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Operator: Hello, everyone, and welcome to Noble Corporation Plc First Quarter 2026 Earnings Call. Please note that this call is being recorded. After the speakers’ prepared remarks, there will be a question and answer session. If you would like to ask a question during that time, please press star and then one on your telephone keypad. Thank you. I would now like to hand the call over to Ian MacPherson, Vice President of Investor Relations. You may now go ahead.

Ian MacPherson: Thank you, Operator, and welcome, everyone, to Noble Corporation Plc 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 is posted in the Investor Relations page of our website as well. Today’s call will feature prepared remarks from our President and CEO, Robert W. Eifler, as well as our CFO, Richard B. Barker. We also have with us Blake Denton, Senior Vice President of Marketing and Contracts, and Joey Kowaja, 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 company 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. Noble Corporation Plc 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 will turn the call over to Robert W. Eifler, President and CEO of Noble Corporation Plc.

Robert W. Eifler: Thanks, Ian. Welcome, everyone, and thank you for joining us. I will 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 we 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 $0.50 quarterly dividend and yesterday our Board declared a $0.50 per share dividend for the second quarter, maintaining our consistent and highly differentiated return-of-cash strategy. Overall, it was a solid start to the year, and I would like to thank our outstanding men and women of Noble Corporation Plc around the world for your fantastic teamwork in helping us to realize our first-choice offshore performance standards.

While it is 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 are 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 have 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 2030. This extension represents net incremental backlog of $330 million, with the current dayrate reduced from $290 thousand to $280 thousand from April 1, 2026 through late 2027, followed by the extension of slightly over three years at just over $309 thousand per day. Next, I am 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 thousand 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 U.S. Gulf of Mexico with an estimated duration of 100 days. In Ghana, the Noble Venture has been awarded a one-well contract with Planet One in Ghana at a dayrate of $430 thousand, expected to commence late this year with an estimated duration of approximately 45 days, with two unpriced options. And 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 will share a few observations on recent developments in the market. In short, all measurable and anecdotal indicators of deepwater rig demand are flashing green. I would submit that this is not a reflection of $100 oil, because most of what we are seeing in the market today has been in motion for months or longer. But, of course, recent events absolutely have elevated energy security priorities around the world, and improved upstream cash flows will only serve to enhance the already strong and expanding demand picture and deepwater 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. And with the 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 this tendering activity has developed 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 is now more than 55% higher compared to the previous high watermark two years ago. The contracted UDW count of 105 includes 14 rigs on future contracts that are not yet working today, six of which happen to be Noble Corporation Plc 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 six to twelve 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. So overall, with the continuing positive development of our backlog as well as the state of the drilling market more broadly, we are even more optimistic about the years ahead than we were last quarter. Now I will pass the call over to Richard for the financial review.

Richard B. Barker: 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 would 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 Black ships’ 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, our total backlog as of April 26 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 billion and $3.0 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 has 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 a 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 Jerry D’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 12, we received notice of early release from the customer, Qatari 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 will now pass it back to Robert for concluding remarks.

Robert W. Eifler: Thank you, Richard. Starting this summer with the Voyager, Jerry D’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 “normal” time, and these are, of course, hardly normal times given the various dislocations resulting from the Strait of Hormuz impasse. But overall, I am pleased to report that all of our projects are progressing very well so far, and we are 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 and are increasingly critical to current and future energy supply.

To wrap up, as the outlook for our business continues to improve, Noble Corporation Plc 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 will turn it back to the Operator for questions.

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Operator: We will now open the call for questions. If you would like to ask a question, again, that is star followed by one on your telephone keypad. Kindly limit your question to one question and one follow-up. Your first question comes from the line of Arun Jayaram of JPMorgan Securities LLC. Your line is now open.

Arun Jayaram: Good morning, gentlemen. Robert, one of the themes of OFS earnings thus far has been the potential impact from rising energy security concerns on the CapEx cycle and, in your case, what this means for offshore rig demand. Historically, when we have seen a sharp move up in commodity prices, it tends to accelerate activity. I was wondering if you could elaborate on how some of these energy security concerns could impact deepwater. Are there 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?

