Hello everyone, and welcome to today's ADNOC Drilling third quarter 2026 earnings webcast and conference call. My name is Sam, and I will be the operator for this call. All participant lines are currently muted. At the end of the prepared remarks, there will be a Q&A session. If you would like to ask a question during the Q&A session, please dial into the call and press star followed by one on your telephone keypad. I would now like to hand you over to Max Cominelli, Vice President of Investor Relations to begin. Max, please go ahead.
Ladies and gentlemen, welcome to ADNOC Drilling's third quarter and nine months 2026 earnings webcast and conference call. My name is Max Cominelli, and I am the Vice President of Investor Relations at ADNOC Drilling. Before handing the floor over to our speakers, I would like to draw your attention to the disclaimer on the second slide. I encourage you to read it carefully. The text contains important information. We advise caution on the interpretation and limits of historical data and forward-looking statements.
I would like to remind you that this presentation and a recording of this call will be available on our website shortly after the end of the call. Today's presentation will be led by our Chief Executive Officer, Mr. Abdulla Al Messabi, our Chief Financial Officer, Mr. Youssef Salem, along with Sultan Al Mansoori, our SVP for Onshore, Adel Al Marzooqi, our SVP for Offshore, and Emri Zeineldin, our SVP for Oil Field Services. 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 afternoon, everyone, and I am really delighted to be with you today. Thanks for everyone for joining us. I would really love to start by recognizing our people. Their commitment, discipline, and focus on delivery remain at the heart of everything that we achieve. Together, we have delivered a record nine-month performance supported by safety and resilient operations, 99% domestic rig availability, and disciplined execution. Financially, we delivered the highest ever level of a nine-month revenue at $3.7 billion. EBITDA, $1.7 billion. Net profit, $1.1 billion, despite the regional environment over the last few months.
This strong performance reinforces our focus and the strength and the resilience of our business model. I am also particularly pleased with the board have exercised the discretionary element of our dividend policy, approving of additional $175 million on top of the base dividend. Together with our quarter three base dividend, this means $350 million, approximately $0.08 per share, will be distributed on the second half of November, taking expected total 2026 dividends to $1.225 billion, 22.5% higher year-on-year.
This reflects the strength of our business, our commitment to disciplined capital allocation, and growing shareholder returns, offering a unique blend for growth and distribution. We are also announcing today the next ambition phase of our growth journey through our Drill-to-Operate strategy. This strategy will allow us to capture more value across the full well cycle, building on our leadership in drilling, our growing Oil Field Services platform, technology, and regional expansion. We will discuss this strategy in more details later. Our focus remains clear. Safe execution, profitable growth, disciplined capital allocation, and growing shareholder returns. With that, I will hand over to our CFO to take you through the financials. Thank you.
Thank you, [inaudible], and a good day to all. We delivered record nine-month results and sequential growth across our key financial metrics in the third quarter. For the first nine months of 2026, revenue increased 2% year-on-year to $3.7 billion, supported primarily by the consolidation of our regional operations, the integration of new island rigs, and higher IDS activity, partially offset by the anticipated lower phasing of unconventional activity and the repurposing of certain rigs. EBITDA increased 2% to $1.7 billion, with a margin stable at 45%, while net profit increased 1% to $1.1 billion. Turning to the third quarter, revenue increased 1% sequentially to $1.2 billion, supported by higher Onshore and Offshore activity, partially offset by the anticipated lower unconventional activity and jack-up repurposing. EBITDA increased 4% to $579 million while net profit increased 2% to $366 million.
Year-on-year performance was impacted as expected by lower unconventional phasing and the repurposing of certain rigs. Turning to cash flow and balance sheet capacity, we generated $978 million of free cash flow, excluding M&A in the first nine months. On track with our $1.2 billion-$1.3 billion full year guidance, while leverage remains strong at just 1x. This financial strength supported the Board's decision to exercise the discretionary dividend and further enhance shareholder returns. I will now hand over to Sultan to walk you through Onshore operations.
Thank you, Youssef, and good afternoon, everyone. The Onshore business delivered another strong quarter with revenue increase 9% year-on-year to $557 million. This growth was driven by the consolidation of SLDC and MBPS, together with higher fuel escalation, partially offset by the repurposing of certain onshore rigs and lower unconventional activity. Sequentially, revenue increased 1%, supported by an additional month of MBPS consolidation, higher fuel escalation, and the reclassification of one rig from offshore to onshore, largely offset by lower rig move activity and lower unconventional revenue.
EBITDA increased 2% year-on-year and 7% sequentially to $259 million, with margin improving to 46%, supported by lower maintenance phasing and cost efficiency. Operationally, the Onshore segment drilled 177 wells during the quarter and maintained 99% domestic rig availability. At quarter end, the onshore fleet stood at 123 rigs, 93 rigs in Abu Dhabi, and 30 regional rigs. During the quarter, one of the repurposing land rigs commenced operational in Oman, demonstrating early synergies from our regional platform. With that, I will now hand over to Adel to cover offshore operations.
Thank you, Sultan, and good afternoon, everyone. Offshore delivered another quarter of solid growth, with revenue up 2% year-on-year to $372 million. The increase primarily reflected a full quarter contribution from the AI-enabled island rig added in June, partly offset by the repurposing of two jackup rigs and reclassification of one rig from offshore to onshore in Q3. Revenue rose 4% sequentially, driven by the new island rig for quarter contribution and favorable maintenance timing. EBITDA reached $247 million, up 3% year-on-year and 2% sequentially, with a strong 66% margin.
