ADNOC Drilling Company P.J.S.C. (ADNOCDRILL) Earnings Call Transcript & Summary

Hello, and welcome to today's ADNOC Drilling Q3 2025 Earnings Call. My name is Bailey, and I will be the operator for today. [Operator Instructions]. I'd now like to pass the conference over to Massimiliano Cominelli, Vice President of Investor Relations to begin. Sir, 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, Abdulla Al Messabi; and our Chief Financial Officer, Youssef El-Sayed 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. Please 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 3 weeks ago, we had the first-ever ADNOC Investor Majlis, and thanks for everyone who have joined us. And 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 entered today a call with a position of strength. In the third quarter of 2025, we delivered a record revenue well over $1.2 billion. EBITDA, $560 million; net profit, $368 million; and last not least, the free cash flow of $477. These results allowed us really to upgrade once again our full year guidance. On top of this, our Board has approved a $250 million, the dividend distribution for the third quarter, which is aligned very much with our announced dividend policy that is raising the floor of 2025 to $1 billion with a minimum 5% annual growth all the way to 2030. Looking ahead, our priorities are very, very focused, sustaining our business growth; invest where retains are the highest; last 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 9 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 8 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 additional discrete services and the unconventional program, which started in the second half of last year. Unconventional continued the strong year-on-year acceleration in the 9-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 unconventional 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 6 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 Enersol ADNOC Investor Majlis on October 8, we have proposed an upgrade to our progressive dividend policy, 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 1.5 fils per share and yesterday approved the third quarter dividend of $250 million or approximately 5.7 fils 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 accretive avenues, as our CEO commented, our strategic priority. 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 unconvention's 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 clients' final investment decision as we continue to unlock new growth frontiers, targeting more than 300 wells annually with 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 SLP's land rig operation in Oman and Kuwait. This transaction has marked our first regional expansion of scale and includes 8 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 4x EBIT to 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 4 acquisitions already completed. As a reminder, since inception, Enersol has deployed approximately $800 million across 4 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 largest fleet, we closed the quarter with a pro forma fleet of 148 rigs, which includes the 8 land rigs in Oman and Kuwait tied to our SMB partnership pending customary approvals. This also includes the 2 jack-up 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 Hail and Ghasha. As a result, we ended the quarter with 100 land rigs pro forma, including Oman and Kuwait and 48 offshore rigs. Overall, own 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 the 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 unconvention, 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 unconvention. In the third quarter, EBITDA benefited from a onetime contribution of $23 million from the sale of an onshore rig, which was offset by higher maintenance sequentially. Excluding these 2 factors, EBITDA would have been in line with Q2 as anticipated in July earnings call. 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 last 12 months EBITDA at 0.8x, below our long-term leverage ceiling of 2x. Cash CapEx for the quarter were $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 reinforced 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 rig. 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 2 new jack-ups, which entered the fleet at the end of 2024 and started operations at the end of Q2 fully contributed to revenue in Q3. 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-risky services, supported by the unconventional program. Overall, unconventional contributed $158 million in the quarter, $120 million in 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 heavy 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 unconventional 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's Investor Majlis on October 8, our Board proposed an upgrade to the progressive dividend policy, 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 6 years of visibility. At the same meeting, the Board approved to distribute a $66 million or 1.5 fils per share special dividend and the third and fourth quarter dividend payment of at least $250 million, around 5.7 fils per share. The third quarter dividend of $250 million around 5.7 fils per share was approved yesterday by the Board of Directors and is 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 in its discretion may approve additional dividends over and above the progressive dividend flow, 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 9 months, the company upgrades its full year 2025 guidance, demonstrating its resilient and defensive growth. The lines upgraded are [indiscernible]. We have upsized the total revenue guidance and now expect $4.75 billion to $4.85 billion. The upgrade is supported by stronger OFS, while the revenue range is raised to $1.3 billion to $1.4 billion, driven by IDS coverage, discrete services and unconventional. Net profit is now expected at $1.4 billion to $1.45 billion. The range reflects the 9-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. We reaffirm free cash flow at $1.4 billion to $1.6 billion, with CapEx now at $0.45 billion to $0.55 billion and the leverage target below 2x EBITDA and the 2025 dividend floor of $1.0 billion. Looking into next year, 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 jack-ups 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, prequalification efforts and oilfield services will come with pre-investment in business ramp-up and operational expenses. In other words, for next year, margin 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 have 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. And within our fleet, we expect IDS rigs to be 70 by the end of 2026. Moving on to the final slide. This slide wraps up all the key messages. Record results, upgraded dividend policy with a special dividend of $66 million and the Q3 dividend of $50 million, totaling 7.2 fils per share returned to investors since the Majlis, continued development on the growth front while delivering on our sustainability agenda. And with this, I thank you all for joining us today. I'll hand over to the operator to start the Q&A.

