Hello and welcome to today's ADNOC Drilling Q3 2025 earnings call. My name is Bailey, and I will be the operator for today. All lines will be muted during the presentation portion of the call, with an opportunity for questions and answers at the end. If you would like to ask a question, please press star followed by one on your telephone keypad. I'd now like to pass the conference over to Max Cominelli, Vice President of Investor Relations, to begin. Please go ahead. Ladies and gentlemen, welcome to ADNOC Drilling's third quarter 2025 earnings webcast and conference call. My name is Max Cominelli, Vice President of Investor Relations at ADNOC Drilling. As always, before handing the floor over to our main speakers, I would like to draw your attention to the disclaimer that you will find on the second slide, which I encourage you to read carefully. The text contains important information. We advise caution on the interpretation and limits of our historical data and forward-looking statements. I would like to remind you that this presentation and the recording of this call will be available on our website shortly after the end of the call. Today's presenters are our Chief Executive Officer, Abdulrahman Abdulla Al Seiari, and our Chief Financial Officer, Youssef Salem. After the presentation, we will have a Q&A session where we will be happy to answer your questions. I will now hand over the call to our CEO, Mr. Abdulla, p lease go ahead. Thank you, Max. Good day, everyone. Very pleased to be with you today to discuss our results and to update you about our strategic progress so far. About three weeks ago, we had the first ever ADNOC Investor Majlis, and thanks for everyone who has joined us. There we have reinforced our roadmap for value creation, long-term visibility, resilience, expanding integrated services, accelerating unconventional, and the new progressive dividend policy. Building on that, we enter today a call with a position of strength. At the third quarter of 2025, we delivered a record revenue, well over $1.2 billion. EBITDA: $560 million. Net profit: $368 million. Last but not least, the free cash flow of $477 million. These results allowed us really to upgrade once again our full-year guidance. On top of this, our board has approved a $250 million dividend distribution for the third quarter, which is aligned very much with our announced dividend policy that's raising the floor of 2025 to $1 billion with a minimum of 5% annual growth all of the way to 2030. Looking ahead, our priorities are very, very focused. Sustaining our business growth, invest where returns are the highest, last but not least, scale the technology to generate more value for all of us. With that, I'll hand over to Youssef to walk you through the presentation. Thank you very much. Thank you, Mr. Abdulla, and a good day to all. I'm happy to share that ADNOC Drilling delivered another record period through the first nine months of 2025. Our revenue increased by 27% year on year to $3.63 billion, driven by rig fleet expansion, significant growth in OFS, and higher activity in unconventional operations. We closed the quarter with a pro forma fleet of 148 rigs, including eight land rigs in Oman and Kuwait under our SLB partnership, pending customary approvals. The strong top-line growth led to industry-leading profitability. EBITDA was up 15% year on year to $1.64 billion, and net profit increased by 17% to $1.06 billion. Our oilfield services segment continues to be a powerful growth engine, with revenue expanding 114% year on year to more than $1 billion, driven by higher IDS coverage and addition in discrete services and the Unconventionals program, which started in the second half of last year. As Unconventionals continued their strong year-on-year acceleration in the nine-month period, recording $502 million in revenue. As anticipated and in line with planning, we expect unconventional revenue of around $0.6 billion for the full year. We expect a similar contribution from Unconventionals in 2026, revenue of around $0.6 billion, after which ADNOC's program is expected to potentially ramp towards 300 plus wells annually, with this growth expected to gradually start from 2027. I will provide further details in the guidance slide. On services, IDS coverage reached 59 rigs in the quarter, with discrete services on a further 53. All in all, oilfield services were offered to 112 rigs, and this coverage is expected to further increase over time, designed to meet rising demand and enhance operational efficiency, keeping us on track to 70 IDS rigs by year-end 2026. Within offshore, island rigs increased to 12 from 10 year on year, and six additional island rigs are on order, with deliveries beginning from 2026 until 2028, with more expected between 2029 to 2030, supporting long-term offshore development and earnings visibility. Finally, as conveyed at the inaugural ADNOC Investor Majlis on October 8th, we have proposed an upgrade to our progressive dividend policy at a 2025 dividend floor of $1 billion, representing a 27% year-on-year increase, growing by at least 5% annually through at least 2030, equating to a cumulative floor of about $6.8 billion over 2025 to 2030. In line with that framework, the board has approved a $66 million special dividend of approximately $0.015 per share, and yesterday approved the third quarter dividend of $250 million, or approximately $0.057 per share, payable in the second half of November 2025 to shareholders of record as of November 6, 2025. Next slide, please. Turning to how we sustain growth with new smart and accurate avenues, as our CEO commented on our strategic priorities. This quarter, we made material progress across our strategic growth pillars, which are advancing our long-term objective of becoming the region's most relevant and technologically enabled integrated drilling and oilfield services company. A particularly significant milestone throughout the period is the continued acceleration of our Unconventionals program, through which 75 out of the 144 wells have already been drilled, with over 30 of these having been fractured. Overall, our JV Turnwell successfully delivered high-efficiency wells while implementing new drilling techniques, including autonomous drilling, that have reduced cycle times and improved safety metrics. This progress sets the stage for potential future expansion, subject to client's final investment decision, as we continue to unlock new growth frontiers, targeting more than 300 wells annually, with a gradual ramp-up expected from 2027. Worth