Robert W. Eifler: Thanks, Arun. It is a good question and the topic on everyone’s mind right now, including ours. I would say a couple things. First, I would reiterate that all of the positive indicators that we mentioned in our prepared remarks and that we are focused on right now started before the conflict in Iran. So this growing narrative around deepwater is very real. There are certain regions that respond more quickly to oil prices in deepwater than others. Traditionally, the U.S. Gulf of Mexico has been one of those, so we are hopeful that we see something that comes perhaps as an early indicator out of the U.S. I think it is less likely that at this point today our customers have rewritten their budgets or made huge five- or ten-year moves—that would obviously be a question for them.

From what we see and hear, we do not have necessarily really tangible evidence today of positive changes that have hit us, but we do hear positive narrative as you do, and we are pretty hopeful. We do not really see any way that this does not turn out positively for our business on top of everything else that we have already seen. These are not the end-all be all indicators, but the numbers we used a moment ago are really striking when you think about the amount of deepwater backlog that has been printed so far this year by Noble Corporation Plc and our competitors and compare that against the amount of outstanding activity that we see—including not just open tenders, but direct negotiations and everything that comes along with our business.

Arun Jayaram: Got it. And maybe just a housekeeping question. You are buying in your lease options on the BOPs, which you talked about in the prepared remarks. Can you help us think about the impact on OpEx from buying in those BOPs—impact in 2026 and then 2027 on a go-forward basis when you buy in all four of those leases?

Richard B. Barker: Yes. We are buying in the leases during the course of this year. 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.

Operator: Your next question comes from the line of Scott Gruber of Citigroup. Your line is now open.

Scott Gruber: Good morning, Robert and Richard. Kind of following on Arun’s question around how customers may respond to higher oil prices. I know it is early days, but in the conversations you are having, are customers starting to indicate incremental interest in exploration? People were talking about it even before the conflict, but is there a sense there will be incremental interest in more exploration or in infill activity with quick paybacks? Any additional color on what conversations indicate for potential incremental activity?

Robert W. Eifler: Thanks, Scott. For sure, yes, there is an increase in narrative and discussion around exploration work. I do not know that we can put our finger on a specific example that has a direct cause and effect related to Iran. But generally we are seeing conversations gain momentum, and across the board, the realization that deepwater is going to play a really important part in the supply stack post everything that has happened here. Our hope is that some of the demand we have seen, whether it be from India or elsewhere, is more likely to solidify than before the Iran issue, but today I am not sure that there is a direct link so far.

Scott Gruber: Understood. And on the Developer/Deliverer—on that rig, you bumped full-year CapEx by $25 million for the reactivation cost. Is that the total cost of restart, or is there more spend required next year? And does the incremental spend include upgrade investment that would add to the dayrate, or is that just a pure restart cost?

Richard B. Barker: The $25 million is the total required for the Woodside contract. If there are any incremental rig upgrades beyond the contract scope, then there will be incremental capital to that. But think about the $25 million as what is needed for the Woodside contract.

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

Eddie Kim: Hi. Good morning. You highlighted the high UDW contracted utilization currently at 95% and that the market is beginning to tighten, which results in higher pricing over time. We have not quite seen that move up in dayrates yet; it feels like leading edge pricing is still in the low $400 thousands. Based on the current backdrop and the amount of tendering and activity you expect over the next year or two, do you think by sometime in 2027 we could be back up into the mid to high $400 thousands, where leading edge pricing was a year or two ago? Is the market currently setting up for that based on what you see today?

Robert W. Eifler: I would say we definitely see the market tightening, because of the convergence I mentioned and because of the demand behind that 95% figure. Tight mindshare leads to higher dayrates. We will see what happens, but we are optimistic about a really tight market.

Eddie Kim: Got it. Follow-up on the Petrobras blend-and-extends. It seems like they handed out a lot of extensions. Were you at all surprised by the number of rig-years they extended, or was this in line with your expectations?

