Thanks, Greg. Reported revenue for Q3 2024 of $268 million included $3 million for amortization of intangible liability that’s related to the 5 rigs we purchased in 2022. As such, we’ll continue to focus on and refer to adjusted revenue, which excludes the impact of this item. Adjusted revenue for Q3 2024 of $265 million included $197 million of day rate revenue, $62 million of mobilization and bonus revenue, and $6 million of recharges and other revenue. Adjusted revenue for the quarter increased by $34 million or 15% relative to Q2 2024. The sequential revenue increase was mainly driven by the $45 million one-time acceleration of mobilization revenue on two suspended rigs in Saudi Arabia related to future years. Without this acceleration, adjusted revenue would have been $216 million for the quarter compared to approximately $231 million of adjusted revenue in the second quarter of 2024. The change in adjusted revenue quarter-over-quarter reflected higher revenue in Vietnam following the contract commencement of the Shelf Drilling Perseverance in August of ‘24, partly offset by lower revenue in Saudi on three other suspended rigs, the Main Pass I, Main Pass IV and Shelf Drilling Achiever and lower revenue in Nigeria as a result of the sale of the Baltic during the third quarter and the end of operations of the Trident VIII, which resulted from the structural lead damage incident we discussed earlier. Effective utilization decreased to 77% in Q3 from 80% in Q2. This is mainly due to the suspension of the operations of five rigs in Saudi Arabia, and the planned shipyard for one rig in Saudi Arabia, and the sale of one rig previously operated in West Africa. Average day rate of $82,000 per day in Q3 was largely unchanged from the previous quarter. Operating and maintenance expenses of $133 million in Q3 decreased from $142 million in Q2, primarily due to lower operating costs on 4 suspended rigs in Saudi, on two rigs in Nigeria, that was the Baltic and Trident VIII and lower shipyard costs on the Shelf Drilling Perseverance ahead of its new contract commencement in Vietnam in August. This was partially offset by higher mobilization costs for the Shelf Drilling Achiever, which started a long-term contract in Nigeria in October. Turning to G&A. G&A expenses of $17 million in the third quarter increased marginally from $16 million in the second quarter. Adjusted EBITDA was $114 million in Q3, representing a margin of 43%, this compared to $72 million and 31% in the previous quarter. Adjusted EBITDA was negative $5 million at Shelf Drilling North Sea with the Shelf Drilling Barsk not working throughout the quarter, and $119 million generated from the rest of the business in Q3. Again, the sequential increase in adjusted EBITDA for Shelf Drilling, excluding SDNS, was mainly driven by the $45 million acceleration of mobilization revenue for the two suspended rigs in Saudi. Income tax expense was $8 million in the third quarter, in line with Q2 and year-to-date tax expense of $25 million represents 3% of revenues. Net interest expense of $36 million for the quarter was $10 million lower than the prior quarter due to the $10 million of one-time expenses associated with the SDNS debt refinancing transaction completed in Q2, the majority of which was non-cash. Non-cash depreciation and amortization expenses totaled $53 million in the third quarter, up from $48 million in Q1 due to higher amortization of deferred costs for 1 suspended rig in Saudi Arabia. The quarterly net income attributable to controlling interest was $68 million in Q3 and included a $45 million gain for the sale of the Baltic. Capital expenditures and deferred costs were sequentially down $3 million to $35 million in Q3, which included $9 million at SDNS. The decrease was mainly due to lower expenditures on the Shelf Drilling Perseverance and preparation of its new contract, which started in August in Vietnam, and on the Shelf Drilling Barsk for a planned contract commencement later in November in Norway, as well as lower spending on fleet spares. This was partially offset by higher contract preparation spending for the Shelf Drilling Mentor and Shelf Drilling Fortress ahead of commencing their new contracts in Q3 in Nigeria and United Kingdom, respectively. Higher spending on the Main Pass IV expected to start operations in Nigeria in December and on the High Island IX in Saudi Arabia for a planned maintenance shipyard project. Our consolidated cash balance as of September 30 was $220 million or $82 million higher than the balance at the end of June. Cash at the parent company increased from $101 million to $193 million, primarily due to the $57 million receipt of net proceeds for the sale of the Baltic and lower debt service payments in Q3. Cash at Shelf Drilling North Sea decreased from $37 million in June to $27 million at the end of September. As a result of the increase in mobilization revenue in Q3, partly offset by delayed contract commencements on the three rigs in Q4 and the impact of further rig suspension in Saudi Arabia, we have revised our financial guidance for full year 2024 in our release yesterday. Fully consolidated adjusted EBITDA is now estimated between $320 million and $345 million compared to our last guidance in August between $290 million and $335 million. At the SDNS level, we now anticipate full year EBITDA between negative $10 million and negative $15 million, representing a decrease of $5 million from the last guidance range. And this shows a start date for Shelf Drilling Barsk in Norway in the second half of November 2024. The full year 2024 EBITDA guidance for the rest of the business is narrowed and increased between $335 million and $355 million, with full year revenues expected to improve from the last guidance by approximately $25 million, mainly resulting from the $45 million mobilization revenue acceleration on two suspended rigs in Saudi Arabia. Revenues in Q4, however, will be impacted by delayed contract commencements in Nigeria for the Shelf Drilling Achiever, which is already on contract since the end of October and for the Main Pass IV expected to be on contract by the end of the year as well as by the recent announcement of the contract suspension of the High Island IV in Saudi. We’ve also revised our full year 2024 guidance on capital spending, now established between $140 million and $160 million compared to our last guidance in August between $135 million and $160 million. The $5 million increase reflects the additional contract preparation at SDNS for the Shelf Drilling Fortress, Shelf Drilling Perseverance and Shelf Drilling Barsk. At the parent level, the full year 2024 guidance on capital spending is narrowed between $95 million and $110 million. The rig suspensions in Saudi Arabia and delayed contract commencement of Shelf Drilling Barsk in Norway have significantly impacted our financial results in 2024. The Shelf Drilling Barsk is now about to start its new contract and will contribute in 2025 to deliver strong earnings and cash flow visibility at the SDNS level with all five rigs under contract. After successfully redeploying two of the rigs impacted by contract suspensions in Saudi, we remain confident in our ability to secure attractive opportunities for several other of the suspended rigs with anticipated return to service by the middle of 2025. As Greg mentioned, since July, we have achieved several other important milestones for the company, including the successful completion of the SDNS acquisition, materially enhancing our fleet composition and simplifying our capital structure. On the back of the recent sales of Baltic in September, the Trident VIII insurance claim process concluded in October will also represent material cash flow inflow for the company in the near-term. These milestones and the significant steps taken this year to address the short-term challenges will position Shelf Drilling well heading into 2025. We’d like now to open the call for questions.