noting that if fully unlocked and contracts awarded, the program has potential to significantly enhance growth through the end of this decade and beyond. Meanwhile, on regional expansion, we're progressing the agreement to acquire a 70% equity stake in SLB's land rig operation in Oman and Kuwait. This transaction has marked our first regional expansion of scale and includes eight fully contracted rigs. We reiterate that this acquisition is structured to be immediately earnings accretive and has been executed at a highly attractive entry multiple of below four times EBITDA, expected to close by the first quarter of 2026. Finally, on EnerSol, the JV has an advanced pipeline of additional transactions on top of the four acquisitions already completed. As a reminder, since inception, EnerSol has deployed approximately $800 million across four acquisitions. Each of these additions allows us to embed in our business advanced technologies, analytics, and AI-driven capabilities across the operations. Moving on to operations in the next slide, please. Looking at the Middle East's largest fleet, we closed the quarter with a pro forma fleet of 148 rigs, which includes the eight land rigs in Oman and Kuwait tied to our SLB partnership, pending customary approvals. This also includes the two jackup rigs that were added to the fleet at the end of December 2024, which began operations at the end of the second quarter of 2025 and contributed fully to revenue in the third quarter of 2025. During the quarter, there's been a minor reshuffle in the rig fleet. The company sold the onshore rig operating in Jordan. Additionally, one onshore rig began operating on Artificial Island for the Highland Rest Shop. As a result, we ended the quarter with 100 land rigs pro forma, including Oman and Kuwait, and 48 offshore rigs. Overall, owned fleet availability was 97% at the end of the quarter. The company expects that some onshore rigs, after the review of their age, will transition from drilling to supporting operations. Consequently, these rigs are anticipated to be repurposed or alternatively disposed. In parallel, we continue to expand our footprint in OFS. In fact, integrated drilling services are now active on 59 rigs compared to 53 last year, with significant progress. Discrete services were delivered across 53 rigs, bringing total OFS coverage to 112 rigs. This means that well over 70% of our drilling fleet is supported by ADNOC Drilling's OFS solutions, a critical element of our value proposition to clients. With this strong operational base, we are well placed to further elevate our integrated operational performance in the future. Moving on to the financials. As you can see from the chart, the third quarter performance shows continued top-line growth, solid margins, disciplined investment, and strong cash generation. Revenue for the quarter increased 23% year on year to around $1.3 billion, and EBITDA grew 10% to $560 million, benefiting from the contribution of the unconventional characterized by relatively lower margins but high returns. Net profit also increased 10% year on year, reaching $368 million with a margin of 29%. This growth was driven by broad-based trends across the different segments, as well as increasing contribution from Unconventionals. In the third quarter, EBITDA benefited from a one-time contribution of $23 million from the sale of an onshore rig, which was offset by higher maintenance sequentially. Excluding these two factors, EBITDA would have been in line with Q2 as anticipated in July earnings quarter. Operational cash flow stood at $667 million, underscoring the strength of our earnings conversion and working capital efficiency. This performance enabled us to maintain a healthy balance sheet with net debt to last 12 months EBITDA at 0.8 times, below our long-term leverage ceiling of 2 times. Cash CapEx for the quarter was $174 million. This investment was consistent with our fleet and OFS growth trajectory. Importantly, this disciplined deployment of capital continues to support our long-term plans while preserving flexibility to fund both growth and growing dividends to shareholders. Overall, our financial performance in the quarter reinforces the strength of our integrated model and highlights our ability to generate consistent value through cycle-resilient execution. Now let's look at revenue for the various segments. Next slide, please. In the third quarter, revenue increased year on year across the various segments. Starting with onshore, revenue increased 5% year on year to $512 million, supported by rigs commencing operations and a $38 million contribution from unconventional activity related to land drilling. Sequentially, revenue for the segment stood broadly flat, as one additional operating day in the third quarter was offset by the conversion of one rig from onshore to offshore segment. As I said earlier, the company expects that some onshore rigs, after a review of their age, will transition from drilling to supporting operations. Consequently, these rigs are anticipated to be repurposed or alternatively disposed. In offshore, revenue increased 7% year on year and 8% sequentially to $365 million due to the conversion of one rig from onshore to offshore during the quarter, and as the two new jackups, which entered the fleet at the end of 2024 and started operations at the end of Q2, fully contributed to revenue increases. The oilfield services segment delivered another outstanding performance, with revenue up 94% year on year to $383 million. This was driven by broader IDS coverage and high discrete services supported by the Unconventionals program. Overall, Unconventionals contributed $158 million in the quarter, $120 million within OFS, and the remainder within onshore. As anticipated and in line with planning, we expect a lower phasing of it in the fourth quarter. Next slide, please. Moving on to EBITDA in the onshore segment, third quarter EBITDA was $254 million, up 5% year on year, with margin expanding to 50%, supported by higher revenue. Sequentially, EBITDA was impacted by higher repair and maintenance costs, which are expected to be at a similar level in the fourth quarter. Offshore operations contributed $239 million to EBITDA, up 4% year on year and 3% sequentially, with a 65% margin, with higher revenue partially offset by heavier maintenance activity in the quarter. The oilfield services segment delivered EBITDA of $67 million, up 72% year on year and 29% sequentially, with a margin of 17%. This increase was driven by higher revenue from the