Ladies and gentlemen, welcome to ADNOC Drilling second quarter 2026 earnings webcast and conference call. My name is Mass 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 the 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 and 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, Mass. Good afternoon, everyone, thank you for being with us today. Before anything else, I want really to thank our people. Their discipline, commitment, and care for the company continue to be the real engine behind our business and financial performance. Together, we delivered another record quarter and our best ever first half, supported by the strength of our long-term contracted model and by the resilience and uninterrupted operations throughout the period. Despite the regional situation, we continue to execute at an exceptional level, delivering for our clients safe and efficient operations. On operational front, our team delivered 99% rig availability, 394 wells, and the non-productive time was reduced by 61% versus target. This translated to strong financial performance with first half revenue of $2.5 billion. EBITDA, $1.1 billion. Net profit, $0.7 billion, showcasing resilience, performance, and growth.
In line with our progressive dividend policy, the Board recommended a second quarter dividend of $262.5 million, bringing first half dividends to $525 million and reinforcing our commitment to attractive growing returns. We also advanced our growth agenda. We have closed during this quarter our MBPS transaction, expanding our regional platform to 30 rigs. After the quarter end, we deployed a repurposed land rig into Oman, demonstrating our ability to capture opportunities beyond the UAE in very synergetic way with our regional platforms. Our focus remain clear: delivering profitable growth, maintaining disciplined capital allocation, and returning cash to shareholders consistently. Looking into the second half, we remain confident in delivering full year FY 2026 guidance, supported by a highly contracted revenue base, expanding Oil Field Services capability, technology deployment, and regional growth. I will close by saying this.
The U.A.E. continues to lead the resilience and growth ambitions, and we are super proud to support that journey by delivering what matters most. In the first half, we stayed focused, worked safely, and delivered consistently without disruption. That discipline will not change. With that, I will hand over to our CFO, Youssef, to walk you through the financials. Thank you.
Thank you, Mr. Abdulla, and a good day to all. We delivered another record quarter supported by the resilience of our contracted business model, continued operational discipline, and the successful execution of our strategy. For the second quarter, revenue increased 3% year-on-year to $1.2 billion, reflecting the positive contribution from our region expansion following the consolidation of our operations in Oman and Kuwait. Together with the continued growth of our Offshore business, partially offset by the impact from two factors previously anticipated: the repurposing of certain onshore rigs and the lower phasing of unconventional. EBITDA increased 2% year-on-year to $557 million, and net profit grew 2% year-on-year to $359 million. As we communicated previously, unconventional activity accelerated significantly during 2025, resulting in a different activity profile this year.
During the second quarter, unconventional contributed $75 million in revenue, comprising $60 million within Oil Field Services and $15 million within the Onshore segment. As discussed during the last earnings call, the lower phasing of unconventional in FY 2026 is expected to be largely offset by revenue from additional OFS services, leading to an expected combined contribution of approximately $0.5 billion from unconventional and these additional services, resulting in reaffirming the full year 2026 revenue guidance of $5 billion and the OFS segment guidance of $1.5 billion. Turning to cash flow, free cash flow for the quarter was $297 million, while free cash flow before M&A stood at $306 million. Finally, our balance sheet remains strong and continues to provide significant financial flexibility. Net debt at quarter end was $2.2 billion, equivalent to one time last 12 months EBITDA and below our leverage target.
This positions us well to continue investing in growth, execute on our strategic priorities, and maintain our progressive dividend policy while preserving a disciplined capital structure. 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 up 8% year-on-year to $554 million. This was driven by positive contribution from the consolidation of our operation in Oman and Kuwait following the SLDC and MBPS transaction, together with higher fuel escalation. Those contributions were partially offset by the anticipated impact from the repurposing of certain onshore rigs. During the quarter, unconventional activity contributed $15 million to Onshore revenue, in line with the planned phasing of the program. Sequentially, revenue increased 16%, benefiting from the consolidation of MBPS, higher fuel escalation, and the additional calendar day. Meanwhile, EBITDA for the quarter was $241 million, representing a 44% margin. Operationally, we continue to deliver excellent execution. We drilled 159 wells during the quarter and achieved 99% rig availability, demonstrating the reliability and performance of our fleet.