During the quarter, we drilled 45 wells, maintaining 99% domestic rig availability. At quarter end, the offshore fleet comprised 49 rigs, including 36 jackups and 13 island rigs. A second AI-enabled island rig joined the fleet in Q3 and is expected to make full quarter contribution in Q4. I will now hand over to Emri to cover Oil Field Services.
Thank you, Adel, and good afternoon. Oil Field Services continue to demonstrate the strength of our integrated model, delivering higher profitability despite the anticipated lower unconventional activity. Third quarter revenue was $318 million, primarily reflecting the anticipated lower phasing of unconventional activity and the OFS activity mix. Unconventional contributed $62 million of OFS revenue during the quarter. Importantly, EBITDA increased 9% year-on-year to $73 million, with margin expanding by six percentage points to 23%, supported by a higher margin activity mix and a $7 million contribution with Enersol and Turnwell.
Sequentially, revenue was broadly stable, while EBITDA trend reflected the activity mix. Our IDS rig count in Q3 increased to 62 from 59 in the same period of last year, and we delivered at least one discrete services across an additional 53 rigs, taking total Oil Field Services coverage to 115 rigs from the ADNOC Drilling own fleet. Integrated drilling services efficiency also continued to improve, reflecting the benefits of integration technology and disciplined execution. With that, I'll hand it back to Youssef. Thank you very much.
Thank you, Emri. I'm very pleased to confirm that the board has exercised the discretionary element of our dividend policy, reflecting confidence in our cash generation, balance sheet, and growth outlook. The board approved a third quarter-based dividend of $262.5 million, approximately six fils per share, together with an additional discretionary dividend of $175 million, approximately four fils per share. The discretionary dividend will be paid in two equal installments of $87.5 million. The first will be paid alongside the Q3 base dividend in the second half of November, and the second is expected in April 2027.
As a result, shareholders are now expected to receive $350 million, approximately eight fils per share in the second half of November. This increases our expected total 2026 dividend to $1.225 billion, approximately 28.1 fils per share, representing 22.5% growth year-on-year and well above the $1.05 billion guaranteed floor. The discretionary dividend is another step in our journey of progressively enhancing shareholder returns. After increasing dividends by 27% year-on-year to $1.2 billion in 2025, we are increasing them by a further 22.5% to $1.225 billion in 2026, well above the dividend floor in both years, demonstrating our capacity to deliver growing and sustainable cash returns to shareholders.
This meaningful acceleration in both years leads to total annual dividends increased by 55% in only two years, doubling from the IPO. For us as management team and for our board, proper capital allocation, including distributions, is top of mind. The significant dividend acceleration is a demonstration that shareholder return is central to how we look at our business and its future strategic evolution. Let's now turn to our guidance. Next slide, please.
Our strong performance through the first nine months gives us confidence in confirming and sharpening our full year 2026 guidance. We continue to expect full year revenue of around $5 billion, EBITDA of around $2.2 billion, and net profit of around $1.45 billion. Based on our nine-month performance, this implies expected fourth quarter revenue of $1.24-$1.25 billion, EBITDA of $575-$580 million, and net profit of approximately $365-$370 million. Within this assumption, if we look at the segments in Q4, we expect slightly lower contribution from Offshore revenue as the positive impact of the island rig that joined the fleet in Q3 will be more than offset by less favorable maintenance phasing in Q4 for that segment. The projected lower contribution from Offshore is expected to be slightly offset by the Onshore and OFS segment.
At segment level, we expect full year revenue of more than $2.1 billion from Onshore, over $1.4 billion from Offshore, and more than $1.4 billion from Oil Field Services. Cash CapEx excluding M&A is expected at around $0.6 billion, while free cash flow excluding M&A remains expected between $1.2-$1.3 billion. Looking beyond 2026, our growth remains supported by the continued scaling of OFS and IDS, regional expansion, and accelerating technology adoption. For 2027, we expect low to mid-single digit growth in revenue and a broadly stable EBITDA margin compared with the 2026 guidance sets. Please be mindful that EBITDA margin levels depend on, among others, the mix of our activity.
Net income is expected to remain stable year-on-year versus 2026, reflecting higher depreciation and financing costs. Maintenance CapEx is expected to be up to $0.3 billion per annum, with around $0.5 billion of gross CapEx expected in 2027. We also target a conservative long-term leverage range pre-M&A between one and two times net debt to EBITDA. More granular guidance for 2027 and beyond will be provided in due course as future business needs and financial contributions are further determined. I'll now hand over to our CEO for the strategic update.
I'm super excited to share with you in the next few minutes the next evolution of ADNOC Drilling, a journey that will keep us busy for the foreseeable future as we engineer and execute our next phase of growth. Since our IPO, we have grown our fleet, expanded Oil Field Services, entered new markets, and built a strong technology capability. Now we are taking the next ambitious step with our Drill-to-Operate strategy. We will build on these strengths to capture more value from every well, expanding across the well life cycle through the services, technology, and regional growth. This is an exciting next chapter for ADNOC Drilling, creating new avenues for growth and sustaining long-term shareholder value. Drill-to-Operate expands our opportunity across the full well life cycle.
We will build on our leadership in drilling and well construction by expanding into selected services across completion, artificial lift, production solutions, and advanced engineering. We will build these capabilities organically through partnership and targeted M&A wherever accretive, always with discipline retained and clear strategic fit. The ambition is simple: broaden our offering, provide more solutions to our client, and capture more value from every well. With that, I hand over to Youssef to take you through what does this mean in more details.