Unconventionals program, broader IDS coverage, and more discrete services, with a positive contribution from the EnerSol and Turnwell joint ventures. Next slide, please. As disclosed at the ADNOC Investor Majlis on October 8, our board proposed an upgrade to the progressive dividend policy at a 2025 dividend floor of $1 billion, growing by at least 5% per year from 2026 to at least 2030. This establishes a committed floor of about $6.8 billion through 2025 to 2030, providing at least six years of visibility. At the same meeting, the board approved to distribute a $66 million or $0.015 per share special dividend and a third and a fourth quarter dividend payment of at least $250 million, around $0.057 per share. The third quarter dividend of $250 million, around $0.057 per share, was approved yesterday by the board of directors, and it's expected to be paid in the second half of November 2025 to all shareholders of record as of November 6, 2025. As per our dividend policy, the board of directors, at any time at its discretion, may approve additional dividends over and above the progressive dividend floor, supported by excess free cash flow and strong balance sheet. This creates a pathway for upside in dividend distributions, reaffirming the board's commitment to sustainable growth in total shareholder value. Moving on to guidance. I'm very happy to share that, notwithstanding recent market dynamics and driven by increased visibility and the strong results of the first nine months, the company upgrades its full-year 2025 guidance, demonstrating its resilient and defensive growth. The lines upgraded are marked in green. We have upsized the total revenue guidance and now expect $4.75 to $4.85 billion. The upgrade is supported by a stronger OFS, where the revenue range is raised to $1.3 to $1.4 billion, driven by IDS coverage, discrete services, and Unconventionals. Net profit is now expected at $1.4 to $1.45 billion. The range reflects the nine-month trajectory and continued benefits from lower finance costs, supported by the October refinancing, as well as the working capital improvements and slightly lower D&A in the remaining period. Overall, for the full-year 2025, we expect revenue and net profit to land towards the top end of the full-year guidance range and EBITDA to be around $2.2 billion. These directional trends imply our expectation of fourth quarter broadly in line with Q3 on revenue, net income, and particularly on EBITDA. This would result in a like-for-like improvement, as Q3 EBITDA benefited from a one-off contribution from the sale of the onshore rig in Jordan. We reaffirm free cash flow at $1.4 to $1.6 billion, with CapEx now at $0.45 to $0.55 billion and the leverage target below two times EBITDA, and a 2025 dividend floor of $1.0 billion. Looking into next year's, we confirm our comments made during the second quarter's earnings call in relation to 2026. Full-year 2026 unconventional revenue is expected to be broadly stable year on year at around $0.6 billion. We expect this vertical to gradually ramp up as ADNOC increases the number of wells over time, potentially from 2027. For this reason, we confirm our forecast for 2026 revenue of around $5 billion, with growth coming from OFS conventional, more offshore activity, new island rigs, and full-year impact of new jackups and consolidation of the business in Oman and Kuwait. We also confirm our expectation of full-year 2026 EBITDA and net profit to remain broadly in line with 2025. The ongoing investment in regional expansion, operation setup, pre-qualification efforts, and oilfield services will come with pre-investment in business ramp-up and operational expenses. In other words, for next year, margins associated with revenue growth will be reinvested into continuing to grow the business. Also, I'm very pleased to say that we have increased our medium-term OFS margin guidance to 23% to 26% from 22% to 26% as the business continues to expand. Finally, on the fleet count, our own fleet is now at 148 rigs, including regional rigs, which means that we've already hit the intermediate fleet target for 2026 of 148 rigs a year ahead. For this reason, we reaffirm over 151 rigs by 2028 to be updated in due course to cater for future organic expansion and unconventional. Within our fleet, we expect IDS rigs to be 70 by the end of 2026. Moving on to the final slide. The slide wraps up all the key messages: record results, upgraded dividend policy with a special dividend of $66 million, and the Q3 dividend of $250 million, totaling $7.20 per share return to investors since the Majlis. Continuous development on the growth front while delivering on our sustainability agenda. With this, I thank you all for joining us today. I'll hand over to the Operator to start the Q&A session. Thank you. If you would like to ask a question on today's call, please press star followed by one on your telephone keypad. If at any point you would like to remove that question, please press star followed by two. Once again, to ask a question, please press star followed by one. We'll start with our first question today. It comes from the line of Faisal Al-Azmeh from Goldman Sachs. Please go ahead. Your line is now open. Yes, hi, and thank you for the opportunity to ask questions, and congratulations on the results. Maybe just a few questions on my side, maybe starting off with just in terms of kind of like your strategy on the GCC expansion. I know you've talked a lot about it before, but maybe if you can just shed some color in terms of how that fits within your medium-term guidance in terms of the EBITDA contribution. What should we expect in the medium term and in the long term? How much associated CapEx should we kind of think about when you know that ties into these long-term plans? Maybe on the OFS side, you've mentioned as well on the unconventional that margins can range between 10% to 20% in 2030, depending on how you source equipment. If you can shed some color in terms of how you get to the 20% and how do you get to the 10%, what needs to be done to kind of move up that margin range. Finally, you've talked a bit about the billion-dollar dividends. How should we think about the upside risk to that figure next year and the years to come? Because you said it's a minimum and it's a floor. Is there room for the company to pay special dividends? What would incite you to pay a special dividend? Thank you. Perfect. Thank you, Faisal. I think if we start with the first question. In terms of the regional expansion, starting with the CapEx piece, we're looking at