunities to find savings that can carry on.

But for the first half, specifically, given the high level of production going down, it's primarily related to the shut-in.

A few questions for me. First, on the ongoing ramp-up you discussed.

You indicated that you aim to increase production back to the pre-shutdown level of around 40,000 barrels per day. So how should we think when will we reach that level?

And what should we expect production for the second half, assuming that there won't be any more shutdowns? And second question is on reserves.

How should we think around any potential impact of the reserves because of production shutdown and then production restart and then shut down again? Will there be any impact at all?

And final question is on the receivables. I understand it's a bit difficult to precisely answer it.

But how should we think about like the repayment profile? And how much do you think could be recovered this year?

Okay. I think your first question was around how quickly do we get back up to previous levels.

I think I said during the sort of production ramp back in June through to July, which was like the 23rd of June to the middle of July. That was like 3 weeks, we got to 45,000.

We've just started on the 16th of August that we've restarted production. here we are not even 10 days into that.

Coiled tubing is in the field lifting wells as we speak. I'd expect to be over 40,000 by tomorrow in terms of production run rate.

It's really about 3 weeks since we start. I'd expect us to be back close to 44,000, 45,000.

That's on the production ramp. I hope that answers that question.

You said with the production shutdown and start and shut down again, do you expect the reserves to be affected? I mean the numbers we're talking about, I wouldn't expect those to really materially affect the overall reserves position because we will be producing at a much higher rate.

The fact that we haven't been producing, that kind of obviously plays into how we produce in the future. But I don't expect the reserves to be affected materially by that.

Yes. I think what you've seen in the activity on the field, it hasn't -- as we ramp up the wells, they've all come back and there hasn't been any issues.

That's from a mechanical or subsurface perspective. That's positive.

On your point on the receivable, basically, we're really focused at the moment dealing with the Q4 2025 that is following the submission of the independent consultants review, and we're working quite hard with the other IOCs and the MNR and so on to get some cargoes allocated from September. We'll have to see.

We also need to recognize that in the summers, the volumes, the throughput of oil going through has been kind of impaired by the security concerns, the fact that us and other fields have been limited, that impairs, I suspect, a little bit the ability for a quick handover of additional cargoes. But now that we are back online, production is ramping up, we hope that we're going to be able to see some of those cargo coming up soon.

The priority is really get that first cargo, get Q4 over the line. Then basically, then you start a program to deal with the first half of this year.

As Jon mentioned, production, the first part of this year was essentially January, February for the large part. We would expect this should be also relatively quick to get the top-up for that period at an elevated oil price that we're seeing at the moment.

But let's focus on Q4. That's the priority right now, and we'll then move ourselves to Q1 after that.

Okay. And then one final question, if I may, that is on CapEx.

Given the accelerated production in the second half, should we also expect you to spend more in second half than in first half?

At the moment, it's a little bit too early to tell if it's just -- I don't think we could say it's going to be double. We still have some discretionary spend that we can put forward in order to kind of prep for next year's activities.

But that's also kind of tied with international pricing and the recovery of cash flow. That's why we didn't reinstate guidance.

But for example, on strategic projects like the wet train and the shutdown and some of the things that we had decided to carry on regardless or not of the production shut-in, those are carrying on. But some well activities and planning for next year's activities like long leads and stuff like that are more discretionary, and we will navigate those as we go through the remainder of this quarter and Q4.

A couple of questions, actually, if I may. In terms of the recovery of the Q4 true-up, do you think you need to have agreement on the full export pricing before you get that perhaps September lifting?

And has that Q4 receivable for the true-up been agreed with the various authorities?

Basically, the Q4 receivable was part of the independent consultants review. Now that, that number has been validated, it's now moving to allocation of additional cargoes to turn those receivables into money.

But there is also a longer-term element to discuss about kind of future production, long-term prices to ensure that we move away from that interim period to get future production. We're also in parallel having conversation with the different stakeholders to put in place long-term export agreements, which would allow us to get international prices right from the beginning.

But I see those as being disconnected. You could still recover the receivables from the Q4 in advance of agreeing long-term agreements related to ongoing production.

Okay. That's great.