[Operator Instructions] And your first question comes from the line of Fredrik Stene from Clarksons Securities. Please go ahead.

Hey Greg and Douglas. Hope you all well and thank you for taking our question. I wanted to touch a bit on the market maybe first. You unfortunately have another suspension now on the High Island IV, I believe. How are you thinking about Aramco now? Because they seem to have been kind of drip feeding those suspensions into the market instead of doing it in one go as they did initially. Do you think they are done? Or could there be even more to come? Greg O’Brien: Yeah. I think drip feed is the right term. You go back to kind of how this all started the rig count was in the low-50s three years ago. Saudi production was at 10 million barrels a day, and the government decided they wanted to go from 12 million to 13 million. And really all of that production growth had to come from offshore. So that was the trigger for the massive uptick in activity through the course of ‘22 and ‘23. Today, they’re producing 9 million barrels a day. And obviously, they’ve decided to cancel that production expansion program. They’ve released 27 rigs in total through the first two rounds. So the rig count was back to the low to mid-60s, is still above where it was before this growth initiative kicked off. We believe they may try to end up back closer to that level in the mid-50s, which implies there’s something like up to another 10 units still to be released. We obviously don’t have perfect visibility. It’s been pretty difficult to predict exactly what they’re going to do. I think part of it’s been tied to production plans. I think there was a hope and a belief that the production cuts would start to be peeled back. That hasn’t happened yet. They’re still continuing to extend these voluntary production cuts. So yes, we were impacted with one additional unit. We don’t think that’s it, to be perfectly honest. There is a floor that has to be relatively high. I mean it seems hard to believe the rig count could go lower than where it was three years ago, but a lot will depend on where oil price is, where the oil markets are in terms of balance -- but yes, our belief is, there will be other news in the coming weeks from other contractors, but that’s more of our sort of guess and expectation based on what we’ve pieced together. So hopefully, there’s not much more just given how much has already been taken out of the rig count in Saudi this year. But that seems to be a possible landing that the rig count ends up kind of back to where it was before the ramp-up three years ago.