Thank you, [inaudible]. This strategy is built around three complementary growth engines, each reinforcing the other. First, drilling remains our resilient cash foundation, supported by predictable U.A.E. activity and disciplined regional expansion. In the long run, and according to current plans, we are targeting a U.A.E. and regional fleet of around 200 ± rigs . As you know, plans always evolve, and for this reason, we are positive about the future ahead. Building on that foundation, Oil Field Services is our integrated growth engine. We foresee an addressable U.A.E. market of around $3 billion in the long term for the services line we already offer.
Our ambition is to further grow our market share in this domain from around 50% today to potentially 60%+ in the long run. Beyond our existing offer, we see significant opportunities in new services, including other OFS and advanced engineering capabilities just introduced by our CEO. The additional addressable market is expected to have a potential between $4 billion- $5 billion in the long term. In these additional segments combined, we are currently targeting a share of around or above a quarter of it in the long term. Together, these three growth engines create one integrated platform, broadening our opportunity and allowing us to capture more value from every well.
Importantly, this strategic evolution is already in motion. Our partnership with Baker Hughes established the foundation for integrated drilling and OFS. Turnwell created our integrated unconventional platform. Enersol is expanding our technology capabilities, and SLB and MBPS have established our regional platform across Oman and Kuwait. We're not stopping here. We are working to announce new partnerships that leverage our existing capabilities and strengthen the execution of Drill-to-Operate. Together, these platforms and future partnerships will help us unlock new avenues of profitable growth and create additional long-term value for our shareholders. Next slide, please.
Finally, our capital allocation framework is disciplined and clear. First, we protect our growing dividend floor, which is $1.05 billion for 2026 and expected to grow by at least 5% annually until at least 2030. Importantly, we retain the flexibility to distribute additional discretionary dividends, as demonstrated this year by the increase in expected total dividends to $1.225 billion. Second, we reinvest in attractive domestic growth across drilling, OFS, and advanced engineering with domestic drilling investments targeting unlevered returns of 10%-13%. Third, we pursue international growth, partnerships, JVs, and M&A selectively, with a strong focus on returns and disciplined entry evaluations and strategic criteria.
In parallel, after funding attractive growth, excess cash can support further discretionary dividends to shareholders, as demonstrated by today's announcement. This framework leaves us positive upon strategic delivery in a future where the combination of profitable growth and distribution will continue to support attractive shareholder returns. To conclude, we delivered record nine months, resilient earnings, and strong operational execution, and we have confirmed and sharpened our full-year 2026 guidance. We are returning more cash to shareholders with a $350 million distribution expected in the second half of November, including the Q3 base dividend and the first discretionary dividend installment.
Record date for the first distribution is 5 November. At the same time, our fleet has grown to 172 rigs, including AI-enabled island rigs and our 30-rig regional platform in Oman. And through Drill-to-Operate, we are advancing the next phase of our strategy, building on our drilling leadership and expanding across OFS, [inaudible] , and regional partnerships. Our focus remains on resilient growth, disciplined capital allocation, and long-term value creation. Thank you for your time. We will now open the floor for questions.
Thank you. We will now open up for Q&A. If you would like to ask a question, you may do so by dialing into the call and pressing star followed by one on your telephone keypad. Should you change your mind and wish to remove your request, you may do so by pressing star followed by two. Our first question today comes from the line of Ricardo Rezende from Morgan Stanley. Your line is now open. Please go ahead.
Hello. Good afternoon. Thanks for taking my questions. If I may, a couple of questions. First one is on the strategy update. When we look at the new segment on the new services in OFS and on advanced engineering, what is your expectations around margins for those services? Should they be in line with what you have in OFS? Second question on dividends, as we see this special dividend being announced this morning. When we look forward, your leverage is on the lower end of your guidance. You have quite a strong free cash flow generation in the coming years. Should we expect special dividends when and if they are announced to be at least around the levels that are announced this morning, or would you keep some flexibility around that? Thank you.
Thank you, Ricardo. I think on the first question, at full run rate, yes, we would expect that the additional Oil Field Services and engineering services would have a relatively similar margin profile, which is a 13% net income like the current Oil Field Service. However, at the beginning, a lot of these services will start through additional partnerships to build the capabilities, like what we have done with Baker Hughes back in 2018 for the Oil Field Services, and like what we have done with Patterson SLB at the beginning of the unconventional. Hence, as we start these partnerships, whether they are in wellheads, casing, completion, production, etc. , there may be effectively stakes being taken by partners.
There may be a consortium economics which gets split, etc . Hence, initially, the margin may be lower, like what we have seen also with unconventional. The net income margin at the beginning may be in the mid to high single digit, up to 10%. But then effectively, within the next five years as we scale these segments, then effectively that is where we expect the margins to normalize back to 13% net income margin, like the classic Oil Field Services. On the second part in terms of dividends. I think the expectation is that the idea of very disciplined capital allocation, the fact that we look very closely every time there is an opportunity to pay additional dividends, yes, that will continue.
However, the amount itself may or may not be the same, because obviously, one, the base dividend itself is growing. For example, this year, the $1.75 comes on top of the $1.0. Whereas next year, the base itself will be $1.1. Also, the CapEx numbers will vary by year. For example, this year the growth CapEx was around, and on top of the maintenance CapEx, the total CapEx was around $600 million. Next year, we are looking at around $800 million of total CapEx, because effectively, as also we are implementing this growth strategy, that effectively takes our current CapEx, which was predominantly this year, the growth CapEx was mostly on the drilling side.