And one short follow-up. You talked about maybe a return to growth next year and drilling next year.

Do you have in mind a possible timetable for that drilling? And would that need in your mind to have agreement on the FDP or approval of the FDP?

I mean, Charlie, we're out tendering at the moment for a rig. Obviously, it will be also some long lead items, which will dictate the exact start date, which we haven't got the answer to.

Our expectation is H2 next year. Yes, we would like to have the field development plan agreed, but we might consider drilling without it.

But I think our very strong preference is we're driving towards agreeing field development plan.

Just firstly, on the draft FDP, obviously, that's been around a while. I was interested whether it's changed much in recent years, thinking particularly around the gas management system or whether you just sort of dusted off the old one.

And I think -- I mean, correct me if I'm wrong, I mean, the last number I saw was sort of $800 million to $925 million for that next phase. So does that still stand?

Are you able to break that down for us at all? And how you think about funding it?

Based on the FDP in terms of development planning, in terms of expanding capacity, both in the facilities and from wells perspective, is similar. We have a few more wells than we had previously towards the back end of the program.

We have a continuous drilling program. The gas management plan, we are considering a number of alternatives.

One is as per the original plan, which was to reinject all of the gas that we don't -- is not needed for use in the plant. The second one is to just reinject the acid gas into a deeper reservoir and produce the sweet gas and make that available for sales.

That's the difference, and we haven't kind of concluded on that yet, but we are sort of honing in on those 2 solutions to the gas side of things. I think the next question was around -- on the CapEx.

Yes. To account for those additional wells, which come later in the life of the asset as well as the gas management program.

We haven't come yet publicly for what those come in because we still need to go through the tendering of the gas project. But I think the estimate that you said at the starting point on a gross basis, we probably expect to see this going a little bit higher obviously because there would be more wells in the back end.

We'll have to see how ultimately the costs come from the gas management. The one thing worth noting is that the cost pool has been mostly depleted since if you move back 2022, 2023, just before the shut-in of the ITP and moving to local sales.

Essentially, the recycling of the CapEx is going to be a much shorter balance. That being said, we think that the cash flow generation of the asset will be improved.

But as well, we thought even back at the days to raise some debt, we know that the high-yield market has been quite supportive of the player over the years and depending exactly how the gas management program turns around, there could be some other providers of capital, but we're looking into this as we speak to make sure that we're well funded. Our pace of investment ties with the robust balance sheet and ensuring that our shareholders are seeing some distribution as we pace the investment over time.

Once we get the FDP over the line, we'll be in a much better place to come with kind of the full story to investors.

Okay. Great.

And can I just sneak in a follow-up, please? Just on the discounts.

The numbers you show on Slide 7, are they a discount for the Kurdistan blend? Or are they sort of specific Shaikan discounts?

And can I ask just what you're assuming going forward in your own estimates?

Yes. To clarify, this is really related to Shaikan.

It takes into account the quality as well as the transportation, the length of the pipeline we use. As Jon said, it's a little bit too early to call that 9% will be forever.

But I suspect it's going to be low single digit -- double digits, I think, going forward. We are looking forward to see how that's going to evolve.

But if you look back compared to the $23, $25 or even $27 per barrel that we saw before, this is a net-net material improvement from where we are. We're really pleased to have those agreements in place with this reduced discount.

Thanks, Danielle. Thanks, everyone, for submitting your questions.

So first question from investors is, what's management doing to unlock the value of the assets as the stock is undervalued and has underperformed over the last few years against industry peers. Jon, maybe I can pass that to you.

Okay. Thank you.

Well, I would say we've outperformed many of our international peers over the past 3 years on a total shareholder return basis, accounting for dividends. I recognize that nonetheless, I agree that there's been an impact on our share price this year due to the deterioration of the regional security environment and our prudent response to shutting production, while many other peers have benefited from ongoing sales, of course, international prices at the inflated international oil price.

Now that we're back into production and seeking to get back to international prices with targeted recovery of the top-up receivable for the actual production we did -- we had produced during this period, we expect our performance to very much recover. This would enable us to drive production growth from the Shaikan Field, which we believe would unlock significant value for shareholders.

Thanks, Jon. The second question on -- there's actually been a few questions on the overdue receivables between 2022 to 2023.