[Operator Instructions] We'll start with our first question today. It comes from the line of Faisal Al Azmeh from Goldman Sachs.

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 EBITDA contribution? What should we expect in the medium term and in the long term? And how much associated CapEx should we kind of think about when that ties into these long-term plans? And then just maybe on the OFS side, you've mentioned as well on the unconventional bit that margins can range between 10% to 20% in 2030, depending on how you source equipment. So maybe 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? And then finally, you've talked a bit about the $1 billion dividend. 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? And what would invite you to pay a special dividend?

Perfect. Thank you, Faisal. So I think if we start with the first question. So in terms of the regional expansion, so 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. So for example, if you look at the Schlumberger 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 8 rigs we acquired were 2,000 and 3,000 horsepower, which on kind of a partially depreciated yet still relatively new rigs, which is our strategy is to be with these acquired rigs somewhere around kind of the 5-year-old rigs. So there's 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. So 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 may be closer to $10 million per rig in terms of CapEx. In terms of the EBITDA contribution, again, if we're looking at some of the higher horsepower rigs like what we have done with Schlumberger, so we are looking on 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 kind of $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. So 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, then 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 '27. So you should have kind of a growth from '26 to '27 coming from that incremental level of activity. Now in 2026, specifically, you will see that our guidance for the EBITDA was still that the overall EBITDA of the business would remain at kind of closer to the $2.2 billion EBITDA level that we will achieve this year. And this is basically as a result of even though we have the additional EBITDA coming in from the land rigs outside Oman and Kuwait starting to come in post regulatory approvals. One is the uncertainty around when exactly these regulatory approvals kick in. And second, 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 kind of in potentially a lighter room. And hence, some of that kind of repurposing may take basically a period of time and hence, again, may not have a full year of operation in 2026 for these older rigs. And hence, some of that may offset some of the expansion we're seeing in 2026 in the region, again, with a potential recovery from '27 onwards. So that's why overall, we've kind of kept that. So 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 '26. But from '27 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. So basically, in Phase 1, what effectively the situation was because the contract was originally a 3-year contract, we were supporting effectively the 7 rigs, which we were working on the unconventional and the 2 frac fleets that we had deployed on a partial owned and rental model. So 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 frac fleets. And that's what resulted in our EBITDA and net income being very close to each other at around kind of 9% net income and kind of 10% to 11% EBITDA. As we effectively move forward into the unconventional Phase 2 with the potential to reach the 300-plus wells, obviously that will be a substantive enough program for us to be able to move effectively into a largely kind of owned fleet of rigs and frac over time. And 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. Now that will be a journey over time as the number of wells ramps up, but that effectively will be the journey that we would go through. Overall, from a net income perspective and from a returns perspective does not necessarily fundamentally change the picture in terms of our 9%, 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 25% return on capital employed and 36% return on equity, but that's effectively the kind of the EBITDA journey that you will potentially kind of go through. In terms of dividends, yes, we are very clear that the amount we have now is a floor. Obviously, the same way previously, when we talked about the $867 million in 2025, that was always very clearly a floor, and we do the upgrade from the $867 million to the $1 billion. So we ended up with a 17% upside to our previous floor. Now when it comes to 2026, we have -- we're going to -- based on all of the growth that's now coming in, we expect to have higher CapEx in '26 than in '25 because effectively, 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, we already ramped up to 59, so now going from 59 to 70, the potential additional island activity in '29, 2030 and the unconventional ramp-up. So all of that means that in addition of the $250 million maintenance, the $200 million of the island rig, there will be additional CapEx levels that will take us above kind of the $550 million level that we currently have for 2025 and can potentially take us to additional CapEx. And obviously, 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. But we know for a fact it will be higher than the $550 million for this year. And 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 expansion 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 dividend for next year. But what we know is that 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. And hence, by that point in time, we'll be back into kind of the situation we're in this year where the free cash flow was significantly higher than the $867 million and based on that, the upside to $1 billion. So again, a very long way of saying, yes, it is only a floor. There's a potential upside. In 2026, we expect that to be more of a growth year from a CapEx perspective. So that upside to the floor may not necessarily materialize in 2026. But by 2027, we definitely see how there is significant upside to that. Obviously, all of this is still not touching on the balance sheet capacity off the back of that record cash flow in the first 9 months. We're now also down to 0.8x net debt to EBITDA, which continues to be well below the 2x kind of soft [indiscernible] that we have, which again creates significant balance sheet capacity for both growth and dividends. But 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. Now in terms of utilizing the balance sheet, that always goes back to kind of 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. And I think you can clearly see that with the sentiment coming from the group leadership in the Majlis with APAC coming up next week. You can clearly see that from an ADNOC and from a Board perspective, we do see that kind of continued growth and hence, the ability to gradually deploy that balance sheet capacity into growth and dividends over time.

