Noble Corporation (NYSE:NE) Q2 2024 Earnings Call Transcript

Noble Corporation (NYSE:NE) Q2 2024 Earnings Call Transcript August 1, 2024

Operator: Thank you for standing by. My name is Bailey, and I will be your conference operator today. At this time, I would like to welcome everyone to the Noble Corporation’s Second Quarter 2024 Financial Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. And I would now like to turn the conference over to Ian McPherson, Vice President of Investor Relations. You may begin.

Ian MacPherson: Thank you, operator and welcome everyone to Noble Corporation’s second quarter 2024 earnings conference call. You can find a copy of our earnings report along with the supporting statements and schedules on our website at noblecorp.com. This conference call will be accompanied by a slide presentation that you can also find located at the Investor Relations section of our website. Today’s call will feature prepared remarks from our President and CEO, Robert Eifler, as well as our CFO, Richard Barker. Also joining on the call are Blake Denton, Senior Vice President of Marketing and Contracts; and Joey Kawaja, Senior Vice President of Operations. During the course of this call, we may make certain forward-looking statements regarding various matters related to our business and companies that are not historical facts.

Such statements are based upon current expectations and assumptions of management and are therefore subject to certain risks and uncertainties. Many factors could cause actual results to differ materially from these forward-looking statements, and Noble does not assume any obligation to update these statements. Also note that we are referencing non-GAAP financial measures on the call today. You can find the required supplemental disclosure for these measures, including the most directly comparable GAAP measure and associated reconciliation in our earnings report issued yesterday filed with the SEC. Now, I’ll turn the call over to Robert Eifler, President and CEO of Noble.

Robert Eifler: Welcome, everyone, and thank you for joining us on today’s call. I’ll begin with highlights of our second quarter results and recent contract awards, then provide some perspectives on the market before turning the call over to Richard to discuss the financials. Lastly, before we go to Q&A, I’ll wrap up with a brief update on our pending acquisition of Diamond, which we are incredibly excited about. Starting with the Q2 results. We had a solid quarter with adjusted EBITDA of $271 million, up nearly 50% compared to $183 million in Q1, with a sequential improvement driven by several key contract startups, including the Noble Regina Allen commencing its contract in Argentina in early May and the Noble Discoverer starting up in Colombia in mid-June.

Subsequent to quarter end, the Noble Fay Kozak has commenced its contract in Brazil in mid-July. Each of these three rigs entailed significant contract preparation scopes, and I’d like to commend our projects teams on executing these crucial shipyard programs very well. In light of these derisked contract start-ups, we are narrowing our EBITDA guidance for this year to a tighter range of $950 million to $1 billion. In June, our Board of Directors announced a 25% dividend increase to $0.50 per share for the third quarter of 2024. This next distribution in September will bring cumulative total capital return to shareholders since our Q4 2022 merger to $470 million and also establishes Noble as the highest dividend payer across all U.S.-listed oilfield services.

And while this is a good start, we are confident that the free cash flow potential of our business in the years ahead looks demonstrably higher, and we will remain committed to returning essentially all of our free cash flow via dividends and share buybacks as this cash flow inflection develops. As reflected in our updated fleet status report published last night adjacent to our earnings release, our total backlog stands at $4.2 billion compared to $4.4 billion last quarter. I would remind you that since our backlog does have a high concentration to the long-term contracts in Guyana and Norway that do not replenish regularly. This tends to create some noise in our backlog trend line. In the Gulf of Mexico, the Noble Stanley Lafosse was extended by Murphy for five additional wells spanning approximately one year from February 2025 through February 2026 for a total contract value of $177 million.

On the jackup side, the Noble Resolve has picked up two additional contracts. First, a 45-day well with Central European Petroleum offshore Poland, followed by a 13-well P&A scope in Spain commencing in Q2 2025 with an estimated duration of about 6 months. Additionally, the Noble Resilient picked up a short-term intervention job with Harbor in the North Sea that has served as a helpful gap pillar this summer between the rig’s other existing programs. And most recently, the Noble Innovator has been extended by BP in the U.K. North Sea from May through December 2025 via prices option of $155,000 per day. Collectively, these contract fixtures represent approximately $275 million in total contract value, including mobilization payments. Now, I’d like to turn to a broader outlook with our semiannual review of current and expected deepwater activity levels across the key geographic segments.