Out of the $300 million to $350 million of growth CapEx this year, more than $200 million was on the drilling through the island rigs, plus some of the other rig upgrades, etc . Whereas obviously going forward, the CapEx will lean more towards the OFS and the engineering services, and that will result in a couple of years of more elevated CapEx, probably closer to the $800 million level. Hence that will also have an impact on that. Now, having said that, again, even with the discretionary dividend this year, we are still at the low end of the leverage, which is onr time.
So even after the $1.75, we remain at the one t ime. So we still have, obviously, a lot of potential to go up, potentially within that one to two times. So we can still maintain the discretionary dividend even with higher CapEx if the Board decides to do that. But I would not take it as, okay, it happened this year, it will definitely happen next year, because again, the CapEx will be higher next year, and the base dividend itself will also be higher.
Okay. That was very clear. Thanks, Youssef.
Thank you. Our next question comes from Faisal Al Azmeh of Goldman Sachs. Your line is now open. Please go ahead.
Yes. Hi, and thank you for the opportunity to ask questions. Maybe just to dive a bit more into the new strategy or the detailed strategy. How should we think about that in the context of the delay in the unconventional plan into next year? How should we think about those numbers as well in the context of higher production capacity out of the U.A.E. and higher production targets? Is there any update on that, and how should we kind of triangulate both? That is my first question, and my second question is more towards CapEx.
You have talked a bit about, obviously, the dividend and next year's potential. Is there room for, let us say, less CapEx next year? Do you feel that, where CapEx levels are for 2027, given that you have reduced CapEx for this year, is there room as well to try to reduce the levels for 2027, whereby you can sustain these dividends? Or do you feel actually it is just a matter of a delay and the likelihood of CapEx moving higher is definitely there for 2027? Thank you.
Thank you. I think on the first point, obviously the strategy, it would happen regardless of, let us say, the timing and the quantum of the UC and any other expansions. Because even from the existing market, that is currently a $4 billion-$5 billion market on the other engineering and other services that we can potentially tap into even to serve the current oil and gas capacity in the U.A.E. This strategy is something we want to do regardless because this market today is available for us, is captive, is effectively being spent by ADNOC, and it is only about building the capabilities and entering the right partnerships and consortia to be able to deliver on that. We would want to do that regardless.
Now, having said that, to your point, obviously that $4 billion-$5 billion then can significantly increase with effectively things like the unconventional and any other expansion increases. It becomes even a more reason to be able to double down on these markets. I would say it gives us an opportunity to expand and grow regardless. But then obviously as the market grows, that is even a further step-up of opportunity. I think obviously we have ADIPEC next week, which is going to be a great opportunity to hear us. I think today, with our results, obviously it is more focused on what ADNOC Drilling is doing in terms of our strategy expansion, our dividends.
Next week will all be about the ADNOC expansions and plans, what ADNOC group is doing, and then how we benefit from that, and how now with the new strategy, we can take an even larger market share and component out of that. I would say we do not really see any substantive delays, and I think the ADIPEC next week hope will be a testament to the plans and what is coming forward. On the other point, in terms of CapEx, we do expect 2027 CapEx to be higher than 2026 because of a couple of things. One is, yes, things like the unconventional, which was effectively now coming in a bit later. That is, yes, will materialize more in 2027 compared to 2026.
Plus also now with that expanded strategy, we are going to be entering a larger number of tenders across the board on additional services like completion, production, mega tenders, tie-ins, production facilities, etc . Hence, by definition, we do expect a larger investment. Now, can that end up being slightly smaller potentially? Because again, that is obviously a lot of that, all our CapEx, as you know, is always effectively CapEx tied to winning, whether it is rigs, whether it is only built to order or buy to order, or similarly, on the OFS and the engineering, all of the CapEx we are going to be incurring is going to be to specific tenders and awards. We do not have any generic preparatory CapEx that we would spend regardless. Everything we would do will be tied to a specific project.
Obviously we have very ambitious plans in terms of what this strategy and segments will add, and hence we have ascribed certain win probabilities on tenders we see coming out next year. So it can potentially end up being lower if these tenders do not materialize in the same way. But obviously our objective and aim is to spend the $800 million next year because obviously we see a significant return on that in then the following years, assuming effectively we can land these tenders as we are targeting to land next year.
Thank you.
Thank you. Our next question today comes from Anna Kishmariya from UBS. Your line is now open. Please go ahead.
Okay. Thank you for taking my questions. First will be also a follow-up on the strategy. What is the timeline that you expect to capture this 25% out of $4 billion-$5 billion? Do you expect to see any contribution from it already next year? What would be the speed of ramp-up there? The second question would be around guidance that you narrowed a bit towards the lower end of the previous one. Could you please comment on what has changed? Is it this maintenance that was planned on the Offshore side, which could affected it, or what was the move there? Maybe final one is details and a technical one. There is a write-off of property on the cash flow side for this quarter. Do you expect any further write-offs to affect your cash flow? Thank you.
I think on the first point on the strategy, to being very conservative, we are going for a five years timeline. Now on that similar five, six years on the OFS, we actually got to 50% as opposed to 25%. Just to be conservative, we are assuming half the ramp-up speed we have had on the OFS on the new service. Obviously, our internal ambitions are higher, but I think that is what we are going with for now as a more conservative estimate. In terms of speed of ramp-up, yes, we will start to see some impact next year.