Robert W. Eifler: It is in line with our expectations. We had thought Petrobras on total rig count would be flat, and they are going to end up dropping by a couple of rigs at least in the near term. We are still hopeful that through time their number remains flat and there is some possibility it could go up. Petrobras is very savvy, and this is in line with their behavior through time. They have secured their rig supply and probably done it at a pretty good time.

Operator: Your next question comes from the line of Keith Beckman of Pickering Energy Partners. Your line is now open.

Keith Beckman: Thanks for taking my question. We have talked about the strong contracting we have seen to start the year, a lot of it driven by Petrobras in Brazil. Are there other regions where you have stronger confidence now for more significant tender conversion throughout the rest of the year? Any regions in particular you would highlight that could see stronger contract conversion?

Robert W. Eifler: I mentioned the U.S. earlier, which sometimes responds quickly—we do not have anything tangible to report there, but fingers crossed. The real meat of your question sits in two places. First, Asia, where we had growing demand even before the Iran conflict, and we think that is likely to solidify going forward because of renewed security concerns—good outcomes for the Viking and follow-on work, also in Australia. Second, West Africa, where a lot of the growth we have been forecasting has been. Higher oil prices help that region; if not incremental work, then projects already on the table are more likely to come through in time.

Keith Beckman: Thanks. And my second question is the outlook for a few rigs—the Black Rhino, the Globetrotter I, and Apex—systems that could still pick up some work as they roll off or are already off contract. Could the Black Rhino still find work in the Gulf, or might it head elsewhere? And any potential work scope for the Globetrotter I or Apex at this time?

Robert W. Eifler: The Black Rhino could easily stay in the U.S.; that is most likely to be 2027 work, but our fingers are crossed about potentially some 2026 work popping up. It is also bid outside of the region, so it is too soon to tell where it will end up. The GT1 is in the same place it has been—we are chasing primarily intervention work. We believe in that market, and everything that has happened makes us believe at least as much, if not more, in that market. We are hopeful to have news on that rig in the next couple of quarters. It remains focused on intervention work, and there are a couple of jobs out there—like one in the Black Sea—that fit that rig well. We are not bidding it into very many drilling programs, but there are a couple things we are chasing right now; that would be a 2027 start.

The Apex is an older unit, and we are evaluating options for that rig right now. There are some opportunities, and we will make a decision over the next couple of quarters as well.

Operator: Your next question comes from the line of Fredrik Stene of Clarksons Securities. Your line is now open.

Fredrik Stene: Thank you for the prepared remarks and the market commentary. I wanted to circle back briefly on Brazil and the Remacom. You got the extension on the Courage, which keeps that rig working till end 2030. But I was wondering about the Faeq Kozak as well. That is rolling off later this year or early next year, and nothing has been announced. Does that mean it has not been part of Remacom? Can we expect it to be extended nonetheless, or did you feel like the terms that were potentially agreeable for Petrobras are not agreeable for you and that you might see that rig working elsewhere?

Robert W. Eifler: The Faeq Kozak is not part of the blend-and-extends that have been announced. We did have it very close on a different program. There are opportunities in South America for the rig that we are chasing, but we are also starting to bid that rig elsewhere. It is not impossible for that rig to continue working for Petrobras, but it is not part of the current blend-and-extend discussions.

Fredrik Stene: Thank you. Then one for Richard. In addition to buying out two of your BOPs, with two more following later this year, you also brought back some of your 2030s secured bonds. I think you said you bought back $55 million, which would suggest a price of 103—good versus market pricing. Should we read more into this given the core structures of the bond—early stages of a potential refi—since you are still siloed in a way with Legacy Noble/Legacy Diamond debt structures?

Richard B. Barker: There was a specific clause in the legacy notes that allowed us to buy back 10% at 103. The bond was trading at 105–106, so we think it was a very value-accretive move to retire that debt. The Legacy Noble bonds are callable now; the Legacy Diamond bond is callable later this year. At the right time, we will refinance the capital structure and collapse that back down into one silo. Through that process, we would expect to realize material cash interest savings on an annual basis. Both bonds are trading well in excess of par today, but we will find the right time to move.