The contracted rig count of UDW floaters with 7,500 feet or greater water depth ratings, currently stands at 105 rigs, up one from last quarter and representing 94% utilization of the marketed fleet, excluding sideline capacity. This level has been fairly constant over the past year as industry expectations for the next leg hire in activity have been constrained somewhat, both by tight rig capacity as well as by lengthening cycle times for certain long-term tenders to convert into contract awards. However, despite flatter activity recently, the forward indicators for further growth through the cycle remain firmly intact. This includes a strong pipeline of FIDs and extremely robust subsea orders as well as customer tenders and direct dialogue regarding future drilling plans.

The historically high level of open demand that we’ve cited over the past couple of quarters has recently increased further to over 110 rig years now. That’s not surprising at all given the relatively low proportion of tenders that have converted to contract fixtures recently. We recognize that there’s a growing need in curiosity about what’s causing the slower pace of awards of late. And while there’s not a single uniform answer, we believe that there are a few contributing factors at play with various parts of the customer base, including, first, capital discipline and stakeholder alignment complexities that are causing contracts to take longer to execute, including partner approvals, permits, et cetera. Second, field development supply chain pinch points, resulting from the sharp rise in global project backlogs over the past few years; and third, short-term after effects resulting from upstream consolidation transactions, which has definitely been a factor at play in the Gulf of Mexico recently.

Although there is generally no indication or expectation of drilling programs being structurally deferred, the recent slower cadence of rig contract awards does factor into the persisting utilization headwind confronting the sixth gen and lower-end segment of the market, which appears likely to drag into 2025, more than we would have assumed earlier this year. Another way to frame this dynamic is to look at how industry backlog has progressed over the past few years, whether measuring backlog by either contract length or in terms of absolute dollars, — the industry UDW fleet witnessed a 40% to 50% backlog expansion between early 2022 and the first half of 2023. Since then, however, total backlog for the industry deepwater fleet has been generally flat, and this looks likely to continue into 2025.

While this slowdown has lasted longer than we had expected, all of the leading indicators for increased activity remain highly compelling. And taking all of this into consideration, we expect the next move higher in industry backlog is likely to come into view sometime next year. With that, let me now turn to the bottoms-up market outlook. The Golden Triangle of South America, Gulf of Mexico, and West Africa comprises over 75% of global UDW market led foremost by Brazil, which has now increased to 34 rigs, up from 27 a year ago, with Petrobras comprising 30 of the 34 UDW rigs in Brazil. Elsewhere in South America, Guyana is at five rigs, Columbia one, and Suriname is currently at zero. Looking out to 2026, this region appears capable of expanding from 40 rigs currently to up to 45 based on visible customer needs.

Next, in the Gulf of Mexico, UDW demand currently stands at 24% and has been fairly stable in the 23 to 25 unit range over the past year. The U.S. Gulf of Mexico has actually been steady to up slightly since early 2023, while the Mexican side has fallen off from three to four rigs of normalized demand to just one unit currently. The inconsistency of activity in Mexico has been one of the contributing downside factors to the region’s market balances recently. The U.S. Gulf, despite digesting a short-term impact from E&P consolidation has been steady as predicted, with current activity of 23 deepwater rigs. There remains a relatively thin spot market over the next few months with the five or so units with near-term availability. However, customer demand indicates that the combined U.S. and Mexican and Gulf of Mexico should remain approximately flat compared to current levels.

West Africa currently has 18 contracted UDW rigs, down slightly from 19 to 20 last year. Angola leads the region with seven rigs with other activities spread broadly across various other countries. Notably, Namibia is currently at a roll with just one active rig compared to three to four rigs last year. There is a clear line of sight to Namibia maturing into at least a three to five-rig market structurally by 2026 as development plans get underway. Coupled with the likely commencement of gas development in Mozambique, the combined West and East Africa market could drive incremental UDW rig demand of five or more units by 2026. The Mediterranean and Black Sea region currently support eight units of demand, which we expect to be flat to down one unit over the next one to two years.