anywhere between $10 million to $20 million per rig, depending on the relative level of rig specs that we're looking at. For example, if you look at the SLB JV, which we've done, which was the first one, we were closer to the $20 million level per rig because the vast majority of the eight rigs we acquired were 2,000 and 3,000 horsepower, which are kind of partially depreciated yet still relatively new rigs, which is our strategy—to be with these acquired rigs somewhere around kind of the five-year-old rigs. There is an element of depreciation, which allows us to have these rigs tried and tested in the countries in which they operate with a proven track record, but at the same time, to be relatively new rigs that still have a significant backlog and an ability to live and operate beyond that backlog. That was closer to $20 million per rig. As we look at potentially packages of rigs that may have a higher contribution of workover rigs to them alongside the drilling rigs, and hence these workover rigs may have a potentially lower horsepower and price, then on these other packages, we're maybe closer to $10 million per rig in terms of CapEx. In terms of their EBITDA contribution, again, if we're looking at some of the higher horsepower rigs like what we've done with SLB, we are looking on an average of somewhere around $7 million per rig in terms of some of the EBITDA that these rigs are able to contribute, $6 million to $7 million per year of EBITDA. If we look at potentially some of the kind of smaller rigs we can potentially look at from some of the other smaller deals, which may have a higher proportion of workover in them, then effectively that kind of EBITDA level may be closer to $3 million to $4 million per rig per year, as effectively a result of that kind of lower horsepower part of the rig. If you add this up, then what that can potentially look like, I think in 2026, you are looking at just under $50 million to come from that kind of regional expansion, but that's obviously subject to the final amount, the exact date of closing, which will impact the specific closing time. As we go forward into 2027, we'll have the benefit of more of these kind of bundles potentially closing, and that's where we see that number potentially going up to $100 million plus of EBITDA starting 2027. You should have a kind of a growth from 2026 to 2027 coming from that incremental level of activity. In 2026 specifically, you will see that our guidance for the EBITDA was still that the overall EBITDA of the business would remain at the kind of the closer to the $2.2 billion EBITDA level that we would achieve this year. This is basically as a result of even though we have the additional EBITDA coming in from the land rigs outside in Oman and Kuwait, starting to come in post-regulatory approvals. One is the uncertainty around when exactly these regulatory approvals kick in. Second, we've also made kind of one of the points we've included is also some of the older rigs we have in Abu Dhabi. Some of these may potentially be repurposed as they cross the 40, 45 years mark, and kind of to support operations in a potentially a lighter way. Hence, some of that kind of repurposing may take basically a period of time, and may not have a full year of operation in 2026 for these older rigs. Some of that may offset some of the expansion we're seeing in 2026 in the region, with a potential recovery from 2027 onwards. That's why overall we've kind of kept that. I think a very long way of saying that regional growth is already embedded in the 2026 kind of $5 billion revenue and $2.2 billion EBITDA because effectively of the timing of closing of the deals and potentially some of the other offsetting factors in 2026. From 2027 onwards, that effectively growth should present an upside both on top line and on EBITDA. If we go to the second point, which is the unconventional piece, in phase one, what effectively the situation was because the contract was originally a three-year contract, we were supporting effectively the seven rigs which were working on the unconventional and the two frack fleets that we had deployed on a partial owned and rental model. We did not acquire any new equipment purely for the unconventional. We've basically utilized what was the capacity we could free up from our existing portfolio with the efficiencies we're introducing, as well as some of the rental rigs and frack fleets. That's what resulted in our EBITDA net income being very close to each other at around 9% net income and 10% to 11% EBITDA. As we effectively move forward into the unconventional phase two, with the potential to reach the 300 plus wells, that would be a substantive enough program for us to be able to move effectively into a largely owned fleet of rigs and frack over time. That's what would allow us to expand over time our EBITDA margin from closer to the 10% to closer to the 20%, in line with our remaining OFS business on the conventional side. That would be a journey over time as the number of wells ramps up. That effectively would be the journey that we would go through. From an overall net income perspective and from a returns perspective, that does not necessarily fundamentally change the picture in terms of our 9% to 10% net income margin on the OFS and the unconventional, as well as our levels of return for the business, which we see stable at the 25% return on capital employed and 36% return on equity. That's effectively the EBITDA journey that we would potentially go through. In terms of dividends, yes, we are very clear that the amount we have now is a floor. The same way previously when we talked about the $867 million in 2025, that was always very clearly a floor. We did do the upgrade from the $867 million to the $1 billion. We ended up with a 17% upside to our previous floor. When it comes to 2026, we're going to, based on all of the growth that's now coming in, we expect to have higher CapEx in 2026 than in 2025 because we have the maintenance CapEx of $250 million, plus we have the island rigs CapEx of $200 million, plus we have now the additional awards that we're finalizing with ADNOC post the Majlis, whether it's the 13 additional IDS rigs, which are now 11 because we already ramped up to 59. Now going from 59 to 70, the potential additional island activity in 2029, 2030, and the unconventional ramp-up. All of that means that in addition to the $250 million maintenance, the $200 million of the island rig, there will be additional CapEx levels that will take us above the $550 million level that we currently