That’s very helpful color, Greg. Thank you. And as a follow-up to that, you guys are international and you obviously have the ability to take your suspended rigs and try to employ them in the other hubs that you are present. But are you able to say something about, call it, the competition from particularly the local players that have also faced suspensions in the Middle East. Are you -- are they keeping themselves to the Middle East? Or have you seen them starting to drip feed or bid their assets into other places as well? And I guess I’m particularly interested in those that I would consider purely local. There are some Chinese players and coastal agents that have bids elsewhere, but the rest, have you -- is it fair to assume that some will be stuck in the Middle East regardless of what Aramco does? Greg O’Brien: Yeah. I think there’s some capacity that likely stays there. But I think for the most part, contractors are trying to find ways to place rigs elsewhere. Some regions are easier to access than others. Some customers are more open to new contractors than others. Southeast Asia is a place where there’s been very good demand, but there’s been more competition. So there have been a couple of softer day rate prints in Southeast Asia. But there have also been some good data points over the last few months as well, like the extensions we announced a few weeks ago. West Africa hasn’t seen as much supply move there because it’s farther away, it’s obviously more costly to move rigs there. And it’s a place that we think is hard to have a small subscale business. We’re the largest player in West Africa and have retained a large position there through good times and bad times. So that helps like for us to scale up another rig or two there is relatively easy to do. It’s, in our view, much harder and makes less sense to move a single rig there. And that’s the other place where we do see very good incremental demand. So yes, some of the regional players have tried to move assets elsewhere and are looking at different ways and structures to do that. And I personally think the rig count in Saudi will eventually go up again. I mean a lot depends on where you think oil demand goes. And if you believe it will continue to grind higher for the foreseeable future, Saudi is going to want to and need to produce more oil. The only place they can do that is offshore. But that’s probably not in the next three to six months, unless something changes. So yeah, you do have -- there are 8 jack-up contractors in Saudi, there’s been an impact on all of them. We’ve obviously been hit more than some others, and we do have an ability to move rigs elsewhere. We’ve made good progress there. We’ll continue to make progress here in the next few months, but it’s been a little bit harder for some of those contractors that don’t have the same footprint and market reach that we do.

Appreciate the comprehensive comments, Greg. I’ll leave with that. Have a good day. Greg O’Brien: Thanks, Fredrik

[Operator Instructions] And your next question comes from the line of Nikhil Bhat from JPMorgan. Please go ahead.

Thank you. Thanks Greg and Douglas for presentation. I have a few questions. One on the suspended High Island rig. Do you mind giving us some color on its capability? And can it be deployed to markets outside the Middle East? Greg O’Brien: Yeah. So right now, we have four rigs still operating in Saudi. They’re all our High Island rigs. And they all have a similar feature. They can operate in and transit through really shallow waters, which is a unique characteristic. There are not many of these rigs in the world. It is a characteristic that is important in the Middle East. That’s part of the reason our rigs have been successful there for so long. They are smaller rigs that have shorter legs. So that does, to some degree, limit the sort of breadth of opportunities elsewhere. So it’s not like the High Island IV could easily go to anywhere else in the world, but obviously, we’re going to look at opportunities. We have a few other standard jack-ups that I’d say are higher priority for us right now. The Harvey Ward is one we’re confident we’ll find work for. The Trident 16 we talked about in Egypt. We think there’s -- there will be activity for that rig there pretty soon. And then obviously, we have a few rigs coming off in India, and we’re focused on trying to recontract a few of those units there. So the High Island IV would not be at the top of our list right now in terms of trying to find a new home, but we do think there will be other opportunities. We’re also trying to see if there are alternative uses for some of our units. P&A is an activity we’ve talked a lot about. That’s an opportunity we set, we think it’s getting bigger and bigger in multiple regions around the world. And that’s the type of activity you typically don’t need a big, fancy, capable rig. So it is a unique rig design. It’s very well suited to operate in Saudi. So that’s part of the reason we’re disappointed with the news. So yes, we’re still working through options. Hopefully, we’ll have news on a few of the other standard rigs first, and then we’ll look to prioritize the High Island IV as well.