The Far East market, including India and Australia represents seven units of UDW demand currently. And Indonesia is expected to drive an incremental demand for a couple more rigs starting from late 2025 or 2026. And then finally, we expect the harsh environment markets of Norway, U.K. and Canada to remain steady, plus or minus. Tying all of this together, the market does feel more flat or up only slightly at least through the first half of 2025. So, we are maintaining a patient and disciplined approach in the meantime. We also continue to pursue intervention work with the Globetrotters, which we are hopeful will begin to show some initial wins fairly soon, albeit with minimal contribution before late 2024 or early 2025. Against this demand backdrop, we expect dayrates to remain in the high 400,000 to low 500,000 range for Tier 1 drillships over the near-term, excluding stacked rigs bidding into multiyear programs at customary discounts, and 6G rates will likely soften slightly until the swap comes out of the lower end of the market.

However, assuming the next leg up in demand materializes as envisioned by 2026, a further increase in day rates is very probable. So, with that, I’ll pause here and pass it to Richard to cover the financial highlights.

Richard Barker: Thank you, Robert and good morning or good afternoon all. In my remarks today, I will briefly review the highlights of our second quarter and then touch on the outlook for the remainder of the year. Contract Drilling Services revenue for the second quarter totaled $661 million, up 8% from $612 million in the first quarter. Adjusted EBITDA was $271 million in Q2, up from $183 million in Q1. Our adjusted EBITDA margin on total revenue improved to 39% in Q2. Cash flow from operations was $107 million, capital expenditures were $133 million and free cash flow was negative $26 million. The sequential improvement in the financial results was driven by stronger utilization across the fleet, including contract start-ups for the Noble Discoverer, Noble Resilient, and Noble Regina Allen as well as the abatement of contract preparation and startup costs that burdened contract drilling expense more heavily in the first quarter.

Our 16 marketed floaters were 78% utilized in Q2, up from 76% in the first quarter. And our 13 marketed jackups were utilized 77% in the second quarter, up from 67% in the first quarter. Average earned day rates in Q2 were 436,000 per day for floaters and $156,000 per day for jackups. As summarized on Page 5 of the earnings presentation slides, our total backlog as of July 31st stands at $4.2 billion, which includes $1.2 billion that is scheduled for revenue conversion in the second half of this year and $1.7 billion that is scheduled for 2025. As a reminder, this backlog does not include reimbursable revenue or revenue from ancillary services. Referring to Page 9 of the earnings slides, we are updating our full year 2024 guidance as follows; firstly, total revenue increases and now is to a range of $2.65 billion to $2.75 billion.

The slight increase in the range is driven by higher reimbursable revenue and revenue from ancillary services. Secondly, adjusted EBITDA now is to a range of between $950 million and $1 billion. The narrowing of the adjusted EBITDA range around our previous midpoint was driven by strong operational performance in Q2, offset by lingering white space in the second half for several floaters as well as a couple of weeks of additional acceptance testing preceding the Noble Faye Kozak contract commencement in mid-July. Thirdly, we are maintaining our guidance range of $400 million to $440 million for capital additions, excluding rebillable CapEx. We expect rebillable CapEx to be approximately $30 million in 2024 with $17 million spent in the first half of the year.

Looking forward to the third quarter, EBITDA is currently tracking slightly lower versus Q2, with sequential revenue tailwinds from the Noble Faye Kozak and a few other rigs, offset by greater anticipated white space on the Globetrotters and the Noble Voyager. I would like to now touch briefly on our free cash flow profile. As we have previously stated, this year’s free cash flow is expected to be heavily second half weighted, driven by higher CapEx in the first half and the key contract startups previously mentioned. Q2 was additionally impacted by the working capital impact associated with the Noble Regina Allen incident in late 2022. Due to the timing of some expected insurance proceeds potentially pushing into 2025, full year 2024 cash flow in the aggregate could be negatively impacted by around $50 million.