have for 2025 and can potentially take us to additional CapEx. We're going to be detailing all of that CapEx as part of our full-year guidance for 2026 when we release the full-year results. We know for a fact it will be higher than the $550 for this year. Hence, as a result, if you look at the free cash flow for next year, after you take into account that higher CapEx and then you take into account the closing of potentially additional expansions in Oman and Kuwait, the additional free cash flow after everything may not necessarily be significantly higher than the $1.05 billion floor for the dividends for next year. What we know is that in 2027, the free cash flow will definitely be expected, as things stand, to be significantly higher than the $1.1 billion dividend floor for 2027. Hence, by that point in time, we'll be back into the kind of situation we were in this year, where the free cash flow was significantly higher than the $867 million. Based on that, we upsized to the billion. Again, a very long way of saying, yes, it is only a floor. There is potential upside. In 2026, we expect that to be more of a growth year from a CapEx perspective. That upside to the floor may not necessarily materialize in 2026. By 2027, we definitely see how there is significant upside to the CapEx. Obviously, all of this is still not touching on the balance sheet capacity off the back of that record cash flow in the first nine months. We're now also down to 0.8 times net debt/EBITDA, which continues to be well below the 2x kind of soft ceiling that we have, which again creates significant balance sheet capacity for growth and dividends. Even without that, you have significant upside just on the free cash flow side with a balance sheet upside to come on top of that. In terms of utilizing the balance sheet, that always goes back to the board's view also on continued growth going forward and the need to reserve that balance sheet for a combination of both the growth and the dividend. I think you can clearly see that with the sentiment coming from the group leadership in the Majlis, with ADIPEC coming up next week, you can clearly see that from an ADNOC and from a board perspective, they do see that kind of continued growth and hence the ability to gradually deploy that balance sheet capacity into growth and dividends over time. Thank you. Thank you very much. Thank you. Our next question today comes from Afaq Nathani from International Securities. Please go ahead. Your line is now open. Hello. Good evening. Congratulations on a great set of numbers. Just a couple of questions from my side. Firstly, on the rigs sold in Jordan, just wondering if there's any recurring revenue or EBITDA impact from that. A little bit of color on that would be helpful. Secondly, on guidance, just a small technical question. We've seen a consecutive uptick in net income guidance, but little to no change in EBITDA. Could you highlight where the higher than expected numbers are coming from? What's driving that? Thirdly, on the 300 wells annual target for the Unconventionals program, which was announced at the Majlis, how exactly should we look at this in terms of incorporating within our estimates? What kind of timeline do you see around these targets to be achieved? Thank you. Definitely. In terms of the rig in Jordan, we don't expect any material impact from that, given it's only one rig out of effectively now kind of 90 rigs on the onshore side or 92 rigs domestic and 100 rigs overall. Hence, the continued growth of our business, both on the drilling and the OFS, will be able to fully offset that. You'll be able to see in Q4 in which there won't be a contribution from Jordan. That will be fully absorbed by the gradual and normal growth of the business. No downside and no negative impact from that. When it comes to the positive impact on net income, that's not on the EBITDA. Part of that is coming from the record cash flow conversion we've had, where we continue to have more than 100% operating cash flow to EBITDA to operating cash flow conversion and more than 100% net income to free cash flow, as basically we're able to collect not only in real time, but also reduce our historical working capital and receivables with the clients and continue to be at an all-time low working capital of around 7%. Obviously, we expect that over time to potentially, again, gradually ramp up. For now, basically, we're able to have that benefit of that record cash flow and hence reducing the interest expense by, again, bringing our net debt/EBITDA down to 0.8 times. We also have the partial benefit of some of the rates coming down, as effectively we operate on a floating rate. That will be amplified going forward, again, as the refinancing we've just completed in October also took place at SOFR plus 75 basis points, which is the lowest level of financing ever for us and for any ADNOC group company as well. In terms of the 300 wells, what we would suggest is a gradual ramp-up. 2026, you already have the specific guidance for that in terms of the $5 billion and for the unconventional being stable from 2025 to 2026. I think what we would suggest post that is running different scenarios and different speeds of that ramp-up. That ramp-up will not be linear, right, because effectively ADNOC is always going to be going through intermediate increases in any capacity that they target. We would recommend post-2026 running different scenarios with different timeline of that gradual increase, but in a nonlinear fashion and more of a back-ended fashion. Understood. Very clear. Thank you, Youssef. Thank you. You're welcome. The next question today comes from the line of Abhishek Kumar. Please go ahead. Your line is now open. Thank you. Thank you very much. I just want to spend a little bit of time on the next year revenue guidance of $5 billion. You gave a very detailed response earlier in the call. If I look at various moving parts, we have the acquisition in Oman and Kuwait, which is going to add revenue. Also, the two jackups, fully impact and island rigs, etc., which is another $100 million, $150 million. In OFS, we are also moving from 59 rigs to 69 rigs on the IDS part. All of this put together and assuming the rest of the things remaining constant, you get a level of $5.3 billion, $5 billion, I mean, thereabout in terms of revenue. I just wanted to understand the impact of some of the land rigs that you said will be retired or repurposed. Is the impact of them going to be of this magnitude, or how should we think about that in terms of the