Thank you. On a related question -- sorry, on a related topic, now that -- like how are you thinking about High Island V, whose contracts expiring in May ‘25, given what’s happened with High Island IV? Greg O’Brien: Sure. Yeah. So the four rigs, they are the same design, but they’re not exactly the same. So the High Island V and High Island IX are on workover contracts and have been customized for that type of activity in the past. The High Island II and High Island IV have been deployed in drilling since they came into Saudi 17 years ago. They performed extremely well, but they’re generally involved in a different type of activity and compete more directly, if you will, with other types of assets, including premium jack-up rigs. We think Aramco wants to keep the High Island V. That will have to be a negotiation and discussion in the coming months, that hasn’t formally started yet. So we believe they’re going to want to keep that rig, but we’re not -- there’s no clarity or answer yet. We should have more information as we get into the early part of ‘25.

Got it. My penultimate question is on ONGC. You mentioned about ONGC or at least your expectation of them issuing a tender for four standard jack-ups at the end of the year. What’s the typical time line that we should think of between, let’s say, whichever rig wins these success for the tender, when should these rigs commence operations, assuming the rigs are available immediately, of course? ‘ Greg O’Brien: Yeah. So we have three rigs coming off contract between a few weeks from now and the end of Q1 that would all be potential candidates for this tender. The two that will operate into 2025, it always takes at least a few months to prepare a rig for a new contract. And then a tender process takes some time, typically at least a few months. The other dynamic is you have this -- you have what’s called monsoon season in India, where you basically can’t start a contract in the middle of the year. It’s either by the end of May or after the 1st of September. So most likely contracts awarded in this next tender round would start second half of the year. But a lot depends on when the tender is launched, how quickly ONGC tries to move through the process, but these tenders with NOCs aren’t always the quickest processes. So our kind of -- it’s possible we could have one unit that could start again before the summer, but it’s more likely this would be second half 2025 start dates.

Thank you. I appreciate the color. Last one for me. Could I please pick on the moving parts behind your EBITDA guidance, especially excluding the North Sea business? Like at the midpoint of your guidance range, the implied fourth quarter EBITDA decline sequentially in the business, especially given North Sea, EBITDA is expected to improve given that Barsk would have commenced operations. Could you maybe talk us through the moving parts in terms of what causes this sequential decline in the business outside North Sea?

Yes. This is Douglas Stewart, speaking to the mobilization revenue, right? So we’re speaking about the inclusion of the $45 million of accelerated mobilization revenue that is included in this guidance. So that’s why you’ll see that in the very beginning excluded out of it. As for the business, we are showing a decrease for SDNS $5 million relating to slight delays in contract commencements. And then -- and also, you can appreciate that the Barsk’s expected date in mid-November as we hope that would be a little sooner than that. For Shelf Drilling, excluding SDNS 2024, we are showing essentially revenues expected to be down for the 1 rig that was suspended in Saudi, the High Island IV and further offset of delayed starts for the 2 rigs in West Africa. So if you look at the Achiever, that was expected to start sooner. And then if you look at the Main Pass IV, that we expect -- that’s expected to start in December. We’d hope that would be in November. But those are the kind of the impacts to the range.

Got it. And are there any other, let’s say, costs that we should be aware of, let’s say, regarding -- I mean, the Baltic is already closed, but maybe the Trident VIII or so on?

Not impacting the EBITDA. Obviously, we spoke about it in terms of cash for the Trident VIII, where we’re expecting to collect the balance of the $50 million of proceeds by the end of the year, but not in terms of EBITDA.

Thank you both.

Thank you. Your next question comes from the line of Taiyadi Espino from Bank of America. Please go ahead.