Our next question today comes from Afaq Nathani from International Securities.

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 a little to no change in EBITDA. So just could you highlight where the higher-than-expected numbers are coming from? What's driving that? And thirdly, on the 300 wells annual target for unconventional program, which was announced at the Majlis, how exactly should we look at this in terms of incorporated within our estimates and what kind of time line do you see around these targets to be achieved?

Definitely. So in terms of the rig in Jordan, we don't expect any material impact from that given it's only 1 rig out of effectively now kind of 90 rigs on the onshore side or 90 rigs domestic and 100 rigs overall. And hence, the kind of the continued growth of our business, both on the drilling and OFS will be able to kind of fully offset that. And 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. So 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 kind of 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 lead time but also kind of 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. But for now, basically, we're able to kind of have that benefit of that kind of record cash flow and hence, kind of reducing the interest expense by again bringing our kind of net debt to EBITDA down to 0.8x. We also have kind of the partial benefit of kind of some of the rates coming down as effectively we operate on a floating rate. And that will be amplified going forward again, as we also -- the refinancing we just completed in October also took place kind of at SOFR plus 75 basis points, which is kind of the lowest kind of level of financing ever for us and for any ADNOC Group company as well. In terms of the kind of the 300 wells, what kind of -- what we would suggest is kind of a gradual ramp-up 2026, you already kind of -- we 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 kind of post that is running different scenarios and kind of different speeds of that ramp-up. That ramp-up will not be linear, right? Because effectively, ADNOC could always be going through intermediate kind of increases in any capacity that they target. So we would kind of recommend kind of post 2026, running different scenarios with different kind of time line of that gradual increase, but in a kind of a nonlinear fashion and kind of more of a back-ended fashion.

The next question today comes from the line of Abhishek Kumar.

I just want to spend a 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, so we have the acquisition in Oman and Kuwait, which is going to add revenue, also the 2 jack-ups, full year impact and hy land rigs, et cetera, which is another $100 million, $150 million. In OFS also, we are moving from 59 rigs to 69 rigs on IDS part. All of this put together and assuming rest of the things remaining constant, you get a level of 5.3 -- I mean, thereabout in terms of revenue. So the impact of -- so 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, yes?

Perfect. So I think if you start from taking kind of the midrange 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. So if you assume kind of 9 months out of that, you're looking at just under -- depending on deal closing time line, you're looking at just kind of $100 million just under that. So let's say, going to around $4.9 billion. You then, as you said, you have the full year impact of kind of the jack-ups and some of the rigs that were not operating for the whole year. So that would add another $100 million. So 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 3 island rigs where you will only have a partial impact because they will come gradually over the years. So for example, for the island rigs, we expect them to come one like almost kind of every year, so like in Q2, Q3, Q4. So effectively, what you end up really operating is as if you've had 1 rig for kind of 6 months, 1 rig for 3 months and 1 rig just at the end of the year. So as if you really added 1 rig, so you're [indiscernible] for the island rigs about $25 million. So 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. So you end up with around $5 billion and $75 million. And 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, and that's how we come back to around the $5 billion. So obviously, the impact is not massive, but kind of in that kind of $75 million, $100 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. And so in that case, we're assuming that there would not be any increase in unconventional in 2026 because I think more than $900 million worth of work is outstanding. So we are assuming $600 million of that would happen in '26 and $300 million-plus would spill over to 2027.