Operator: Your next question comes from the line of Doug Becker of Capital One. Your line is now open. Mr. Becker, your line is now open.

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

Robert W. Eifler: Good question. As a reminder, we feel we have one of the most competitive fleets globally right now. All of the drillships will have MPD here in the not too distant future, and we believe we have more of NOV’s automation equipment installed on our rigs than the entire rest of the world combined. We are really proud of where we sit on rig technology. We have upgraded or will upgrade a couple of the rigs for direct 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 are happy with where everything sits now. We constantly communicate with our customers around technology they value and work with them in the normal course of business to find technology that works for our rigs.

There is always some discussion around who pays for that, but we are seeing a real push by customers to have the best technologies as a lot of things are proving their value, whether in safety—red zone management—or in efficiency—MPD, automation, and other things. We think that trend will continue. Some of that will come from customer-supplied CapEx; some possibly from us. But we are starting from a high place as a company.

Doug Becker: Richard, a quick one. You mentioned the low end of the range was de-risked through contracting. What would we need to see to get to the high end of the range for this year?

Richard B. Barker: A few parts to get to the high end. In Q1, we had great uptime performance and fantastic cost control across the company—there are opportunities to drive cash flow that way. Specific to the Black Rhino, if opportunities come to fruition for that rig in the back half of the year, that would lead us toward the higher end of the range.

Operator: Your next question comes from the line of Analyst of BTIG. Your line is now open.

Analyst: Good morning, and thanks for taking my questions. First, on your comments that the U.S. Gulf is a basin that typically reacts quickly to changes in oil prices—have you heard anything yet from customers in the region? And thinking about your fleet, implications for the Black Rhino?

Robert W. Eifler: I wish I had a great story for you. Our customers continue to preach discipline and will continue to be disciplined. The U.S. is a place where some smaller independents can be a little more price sensitive in the near term than some majors. Related to Richard’s statement, to the extent something pops up for the Black Rhino, that is upside in 2026 for us. We are hopeful this environment eventually translates to a little incremental work.

Analyst: Thank you. And turning to the jackup fleet—now with the closing of the sale behind us—anything you want to highlight on the longer-term outlooks in Norway and the UK? A lot of 2026 is spoken for, but thinking about 2027 and beyond.

Robert W. Eifler: For the CJ70s in 2027, we feel really good about having four of those rigs contracted, with multiple paths to having all five contracted. We are probably a little bit short of scarcity in that market on programs that genuinely require CJ70s, but broadly we would characterize our view as flat to up for CJ70s. We are cautiously optimistic.

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

Joshua Jayne: Thanks. I wanted to touch on inflation and supply chains. You highlighted a number of project and rig startups you will have over the next twelve months and the focus on execution. What are you seeing with respect to global supply chains—not just the Strait, but outside of it—and how are you managing things to ensure projects start on time with no delays?

Robert W. Eifler: Thanks. It is something we are extremely focused on. Logistics are strained—some of that started before Iran—but fuel prices are up now and that adds a bit of cost. Cost-wise, we are not seeing material effects directly correlated to the war. Transportation costs are up, yes. Everything else we are buying for these projects has been built effectively, so we feel reasonable, although there is risk given everything happening. We are really focused on timing right now, and that is where we are seeing a lot of pressure. We are going multiple layers deep to track the equipment we need and ensure we get everything on time so we are ready for our customers. We are optimistic and working hard to stay on time. There is a lot of pressure on the groups trying to pull everything together.

Joshua Jayne: Understood. And a follow-up on autonomy. There was a release in March where Noble Corporation Plc, in conjunction with Halliburton and Exxon, automated rig operations and subsurface interpretation, real-time hydraulics. Can you speak to that and where you think we are going over the next couple of years with respect to advances in autonomy on the rig floor?