At the end of the quarter, our Onshore fleet stood at 122 rigs, comprising 92 rigs in Abu Dhabi and 30 rigs outside the U.A.E. across the region. Following the quarter end, one of our repurposed land rigs commenced operation in Oman, making ADNOC Drilling's first organic rig deployment in the region and an important milestone in our regional expansion strategy. With that, I will now hand over to Adel to cover Offshore operations.
Thank you, Sultan, and good afternoon, everyone. The Offshore business delivered another quarter of solid growth, with revenue increasing 6% year-on-year to $358 million. This performance was driven by the continued contribution from the two jackup rigs that commenced operations at the end of the second quarter of 2025. Together with the initial contribution from our new AI-enabled island rig, which joined the fleet in June ahead of schedule. Sequentially, revenue increased 4%, supported by an additional calendar day and the partial contribution from the new AI-enabled island rig. EBITDA reached $241 million, maintaining a healthy 67% EBITDA margin. Our Offshore business continues to build strong momentum, supported by high fleet utilization and the ongoing expansion of our fleet. During the quarter, we drilled 44 wells while maintaining 99% rig availability, demonstrating the reliability of our operations and the strength of our execution.
At quarter end, our Offshore fleet increased to 49 rigs, comprising 36 jackup rigs and 13 island rigs. Looking ahead, we expect another island rig to commence operations around the middle of the third quarter, which further supports our growth trajectory. I will now hand over to Emri to cover Oil Field Services.
Thank you, Adel, and good afternoon, everyone. The Oil Field Services business continued to make and drive strong progress during the first half of 2026 and second quarter, with increasing activity across our integrated drilling and discrete services business and further improvement in cost initiatives, digital automation, operation efficiency, and new technology adoption. Revenue for the quarter was at $320 million. As anticipated, this reflected the planned lower phasing of unconventional activity, which contributed around $60 million to the overall Oil Field Services revenue in the same period. As of end of the second quarter, 81% of unconventional phase one wells were drilled and 53% fracked. This was partially and favorably offset by the continued growth in our integrated drilling and discrete services business, with the number of IDS rigs increasing to 61 from 58 in the same period last year.
With Oil Field Services, be it integrated drilling or discrete, delivered on 114 rigs from the ADNOC Drilling own fleet in Q2. EBITDA increased significantly to $75 million, representing a 44% year-over-year increase and a 23% EBITDA margin. This improvement reflects the continued expansion of our integrated and discrete services offering, together with a favorable activity mix cost efficiencies during the quarter, delivering favorable profitability and net income results. Meanwhile, integrated drilling efficiency improved by 30% compared with our 2025 benchmark, demonstrating the benefits of our integrated operating model, digital technologies, continuous focus on automation, digital offering, execution quality, and new technologies introduction. With that, I'll hand it back to Youssef. Thank you very much.
Thank you, Emri. Our Board of Directors has recommended a dividend of $262.5 million, approximately AED 0.06 per share, expected to be paid in the second half of August to shareholders of record as of August 10, 2026. Together with the first quarter dividend distribution, this brings total dividends declared for the first half of the year to $525 million, representing half of our $1.05 billion annual dividend floor for 2026. Importantly, I would also like to highlight that the Board retains discretion to approve additional dividends above the floor after considering free cash flow accretive growth opportunities. Let's now turn to our guidance. Next slide, please. The first half has further demonstrated the resilience of our business model. Despite the evolving regional environment, we have delivered strong operation execution, resilient financial performance, and disciplined capital allocation.
We are pleased with the strong momentum, based on our current trajectory, we expect to deliver for the nine months, revenue of around $3.71 billion, EBITDA of around $1.64 billion, and net income of around $1.07 billion. This performance reflects continued broad-based growth across the business, supported by fleet activity, oilfield service expansion, and increasing contribution from newly integrated operations. Importantly, these trends imply a third quarter with slightly higher revenue, EBITDA, and net income sequentially, demonstrating the resilience and consistency of our operating model. The expected sequential revenue growth in Q3 is primarily supported by three clear drivers. First, MBPS will contribute approximately one additional month of consolidated revenue in the quarter. Second, we expect incremental revenue from island rig activity, reflecting a full quarter contribution from the rig that became operational in June, and the expected mid Q3 startup of another island rig.
