Thank you, operator, and welcome, everyone, to Noble Corporation's first quarter 2026 earnings call. You can find a copy of our earnings report along with the supporting statements and schedules on our website at noblecorp.com.

We will reference an earnings presentation that's posted in the Investor Relations page of our website as well. Today's call will feature prepared remarks from our President and CEO, Robert Eifler, as well as our CFO, Richard Barker.

We also have with us 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 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 an associated reconciliation, in our earnings report issued yesterday and filed with the SEC.

Now I'll turn the call over to Robert Eifler, President and CEO of Noble.

Thanks, Ian. Welcome, everyone, and thank you for joining us.

I'll open today's call with a brief summary of our Q1 highlights and recent contract awards, followed by an update on the market. Richard will then cover the financials before I wrap up with closing remarks and move to Q&A.

During the first quarter, we earned adjusted EBITDA of $277 million and generated free cash flow of $169 million. We again distributed our 50-cent quarterly dividend, and yesterday, our board declared a 50-cent per share dividend for the second quarter, maintaining our consistent and highly differentiated return of capital strategy.

Overall, it was a solid start to the year, and I'd like to thank our outstanding men and women of Noble around the world for your fantastic teamwork in helping us to realize our first choice offshore performance standards. While it's an understatement to say that energy markets have seen extreme volatility over the past couple of months since the outset of the Iran conflict, we're fortunate to have experienced limited operational disruption, confined to just one jackup in the Middle East, the Mick O'Brien, which we sold in January, but have continued to operate under a bareboat agreement.

All of our crew and related personnel were safely evacuated from the rig during the early days of the conflict, and Richard will expand on the rig's current status. Outside of the war-impacted region in the Middle East, commercial momentum throughout the offshore drilling market remains brisk, irrespective, in many ways, of the recent oil price surge.

However, the recent reawakening of energy security concerns around the world and the corresponding move higher in the oil futures strip are clearly supportive of the already steadily improving demand trends evident in the deepwater and harsh environment offshore markets where we operate. Over the past three months, we secured new contract awards totaling approximately $565 million.

First, the Noble Courage received an extension with Petrobras of slightly more than three years, which will keep that rig committed in Brazil through the end of 2030. This extension represents net incremental backlog of $339 million, with the current dayrate reduced from $290,000 to $280,000 from April 1st, 2026, through late 2027, followed by the extension of slightly over three years at just over $309,000 per day.

Next, I'm pleased to announce that the Noble Deliverer has been awarded a five-well contract from Woodside in Australia, which will support that rig's reactivation. This contract is valued at $121 million, based on an estimated 300 days of firm scope, excluding options, and also does not include revenue for additional services or potential rig upgrades.

In Guyana, the Noble Developer has been awarded a one-well contract with ExxonMobil at $375,000 per day, which is scheduled to slot in after the rig's current program, right around year-end. Next, the Noble Black Rhino has recently commenced an exercised option well for Beacon in the US Gulf, with an estimated duration of 100 days.

In Ghana, the Noble Venturer has been awarded a one-well contract with Planet One in Ghana at a dayrate of $430,000, expected to commence late this year with estimated duration of approximately 45 days, with two unpriced options. Finally, in Southeast Asia, the Noble Viking has received an additional one-well contract in Malaysia, which is expected to extend the rig through October this year.

With these awards, our current backlog stands at $7.5 billion. Now I'll share a few observations on recent developments in the market.

In short, all measurable and anecdotal indicators of deepwater rig demand are flashing green, and I would submit that this is not a reflection of $100 oil, because most of what we're seeing in the market today has been in motion for months or longer. Of course, recent events absolutely have elevated energy security priorities around the world, and improved upstream cash flows will only serve to enhance an already strong and expanding demand picture and deepwater exploration thesis.

In parallel, the volume of deepwater contract fixtures has spiked in the early part of this year, partially, but not entirely, due to the execution of Petrobras' wide-reaching contract extensions. The first quarter saw 32 rig-years of UDW fixtures, which was roughly double the average quarterly run rate of last year.

With conclusion of Petrobras' extensions in April, this month alone has already had more than 40 additional UDW rig-years fixed, bringing year-to-date backlog additions significantly above the entirety of last year's contracting volumes for the full year. Petrobras has comprised over half of 2026 year-to-date deepwater rig-years fixed, and non-Petrobras contracting activity has also continued at a healthy level.