There are already tenders that we have already participated in under the new strategy before even launch of the strategy, because we wanted to not launch that to the market until actually we have some proof points internally that we are able to form consortia, we are able to go and bid, we are able to be competitive on pricing. Obviously, it is still relatively small, so it will be a small contribution. But as soon as end of this year, beginning of next year, we should be awarded some of that, and then that should financially contribute at our 2027 numbers. But again, it will be very small. I think the real ramp of finance should be in 2028, because we are doing the strategy also in anticipation of a couple of mega tenders to come out from ADNOC on the Oil Field Service engineering side.
We award in 2027, and then the financial impact will to come in 2028. I think when it comes to the lower end of the previous guidance, which is more on the net income on the $1.45, I think a bit that will still be within, let us say, low to mid as opposed to strict low. I think that is more of coming that our guidance range is always the low end is the 100% contracted coming into the year. Then the mid to high factors in some of the ongoing projects. So as something like unconventional, for example, was not phase one, phase two, back-to-back, but rather we largely finished phase one, and then you have these transition quarters in Q3, Q4, and then really phase two is more of next year.
As you have some of these projects that are being decided upon, the launch is really more of a 2027 launch. That is where the low end, which is the contracted end, does happen, but some of the mid to high end also. Obviously, we do have some incremental costs with the current situation related to transportation, inventory, etc . Again, some of that we are able to pass through the cost plus contracts. But for example, the OFS is not necessarily cost plus. There is also obviously some pressure in terms of transportation and things like that we have to also be a bit conservative about how we continue to account for until year-end. If we have additional reimbursement from clients on that, then that would be further upside, b ut that is something we are also baking in.
We see it as more of the resilience of the contracted side of the business and then being able to absorb the impact from the guidance range. I think on the last point, it is a very minor point. This is what we call lost in hole equipment. This is basically if in the OFS, effectively something is lost in hole and that we get reimbursed for by the client. Effectively, you see a write-off of the asset to a small amount, but then you see effectively a reimbursement from the client. Net-net, it has no net financial impact. It is something we cannot forecast. Obviously, something that happens outside of everyone's control in the well. We do not forecast it, but obviously, even when it happens, we will be compensated, so it will not have a net impact on the company.
Very clear. Thank you so much.
Thank you. The next question is from Mick Pickup from Barclays. Your line is now open. Please go ahead.
Yeah. Afternoon, all. Just a couple of quick ones for me. Can you just talk about impact of fuel costs on your business, how they are handled within your costs? Secondly, you do talk about going to 200 rigs now, your new plan. Is it best just to think of that as, let's say, a block of drilling rigs and an expansion across at current average rates? Is that the way to think about it? Obviously, there's going to be international in there's going to be Onshore, Offshore, but is it best for us just to think of it as an increase on mass?
Sure. Thanks, Mick. I think on the first point on the fuel cost, the way you see it predominantly is on the Onshore segment because that's where we procure the fuel and then we charge the client for that. So you see a higher OpEx and higher revenue on Onshore, relatively proportionally. Again, the net-net impact is relatively small. Obviously, there's a profit margin for us on the fuel, so it's not literally a dollar for dollar. We do make a bit of money on it. But the impact that you see is, if you want, is not the full amount because again, it is partially a pass-through. The Offshore, there's no impact because the client procures that fuel directly, so it neither appears in our cost nor in our revenue.
When it comes to the rig count, yes, I think your assumption is fair because if you look at how we go from the 172 to the 200, you will see that the rigs we're looking at are broadly in line with the overall mix. So it does include effectively another four offshore island rigs domestically, one in Q4 this year and then three next year in Abu Dhabi. It includes four onshore rigs regionally, which are currently being built in China to go through the MBPS platforms, three to Kuwait, one to Oman. It would include, effectively, the bulk of it will be the unconventional rigs for the development phase on the domestic land site. Then it may also potentially include subject to final award from KOC, the one or two jackups that will be awarded based on us being the lowest bid there.
If you see the awards, you will see it's relatively balanced, almost 2/3 domestic, 1/3 international. It is majority land, minority offshore. So it overall is relatively close to our overall portfolio mix and composition. Hence, if you take an overall average of our entire portfolio and assume a prorated to that, yes, that would be fair. We will also expect that the IDS number of rigs will continue to ramp up also proportionately to the numbers that we have now. So the same way we're currently at a 50% going to 60%, that will also continue to happen on the new rigs. So yes, it will be fair to assume a relatively proportion to the existing mix across the board.
Thank you.
Thank you. As a reminder, if you would like to ask a question today, please press star followed by one on your telephone keypad. Our next question comes from the line of Oliver Connor from Citi. Your line is now open. Please go ahead.
Thank you for taking my question. Maybe just coming back on the strategy piece. So quite a diverse set of opportunities within that new services suite, pumps to EPF and tubes. Maybe if you can give us a little bit of color around how you see those various buckets in terms of relative size or whether you are targeting a particular segment first and then looking to build into other sectors later in the decade. Then, I guess the second question is around CapEx. You said it was going to be tied, I guess, to win rates, probabilities, alongside that, maybe can you give us a sense of potentially how much CapEx would be going into this business once it is scaled? Thank you.
Definitely. So on the first point, yes. We would be leading, I think the fastest piece we are seeing is on the early production facilities and the tie-ins, and that is because effectively as ADNOC is ramping up the project it is undergoing. The need effectively, one, to have these early production modular facilities until the permanent facilities can be ready in two to three years is higher. Also the need effectively to be able to tie in some of these wells. So today, ADNOC has a significant inventory of wells which have been drilled but not tied in, as effectively historically the capacity of ADNOC was significantly above, what the OPEC quotas were.