Hey. It’s actually Gregg Brody from Bank of America. Tai works with me. Just -- so you mentioned the one asset sale in 1Q ‘25. Can you just talk about the depth of the market, where you see those rigs going? I know you were considering additional sales. Can you just walk us through how that gets -- how those occur timing? Greg O’Brien: Sure. Yeah. So the Main Pass I rig we’re running a bit of a competitive process, if you will. There are -- we had interest from several operators looking to buy a jack-up rig that was in decent condition that could be converted to a production unit. And for an operator, it’s generally quite a bit cheaper to do that than building a new production unit from scratch. I’d say that market is not enormous. There are typically a few of these projects a year, and time lines can depend on funding and well plans, et cetera. So we’ve had good interest in that unit. Could there be another one or two type of opportunities like that? I think so, but it’s not like you can sort of force that to happen in a 30 to 60 day period. So that’s the one rig we’re focused on for now. It’s still in class. It’s in good shape because it’s worked consistently for 17 years in Saudi. But we have started to take some of the drilling equipment off that can be used elsewhere in the fleet. And then we may have one or two other units depending on how things go in India, like I think we’d be prepared to shrink our fleet there by one or two units to try to make sure that market remains in balance. But that’s the only unit for now we’re focused on selling the Main Pass I. But this is obviously something that’s worth thinking about all the time, pretty dynamic process. And then I mentioned P&A is another way to try to deploy one or two standard jack-ups. And we do see live opportunities in a few markets for that type of work. But for now, yes, we’re focused on 1 unit. We’ve talked about up to $20 million potential sale price. I’d say that’s would be the better end of where we could shake out, but hope to have clarity on that rig next few months. And that could inform how we think about other units as we move into 2025.

And I know you mentioned P&A earlier, the P&A is for rigs you plan on keeping, not rigs you plan on selling for others to do P&A. Greg O’Brien: That’s right. I mean the Baltic, that was a somewhat unique case. We had a counterparty that had won the contract for a program in Malaysia, and they needed a specific asset. So it was their contract, they wanted to buy a rig, but then they’ve asked us to help them with most of the operation for that program. Yes, for the most part, we’d look to do this ourselves. We’ve done a lot of P&A work in Thailand and other markets -- and it’s -- we do think it’s a big kind of long-term opportunity set for us. That would be more kind of regular way day work contracts is the way to think about it.

Got it. And those things you would announce without -- you wouldn’t necessarily announce them as backlog and they would just be... Greg O’Brien: Yeah, that’s right. Yes, that’s right. That’s right.

And then just as we think about ‘25, how are you thinking about capital need -- sort of CapEx needs? And just remind us what’s -- how much you need to spend on maintenance? Greg O’Brien: So we’ll plan to give formal guidance in March when we’re out with year-end numbers. I think broad brush, we’re around 100 or a touch higher with our guidance for ‘24 on the kind of parent company fleet. I think that’s a reasonable level to think about on a go-forward basis. We used to talk about 115 plus, but we’ve now monetized two units, and we have one more that we’re looking to move off as well. So that helps bring down annual maintenance CapEx. And then the SDNS, that five rig fleet, this was a chunkier year because we moved a rig to Vietnam, and we had some contract prep to do on the Barsk in Norway. When we did that financing in the first half of the year, we talked about a kind of annual level closer to 25 as a long-term multi-year average, and that’s probably a decent kind of bogey to think about. So 130-ish is how I’d think about medium to long-term annual spending. But obviously, that’s more kind of high level. We’ll give more explicit guidance in a few months.

That’s helpful. Two more questions on industry and one specific question. Obviously, Pemex, not on the other side of the ocean. Do you see any of those rigs potentially coming overseas? What are you hearing? Greg O’Brien: I mean, possibly, we’re not as close to that market as some of our peers. What we’ve gathered is, this is more chatter, if there are suspensions, they’re probably more short-term in nature. What Aramco has communicated is the suspensions in Saudi are more indefinite in nature. So there’s a difference there. So I’m skeptical you’d see many rigs come out of Mexico to go elsewhere, just given how production has developed in Mexico and the need to keep putting money into the ground. But yes, we don’t have, I’d say, perfect insight there.