Notably, despite this recent surge in contract fixtures, the pipeline of open demand in the form of tenders and pre-tenders has actually continued to expand rather than deplete. Last quarter, we observed slightly over 100 rig-years of open floater demand, which was a 33% year-on-year increase.

This figure has now eclipsed 110 rig-years. All of this tendering activity is developing alongside an increasingly tightening supply-demand balance.

Total UDW contracted utilization is currently 105 rigs, or 95% of marketed supply. This is approaching recent peak contracted demand levels of two years ago, albeit with markedly different directional momentum, especially considering the renewed length of backlog across the South America region, juxtaposed against open demand throughout the rest of the world that's now more than 55% higher compared to the previous high-water mark two years ago.

The contracted UDW count of 105 includes 14 rigs with future contracts that aren't yet working today, six of which happen to be Noble rigs. We have been anticipating the convergence of future contracted utilization and present utilization as a critical factor that could substantially eliminate industry white space and result in a comprehensively tight market.

This convergence becomes increasingly tangible as these 14 future contracted assets ramp up over the next 6 to 12 months with average contract durations of two years per rig. Taken together, all these market dynamics are resulting in upward dayrate pressure.

Therefore, we believe it is likely that we will begin to see floater rates move higher as we move through the rest of this year. Overall, with the continuing positive development of our backlog, as well as the state of the drilling market more broadly, we're even more optimistic about the years ahead than we were last quarter.

Now I'll pass the call over to Richard for the financial review.

Thank you, Robert, and good morning or good afternoon, all. In my prepared remarks today, I will briefly review the highlights of our first quarter and then discuss the outlook for the remainder of 2026.

Starting with our quarterly results, contract drilling services revenue for the first quarter totaled $742 million, adjusted EBITDA was $277 million, and adjusted EBITDA margin was 35%. Q1 cash flow from operations was $273 million, capital expenditures were $104 million, and free cash flow was $169 million.

I'd like to touch on a few discrete cash flow-related items during the first quarter. Firstly, we received $210 million in cash proceeds from the jackup sale to Borr Drilling, in addition to the $150 million seller's note, which is recorded in other assets on the balance sheet.

Secondly, we completed the lease buyout on the first two of the four BlackShips BOP systems for $36.5 million. The buyout of the remaining two BOP systems is expected to occur during Q2 and Q4 this year for approximately $18 million each.

In total, the lease buyout for all four systems is expected to cost $73 million. The cash outflow for these payments is not part of capital expenditures, but instead is part of financing activities on our cash flow statement.

Lastly, during the first quarter, we redeemed $55 million principal amount of the 8.5% senior secured notes at 103 as an opportunistic and efficient use of capital. As summarized on page five of the earnings presentation slide, our total backlog as of April 26th stands at $7.5 billion.

As a reminder, our backlog excludes reimbursable revenue as well as revenue from ancillary services. Our current backlog includes approximately $1.8 billion that is scheduled for revenue conversion during the remainder of 2026 and $2.4 billion scheduled for 2027.

Referring to page nine of the earnings presentation, we are maintaining full year 2026 guidance for total revenue between $2.8 and $3 billion, which includes approximately $150 million in reimbursable and other revenue, and adjusted EBITDA between $940 million to $1.02 billion. Capital expenditures guidance for this year is increased by $25 million, and this is due to the contract award supporting the reactivation of the Noble Deliverer.

The lower side of our adjusted EBITDA range is fully contracted by current backlog. Although we have banked a somewhat stronger than expected first quarter in terms of adjusted EBITDA, this is offset by a few discrete items, including the recent notice of early contract termination on the Mick O'Brien, the lower near-term dayrate revision resulting from the Courage's blend-and-extend, and slightly later estimated contract commencement dates for the Gerry de Souza and Endeavor, driven by customer schedules.

Regarding the Mick O'Brien, recall that we closed the sale to Borr Drilling in January and have continued to manage the rig through the completion of its current contract in Qatar, with a corresponding bareboat that we pay to Borr into early December 2026. On April 12th, we received notice of early release from the customer, QE LNG, and we are now in the process of winding down operations.

The contract termination is effective after 30 days, and this will result in an estimated negative impact of approximately $15 million due to our remaining bareboat obligations through early December, as well as stacking costs for the rig. To sum up, we have had a very solid start to 2026 from a financial point of view.