impact? Yeah. Perfect. I think if you start from taking the kind of the mid-range of the revenue of this year of $4.8 billion, then you add to it the regional expansion. The current kind of bundle we have on the regional expansion is $125 million of revenue for a full year. If you assume kind of nine months out of that, you're looking at just under, depending on deal closing timeline, you're looking at just kind of $100 million, just under that. Let's say going to around $4.9 billion. You then, as you said, have the full year impact of kind of the jackups and some of the rigs that were not operating for the whole year. That would add another $100 million. That would take you to $5 billion of revenue. On top of that $5 billion, you would then add the OFS growth. The OFS growth, obviously, again, because these 11 additional ones will be added gradually over the course of the year. Similarly, for the island, the three island rigs, where you will only have a partial impact because they will come gradually over the year. For example, for the island rigs, we expect them to come one like almost kind of every, so like in Q2, Q3, Q4. Effectively, what you end up really operating is as if you've had one rig for kind of six months, one rig for three months, and one rig just at the end of the year. As if you've really added one rig. You're looking for the island rigs about $25 million. You go to kind of $5 billion with $25 million extra, plus with the OFS, and again, because it's only a partial impact, around $50 million. You end up with around $5 billion and $75 million. That's why effectively the impact of the land rigs, kind of as you said, some of the repurposing we've done partially offsets that addition above the $5 billion. That's how we come back to around the $5 billion. Obviously, the impact is not massive, but kind of in that kind of $75 million range that we would have basically been able to cross the $5 billion by, that kind of brings us back down closer to the $5 billion level. Okay. In that case, we're assuming that there would not be an increase in unconventional in 2026 because I think more than $900 million worth of work is outstanding. We are assuming $600 million of that would happen in 2026, and $300 million plus would spill over to 2027. Correct. Correct. Basically, the idea behind that is if you look at the schedule so far, obviously, on the drilling side, we are significantly ahead of plan. We've now effectively drilled more than 80 wells in effectively within the first less than 15 months of the program. From a delivery perspective, we're significantly ahead of the three-year original program that we've had. However, what you will see is on the fracking side, we've fracked completely just above 30 out of that. That's effectively a function of the client ADNOC Onshore securing the infrastructure that's required in terms of the water, the sand, etc., to allow us to complete the completion of the fracking. That's why when we do the budgeting, we always kind of put fully the drilling component, which is fully within our control, and we're able with the efficiencies to be always ahead of plan. You always have the sequential part or the kind of phased part around the fracking coming in as the client becomes ready with the infrastructure. By the end of next year, 2026, we would have definitely completed the entire program from a drilling perspective. We're kind of completely ready to be able to do that. It's the phasing of that fracking completion that basically creates some of that phasing into 2027. Okay. That's very clear. Maybe one more on the unconventional second phase. We have talked about them starting and contributing from 2027 onwards, gradual phasing with 300 wells plus potential ultimately. I just wanted to understand how much of this would be directed towards oil, how much of that would be directed towards gas, and in terms of revenue potential between oil and gas, how that stacks up. I think from an ADNOC perspective, they have not disclosed a split, and obviously, you will see that ADNOC overall has not disclosed anything on the oil beyond the 2027 timeframe, which is the 5 million barrels per day. However, you will see that, for example, on the conventional side, they did kind of indicate that we already have three rigs contracted to come in 2027 and 2028, and we have now the additional potential island drilling in 2029 and 2023. You will see that there is kind of a directional guidance towards that continued growth and deployment of additional drilling activity. From a numerical perspective, ADNOC is not officially communicating beyond the 5 million barrels per day by 2027. In terms of when it comes to the revenue for us, on a gas well, on a full lump sum, we expect kind of a long-term sustainable number to be around $10 million per well and on the oil to be around $8 million per well. Hence, overall, to be on the more conservative side, regardless of the split between the oil and the gas, it may be more conservative over time to trend that towards the $8 million. Upfront, it's more gas-weighted, so you would be able to start with the $10 million, but over time, to be more conservative, regardless of the split, you can trend it towards the $8 million. Okay. Thank you. That's very, very clear. I'll hand it back. Thank you. Thank you. The next question today comes from the line of Mick Pickup from Barclays. Please go ahead. Your line is now open. Good evening, everyone. It's Mick here from Barclays. A couple of questions, if I may. Just looking at the oilfield services, you saw a step down in Unconventionals that you mentioned, but you saw a very sharp jump up in revenues. It seems excessive, that jump up relative to 2Q. Can you just tell what's driven that, given that guidance implies we probably step down a little bit in 4Q as well? Definitely. I think if you look at the OFS, it's two components. There is basically kind of the two-thirds of it is the integrated drilling services side. For that, we have a very clear guidance because we have a very clear ramp-up of the schedule. For example, how we've gone from 57 to 59 IDS, and then we also have the plan to go to 70. The other one-third, which you kind of see sometimes more of these jumps, is on the discrete services. This is effectively not necessarily that a specific rig is allocated to ADNOC Drilling. This is basically the client has master contracts for different services, and under these different services, they're able to call some of these OFS basically within kind of short order and able to ramp up the level of