With the Q2 cash flow deficit, we did draw down $35 million on the revolver in June. We expect this to be repaid in the near future. We believe that we have now reached an inflection in our free cash flow. We continue to expect full year free cash flow to be up very slightly year-on-year and exiting at a very healthy run rate in the second half. As we look towards 2025, we remain constructive on the market outlook. However, we do recognize that until we see a pickup in the pace of contract awards to our total floater rig demand increases more materially. We are likely to see lower utilization for our currently uncontracted 6G rigs well into 2025. As it relates to capital allocation, and as Robert has mentioned, with the material step-up in free cash flow expected in the second half of the year, we expect to get back into the market and start executing again on our share repurchase program as we look to return essentially all of our free cash flow to shareholders.

With that, I’ll turn the call back over to Robert.

Robert Eifler: Thank you, Richard. Before we turn to Q&A, I’d just like to provide a quick update on the Diamond transaction. As disclosed last week, the HSR waiting period has expired, and the definitive proxy has been filed. Completion of the transaction is subject to the satisfaction of the remaining customary closing conditions, including Diamond’s shareholder vote, which is scheduled for August 27th and regulatory clearance in Australia. We are maintaining our expectation for closing by Q1 2025, although there are potential paths for closing this year. Not only are we incredibly excited about this highly complementary and accretive combination, but also it has been equally encouraging to see the market’s positive response to the transaction.

As the leading consolidator in the industry, we believe Noble has demonstrated a clear and powerful value proposition to customers, employees, and shareholders by leveraging scale and delivering seamless integration results for all stakeholders. I’m extremely proud and appreciative that our men and women onshore and offshore have established such a strong track record, not only is drillers, but also as highly effective innovators and integrators. This has been a huge X factor in what we’re trying to achieve and become. And I’m quite confident that bringing in Diamond’s world-class assets and people will provide another opportunity for us to shine together. With that, operator, we’re now ready to turn the call to Q&A.

Q&A Session

Operator: [Operator Instructions] Your first question comes from the line of Scott Gruber with Citi. Your line is open.

Scott Gruber: Yes. Good morning and solid quarter.

Robert Eifler: Thanks Scott.

Scott Gruber: I want to start on the macro, and I appreciate all the color around this pause we’re seeing. I guess I wanted to ask about the backdrop here. Are we really seeing a transition from the infrastructure-driven development focus post pandemic to a better balance between greenfield and tieback. It just strikes me that success in new frontiers such in Namibia is great for the industry. But does that contribute to a kind of temporary slowdown in contracting as operators process new prospects and think about resetting their future workflows?

Robert Eifler: Yes, it’s a great question. I think it’s kind of central to how we think about the medium term. There are some data that suggests that greenfield is ticking up. And I will say, in our own fleet drilling today, we’re seeing effectively the same percentage of the fleet deployed around exploration as we have for the past couple of years. But then there’s some of the third-party data out there that, as I mentioned, suggests that greenfield is improving here. Certainly — and of course, you can define it, I guess, a little bit differently. But certainly, the FID, the uptick in that we see and that we’ve been predicting will lead to a higher use of drillships worldwide is driven by greenfield. And so we’re pretty bullish about where this is headed here late 2025, 2026.

Scott Gruber: Got it. And then just turning to the Globetrotters. You mentioned finding intervention work for them. Does that mean that you’re likely to continue to focus on the Gulf of Mexico for those rigs? Or would you be willing to move those rigs out, even if you have to pay for it? And just the kind of overall thoughts on how consistent the intervention work could be for those assets here for the next year or so?

Robert Eifler: No, I think those rigs could work anywhere. We’ve actually pursued some intervention work well outside of the U.S. golf on a number of occasions. I would say that I guess the good news is that the lead time to booking intervention work is typically a lot shorter than drilling work. But I’d also say that, that’s probably more the case in the U.S. where things can move more quickly and there’s obviously all the infrastructure and everything right there, then elsewhere in the world where I’d say, on average, even for intervention work, there’s probably a slightly longer contracting lead-time elsewhere. But we’re bidding it all over and have some interesting opportunities in places outside of the U.S.