This will be partially offset by the repurposing of two jackups that I discussed on our previous earnings call. Third, we are beginning to capture early synergies from MBPS, particularly in Oman, where one land rig is already supporting PDO and contributing to activity levels and revenue generation. These fundamentals also give us confidence in reaffirming that we will be within our full-year 2026 guidance. We expect revenue of $5 billion, EBITDA around $2.2 billion, net profit around $1.45 billion, and free cash flow pre M&A between $1.2 billion-$1.3 billion. Looking ahead, our outlook remains well supported by sustained drilling activity, continued offshore fleet expansion, growing oilfield service, and increasing contributions from our regional platform. Within OFS, we remain on track to reach 70 IDS rigs by year-end while continuing to expand the deployment of discrete services across our fleet.
As we have discussed today, the lower phasing of unconventional during 2026 is expected to be offset by additional services, leaving our overall guidance reaffirmed at $1.5 billion of Oil Field Services revenue. For 2027, based on current visibility, and given that any potential additional rig demand in Abu Dhabi beyond the additional contracted island rigs will require time to materialize as client plans are finalized and the rigs are procured and delivered. A sensible working assumption, though not yet firm guidance, would be to target revenue growth in the low to mid-single digit, with EBITDA margin somewhere around the 2026 levels. Over the medium term, we remain focused on preserving the quality of our earnings while supporting ADNOC's upstream growth ambitions.
We continue to target EBITDA margins of around 50% across our domestic conventional drilling business and 23%-26% for conventional oil field services, with maintenance CapEx of up to $0.3 billion per annum. These targets reflect our continued focus on disciplined growth, operational efficiency, and sustainable returns. We expect to provide more granular guidance for 2027 and more color over the medium term at a later stage, not later than Q3 or at the latest full-year results once the phasing for potential additional rigs and OFS volumes is finalized. Overall, our priorities remain unchanged. We will continue to execute with discipline, allocate capital selectively and responsibly, and convert our strong operational performance into sustainable cash generation and attractive shareholder returns. Next slide, please.
To conclude, ADNOC Drilling delivered another record quarter and first half, showcasing the strength of our strategy, the resilience of the business model, and our ability to execute at scale. The outlook remains strong. As a strategic enabler of ADNOC's upstream growth, our integrated capabilities across oil and gas, conventional and unconventional resources, positions us to capture demand and deliver sustained value for clients and shareholders. Reflecting this momentum and confidence in future cash generation, the Board approved a second quarter 2026 dividend of $262.5 million, or approximately AED 0.06 per share, bringing our H1 2026 dividend to half of our $1.05 billion annual dividend floor, which is expected to grow by at least 5% annually through at least 2030. We also advanced our technology-led growth agenda, deploying our first AI-enabled automated island rig ahead of schedule.
This strengthens automation, utilization, and efficiency while turning operational data into higher productivity, lower unit cost, and long-term value creation. Thank you for your time. We will now open the floor for questions.
Thank you. To ask a question, please press star followed by one on your telephone keypad now. If you change your mind, please press star followed by two to remove yourself from the question queue. When preparing to ask your question, please ensure your device is unmuted locally. The first question today comes from Ricardo Rezende of Morgan Stanley. Your line is now open. Please go ahead.
Hello. Good afternoon. Thanks for taking my question. I have a couple questions on this rig that you just got in Oman, your first organic rig. First one is, what's the potential that you see for incremental rigs there apart from what you already have with the Schlumberger JV and with MBPS? The second one, if you look at this new contract, how would you compare the returns of what you see in Abu Dhabi and what was the implied returns as well on the two recent M&As? Thank you.
Perfect. Thanks a lot, Ricardo. I think in terms of, if you remember, we had a number of older rigs in Abu Dhabi that we had said effectively these would no longer be suitable for the latest types of operations that kind of ADNOC wants with the latest automations, et cetera. Hence we'll basically be taking them out of operations, repurposing them, and then seeing if they can either do lighter work inside Abu Dhabi, some more work over work or surface holes, et cetera, or we can potentially explore some other regional work for them. That's the background for this rig. This is the first one out of them to effectively go and start doing work outside.