activity depending on what they need. What we have been generally doing is ramping up these discrete services where currently we have 53 other rigs where, at any point in time in the quarter, effectively ADNOC is having additional services come from us. This is part of our overall strategy where the idea is to be almost on half of the fleet by end of next year on the IDS side and be very close to the remaining half on the discrete services and then look to ramp up the integrated part over time. We expect to see continued strong performance into Q4. That's why you've seen we've ramped up the guidance for the OFS into the $1.3 to $1.4 billion revenue. Also, as a result of that, as the OFS business is gaining more scale, we also see the 23% conventional OFS margin, which has already been achieved in Q3, as now the new floor for where we expect the margin to be going forward for the conventional. That's why we've also upgraded the guidance for that. I think that's a strong segment that we expect to continue to be strong into Q4 and into next year. Okay. Can I just ask on the extended maintenance in the quarter? Clearly, not something you plan for. Can you just tell us what went wrong and why it's not going to happen again in the future? Yes. I think this more has to do with the phasing of when the client decides to choose some of their maintenance activities depending on their well sequencing. Basically, you have, first of all, our forecast of the maintenance overall, where let's say we forecast that every five to six years, we basically have our major maintenance. Within that, we have our periodic maintenance, etc. Now, when the client effectively is in the process of going from one well program to another well program, is in the process of moving the rigs, they can decide to alter when exactly they want to have the maintenance piece, etc., in order to fit better with the overall program and optimize how they use the rigs overall to make sure that there is no idle time or no standby time for the rigs at this point. Later on, make sure that the rig is not forced to move into maintenance when effectively they need it to be actively deployed in the rig. All of this is part of a phasing by the client. That's why it cannot be repeated because it's not a question of, okay, it's a question of you do this maintenance every a certain amount of time. By definition, by kind of pulling it forward, it's the other way around. You actually end up optimizing maintenance versus what you expected later on. It's a net zero over an extended period of time by definition. The higher it is now, it actually has to be taken out of a time later on. Okay. Perfect. Thank you. That's very clear. Thank you. The next question today comes from the line of Leo Curry from UBS. Please go ahead. Your line is now open. Hi, there. Thanks for the color on the acquisition of the rigs. Just a quick one on the ones you're looking to repurpose or sell. What's kind of the rationale there between how you'll decide between which ones to repurpose, which ones to sell? Can you give us any more indication of what kind of number they would sell for? Is there any reason that CapEx might have been slightly higher than we were expecting? Is this just phasing, or can you point to any specific projects? Thank you. Definitely. Starting with the second point on the CapEx, I think compared to where we started the year at the beginning of the year, we've got awarded the three additional island rigs to come in 2027 and 2028. Our original CapEx guidance was based on the three rigs that were already being built to arrive in 2026, and these are exactly in line with expectation. What happened then is we got awarded three additional island rigs to come in 2027 and 2028, for which effectively we've started already building these rigs. Hence, we've had an additional CapEx accrual. Similarly, when we started the year from an IDS perspective, we were expecting kind of in the medium term to be at around the 60 rigs. As we now effectively ramp up to the 70 rigs, we're ramping up the amount of effectively oilfield service equipment we are ordering. This additional kind of growth for the business has resulted in this additional CapEx for it to kind of be able to come in. That's why that's kind of where you've seen the additional CapEx coming in. In terms of your first question on how we would make the decision on the repurposing versus that, it would be a question of the return on the incremental CapEx, any incremental CapEx being required for the repurposing and the time period that's required for the client to shift the activity. If we see that that effectively incremental CapEx we can be returned accretive on relative to our thresholds, which is the 25% return on capital employed and 36% return on equity, then we will seek the repurposing. If not, like what we have done with one jackup, where we've basically divested the jackup for it to be converted into a production platform by another entity. For us, these alternative activities, whether production platforms on the offshore side or whether to support some of the workover and surface and water operations on the onshore, if it is accretive to the returns of the core business, then we would conduct this in-house. If it's not, then effectively we would be divesting this, and then other third parties can then use that for the purpose of these conversions. Generally, the residual value of the rigs is in the after such a period of 40 to 45 years, is in the single-digit million dollars, more towards higher single-digit if it's on the offshore side and more towards kind of the lower single-digit if it's on the onshore side. Thank you. Thank you. Our next question today comes from the line of Aakarsh Tomar from SICO. Please go ahead. Your line is now open. Hi. Thank you for the opportunity to ask the question, and congratulations on a great set of results. This is Aakarsh Tomar from SICO Bahrain. My first question is on your number of rigs. You had 142 rigs by the end of last year, and now if I exclude SLB, it's 140. One rig you mentioned in Jordan, can you tell me what's the other rig? Like have you divested it or any other reason for that? The rigs that are converted from onshore to offshore, how does that change your revenues and profitability from these rigs? Because as I understand, the contractual framework is to have 11% to 13% IRR on offshores and 10% to 12% on onshores. These two, please. Absolutely. I think on the first point, the other one was just a jackup which you were discussing, which is basically