Correct. Correct. And 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 effectively within the first less than 15 months of the program. So from a delivery perspective, we're significantly ahead of the 3-year original program that we've had. However, what you will see is on the fracking side, we completed just above 30 out of that. And that's effectively a function of the client ADNOC onshore, securing the infrastructure that's required in terms of the water, the sand, et cetera, to allow us to complete the completion of the frac. And 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. But then 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. So by the end of next year '26, we would have definitely completed the entire program from a drilling perspective. We're completely ready to be able to do that. It's the phasing of that [fracking] completion that basically creates some of that basically phasing into 2027.

Okay. That's very clear. And maybe one more on the unconventional second phase. So we have talked about starting and contributing from 2027 onwards, gradual phasing with 300 wells plus potential ultimately. And so just wanted to understand, I mean, 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?

So 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 time frame, which is the 5 million barrels per day. However, you will see that, obviously, for example, on the conventional side though they did kind of indicate that we already have 3 rigs contracted to come in '27 and '28. And we have now the additional potential island drilling in '29 and 2030. So you will see that there is kind of a directional guidance towards that continued growth and deployment of additional drilling activity. But from a numerical perspective, ADNOC is not kind of officially communicating beyond the 5 million barrels per day by 2027. In terms of when it comes to the revenue for us, so on a gas well on a full lump sum, we expect kind of on a long-term sustainable number to be around $10 million per well and on the oil to be around $8 million per well. And hence, overall to be on a 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 cannot 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.

The next question today comes from the line of Mick Pickup from Barclays.

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 is relative to 2Q. So can you just tell what's driven that given the guidance implies we probably step down a little bit in 4Q as well?

Definitely. So I think if you look at the OFS, it's 2 components. There's basically kind of the 2/3 of it is the integrated drilling services side. And for that, we have very clear guidance because we have a very clear ramp-up of the schedule. So for example, how we've gone from 57 to 59 IDS, and then we also have the plan to go to 70. The other 1/3, which you kind of see sometimes some of these -- more of these jumps is on the discrete services. So 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. And what we have been kind of generally doing is ramping up the 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. And again, 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. And we expect to see kind of continued strong performance into Q4. And that's why you've seen kind of we've ramped up the guidance for the OFS into the $1.3 billion to $1.4 billion revenue. And 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 kind of the margin to be going forward for the conventional and that's why we've also upgraded the guidance for that. So I think that's a strong segment that we expect to continue to be strong into Q4 and into next year.

Okay. And 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 is more has to do with the phasing of when the client decides to choose some of their maintenance activities depending on their well sequencing. So basically, you have kind of -- first of all, you have our forecast of the maintenance overall. Well, let's say, we forecast that every 5 to 6 years, we basically have our major maintenance. Within that, we have our periodic maintenance, et cetera. 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, et cetera, 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 and then 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. So all of this is part of a phasing by the client. And that's why it's not -- 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. So 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. So it's a net zero over an extended period of time by definition. So the higher it is now, that actually have to be taken out of a time later on.

The next question today comes from the line of [indiscernible] from UBS.

Thanks for the color on the acquisition of the rigs. Just a quick one on the ones you're looking to repurpose/sell. What's kind of the rationale there between how you'll decide between which ones to repurpose, which ones to sell? And can you give us any more indication of what kind of number they would sell for? And just the second one, 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?

Definitely. So 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 3 additional land rigs to come in '27 and '28. So our original CapEx guidance was based on the 3 rigs that are already being built to arrive in 2026, and these are exactly in line with expectation. What happened then is we got awarded 3 additional island rigs to come in '27 and '28 for which effectively we've started already building these rigs, and 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 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. So this additional kind of growth for the business has resulted in this additional CapEx for it to kind of be able to come in. And 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 will 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. So if we see that effectively incremental CapEx, we can be returned accretive on -- relative to our threshold, which is a 25% return on capital employed and 36% return on equity, then we will seek the repurposing. If not like what we have done kind of with one jack-up where we basically divested the jack-up for it to be converted into a production platform by another entity. So for us, it's 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'll 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.