Scott Gruber: Great. I appreciate it. I’ll turn it back. Thanks.

Robert Eifler: Thanks Sean.

Operator: Your next question comes from the line of Greg Lewis. Your line is open.

Greg Lewis: Yes, hi, thank you and good morning everybody and thanks for taking my question. Robert, I was hoping you could talk a little bit more about what we’re seeing in the ultra-deepwater market. If you kind of like look at fixtures, it looks like really where we’re seeing the uplift in pricing is more in 2026 as opposed to rigs kind of being contracted for work starting in kind of the front half of 2025, realized in your prepared remarks, you mentioned Namibia and Mozambique. Is that really — you think what’s driving that? Or could there be a few other things, i.e. the yards that are still looking for the remaining contracts being gobbled up by then or just kind of hoping you can elaborate more on your thoughts around why we’re seeing those higher pricing, I guess, 12 to 18 months now?

Robert Eifler: Yes. Well, I guess a couple of thoughts. First of all, I think a lot of people — I wouldn’t say everyone, but I think a whole lot of people see continuing tightness, particularly in the 7G market. And so there’s an expectation that even with some of these shipyard rigs coming in that the market is going to be tight. We’ve used the word balanced a bunch in the past, which kind of standby, but balanced for sure, gives rise to increasing day rates is like we’ve seen for the past two years now. So, I think that’s part of it. We — as we said in the remarks, the next year or so is flattish. And so when you think through that, there’s perhaps a tendency to provide a slight discount for near-term work — but I don’t think that, that’s a major dynamic right now, frankly, among the highest end rigs.

I think generally, people see this — all these various forward indicators that we’ve described a few different times and are quite confident as we are that demand is going to materialize out of that.

Greg Lewis: Okay, great. And then I was hoping maybe you could provide some thoughts around the Voyager had that contract or wrapped up in Suriname, just kind of — you’ve been calling out, I guess, the bifurcation in the 6G market versus the 7G market for at least the last few quarters. That’s a seventh-gen dual BOP rigs. So any kind of thoughts around potential opportunities for that as we kind of look out over the next, I don’t know, six to 12 months?

Robert Eifler: Yes, I’ll let Blake give some color on kind of where and when we’re seeing opportunities. But there’s always a couple of 7G rigs available in Voyager happens to be right now, and we’ve got a bunch of conversations behind it, but…

Blake Denton: Yes, sure. Thanks, Greg. This is Blake. So, the Voyager did conclude its contract now. It will be performing SPS scope for the next couple of months and then be available later in the year. We’re bidding it all over the world, really, some good encouraging customer conversation. I think when we look at the likelihood of picking up the next contract, those conversations turning into firm awards, we’re looking more like first half of next year.

Greg Lewis: Super helpful. Thank you for the answers.

Operator: Our next call — our next caller comes from the line of Kurt Hallead with The Benchmark Company. Your line is open.

Kurt Hallead: Hey good morning, everybody.

Robert Eifler: Good morning Kurt.

Kurt Hallead: Hey I always appreciate the insights and the color on the market dynamics. So if I were to broadly summarize your summary, right, it looks like you guys are looking for potentially a range of 10 rigs of incremental demand once we get out into the second half of 2025 and into 2026 with half of that effectively coming from Brazil, the other half from Africa. I just wanted to make sure that I’m not misinterpreting anything that you said or misinterpreting any of your numbers that you put forth so far?

Robert Eifler: No, that’s it. I mean I would — I guess, I would qualify that we’re probably five to 10 total. You’ve repeated our description of where the 10 come from. If you get a few rolling off in the meantime, maybe the total incremental comes down a little bit from there, but probably a little too early to tell, but that’s right.