Definitely, we see more opportunities because, again, if we look outside, whether it's Kuwait driven by the three to four million expansion or Oman, which is obviously in the current situation with higher oil prices and effectively very minimal impact on their operations, they're actually very well positioned to keep expanding. Yes, we definitely see opportunities in both markets, and we're pursuing these opportunities in many ways and patterns. One is our existing rigs in Abu Dhabi, any availability we have, pushing it into these markets. Two is additional organic wins by the two platforms we acquired. For example, SLDC, they already had two rigs in Kuwait. They got a new multi contract for these rigs for the new Mutriba project in Kuwait earlier this year, which will get deployed in Q4.
Similarly, MBPS won four rigs and tendered three in Kuwait and one in Oman. We're effectively winning work directly as ADNOC Drilling and then pushing this through the JVs, in this case, through MBPS. MBPS and SLDC are also winning their own work directly, plus potentially additional M&A either as bolt-ons to these two platforms or as additional platforms running next to these two. There are plenty of opportunities, and we're pursuing them in plenty of ways. In terms of the returns you mentioned. On day one, the returns outside, by definition, will be higher than the returns inside because we are going after only contracted rigs. Obviously because these are over the time, these relatively have higher volatility than Abu Dhabi. The valuation multiples at which these rigs are acquired reflects implied volatility.
When we're buying rigs at 3.5x , 4x EBITDA. On day one, it's generating that EBITDA because by definition, we're only buying contracted rigs, but the price does bake in that effectively there will be under-utilization period over many years. Hence, by definition, on day one, the returns are superior. For example, free cash flow yield on day one is mid double digits compared to 8% free cash flow yield that we have on our operations in Abu Dhabi. The returns on day one from a cash perspective will be accretive from an EPS, et cetera. Obviously, we're taking into account the fact that obviously over time, there will be periods of under-utilization that will bring it back in line with the overall returns of the business.
Obviously, in case of this specific rig in Abu Dhabi because that's going to Oman because that rig has already left operations in Abu Dhabi. That's coming in as completely incremental. Effectively no additional CapEx for it because the rig was already existing in Abu Dhabi with the book value and had already left operations already in Q1, Q2. There was no revenue and earnings coming from this, it's purely incremental. By definition, it's completely accretive from a returns perspective. Generally, the trend we see is short term, everything will be accretive that we buy, et cetera. Longer term, it will probably be back in line once you adjust for periods of low utilization compared to Abu Dhabi.
Okay, that's clear. Thanks, Youssef.
Thank you, Ricardo.
Thank you. The next question comes from Anna Kishmariya of UBS. Your line is now open. Please go ahead.
Good day. Thank you for taking my questions, a couple from my side. The follow-up around this Omani rig, if I may. What is the progress with other rigs? Is there any possibility for others to be redeployed in Oman or Kuwait, or is there any that you plan to divest or scrap? That would be the first one. The second one around the CapEx, which is for now going at a very low run rate CapEx spend in first half. Is there a downside potential for your guidance, or you expect a significant ramp up in the spending into the second half of the year? Probably one more around the midterm guidance for 2027. Your guidance that you provided for 2027 just now around the comments for revenue growth.
Can you please provide a little bit more color around what are the main drivers, and if there are upside, downside risk to this estimate, can you let us know which one would be the main driving forces? Thank you.
Definitely. I think on the CapEx one, we expect to end the year closer to the lower end of the guidance range of $600 million-$800 million, closer to the $600 million. The main difference between H1 and H2 is the performance milestones on the rigs being delivered. Because effectively the island rigs are coming in a more back-ended way, and similarly, the OFS equipment for the ramp up from 60-70 IDS rigs. That's why the CapEx is more back-ended in nature, but we still expect to end somewhere around the $600 million bottom end of the range. In terms of the medium-term guidance, the kind of that guidance is that the main source of that is the contracted part.