And then this is just a technicality here, with the rig suspensions in Saudi Arabia, it’s my understanding it’s -- they may have to switch to another rig after 12 months just because of the way the contract is designed. Is that correct? And does it really matter? Greg O’Brien: No. So most of the contracts, not every single one of them. So some of the rigs that were contracted in 2022 that are on these maiden contracts are more protected and generally have some degree of hook or termination penalty. And we were more weighted to extension contracts because we’ve had a large business in Saudi for a long period of time. As a result, sort of it was easier to look to suspend and lay off some of our rigs because units that had just come in had more of a short-term financial impact to Aramco to suspend. But these contracts generally have a suspension rate that’s up to one year, Aramco then could look to extend the suspension period. We asked for and received a right to terminate the contracts ourselves during the suspension period, which is what we did for the Shelf Drilling Achiever and Main Pass IV, so that those rigs would be free and clear. We can move them elsewhere. And we’ve now secured multi-year work for both of those rigs at frankly, better rates and margins in that market. But yes, it’s up to one year suspension period is how the construct generally works.

You gave us a way to think about how many more rigs could leave the market. Have Saudi said anything specific to you? Or are they -- does it continue to remain a little vague? Greg O’Brien: So what I mentioned in the -- I guess it was the question Fredrik asked. So the rig count had moved towards the mid-60s as of a few weeks ago. And we’ve gotten some indications that, that rig -- the rig count could move back towards the mid-50s, if production remains where it is and the production capacity target remains where it is. So we’ve been impacted by 1 unit. There’s been no other communication from other contractors in Saudi. If there are other rigs to be released, there will be news from other contractors. But again, that’s just more kind of gathering intel from different sources over the last few weeks. And obviously, this is dynamic, right? I mean if the oil markets improve with the presidential election, I think there’s an argument that there will be more pressure on Iran. That’s been a big source of supply growth in the international markets the last few years. Could that change? Possibly. So I think there’s a clear focus from Saudi on trying to help manage the oil price in the oil market. And obviously, fiscal cash flows, I think that’s the biggest driver of all this. But yes, that’s our latest thinking.

You’re the only one in the last week or so that’s gotten one of these notices. Greg O’Brien: That’s confirmed anything publicly, yes.

Yeah. Okay. And then the last question for you. Obviously, congrats on closing the North Sea transaction. I know there’s a guarantee from the top, but I’m curious, how do you -- in your mind, how do you see bringing these 2 entities together so you no longer have to report separate entities? Greg O’Brien: Yeah. So we now fully own that business on a 100% basis. From an equity standpoint, it’s brought in. From a credit standpoint, I think longer-term, that could make some sense. We’re still relatively early days in the bonds in both silos. So if we wanted to refinance the North Sea bond right now, there’d be a pretty decent early refinancing penalty and the parent company bond has not traded that well. So we don’t see any urgent need to do that. I think, proven over time, we try to find ways to streamline and simplify the capital structure. The way we set up SDNS was kind of the other direction, but that was a way to get what we thought was a great deal done. So I wouldn’t expect anything to change in the very near-term. But as we move through time and we get closer to call dates and those call prices step down, I think that’s something that would make sense. But yes, no immediate plans to do anything.

Right. Thank you for all the time, guys. Greg O’Brien: Sure. Thanks.

Thank you. Your next question comes from the line of Karl Blunden from Goldman Sachs. Please go ahead.

Hey, good morning, Greg. Thanks for all the color today. My question is just on the West Africa rig ramping now in December. Can you give a bit more detail on where you are in that process? Any potential for that time line to shift sooner or later? Or what’s the main risk factors you are watching at this point? Greg O’Brien: I think we mentioned that we expected to sign the contract in the coming days, which is pretty specific. The rig is physically there. Yes, we think the risk that the time line shifts is pretty low. We have been talking about this rig for some time, which we admit, but the rig is now there. We’re very close to getting this sort of formally done.

That’s helpful. Thanks, Greg.

Thank you. There are currently no further questions. I will hand the call back for closing remarks. Greg O’Brien: Very good. Thanks, everybody. Appreciate the time, and we’ll be in touch next few months. Thanks.