Kurt Hallead: Okay. And then maybe I know you guys have it stepped out and said anything about 2025 stand-alone yet. And obviously, that will all change once you get Diamond under your belt. But I would just venture to say that given what you’ve kind of mapped out right now, the second half progression on EBITDA and free cash flow probably spills over into the first half of 2025 barring any black swan events. Is that a fair way to look at things right now?

Richard Barker: Yes, Kurt, I think that’s a very good way to think about 2025. Obviously, we’re kind of seeing flattish EBITDA here in the second half of the year. One element as it relates to free cash flow, I do want to point out is that we do expect CapEx next year to come down nicely, right? So we’ve always said that 2023 and 2024 was kind of peak CapEx. And so as you think about free cash flow in the context of 2025, that number is expected to be down nicely versus 2024.

Kurt Hallead: Okay, that’s great. We’ll turn it over. Thank you guys.

Richard Barker: Thanks Kurt.

Operator: Your next question comes from the line of Eddie Kim with Barclays. Your line is open.

Eddie Kim: Hi good morning. Just wanted to ask on your revised EBITDA guidance here for the full year. You raised the low end of the guide from $925 million to $950 million. You previously talked about the low end of the guide being a level at which you could end up if you didn’t secure more work or incremental work for your I rigs. So, just curious if that is still a fair assumption today. It looks like you have three idle floaters today in the developer Globetrotter and now the Voyager. Does that low end of the guide, assume no incremental work for these rigs this year? Or how should we be thinking about that?

Richard Barker: Yes, Eddie, it’s a very good question. I think that’s a good way to think about it. We don’t need to win any more work to get to the low end. And look, it’s a somewhat tight range now. And I think there’s potential or real potential to get to the midpoint of the range with our new work as well.

Eddie Kim: Got it. Thank you. All clear. Just my follow-up is on the [Indiscernible]. You’ve been very disciplined with reactivating this rig. Just given the conversations you’re having, is it likely we’ll see a contract announcement for that rig before kind of midyear next year? Or given your flat kind of demand outlook in the near-term, could the timing of that contract announcement on that, Rick, maybe go beyond that timeframe.

Richard Barker: Yes. Look, I think always hard to predict on something that’s kind of could be way off. But I would weight it towards there not being a prediction before midyear next year. Another I think it’s more likely that an announcement would come after midyear next year than before. But there’s a lot in the pipeline right now, as we’ve described. Our customers are in budget season right now. And typically, you see a lot of tenders and negotiations that come out of that. And so we’re still kind of wondering as well when we’re going to see this pipeline materialize, it could be earlier than we kind of described in the call. And of course, like this year, maybe it pushes slightly later than we’d like. But yes, if I have to answer the question, I’m going to say it’s not in the first half of next year.

Eddie Kim: Got it. Great. Thanks for the color.

Operator: Your next question comes from the line of Doug Becker with Capital One. Your line is open.

Robert Eifler: You there Doug?

Doug Becker: Robert, you alluded to supply chain pinch points as one of the reasons for the slower pace of awards. I was hoping you could expand on that. Just where exactly are you seeing the bottleneck that’s causing this?

Robert Eifler: Yes, I would say that, that is a more general statement about supply chain kind of coming out of a pretty substantial ramp in activity. And it probably manifests at different points for different customers in different regions. I think as most people know, coming out of this extended downturn, inventories are very low and inventory management has been very efficient. And so there are not — there is not as much to just pull from shelves. And likewise, and kind of further down the supply chain, it doesn’t affect us, but it affects our customers when you get into vessels, FPSOs, more specifically, there’s a big backup in the shipyards. And so I think I think in some instances, it may be an FPSO. In another instance, it may be a wellhead and another one probably slightly less likely, but somewhere else it may be casing that if nothing else is making it harder to pull programs earlier.

So, you’re seeing this kind of gentle slide to the right that we’ve witnessed over the last year.

Doug Becker: That’s good context. And then you pointed out that the HSR has expired and you’re waiting on clearance in Australia. What’s the status with European regulators? Are there any European regulatory milestones you’re waiting for?