It's basically the additional three island rigs which are coming next year, partial impact of them, plus the full year impact of the rigs that came in this year and the full year impact of the OFS ramp-up that we have this year, and again, the full year impact of MBPS and SLDC, which are partial this year. It's the low to mid-single digit guidance we provide on growth. This is the pure contracted growth, which is coming from things which was mid-year, adjusting them to be full year, or mid-year impact or part-year impact of contracted rigs coming in next year. The upside to this comes mainly from two things. The upside risk comes from the regional M&A. Obviously we have, in addition to the two we've closed, we have kind of multiple ones in different parts of the pipeline at different stages.
Similarly, on the Enersol side. Again, we don't bake M&A into our guides. Effectively, as and when these close, this will present the main upside risk that we have. Then the second upside risk is on the unconventional. Again, we don't include this in the guidance until effectively ADNOC has done the FID, which is still on track for later this year. Effectively, once the FID comes in, that becomes the other upside risk. I would say, we don't really see any material downside risk from there because I think, again, similar to this year, you've seen that even if we have a lot of stress from a regional environment perspective and things like that, it doesn't really impact the business. I think the contracted business has proven very solid, and the low to mid-single digit is contracted growth.
We don't really see any material downside risk to it. The upside risk from the unconventional and the M&A. Going back to your last question about the rigs. For us, all options are open. One is obviously using opportunities to redeploy them domestically. For example, they may not necessarily be the most suited rigs for unconventional, but there is an opportunity, for example, if there's ramp up to swap some of the more powerful rigs towards the unconventional and then free up some of the less developed work, less intensive work to be done by these rigs. We have different options around that domestically, plus the regional deployment option where we're actively tendering them to different parties across different countries.
Yes, we always have the, for example, like historically what we've done with jackups is we've kind of sold them to be converted to production platforms elsewhere because that's what's kind of the highest value use. Also if someone can obviously, if these rigs will be put to use as pure drilling rigs, then we'd rather do this ourselves. If they're going to a specific geography where for some reason we don't want to operate or they're being converted to another type of asset outside our remit, then at that point in time, a sale can potentially be an option. These rigs are now out of the numbers in all ways. Whichever form they come back in will be an upside.
Thank you very much. Maybe just two follow-ups here regarding this repurposing rigs. What is the progress for the others? Do you still plan to find a new home or a new solution for them towards the year-end? Or some of them could take longer? The second one around this unconventional upside risk that you mentioned. You think that if we have the FID later this year, there could be some portion of revenue which will be booked already in 2027? Or because it might take a bit longer for the new rigs? What is the thinking here? Thank you.
Yes, definitely. On 2027, I think the answer is yes. Again, obviously we do have existing rigs in the portfolio. Unconventional phase two is not completely reliant on additional rigs. We also have rigs that we have with the rigs that we can again continue to optimize as we continue to increase efficiencies or, like we discussed, potentially moving some of the older rigs in some of the conventional operations and moving some of the more powerful rigs to unconventional operations. Also effectively ramping up the development means a faster path to fracking the wells inventory we've built as well to be able to be ready for production. Yes, we can have revenue starting to come in from 2027 on that. When it comes to the point around the repurposing, yes. That's the point we discussed that basically, yes.
Currently, as of now, the only one that's contracted is under [Oman ]. All others are still kind of different options. That is why we don't have them anywhere, neither in the 2026 guidance nor in the 2027 growth guidance. Yes, these can continue to play out into next year. It doesn't necessarily need to be wrapped up this year. Whether it comes in this year or next year, in either case will be an upside to the current guidance on both 2026 and 2027.
Thank you very much.
Thank you. The next questioner is Audrey Zong. Your line is now open. Please go ahead.
Hi. Good afternoon. This is Audrey from China Securities, and thank you for taking my question. I have two questions. The first question is about inventories. We noticed that the inventories increased by 51% YoY. Because you need to build additional stock to protect business continuity amid the regional situation. I want to know what the inventory consists of and when you expect that the free cash flow and inventory levels will be normalizing? This is the first question. The second question is about the fuel cost. Actually, you mentioned the fuel cost in your Onshore business. You mentioned that the higher fuel escalation supported Onshore revenue, while higher fuel costs also contributed to the increase in Onshore operating expenses. Could you please clarify what type of fuel and operational activities this cost relate to?