Robert W. Eifler: That is going to continue; that is the path of everything. Noble Corporation Plc does not do anything specifically subsurface. We are focused on having the most efficient rigs and some of the logistics around that. We work very closely with other service companies and with our customers. A hallmark of where things are headed is that everyone is much more collaborative today so maximum efficiency is achieved by service companies and operators working together early, collaborating on shared technologies like what you referenced—there are a number of examples like that. That is the path of drilling today. We have said before we have shifted from the concept of drilling ourselves out of a job to drilling ourselves into a job.

We have seen that work directly in Guyana, where they have had FID under circumstances that were probably not possible even three or four years ago given the efficiency then. Technology and automation are really enablers for deepwater work going forward. The further deepwater comes down the cost curve, the more there is for the entire industry. We are very optimistic about that.

Operator: Your next question comes from the line of Analyst of Melius Research. Your line is now open.

Analyst: Good morning, Robert and Richard. Robert, thinking about the various regions around the world that you participate in, which one or two over the last ninety days have started to show more urgency on moving FIDs forward or getting FIDs done as this deepwater cycle steps up?

Robert W. Eifler: Asia, for sure—we have seen a real change in the amount of demand and urgency there. And then Terracom, where there is an enormous amount of work: in Guyana, and Venezuela seems more open, and a number of other shallower-water trends that are creating a lot of demand through that region. It is all pretty interesting.

Analyst: And on managed pressure drilling—you mentioned all of your rigs will be outfitted with MPD. What percentage of wells now are being drilled with MPD, and how much of the well is drilled with MPD?

Robert W. Eifler: To clarify, it will be all the drillships that have MPD. I may not have a precise percentage; it is a high percentage. There are certain technologies that can be used outside of MPD, but over the past ten years, MPD is going the path of the top drive—almost ubiquitous. We are happy with where we are on having the rigs outfitted. It is a $25–$30 million expense depending on where your piping is, and you have out-of-service time, so we are happy to have that pretty much paid for.

Operator: Your next question comes from the line of Noel Parks of Tuohy Brothers. Your line is now open.

Noel Parks: Good morning. One artifact of tightening in the rig market could be lengthening of contract term. I have not really seen that yet, but I have noticed more prompt contract extensions, maybe suggesting operators who were betting on lower-for-longer dayrates are losing that bet. Are you seeing that?

Robert W. Eifler: On length of contract: two or three years ago, the last time we hit this inflection, average contract term was still less than a year. An important point we made is we are seeing more big development projects driving demand. I think the average contract term was at least two years on some of the recent contracting. That is a huge change compared to where we were. Think about approaching a similar utilization point as the last time dayrates hit $500 thousand, but with more term and a lot more open demand—like double the open demand—than before. We are pretty optimistic.

Noel Parks: You mentioned producers’ capital discipline is still in place. Comparing to 2022’s uncertainty, how are they deciding during the current turmoil—looking past it and thinking about what comes next?

Robert W. Eifler: Our customers are very long-term minded. There has been a big movement toward exploration in deepwater, which to me is the most important test of the market. That started before Iran and has not slowed. We hope it is solidified by what is happening now. We would not expect our customers to waver from their commitment to discipline, and our optimism does not require them to abandon discipline.

Operator: Your next question comes from the line of Analyst of JPMorgan. Your line is now open.

Analyst: Good morning, and thanks for the time. Can you elaborate on the moving pieces with the Mick O’Brien? You called out a $15 million impact. How much is the bareboat piece versus stacking costs? And when the rig goes stacked, does that end the relationship between the two entities and the rig is free to seek work elsewhere, or are there any other items we should be aware of?

Richard B. Barker: It is an early termination for the rig. The $15 million is about six months of the bareboat charter plus stacking costs—that is essentially the $15 million. That is the extent of the impact; we do not see any other impact to our financials. Once we get to early December, the rig will move over to Borr.

Operator: As of right now, we do not have any pending questions. I would now like to hand the call back to Noble Corporation Plc management for closing remarks.

Ian MacPherson: Thanks for joining us today, everyone. We appreciate your interest, and we look forward to speaking with you again next quarter. Have a great day.

Operator: Thank you for attending today’s call. You may now disconnect. Goodbye.

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