Our next question today comes from the line of Aakarsh Tomar from SICO.

Congratulations on a great set of results. This is Aakarsh Tomar from SICO Bahrain. So my first question is on your number of rigs. So you had 142 rigs by the end of last year and now if I exclude SLB, it's 140. So 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? And secondly, the rigs that are converted from onshore to offshore. So 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. So these 2, please.

Absolutely. So I think on the first point, the other one was just the jack-up, which you were discussing, which is basically the old -- one of the very old jack-ups 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. So that's kind of the other rig. Obviously, that will be kind of more than offset going forward by the 6 additional offshore rigs coming in and then potentially additionally in '29, 2030. So the Offshore segment will continue to grow and will not be impacted by that divestment, similarly to the Onshore segment that kind of from a Q3, Q4 perspective is able to kind of offset that Jordan piece. When it comes to the onshore to offshore conversion, what basically happens is to any -- 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 kind of IRR range of that 11% to 12% piece and hence, already in line with what the minimum under the offshore would be. So it's basically only to the extent of any incremental CapEx that we incur as part of these conversions that this kind of gets compensated. Otherwise, effectively, these rigs continue kind of at the base rate is the same and then any additional reimbursements and returns on any incremental CapEx.

Just one more follow-up, if I can ask. The number of 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? Is it like low single digit or any other number that you can give?

Yes. It's roughly expected to be around high single digit, obviously subject to final requirements by the client and what they decide to do, but the expectation would be around high single digit.

And 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 injection and treatment. They can be support some of the surface operations. So in general, to your point, it's basically a lighter operation. And hence, there would be kind of an impact in terms of kind of a potentially partially kind of reduced revenue from them. But again, that would be kind of more than offset by the land expansion regionally. And hence, overall, the land segment will continue to grow with its regional operation.

The next question today comes from the line of Oliver Connor from Citi.

Congratulations again on the 3Q results. I guess one for Youssef. I mean, if you think of the year-to-date, I mean, you've been very successful on your guidance upgrade as the year has progressed. I mean, looking ahead into 2026, you've obviously outlined some broad sort of financial framework expectations. But 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?

Thanks, Oliver. Yes. So one would be M&A closing. So to the extent we're able -- so currently, we have kind of planned for end of Q1 for the SLDC deal. And then to the extent we're kind of doing any other deal, then these would close kind of later than that date. So the extent we're able to bring these forward, then this can be one of the potential upside. Another potential upside can be to the extent that basically the kind of from an infrastructure perspective on the unconventional ADNOC is able to kind of operate at that same speed we are on the drilling side. And hence, we're able to bring some of the completions that will otherwise go into '27 earlier once these wells are drilled. So we're able to bring in some of the $300 million revenue remaining in the contract into next year as well, then that would present another upside. And the third one would be is if the OFS 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, then that can be a potential upside as well. So I'd say these are probably the 3 main upsides we can potentially see next year throughout the year.

Our final question today comes from the line of Ildar Khaziev from HSBC.

When you talk about free cash flow surplus with respect to the potential discretionary dividends, do you account for the M&A cash outlays? In other words, does your $1.5 billion free cash flow guidance for this year suggests a room for a higher dividend already this year or rather not?

The $1.5 billion does not include the M&A. And 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 investments where we have the long-term commitments. Then we go into towards discretionary dividend and dividend for upgrades like what we've done this year, but taking kind of a multiyear view on what that sustainable dividend would be, taking into account the second piece, which is the increased domestic growth. And then the last piece is the regional expansion. So 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 of that we're trying to maintain flexibility and sustainability, taking into account that there will be more domestic investments over time. And then the excess free cash flow having taken that view specifically for this year, we are then redeploying into the regional expansion. So it's not necessarily that we are prioritizing the region above the dividend. Dividend is the priority. But to the extent that the dividend is not increasing anyway because we are still waiting on that multiyear view to take, then in the meantime, some of this cash can be deployed in that regional expansion. So the dividend upside is not limited in any way. And also, 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. And hence, 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. And even if there's any regional M&A, that can be continued to be funded with debt.

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.