With continued contract wins in the quarter and solid project execution, we continue to solidify the expected path to a healthy inflection in both EBITDA and free cash flow starting in 2027, as we outlined in detail on our call last quarter. With that, I'll now pass it back to Robert for concluding remarks.

Thank you, Richard. Starting in the summer with the Voyager, Gerry de Souza, and Interceptor startups, followed by the Valiant and Endeavor later this year, and then the Great White, Deliverer, and Venturer throughout next year, we have a sharp organizational focus on project execution.

This is a large slate of projects to deliver in a quote "normal" time, and these are, of course, hardly normal times given the various dislocations resulting from the Strait of Hormuz impasse. Overall, I'm pleased to report that all of our projects are progressing very well so far, and we're incredibly excited to be preparing for commencement on these important drilling campaigns for our customers.

These programs span virtually all of the major non-OPEC offshore basins around the world, which are increasingly critical to current and future energy supply. To wrap up, as outlook for our business continues to improve, Noble is very well positioned to grow into the next leg of the offshore drilling cycle with a strong balance sheet, $7.5 billion of backlog, and repricing opportunities across some of the most capable drillships and jackups in the world.

If anything, we feel better about 2027 today versus last quarter given the Deliverer contract as well as the improving market dynamics confronting our open drillship capacity. Meanwhile, we will continue to drive shareholder value through our robust return of capital program.

With that, I'll turn it back to the operator for questions.

Good morning, gentlemen. Robert, one of the themes of OFS earnings thus far has been just the potential impact from rising energy security concerns on just the CapEx cycle, in your case, what this means for offshore rig demand.

Robert, historically, when we've seen a sharp move up in commodity prices, that's obviously tend to positively impact shallow-water demand. I was wondering if you could maybe elaborate on your thoughts on how some of these energy security concerns could impact the deepwater.

I'm thinking about, are there kind of projects that the majors have been sitting on that they may not have pursued in a lower commodity price environment that may come back into the fold at strip?

Thanks, Arun. It's a good question.

I think it's the topic on everyone's mind right now, including our own. I'd say a couple of things.

I'd reiterate that I think all of the positive indicators that we mentioned in our prepared remarks and that we're focused on right now started before the conflict in Iran. This growing narrative around deepwater, I think, is very real.

I think what I would say is there're certain regions that respond more quickly to oil prices in the deepwater than others. Traditionally, the US Gulf of Mexico has been one of those.

We're hopeful that we see something that comes perhaps as an early indicator out of the US. I think it's less likely that at this point today our customers have rewritten their budgets or made huge five- or 10-year moves.

That'd obviously be a question for them. What I think from what we see and hear, we don't have necessarily really tangible evidence today of positive changes that have hit us.

I think that we hear obviously positive narrative as you do, and we're pretty hopeful. We don't really see any way that this doesn't turn out positively for our business on top of everything else that we've already seen.

These aren't necessarily the end-all be-all on indicators, but the numbers we used just a moment ago, I think, are really striking when you think about the amount of deepwater backlog that's been printed so far this year by Noble and our competitors, and compare that against the amount of outstanding activity that we see. Obviously, our numbers were just open tenders, but there're direct negotiations and everything that comes along with our business behind all that as well.

Got it.

Got it. Maybe just a housekeeping question.

You guys are buying in your lease options on the BOPs, which you talked about in the prepared remarks. Can you maybe help us think about the impact on OpEx from buying in those BOPs?

I'm thinking about maybe the impact in '26 and maybe as we think about '27 on a go-forward basis when you buy in all four of those leases.

Sure, Arun. Yes, we're obviously buying in the leases during the course of this year, and on an annualized basis, it will have a benefit to EBITDA of about $25 million.

In 2026, probably about half of that will be realized.

Great. Thank you.

Yes, good morning, Robert and Richard. Kind of want to follow on Arun's question, just around how customers may respond to higher oil prices.

I know it's early days, but just curious, in the conversations you're having with customers, are they starting to indicate incremental interest in exploration? I know people are talking about it even before the conflict, but is there a sense that there will be incremental interest in more exploration?

Is there incremental interest in infill activity with quick paybacks? Just any additional color you can provide on what the conversations with customers are indicating to be potential incremental activity.

Thanks, Scott. Look, I think that so, for sure, yes, there is an increase in narrative around and discussion around exploration work.