What's the update on those receivables? And is there a resolution forthcoming anytime soon?

Gabriel?

Yes. Thanks, Aaron.

The recovery of those historical receivables, including '23 and '22 is part of the ongoing discussion with the MNR as part of the other outstanding Shaikan commercial matters. The talks are progressing and regarding the timing and the form of the potential settlements of all the historical receivable.

But what I'm happy to point is that, as you can see in our account in Note 12, we are actually effectively continuing to recover the cost oil portion of some of those 2022 and 2023 arrears. That balance has been going down since the back end of last year.

It's positive and derisks that position.

Great. So next question is just on M&A.

Do you envisage opportunities to merge or diversify the asset base and therefore, enhance revenue streams in the next 12 months? Jon, would you like to take that?

Thank you. Yes.

Look, our primary focus remains unlocking the full production sharing contract entitlement from export sales and returning to disciplined investment in production growth from the Shaikan Field. But of course, we also look at opportunities to grow production and diversify our portfolio inorganically that will be value accretive and consistent with our current financial profile.

Great. A few here on the top-up.

I think Gabriel has covered that quite extensively, but there's one here just on -- regarding the September liftings that we talked about. Are you now supposed to receive international oil prices for those liftings?

Or is it still the interim deal with local prices with a potentially later top up?

Yes. The way it works is that there's a dollar amount of receivables owed to the IOCs.

Basically, they take the international pricing that you kind of divide that amount at that point in time, it determines the number of barrels. Then the IOCs are allocated some barrels.

We sold those barrels. As this is converted back to cash, we're able to deplete our receivables.

The short answer is yes, it would be on international pricing.

Great. Next question is just on the CPR.

The last CPR was from 2022. When would there be a new CPR?

Jon?

Yes. I mean, with us progressing to a field development plan agreed with the Ministry of Natural Resources, we would move quite swiftly to also to reinvigorate the last CPR.

But I mean, one thing I would say is that the field has continued to perform as expected. It's continued to produce as we thought it would with -- it's been very, very reliable.

From that perspective, that's why it's quite easy to say our reserves haven't changed significantly, albeit obviously, we're still looking at doing a major development to liberate those reserves, but it is behaving predictably. So it gives us confidence to state the numbers having not done a CPR since '22.

Great. And just for you, Jon, again.

Can you elaborate on how the security situation has changed in such a way that you've decided to restart production?

Yes, very much so. We continue to look at what's been going on, obviously, between the U.S.

and Iran. We've kind of continued to see that there was a buildup in military hardware by the U.S.

kind of up until about 10 days, 2 weeks ago. Then the U.S.

has kind of backed off, going full tilt militarily and continued with its rhetoric about going full tilt, but it hasn't done it, plus connected with the kind of the conversations around having sufficient Patriot missiles and other interceptors of drones and ballistic missiles, having a reduced number of those in the region and therefore, wanting to potentially go move to a negotiated solution. Then obviously, you'll have heard recently yesterday, the Secretary of State of the U.S.

has come out -- the Secretary of State, [ but investments ] come out and said that they're going to go full tilt on trying to bring Iran to the negotiating table through economic hardship means. From our perspective, we've seen obviously the militias, who are Shia militias sponsored by Iran have been largely responsible for most of the ordnance fired into Kurdistan.

Certainly, some has come from Iran, but the vast majority has been fired by the militias. We've seen the militias basically in negotiations with the Iraqi government about political power, but also kind of getting to a place where they are -- have backed off military activity as well.

Whilst people are talking about the U.S. leaving Iraq, also connected with the new Prime Minister of Iraq saying that he's expecting the militias to disarm, albeit there are rumblings about the timing of that and how that's going to be affected.

Our overall assessment is that we've seen less hostilities towards Kurdistan, less hostilities towards IOCs, not for a considerable period of time actually. Therefore, that's led us to go back to being able to produce -- but we're going to continue to monitor the situation.

And of course, it may deteriorate again, in which case we might have to shut in, but our hope is that we can continue to produce.

Great. Thank you, Jon.

I don't have any further questions from the webcast. So I will hand back to the operator to close the call.