With effectively these restrictions now no longer being in place and ADNOC being able to ramp up towards its capacity, the urgency to be able to tie in these wells and make them available for production is higher. We do see the early opportunities are opportunities within that engineering side on the early production facilities and tie-ins, and that is anyway by size as well, that is the largest component of the four to five. That is also the piece that we can move in quickly, in the form of consortia, etc . Then followed by things like the OCTG, where there is more capability building that we need to do around logistics, vendor management, all of that. That is where we are looking to enter into partnerships as well, to be able to do that.
On the CapEx side, I think for us, effectively as we go forward as the rig CapEx start to normalize and be more of a $100 million or lower than that, and then a $300 million of maintenance. We really see the bulk of the CapEx, which is the $400 million remaining as the annual CapEx on the OFS and the engineering. We think effectively that is a level of CapEx between the two segments that can really support continued real growth, kind of double-digit growth within that OFS plus engineering segment, combined year on year. Because that is effectively how we will be able to continue to drive, let us say, the overall growth of the company. So we see that $400 million of annual CapEx between both segments combined, OFS engineering, as a level that will allow us to get to the growth objectives we have.
Very clear. Thank you.
Thank you. Our next question comes from Alex Comer of JPMorgan. Alex, your line is now open. Please go ahead. Alex Comer of JPMorgan, your line is now open. Please go ahead.
Hello. Just a question from me on this new strategy. Just so I am clear here, you are talking about partnerships and those other different things. Are you intending to purchase companies, and if so, how much do you intend to spend or is this going to be a kind of partnership and then after a while you buy them? I am just trying to work out what the M&A component of this might be.
Yeah, I think our base case is partnerships. I think if you look historically, the vast majority of capability building we have done was via partnerships, right? So whether it is with Baker Hughes on the OFS side, whether with SLB and Patterson on the Turnwell side. Even with MBPS and SLDC, obviously it did have an M&A component in terms of buying into existing rigs, but also there is a partnership component of continuing to scale together. So for example, on the SLDC platform, we now have the partnership with SLB, where they have the lump sum turnkey on Mutriba, and then we are providing the rigs into that. On MBPS, we have also moved one rig from the U.A.E. into that business, and then we also won four more rigs organically we are currently building.
So it is always partnership first, and then M&A really becomes more surgical and specific if we think that there is specific technology that if we own as opposed to partner on, then that unlocks significant potential for us. Like what we have done on some of the Enersol companies like Deep Well and Gordon, because we have seen with the massive kind of boom in the unconventional, that really being able to own this kind of technology would really unlock major value creation for us over time. So I think as we think about CapEx, I would think of it much more as our pro rata share of the partnership CapEx in terms of purchase of equipment, as opposed to CapEx to purchase companies.
Also the way our plan is devised to kind of meet the current consensus long term is devised around partnerships. Any significant M&A would be incremental to both all the, let us say, the current consensus in terms of numbers as well as the current CapEx, and that will be really evaluated on case by case if it is really needed. But the base case is partnerships first, and then M&A continues to be very disciplined and specific as and when needed.
And just so I understand this, all these companies have got all these technologies and all these bits and pieces and they obviously have this toolkit and you do not have that. And you are looking for a partnership based on presumably 50-50 or some mix of that. So this is based just purely on you bringing relationship to the party or what? I am just trying to work out why, if I am one of these guys, why I should not go for 100% of the opportunity rather than give you guys a cut.
Yeah, a few things. Obviously, yes, relationships obviously is one. The ultimate client kind of owns 78.5% in ADNOC Drilling. Two is our in-country value score. Today, we are effectively at 91%, we have the highest in-country value score in the U.A.E., which means that from a procurement perspective, we have a favorable position. Three, from a cost of capital perspective, we have the lowest cost of capital. Today we have a live example where we have one of our partners in one of the consortia. They basically went to kind of borrow from one of their local banks as effectively for that project level. And then if you look at the initial price quoted and the subsequent price quoted, once effectively ADNOC Drilling is added to the JV, it is 1% lower on the cost of debt.
So our ability to also significantly reduce the cost of capital is quite significant. Also, some of these projects are multi-billion dollar projects on the production facilities and the tie-ins. So also the capital strength required for these companies to be able to demonstrate and the requirements from procurement, again, effectively as we come in, a lot of these requirements become much easier to provide. So I would say it is a combination of relationships. Effectively, kind of favorable procurement dynamics, lower cost of capital. And then ultimately the idea is for every one of these players, we will ultimately find someone to do it with, right? So if it is not that player, it is going to be another.
So effectively, ultimately, for whichever players that want to continue to keep and grow that market share, we effectively become an actual partner because otherwise also we pose very significant competition risk. You have seen, for example, a player like Baker Hughes, when we partnered with them, the significant step up in their volume of equipment sales in the U.A.E. as we effectively became more than 50% of the market, compared to some of the other players having necessarily partnered with us at that point in time.
So there are actual case studies in the market of basically how that becomes a real kind of boost for their business long term, even if it is not necessarily on their market share, purely on the service provision. But when they look at their overall economics, including equipment provision, including what otherwise would have been the case if we partner with someone else, it still makes a lot of sense for them.
Okay, thanks.
Thank you. Our next question is from Guillaume Delaby from Bernstein. Your line is now open. Please go ahead.