What was the impact of the higher fuel prices on the Onshore EBITDA and margins?
Why was fuel cost highlighted only for the Onshore segment rather than Offshore? Thank you so much.
Thank you so much, Audrey. On the first question, we have two types of inventory. We have the inventory, which is on the rigs. This is more of a cost item for us in terms of all the consumables and spare parts we need to use on the rig, et cetera. It's more of just for us to be able to earn the day rate. We have the inventory on the Oil Field Services, which part of it is actually that we sell. Part of that inventory is chemicals, fluids, et cetera. We actually make a margin on and we make money out of. In terms of the impact on free cash flow going forward, given that the inventory has already peaked, we don't see a continued impact on free cash flow because at this point, we're already at the peak.
What will happen is at some point, we'll have a benefit from the unwind of that inventory. At some point, we'll have a positive one-off impact on free cash flow, we go back to normalized levels. I think when that happens, that's uncertain because that's linking to when we have a more operating environment or transportation environment in which we are no longer concerned about potential disruption to our supply chain, and hence we are comfortable bringing down this to a normal level. I think that is yet to be seen when effectively you're able to reach that comfort on returning to a normal maritime operating environment. From here, there will be no further negative impact because we're already operating at that peak requirement, which is needed. The point on fuel cost. First, why is it an Onshore, not an Offshore?
The difference is in Onshore, part of our scope for the client is we buy that fuel ourselves, and then we supply it to the rigs, and this fuel is needed, or this diesel is needed for the effective generators on the rig in order for this to be able to generate the power for the rig and operate the rig. Whereas on the Offshore, it becomes both a cost and a revenue for us. Whereas on the offshore side, the client, ADNOC Offshore, is the one that does the procurement of the fuel, and they're the ones who cover and pay for it directly. We don't have it either in the cost nor in the revenue, and that's the difference between the two. When it comes to your point of why has it become more expensive, that's just a function of the increased oil prices globally.
Ultimately, the diesel, the fuel price is a function of this. As the oil price goes up, then the fuel or the diesel price becomes higher. We purchase it more expensive, and that's where the cost goes up. Then we sell it effectively to ADNOC Onshore, provide it to ADNOC Onshore, also more expensive, and hence where the higher revenue is. The impact at the end on EBITDA profitability is relatively immaterial because at the end, this is more of buying. We have a little bit of a markup there. At the end, the bulk of the cost gets transferred. Obviously, markup moves with the price, but the markup is not massively sensitive to the price. Hence, overall, what you will see is revenue and cost almost moving down and up proportionately together.
EBITDA net income would not change in a very large way quarter-on-quarter or year-on-year as a result of that.
Great. Thank you, Youssef. That's very clear and that's very helpful. Thank you very much.
Thank you, Audrey.
Thank you. The next question is from Rabih Moussa of Epicure Investment Management. Your line is now open. Please go ahead.
Hi, gents. Thank you. Thank you for the call. I have a couple of questions from my side. How do you expect the active rig count to grow over the next two quarters? What is the average day rate for the onshore rigs? I have one on the island rigs. Can you walk us through the timing of the new island rigs? What day rate do they earn and when do they start contributing? I will start with those.
Thank you very much. On the rig count, domestically, the major movement is related to the additional island rigs. We have one that started operations, and then we have five more starting operations between the end of this year and next year. Ramping up from around broadly 140 domestically to around 145 domestically, broadly. When it comes to the regional part, currently we have broadly around 30. The main ramp-up would come from the new rigs won by MBPS, predominantly the four additional rigs. We have that rig moving outside. SLDC for now, the rigs they won is more of a renewal of existing rigs. Net net will be around 35 region. I would say by the end of next year, we should be somewhere around the 145 domestically plus the 35 regionally. We should be somewhere around the 180 rigs.
When it comes to the island rigs, the rig CapEx per rig is around $70 million. We're effectively adding almost these rigs one every quarter, every other quarter until the end of next year. If you look at it on a revenue, you see on average, the island rig makes around $20 million of average revenue a year. You're looking at $25 million. You're broadly looking at around $70,000 implied revenue per day for these island rigs if you do the $25 million on the number of days.