I don't know that like I said before, I don't know that we can put our finger on a specific example that has a direct cause and effect related to Iran. I think that generally, we're seeing conversations gain momentum, and I think across the board, the realization that the deepwater's going to play a really important part in the supply stack post everything that's happened here.

Our hope is that some of the demand that we've seen, whether it be from India or elsewhere, is more likely to solidify than before the Iran issue. Today, I'm not sure that there's a direct link so far.

Okay. We'll wait.

Then on the Deliverer, on that rig, you bumped a full-year CapEx by $25 million for the reactivation cost. Is that the total cost of restart, or is there some more spend required next year?

Then does the incremental spend include any upgrade investment that would add to the dayrate, or is that just a pure restart cost?

The $25 million is the total required for the Woodside contract. If there are any incremental rig upgrades, then there would be incremental capital to that.

Think about the $25 million as what's needed for the Woodside contract, Scott.

Great. That's it for me.

Appreciate all the color.

Hi, good morning. You highlighted the high UDW contracted utilization currently at 95% and that the market is beginning to tighten here, which of course results in higher pricing over time.

We haven't quite seen that move up in dayrates yet. It feels like leading-edge pricing is still in the low 400s.

Just based on the current backdrop and the amount of tendering and activity you expect to see over the next year or two, do you think, by sometime in 2027, we could be back up into the mid to high 400s, which is where leading-edge pricing was at about a year or two ago? Is the market currently setting up for that based on what you see today?

I guess what I would say is we definitely see the market tightening, and that's because of that convergence I mentioned, but also because of a lot of the demand that we see behind even the 95%, the demand that's creating that 95% number. Obviously, tight markets leads to higher dayrates, we'll see what happens, but we're pretty optimistic about a really tight market.

Got it. Great to hear.

My follow-up is just on the Petrobras blend-and-extends. It seems like they handed out a lot of extensions.

Were you at all surprised by just the number of rig-years they extended, or was this kind of all part of their plan and in line with your expectations?

I think it's in line with our expectations. We had always kind of thought Petrobras on total rig count would be flat, and they're going to end up dropping by a couple of rigs, at least in the near term.

We're still hopeful that through time, their number remains flat, and there's some possibility, I guess, that it could actually go up. Look, I think Petrobras are very savvy, and I think this is in line with their behavior through time, and they've secured their rig supply and probably done it at a pretty good time.

Yep. They sure did.

Great. Thanks for that color, Rob.

I'll turn it back.

Thanks.

Hey, thanks for taking my question. We've kind of talked about some of the really strong contracting that we've seen to start the year here, a lot of it driven by Petrobras in Brazil.

Are there any other regions in particular that maybe you have stronger confidence in now for more significant tender conversion throughout the rest of the year, maybe on the back of energy security, but just any regions in particular you wanted to highlight that could potentially be stronger contract conversion through the rest of the year?

Sure. Here's what I would say.

I mentioned the US earlier, which I think is a region that sometimes responds quickly, don't have anything necessarily tangible to report there, but fingers crossed. I think the meat of your question would sit in two places.

First would be Asia, where we think that we had growing demand even before the Iran conflict, and we think that that's very likely to solidify going forward because of the renewed security concerns, which is obviously a good outcome if that happens for the Viking and in follow-on work also in Australia. Then secondly, I would say that a lot of the growth that we've been forecasting has been from West Africa, and higher oil prices just help that region.

There's just no way that hurts all of that. I think if anything, if not incremental in West Africa, then we're hopeful that projects on the table are just even more likely to come through and done.

Awesome. That's really helpful.

Then my second question was just trying to get the outlook for a few rigs. I think about kind of the Black Rhino, the Globetrotter I, and Apex as some rigs that could still fill up some work, they roll off or are already off contract.

Maybe, what do you think the Black Rhino could still potentially find work in the Gulf, or do you think it may have to head elsewhere? Then just any potential work scope for the Globetrotter I or Apex at this time, you could help me out on that.

Thank you.

Sure. Yeah.

The Black Rhino could very easily stay in the US. That's most likely to be '27 work, but like I said, our fingers are crossed about potentially some '26 work popping up.

It is bid outside of the region as well. Just a little too soon to tell where that rig will end up.

The GT1 is in the same place it's been, where we're chasing primarily intervention work. We believe in that market, and everything that's happened kind of makes us believe at least as much if not more in that market.

We're hopeful to have some sort of news on that rig in I don't know, the next couple of quarters. It remains focused on intervention work.