Yes, good afternoon. This is a fascinating new journey. I would like also to have a few questions to ask. You want to be involved in wellheads, in OCTG. Do you want to be involved in the technologies or also in the manufacturing of those equipment? Your partnerships, I suggest, would be with local industrial companies. Am I correct? This is my first question. My second question relating to the strategy, I understand that this is mainly a regional strategy. Tell me whether I am correct. However, within Enersol, I suspect that the biggest proportion of revenue from Enersol is coming from the U.S.
If you can help me, I would say reconcile what is going to be the role of Enersol within the strategy. Do you plan to fully consolidate Enersol? How are you going to reconcile the strategic focus on your region with the revenue from the U.S. coming from Enersol? My questions are a little bit confused, but basically there are many moving parts, and I would like to try to see how all that is going to work together. Thank you.
No, they are very clear and great questions. Thank you so much. On the first point, we are not looking at manufacturing as an immediate priority. Our focus really is on the engineering side. Procurement, installation, servicing, maintenance, provision, because ultimately we see that as the lower capital intensity part. Also, as you said, we will come to it because we have a more of a local and regional strategy. We are not looking trying to be a global manufacturer. Maybe there is massive economies of scale on a global level or a technology which is provided completely globally. We are very much focused on servicing our existing markets.
For example, if we partner with a global manufacturer of a certain product, what we are focusing on is providing it in the Middle East. Does it also make sense to have a local facility here that maybe can do some scope for the local, for the regional market, but not necessarily to go and buy into a global manufacturing facility somewhere else, which kind of serves markets, which, as you said, may not be core to our strategy, which is very much focused on the region being the lowest cost producer and the lowest emissions per barrel globally.
On the second point, in terms of our partners, it will be a mix. Things which are more technology heavy, things like OCTG, etc. , these things may be the partners in that case may be a bit more global. Things where it is more delivered on ground engineering, things like tie-ins, production facilities, which are more focused on the ability to really deliver the right scope, people, cost control, project management on ground. Partners here may be more local and regional in nature. When it comes to the strategy, yes, it is very much local first, regional second. So we built our capabilities here. We have built first kind of the lowest cost drilling company. Then we went and effectively became competitive.
That is why when we went to Kuwait, we were the lowest bidder for the rigs. Same thing on the OFS. We have built it domestically. Now we are going regionally. Same thing will happen on the engineering. It is always local first, build scale, establish a clear competitive positioning, and then take it outside. When we think about global and Enersol, really this is more of global to bring it regional local, right? So we only do a U.S. technology, for example, Deep Well and unconventional technologies because unconventional boom in the U.A.E. and the Middle East.
If there was no unconventional link in the Middle East, we would not go and buy unconventional companies in the U.S. simply because they have U.S. revenues. So the U.S. revenues, we see that as just one part of the equation. But the strategic reason really is the synergy and the revenue uplift that can come from the deployment of these companies in the Middle East. So we always think of it as we are targeting long-term, 80% earnings from the U.A.E., 20% international. When we say international, it is predominantly Middle East. Then, yes, that will have a small component of international revenues being inherited when these companies come in. But that is not the driver of the deal. The driver of the deal is very much the local and regional synergy from these.
Where does Enersol sit in general in the strategy? It continues to be a very strong M&A vehicle for us for these specific technologies, niche technologies that we look after. Because, again, we effectively, our focus is not to go and operate a company or acquire a company in the U.S. We at ADNOC Drilling at the parent company level extremely focused on our on-ground delivery and execution here. If there is this good technology in the U.S. that someone needs to go and hunt and acquire and et cetera, then that's Enersol's job. Our job becomes really how do we integrate it here and synergize it here. That's for us the key focus.
So Enersol will remain that. There may also be opportunities in the future where effectively certain tenders are being issued in the region and awarded to multiple companies. There may be an opportunity in addition to the ADNOC Drilling share for also Enersol to have a share on top. That would be another potential synergy. The core focus of Enersol is really to go and hunt these global technologies and manage them, and then we effectively synergize them in the Middle East from our side.
Thank you so much. Very clear. I turn it over. Thank you very much. Cheers.
Thank you. As one further reminder, if you would like to ask a question today, please press star followed by one on your telephone keypad. Our next question comes from the line of Audrey Zong from CSC. Your line is now open. Please go ahead.
Hi, good afternoon. This is Audrey Zong from China Securities, and I have two questions. My first question, Youssef, you just touched a little bit about it, and could you please share more about it? It is about how you benefit from the ADNOC upstream spending. Given your long-term take or pay contract and the day rate model, do you earn more if the same rigs drill more wells? Would you need additional contracts or an expansion of your Oil Field Service business or the new strategy you launched to capture that upside? This is my first question.
My second question is about the wells you drilled in Q3. You reported 177 onshore wells and 45 offshore wells drilled in your domestic operations in Q3. Could you please share how many were new wells and how many involved work on existing wells? Maybe roughly how many of these wells were drilled to offset the depletion and how many were drilled to add production capacity? Thank you.
Perfect. I think on the first point, and yes, we do earn more even if the existing rigs are doing more wells, and we do that in a number of pieces. First, we charge a rig move fee. Every time a rig moves from a well to a well, we charge a lump sum for that. If the rig is becoming more efficient and moving more between the wells, then effectively we are charging more, so we are generating on that. Second, some of our charges are on a lump sum basis. For example, on the unconventional, we charge per well, not per day. As the rig becomes more efficient and does more wells, we also charge more.
Third, we are now also piloting with ADNOC a kind of efficiency sharing arrangement where if we drill wells faster, we get a 5% step-up in the day rate, and then if it is slower, we get a 2% reduction. It is disproportionate to the upside. That also means we have more upside as we do that. Fourth, also in the existing Oil Field Service, even before the new strategy, a lot of these services are on a job rate per well. As we are doing more wells in a certain year, we end up doing more services, so we end up generating more revenue.