What are the day rates for the jackups, the 36 jackups?
If you look blended revenue per day, we're currently at around $95,000-$100,000 implied revenue per day. If you look at the total revenue making from the jackups on the jackup count we have, implied revenue per day is around $95,000-$100,000.
Okay. Thank you. I have a question on the Onshore margin. Where do you see the Onshore margin settling once the SLB and MBPS are fully integrated? It fell from 35%-29% year-on-year.
Yes, I think for us, ultimately, we see it close to around in the mid-to-high 40s. That will just depend on the ultimate mix between regional and local. Local rigs will continue to be around 48%-49%. Regional rigs between 30%-35%. The blended will be somewhere between 45%-47%, depending on the weighted average between the two sub-segments.
Okay. Thank you. One on the CapEx. How is it split across segments, your guided CapEx for this year?
The $600 million, we have around $200 million on the island rigs. That is the single biggest component. Then the remaining amount, the majority of that is on the maintenance side. We have around $250 million on maintaining both existing rigs as well as the OFS. Then we have another around $150 million of growth CapEx outside the island rigs, and the majority of that is on the Oil Field Services side. Then we have, again, some on the rig side in terms of some of the new automations, cameras we are putting on some of the rigs, et cetera. The single biggest component is maintenance, followed by offshore island rigs, followed by oil field services growth CapEx.
Okay. Thank you. On the Al Ghallan jackup, can we factor in more reactivations or should we expect more reactivation similar to this jackup coming in?
I think for now we'll stick with that. I think for us, again, we want to guide on more of a contracted and also contracted. While obviously we're always going to be seeking different ways, again, to repurpose, et cetera, for now, we're just guiding based on the ones that we do have a contract for, and we will keep it based on that. Obviously, if something gets reactivated, repurposed, or operating in a different environment, then obviously we'll communicate that immediately.
Okay. Thank you, Youssef. One final one on the tax. What rate should we expect going forward under the new U.A.E. tax rules?
We said the 9%. We're subject to an Abu Dhabi fiscal tax as opposed to the U.A.E. federal income tax. For us, we remain bound by the Abu Dhabi fiscal arrangement, which continues to be at the 9%.
Okay. Thank you, Youssef. That was very helpful. Thank you.
Thank you. The next question is from Ildar Khaziev of HSBC. Your line is now open. Please go ahead.
Hello, thank you so much. I have a question about CapEx. You mentioned that CapEx will likely be at the lower end of your range, which is $600 million. Can you clarify why it has moved lower, and should we expect this CapEx to be pushed into 2027? Thank you.
Exactly. We see that more as a carryover because, for example, some of that was an allowance more on the unconventional side on the fracking and the additional rigs. Effectively as that FID is now expected to come into Q4, by definition, by the time that happens and we place the orders and we start accruing performance milestones on that, there would not be any material contribution to the CapEx from an accrued perspective in 2026. That really was the major balance of our CapEx. We expect that to almost follow into next year. If, let's say, if we started saying, okay, this could have been up to $800 million this year, $200 million of it got phased into next year, obviously we definitely expect the CapEx next year to be higher than this year.
We'll finalize the exact CapEx as part of our Q3 results when we're providing full-term guidance. Definitely, yes, that is a CapEx phasing from this year to next year, we expect a higher CapEx next year compared to this year to reflect this phasing. We still have the island rigs coming in next year, we still have that. We still have the OFS growth. Everything that we had this year in terms of maintenance and growth, that $600 million, still carries forward into next year. On top of it, potentially that $200 million of rephasing of the unconventional CapEx into next year. Probably next year is where we will become closer to that, again, $800+ million. We'll finalize the exact number. Whereas this year becomes the lower end of the $600 million.
Very clear. Thank you so much.
Thank you. As a final reminder, if you would like to ask a question, please press star followed by one on your telephone keypad now. We have no further questions at this time. Therefore, this concludes today's ADNOC Drilling second quarter 2026 earnings webcast and conference call. Thank you all for joining, and you may now disconnect your lines.