Then there's a couple jobs out there like the one in the Black Sea that really kind of work very well for that rig. We're not bidding it into very many drilling programs, but there's a couple things out there that we're chasing right now.

We're hopeful to have something for that rig, which would be '27 start. Then the Apex is an older unit, and we're just evaluating options on that rig right now.

There are some opportunities for the rig, and we'll make a decision on what to do with that rig here over the next couple of quarters as well.

Awesome. That was really helpful.

I will turn it back. Appreciate your time.

Thanks.

Hey, Robert and team. Hope you are well, and thank you for the prepared remarks and the market commentary in particular.

I wanted to circle back briefly on Brazil and the Roncador. You got the extension on the Courage, which was nice to see, keeping that rig working until end 2030.

I was wondering about the Faye Kozack as well. That's rolling off, I think, later this year or early next year, but nothing announced on this one.

Does that mean that hasn't been part of Roncador? Can we expect that to be extended nonetheless, or did you feel like the terms that were potentially agreeable for Petrobras weren't agreeable for you and that you might see that rig working elsewhere?

Thanks.

The Faye Kozack is not a part of the blend-and-extends that have now been announced. We did have it very close on a different program.

What I would say is there are opportunities in South America for the rig that we're chasing, but that we're also starting to bid that rig elsewhere. It's obviously not impossible for that rig to continue working for Petrobras, but it's not part of the current blend-and-extend discussions.

All right. Thank you.

That's very clear. Then one for Richard as well.

In addition to buying or buying out two of your BOPs with two more following later this year, you also bought back some of your 2030s secured bonds. I think you said that you bought back $55 million, which, based on cash flow at least, would suggest a price of 103, at least if it's 55 [unclear], which would be good compared to market pricing.

I was also wondering if we should kind of read more into this given the call structures of the bond that this is quote "early stages" of a potential refi since you're still siloed in a way with legacy Noble, legacy Diamond debt structures at the moment, and everything is trading pretty tight versus historical spreads at least. Any commentary around that would be super helpful.

Thanks.

Sure. Yeah.

There was a specific clause in the legacy Diamond notes that allowed us to buy back 10% at 103. The bond was trading at 105, 106, we think it was a very value-creative move for us if you will to buy in that debt.

The legacy Noble bonds are callable now. The legacy Diamond bond is callable later this year.

At the right time, we'll definitely refinance the capital structure and collapse that back in, or collapse down into one silo. Through that process, we would expect to realize material cash interest savings on an annual basis.

Obviously, both bonds are trading well in excess of par today, but we're going to find the right time to go for us.

Right. Great.

Appreciate all the answers, and wish you a good day. That's all for me.

Thank you.

Thank you. Robert, just as the market evolves, do you see an opportunity for some upgrades on the drillships to even improve their competitiveness even further?

It's a good question. I think we highlighted it last call, but as a reminder, we feel we've got one of the most competitive fleets on the globe right now.

All of the rigs will have MPD here in the not-too-distant future. I think we have more of NOV's automation equipment installed on our rigs than the entire rest of the world combined.

We're really proud of where we sit on rig technology. We have upgraded or will upgrade a couple of the rigs for derrick capacity, which is a pretty easy upgrade for a couple of our rig classes.

I could see us doing something like that for certain programs. By and large, we're pretty happy with where everything sits right now, though.

I guess I'd add one caveat. We are constantly in communication with our customers around technology that they value, and, of course, work with them as a normal course of business to find a technology that works for our rigs.

There's always some discussion around who pays for that stuff, but I think right now what we're seeing is a real push by customers to have the best technologies as a lot of things are really starting to prove their value, whether it's in the form of safety, perhaps red zone management, or on, of course, on efficiency, which would be more like MPD and automation and other things. We think that the trend will continue.

Some of that's going to come from customer-supplied CapEx, some of that's possible from us, but I think we're starting from a pretty high place right now as a company.

Would agree. Richard, a quick one.

You mentioned the low end of the range was kind of derisked through contracting. What would we need to see happen to get to the high end of the range for this year?

Sure, Doug. There's there's a a few few parts, if you will, to get to the high end.

Obviously, in Q1, we had great uptime performance and fantastic cost control throughout the entire company. I think, obviously, opportunities there's opportunities there, if you will, to to to to drive cash flow that way.