the old one of the very old jackups that we've had that reached that 45 to 50 years old, and hence, we've divested for it to be converted into a production platform. That's kind of the other rig. Obviously, that would be more than offset going forward by the six additional offshore rigs coming in, and then potentially additionally in 2029, 2030, so the offshore segment will continue to grow and will not be impacted by that divestment. Similarly to the onshore segment that from a Q3, Q4 perspective is able to offset that Jordan piece. When it comes to the onshore to offshore conversion, what basically happens is only any incremental CapEx that's required as part of the conversion, that's what gets taken into account because already these rigs, even when they were on the onshore side, they were within that IRR range of that 11% to 12% piece, and hence, they're already in line with what the minimum under the offshore would be. It's basically only to the extent that any incremental CapEx that we incur as part of these conversions that this gets compensated. Otherwise, effectively, these rigs continue at the base rate is the same, and then any additional reimbursements and returns on any incremental CapEx. Thank you very much, Youssef. Just one more follow-up if I can ask. The number of the rigs that you mentioned in Abu Dhabi for repurposing that you said for next year, can you give us a rough idea of how many rigs these would be? Are these like low single-digit or any other number that you can give? It's roughly expected to be around high single-digit. It's obviously subject to final requirements by the client and what they decide to do, but the expectation would be around high single-digit. When you repurpose them, they would be like workover rigs going forward from 2027? Correct. Correct. They can be workover. They can be water to kind of support on water wells or kind of water injections and treatments. They can be to support some of the surface operations. In general, to your point, it's basically a lighter operation. Hence, there would be kind of an impact in terms of kind of a potentially partially kind of reduced revenue from them. Again, that would be kind of more than offset by the land expansion regionally. Hence, overall, the land segment will continue to grow with its regional operation. That's very helpful. Thank you so much, and all the best for the next quarter. Thank you. The next question today comes from the line of Oliver Connor from CITI. Please go ahead. Your line is now open. Hi. Thank you for taking my question, and congratulations again on 3Q results. I guess one for Youssef. If you think of the year to date, you've been very successful on your guidance upgrade as the year's progressed. Looking ahead into 2026, you've obviously outlined some broad sort of financial framework expectations. Could you sort of point to areas where you think maybe there's scope for more improvement, more efficiency, or quicker sort of activity levels through the year for us to sort of think about for next year? Thank you. Thanks, Oliver. Yes. One would be M&A closing. To the extent we're able, currently we have planned for end of Q1 for the SLB deal. To the extent we're doing any other deals, these would close later than that date. To the extent we're able to bring these forward, this can be one of the potential upsides. Another potential upside can be, from an infrastructure perspective on the unconventional, ADNOC Onshore is able to operate at the same speed we are on the drilling side. Hence, we're able to bring some of the completions that would otherwise go into 2027 earlier once these wells are drilled. We're able to bring in some of the $300 million revenue remaining in the contract into next year as well. That would present another upside. The third one would be if the oilfield services business is able to ramp up to the 70 rigs, which is currently relatively uniform throughout the year. Being able to bring some of this forward can be a potential upside as well. I'd say these are probably the three main upsides we can potentially see next year throughout the year. Thank you. Very clear. Thank you. Our final question today comes from the line of Ilber Kazif from HSBC. Please go ahead. Your line is now open. Thank you very much. Hi. When you talk about a free cash flow surplus with respect to the potential discretionary dividends, do you account for the M&A cash out, please? In other words, does your $1.5 billion free cash flow guidance for this year suggest a room for a higher dividend already this year, or rather not? Thank you. The $1.5 billion does not include the M&A. Generally, the way we look at it from a waterfall perspective, we start with our base guaranteed dividend. Then we go into our in-country domestic investment where we have the long-term commitments. Next, we go into discretionary dividend and dividend floor upgrades like what we've done this year, but taking a kind of multi-year view on what that sustainable dividend would be, taking into account the second piece, which is the increased domestic growth. The last piece is the regional expansion. For example, if we decide this year to increase the dividend to $1 billion as opposed to a higher number, it's not necessarily because we're trying to free cash flow to use it for the regional expansion, but it's more that we're trying to maintain flexibility and sustainability, taking into account that there will be more domestic investments over time. The excess free cash flow, having taken that view specifically for this year, is then redeployed into the regional expansion. It is not necessarily that we are prioritizing the region above the dividends. The dividends are the priority, but to the extent that the dividend is not increasing anyway because we are still waiting on that multi-year view to take, in the meantime, some of this cash can be deployed in that regional expansion. The dividend upside is not limited in any way. We do have debt capacity to be able, and our available debt capacity is significantly higher than our M&A ambition because our M&A remains very disciplined and targeted. If effectively the view is the dividend can be increased further in a sustainable way in conjunction with the domestic investment, then we'll be able to go ahead with that. Even if there's any regional M&A, that can continue to be funded with debt. Thank you so much. Thank you. This concludes today's question and answer session and concludes today's call. Thank you all for your participation. You may now disconnect your lines.