And then to your point, the new strategy adds even more to that because as we are providing more and more services, as effectively this rig is doing more wells, we are charging more and more per well, and hence that creates even more opportunities for us to continue to earn. And then obviously this further improves the return because then our CapEx is not going up as much, but the revenue generating from these wells continues to increase, and hence effectively, we are able to come in. We are also moving now into what we call rigless services. So services without even having the rig being there.
So things like production enhancement, etc. , which means that even effectively, not only is as the rig does more wells we get more revenue, but we also get revenue without even the rig being there, and all of that will contribute more and more to our returns. In terms of the activity, the vast majority of our activity today sits on new drilling as opposed to workover and maintenance, and this is because the great kind of nature of the Abu Dhabi wells and the natural flow of these wells, b ut obviously, as these wells age over time, we expect an increasing proportion of maintenance and workover, and that will present another major growth opportunity for us.
If you look at some of the other markets around the region, like Kuwait, etc. , the number of workover rigs is substantially higher, and the number of workover wells is substantially higher than the U.A.E. today. So as that also ramp-up happens over time, that will be another major growth opportunity for us. But today, to your question, the vast majority of the work is on drilling of new wells.
Great. That's very clear and very helpful. Thank you, Youssef. Thank you very much.
Thank you. The next question comes from Ildar Khaziev from HSBC. Your line is now open. Please go ahead.
Hello. Thank you so much. I have one question about your new strategy. You mentioned that you don't necessarily want to become a large equipment manufacturer given the scale requirement and high CapEx intensity. If we look at the entire value chain, are there any parts of it or other services which you don't yet target? If that's the case, why? Thank you.
I think from a service provision, by the end of this strategy, we would be doing everything on a service perspective. I think what we will not necessarily be doing yet is, as you said, the manufacturing of these different components. For example, today, we are obviously the leader in the U.A.E. in directional drilling, right? However, we don't manufacture that equipment. We purchase that equipment, but then effectively from a service perspective, we are the market leader. We have the people, the maintenance, the delivery on the ground, the best track record of running this equipment.
Within five years from now, the idea is we become a full end-to-end lump sum turnkey well solutions provider from the site preparation of the well all the way to enhancing the production from this well and everything in between. However, we don't necessarily have to manufacture every part. If we find certain elements where there is additive manufacturing, 3D printing, other ways of basically CapEx-light additive, then we look at that. But broadly, we'll continue to focus on the service part as opposed to the manufacturing part.
Thank you.
Our next question comes from Rabih Moussa from QIC Asset Management. Your line is now open. Please go ahead.
Hi. Thank you for the call. Just a couple of questions from my side. The first one on the two rented rigs. Can you clarify if these are onshore or offshore? And what was the average day rate achieved across the entire fleet? And on the MBPS land rigs, can you state the utilization rates for these rigs? And the final one is on the availability. The onshore rig availability was reported to be around 99%. Can you confirm whether this figure includes all the 123 rigs?
So on your first question, the rented rigs are offshore rigs that we have now. The rented rigs are very short-term rigs just to plug requirements. They do not contribute materially to any kind of really meaningful contribution for us. We have that. Originally, we had two, that is down now to one offshore rig. One of these already got released, and then we have another one onshore rig, so that kind of makes changes. But effectively, the contribution is de minimis ultimately to our financials, and ultimately long term, you can really think of it as a fully owned fleet with all of these ultimately being released.
When it comes to the 99%, yes, the availability here is captured within all the working rigs. That captures all of the working rigs. When it comes to the point around utilization, if you look at the Onshore segment, roughly we have around 90 rigs, roughly in the U.A.E. Around 80 of these are the kind of younger rigs, which average around 11 years old. Some of them are the newer ones, eight to nine, and then some of the older ones. Then we have the 10 very old rigs.
Some of these go up to 45 years, etc . These are the rigs which are being repurposed. We sent one of them to Oman. We are figuring other things we can do with these rigs. So the utilization, you can think of it broadly as 80% out of the 90%, with the 99% availability being, yes, for all the working onshore rigs and similarly on the offshore rigs. Sorry, I think I missed one question you had in the middle between the two rented rigs and then the utilization and availability.
Yeah. So there was two actually. One is on the average day rate across the 123 rigs, and one is on the utilization rate for the 22 MBPS land rigs.
Yes. So I think if you look on the MBPS side, we have around 19 effectively out of these 22 are working. Again, the ones which are not working are the relatively smaller workover rigs. We have some very small rigs in Bahrain, etc. , which have very limited contribution overall. So you can think of it as, again, closer to 80%-90% utilization, which is again, what's already reflected in the plan and in the financials. When you look at overall, so we don't disclose specific data, but I think if you look at implied revenue, you will see on the jackup side, our implied revenue is around $90,000-$95,000 per day, effectively implied on that.
The island rigs, it varies between some of the older ones and newer ones. So if you look at some of the older ones, that may be 55%, etc. , but some of the newer ones closer to 70,000 per day. The onshore, again, it varies. It is in the 30s per day. Again, it varies depending on the horsepower, the ancillary services we provide, the age, etc . So it kind of varies by segment and by horsepower.
Okay. Thank you, Youssef. That was very helpful.
Thank you. And there are no further questions. So at this time, I would also like to conclude today's conference call. Thank you everyone for joining. You may now disconnect. Have a great rest of your day.
Thank you