Robert Eifler: No, the only — the only remaining regulator is Australia. And I’ll add the color that was anticipated, and that really drove our original timeline and how we’ve described the first quarter maybe slightly earlier when we announced this. So really, nothing has changed on the total timeline because of that piece, but yes.

Doug Becker: Got it. Thank you.

Robert Eifler: Thanks Doug.

Operator: Your next question comes from the line of Josh Jayne with Daniel Energy Partners. Your line is open.

Josh Jayne: Thanks. Good morning. I wanted to switch a little bit and maybe get your global perspective on the jackup market. You talked about in your prepared remarks, sort of Northern European market is characterized by improving demand and visibility in Norway in 2025 and more cautious near-term outlook in the North Sea from some policy and permitting uncertainty in the U.K. Could you expand on both of those thoughts? And then maybe just give us a walk through the global jackup market, I think that would be helpful.

Robert Eifler: Sure. Yes, I can start and then Blake jump in. So, the U.K. has long awaited the elections there and the implications arising from that. Some changes have already been made. I think that market all things considered has actually performed pretty well. I think that the changes that have come politically there already since labor took over were well understood and anticipated. And so while obviously not helpful for our business. I think we’re right now not seeing any substantial negative change from what we’ve seen so far. I would remind that we do think that carbon capture could provide some helpful lift in that market, maybe next year, maybe the year after, but generally in the near to medium term going forward.

In Norway, it’s been basically flat, and we think it stays flat for a little while longer, perhaps with an additional unit of demand next year and then perhaps a leg up from there. More globally, there’s obviously a little bit of negative news out of Saudi recently. We are, as you know, not in the mix there, so not close to news flow. But I would say that the global jackup market is quite strong, and it’s stayed steady. It moved healthily straight through the more significant Saudi announcement from a few months ago. And we’ve seen a number of those rigs be redeployed elsewhere in the globe already. And so I think that market is generally pretty consistently strong.

Josh Jayne: And then maybe you could just talk operationally on the cost side. I think your commentary, looking into the first half of 2025 was helpful on the deepwater side. But over this period of sort of softer utilization for some of the deepwater units in your fleet that are available, could you talk about how you’re managing them on the cost side today. Maybe that would just be helpful things you’re doing in terms of trying to maximize cash flow while you have sort of this lull in your contracting activity for some of those assets?

Robert Eifler: Yes, it’s a good question. We are managing costs very closely. You heard Richard’s answer to — with some color around our remaining guidance here for 2024 and how a lot of that is within our control on the cost side. We’ve reduced costs where we have availability on some of the rigs. And obviously, we’re — that’s something that we have to do when we have availability, that looks like it’s going to stretch out more than just a short gap — so I think the organization has done a really, really good job. It’s been a focus for us this year. And our men and women that are in leadership positions on the rigs have a lot of influence on our handrail numbers. They’re focused, and they’ve done really a great job of managing their business rig by rig here this year. So, I’m very proud of what everyone has done.

Josh Jayne: Okay. Thanks.

Operator: Your next question comes from the line of David Smith with Pickering Energy Partners. Your line is open.

David Smith: Hey good morning and thank you for taking my questions.

Robert Eifler: Good morning.

David Smith: So, I think we have some previously stone newbuild drillships that are being priced into the market. But I wanted to ask if you’re seeing any signs of increased competition from some of the semis that have been sidelined for a while. I think there were some that previously worked in Mexico, and there are some relatively young Chinese mean Chinese newbuilds and whether that contributes to the comment about potential greater day rate bifurcation? Or if you’re really just talking about pricing softness for the active 6-gen semis facing potential downtime?

Robert Eifler: Yes. Look, it kind of all runs together or in sync, I guess. We think on the sixth gen side, if you just look at rigs rolling off contract for the remainder of the year, as you described, we’ve got some active rigs that have rolled off or are rolling off and then you’ve got some others that have been off a little longer. So utilization probably dips before it returns to flat here in the very near-term on the six-gen side. And then, as I mentioned earlier, that some of those rigs can go into the shorter lead time type programs. And so I think there’s a chance of a pretty quick recovery as customers come out of budget season, but we’re just going to have to wait and see. We just don’t really know right now. But it all goes in, in my opinion, it all goes into the kind of a total marketed utilization that affects bidding behavior, I don’t know.