I think, specific maybe to the Black Rhino, obviously if if opportunities were to come to fruition for that for that rig in the back half of the year, then then that that would lead, I think, to us us being towards the higher end of the range.

Thank you.

Hey, yeah, good morning, and thanks for taking my question. First, I kind of wanted to ask a bit more about your comments earlier that the US Gulf is a basin that typically reacts quickly to changes in oil prices.

Just kind of curious if you've heard anything yet from customers in the region, and I guess thinking more about your fleet, maybe how that could have some implications for a rig like the Black Rhino. Thank you.

It's a good question. I wish I had a great story for you.

I can't say, our customers continue to preach discipline and will continue to be disciplined. I think the US is a place where some of the smaller independents can be a little bit more price sensitive in the near term, perhaps, than some of the majors are.

I would say also kind of related to Richard's statement just a moment ago, to the extent that something pops up for the Black Rhino, that's some upside in 2026 for us. We're hopeful that this environment eventually translates to a little bit of incremental work.

Great. Thank you.

Then just wanted to turn to the jackup fleet quickly, now with the closing of the sale behind us. Kind of just curious on anything you want to highlight on the longer-term outlooks in Norway and the UK.

I know that a lot of '26 is spoken for these rigs, but I guess just kind of thinking about '27 and beyond.

It's a good question. I think for the CJ70s, in 2027, I think we feel really good about having four of those rigs contracted and with multiple paths to having all five of those rigs contracted.

We're happy with that. We're probably a little bit short of scarcity in that market on programs that genuinely require CJ70s.

I think I would kind of broadly characterize our view as flat to up for CJ70s. Been a little while since we would say that with that conviction, cautiously optimistic there.

Great. Thank you for taking my questions.

Thanks.

...out over the next 12 months and the focus on execution. Could you speak to what you're seeing...

Go ahead,

Josh. Josh, two seconds.

Let me interrupt you. You just came in.

We didn't hear the first part of your question. Sorry,

we may have had

an issue on our end.

That's okay. Can you hear me now?

Yes, sir.

Just want to touch on inflation and supply chains. You highlighted a number of project and rig startups you'll have over the next 12 months and the focus on execution.

Could you speak to what you're seeing with respect to global supply chains, maybe not just only the Strait, but also outside of the Strait, and how you're managing things to make sure the projects start on time with no delays?

Thanks. It's a good question.

It's something we're extremely focused on here, as we mentioned. I would say logistics are strained, and some of that started before Iran, but obviously fuel prices are way up now, and so that's adding a little bit of cost into the system.

Right now, I would say, cost-wise, we're not seeing material effects as directly correlated to the war. Transportation costs up, yes.

I think everything else, all the stuff we're buying for these projects is bid and built effectively. We feel reasonable, although there's probably risk there, obviously, given everything happening.

We are really focused on timing right now, and that's where we're seeing a lot of pressure. We're going multiple layers deep here to track the equipment we need and then try to ensure that we get everything on time so that we're ready to go for our customers.

Again, I guess I'd say we're optimistic and working hard to make sure that we stay on time here. There is a lot of pressure out there on the groups trying to pull everything together.

Understood. Thanks.

Then maybe just one follow-up just to address latest developments in autonomy. There was a release in March where Noble, in conjunction with Halliburton and Exxon, automated rig operations and subsurface interpretation, real-time hydraulics.

Maybe you could just speak to that and where you think we're going over the next couple of years with respect to advances in autonomy on the rig floor.

That's going to continue. That's the path of everything.

Noble doesn't do anything specifically subsurface. We are focused on making sure that we have the most efficient rigs and then some of the logistics around that.

We work very closely with the other service companies and with our customers, of course. I think one of the things that's the mark of kind of where things are headed is that everyone is much more collaborative today so that I think maximum efficiency is achieved by service companies and operators really working together early, collaborating on shared technologies like what you just referenced.

There are a number of examples like that out there. That is the path of drilling today.

I think we've said before that we kind of waxed poetic about the change from the concept of drilling yourselves out of a job and into the mindset of drilling yourselves into a job. We mentioned previously that we've seen that work directly in Guyana, where they've had FID under a set of circumstances that probably were not possible even three or four years ago given efficiency then.

We think that technology and automation is really an enabler for deepwater work going forward. The further deepwater comes down the cost curve, the more there is for the entire industry.

We're really optimistic about all of that.

Understood. Thanks for taking my questions.

Thanks, Josh.