Blake Denton: Yes. The only other comment I would add to that is when you look at our benign semis, we compete at the very top end of the market. So, the drilling efficiencies on our D class rigs rival drillships. And so you see — we compete well with operators that are looking at a really total cost of ownership model and factor in those efficiencies. Where you see the lower spec semis compete is for really great focused operators largely in regional basins.

David Smith: Good color. I appreciate that. And just a real quick follow-up, following up on Josh’s question, specifically the improving visibility in Norway for 2025. My recollection is no way demand for jackups tends to have longer visibility often longer-term contracts. So, I was curious if that visibility improvement for 2025 maybe includes some timework that could help from a visibility past 2025?

Robert Eifler: Yes, there’s the potential for a little bit of term work and there is the potential for a little bit of shorter-term work there from what we know about. And I guess I would kind of say that a true step up with solid term work, probably more of a 2026 thing than a 2025 thing.

David Smith: Great. That’s all I have. Thank you very much.

Operator: And your next question comes from Noel Parks with Tuohy Brothers. Your line is open.

Noel Parks: Hi good morning. You’ve talked a good bit about sort of what the customers are thinking. And I was wondering around the capital discipline aspect of their pace of decision-making, do you give a sense more an issue of sort of notification or disclosure of their plan that is what’s going on or more actual hesitation internally even commit to what they might do going forward?

Robert Eifler: Yes. It’s — I guess it’s a combination of things. One, just capital discipline, as everybody knows, is — remains paramount for everyone, where whether it’s on the E&P side or on the services side. And so I think people are making very conservative investment decisions that just has an obvious effect. But another place that perhaps this plays out is that in that kind of or of conservatism, you have in any given investment decision, almost always, you have various different partners. That perhaps have various different capital requirements or views or thresholds. And so we’re seeing a number of instances where you’re getting kind of two out of three partners that would like to do something or one out of three or something that has either disrupted a project or maybe just moved it in more instances, just push it to the right a little bit until waiting on new information or waiting on whatever it may be.

But we are seeing that as somewhat of a dynamic. I also think as you — here, our business often kind of seasonal around budget season, we’re all kind of waiting to see what gets approved. But I think it plays out in that sense as well, where in a world that’s extremely disciplined, maybe it’s less obvious what’s going to get approved and not as they go through their own budgeting processes.

Noel Parks: Great. Thanks. And just sort of a related question. You mentioned where there’s white space. Of course, that’s visible to everyone. And I guess I’m thinking from the standpoint of who’s on the far end of the white space. Do you have any sense that customers that may be kind of a loss there — I shouldn’t say a loss, but are a little bit less worried about schedule slippage because, I mean, the potential always exists, like you can fill the white space, right, and that, that could have some ripple effects? Or are the customers just like we want the price we want, that that’s kind of our main concern, and we’ll just roll with whatever happens as far as availability?

Robert Eifler: Yes, I think the mood right now — I mean, everybody sees availability this year. And everybody knows that there’s a few rigs that could come in from the sideline, these so-called stranded shipyard rigs. I think the average kind of belief is that there’s going to be some availability in 2025, and that gets a lot tighter at the end of 2025 and going into 2026. And so you see that play out with some people who are probably more risk averse and more concerned about what’s coming there. And then some others that have watched the last few years and said, well, generally been able to get a rig and Noble to describe it as a balance and maybe perhaps someone sees it as balanced as well and is comfortable waiting. But I think you see kind of a variety of different beliefs and approaches.

Noel Parks: Great. Thanks a lot.

Operator: And there are no further questions at this time. Mr. MacPherson, I will turn the call back over to you for closing remarks.

Ian MacPherson: Great. Thank you, everyone, for joining us today, and we look forward to speaking with you again next quarter. Goodbye.

Operator: This concludes today’s conference call. You may now disconnect.