Hey, good morning, Robert and Richard. Robert, curious, as we think about the various regions around the world that you guys participate in, which one would you say over the last, or which one or two or three over the last kind of 90 days have started to show a bit more urgency on moving FIDs maybe forward or just getting FIDs done for projects as this deepwater cycle steps up?

I'll give an answer and look at Blake, make sure I get it right. I think Asia, for sure, we've seen a real change in the amount of demand and urgency there.

Then I would say CARICOM, where there's an enormous amount of work that obviously a lot of it we knew in Guyana, but then suddenly Venezuela seems more open, and a number of other actually kind of shallower-water trends that are creating a lot of demand through that region is all pretty interesting.

Got it. Then on the managed pressure drilling, I think you mentioned all of your rigs are now or will be outfitted with MPD.

What percentage of the wells now are being drilled with MPD, and how much of the actual well is drilled with MPD?

Just to clarify, the drillships will have it'll be all the drillships that have MPD. I may have to I don't know if I have a percentage on on it's a high it's a high percentage.

Look, there's there are certain technologies out there that can be used out outside of MPD, but, the feeling for us has been that over the past really 10 years, that that MPD is kind of going the path of the top drive, where it's it's almost ubiquitous. We're we're pretty happy with with with where we are on on having the rigs outfitted.

It's, it's it's a $25 to $30 million expense, depending on where your piping is and and then and that's before you get out-of-service time. We're we're we're pretty happy to have all that pretty much paid for.

Got it. Thanks, Robert.

Thanks.

Hi, good morning. We've touched the edges of this, but I've been thinking, of course, that one of the artifacts of things tightening up again in the rig market could be that we ought to begin to see some lengthening of contract term length.

It seems like I haven't really necessarily seen that yet, but I have noticed some more prompt contract extensions, maybe suggesting that any operators who might have been betting on lower for longer dayrates may realize they're losing that bet. I'm just wondering if you were seeing that yourselves.

Sorry, when you said term, do you mean contractual terms or the length of the contracts?

Length of the contract.

Yeah. If you recall, two or three years ago, the last time we kind of hit this inflection, I think average contract term was still less than a year.

I think that's one important point we kind of made in the comments is, yeah, I don't think there's a ton of priced options out there. If someone has a priced option, I think they're pretty likely to take it right now.

Across the board, I think we're seeing more and more big development projects that are driving this demand. Like we mentioned earlier, I think the average contract term was at least two years on some of this recent contracting.

That's a huge change compared to where we were before. You think about hitting kind of similar utilization point as what the last time dayrates hit right at 500, approaching a similar utilization point, but with more term and a lot more open demand than before, like double open demand.

We're pretty optimistic.

Great. I'm just wondering, you did mention briefly that the factors of capital discipline are still very much in place with producers.

I was just wondering if, this time around, with the geopolitical turmoil, I'm sort of thinking back to 2022 that we still had sort of more uncertain macro environment, rate environment was about to take off and head a lot higher. I was just wondering if, as far as you see them trying to decision-make during the current uncertainties, is this very reminiscent of sort of our last big international flare-up, or do they sort of are just looking past it and just thinking about whatever comes next?

Our customers are very long-term minded, obviously. There has been this big movement towards exploration in the deepwater, which, to me, is the most important test of the market that started before Iran, that hasn't slowed down.

We hope that it is only solidified by what's happening right now. I guess another way to put it would be we certainly wouldn't expect our customers to waver from their commitment to discipline, and our optimism does not require them to abandon any discipline.

Great. Thanks a lot.

Thank you.

Hey, good morning, and thanks for the time. Can you just elaborate on the moving pieces with the Mick O'Brien?

I think you called out $15 million impact. Maybe how much is the bareboat piece of that versus I believe you mentioned a stacking cost?

Then the termination, or I guess when the rig does get stacked, does that effectively end the relationship between the two entities, and that rig is free to seek work elsewhere, or are there any other lingering items we should be aware of? Hey,

Aaron. Obviously it's an early termination for the rig, the $15 million, if you think about that, is about the six months of the bareboat charter plus stacking costs.

That's essentially the $15 million. That's the extent of the impact.

We don't see any other impact to our financials. Obviously, once we get to early December, that rig will move over to Borr.

Great. Thank you.

Thanks for joining us today, everyone. We appreciate your interest, and we'll look forward to speaking with you again next quarter.

Have a great day.