Thank you for your patience. My name is Bailey, and I will be your conference operator today. I would like to welcome everyone to the Noble Corporation First Quarter 2025 Earnings Call. I will now hand the call over to Ian MacPherson, Vice President of Investor Relations. You may begin.

Thank you, operator, and welcome everyone to Noble Corporation's first quarter 2025 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. We will reference an earnings presentation that's posted on the Investor Relations page of our website. 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. 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. Good day, everyone, and thank you for joining us as we present our results for the first quarter. I'll begin with financial and operational highlights from the first quarter, recent commercial activity, our perspective on the market, and then hand it over to Richard to cover the financials. As usual, I'll wrap up with closing remarks before we go to Q&A. In the first quarter, we delivered strong results with adjusted EBITDA of $338 million and free cash flow of $173 million. We continue to execute on our return of capital program, paying $80 million in dividends and repurchasing $20 million of shares during Q1. Yesterday, our Board declared another $0.50 per share dividend for the second quarter of 2025. And I'm pleased to highlight that we have now surpassed $1 billion in combined dividends and buybacks since Q4 2022, including this quarter's announced dividend. On the integration front, our progress has been right on target. The legacy Diamond fleet recently went live on Noble's ERP system ahead of schedule, positioning us to achieve our previously stated synergies of at least $100 million by the end of the year. We are also pleased to share a number of significant commercial and operational successes. As we announced yesterday, we have recently been awarded long-term contracts by two major oil companies, comprising nearly 14 rig years of additional backlog across four rigs with a total revenue potential between $2.0 billion and $2.5 billion. First, the Noble Voyager and another 7G drillship to be named were awarded four rig years each by Shell for operations in the U.S. Gulf. These contracts provide for a base dayrate value of $606 million per rig, plus the potential to earn up to an additional 20% based on the operational performance of each rig. Voyager is expected to commence in mid-2026, and the second drillship is slated to commence in Q4 2027. And both contracts have four one-year options following the firm four-year term at mutually agreed dayrates. As part of the Shell contracts, we will be making certain upgrades to the rigs, including increasing the direct hook load from 2.5 million to 2.8 million pounds, adding a controlled mud line system, which is essentially an alternative approach to manage pressure drilling, installing active heave compensated cranes, and finally, installing closed bus power system upgrades for reduced carbon footprint. All of which are intended to make these units among the most high-spec drill ships in the world for the remaining life of the assets. In total, these upgrades are expected to comprise $60 million to $70 million of CapEx per rig, which we anticipate being spread among 2025, '26 and '27. So all-in, we are incredibly happy to be awarded these landmark long-term contracts from Shell in a premier basin and look forward to getting started. Next, we've also recently been awarded strategic contracts from TotalEnergies in Suriname for two rigs. One 7G drillship yet to be named and also the 6G semi Noble Developer. The contracts span 16 wells per rig or approximately 1,060 days each and are expected to commence between Q4 2026 and Q1 2027. Together, the firm revenue of the two contracts is $753 million, and the contracts allow for an additional $297 million in revenue tied to collective operational performance. There are also four one-well options available across both contracts. We don't have any significant CapEx associated with these programs. Again, we are immensely proud to be selected by Total for their marquee development program in Suriname, which affords us the opportunity to expand not only a very robust and long-standing relationship with Total, but also our comprehensive presence throughout the Guyana Suriname region, where we have been able to develop highly valuable basin-scale and expertise. Each of these new long-term contracts in Suriname in the U.S. Gulf carries customary cost escalation provisions as well. We firmly believe that Noble shines brightest in long-term and collaborative relationships, and we look forward to delivering meaningful efficiency and risk management through these four new contracts. Based on an abundance of internal performance data and learnings from across our fleet, we generally expect that, quote, normal operational performance on these contracts can yield a significant amount of incentive revenue capture and we are booking an average across the four contracts of approximately 40% of the combined variable revenue components in our backlog, which we believe represents a reasonable estimate at this time. Although we can certainly envision realistic upsides to that, through the course of the campaigns. These performance contracts provide a great alignment with our customers, enabling substantial economic upside to both parties as drilling efficiencies are realized. In other words, if we're getting paid at the high end of the range, everyone is happy. Now turning to other new contracts and extensions. In Colombia, Petrobras has exercised an option for an additional 390 days on the Noble Discover at its existing dayrate, which we expect will extend this campaign into August 2026 and keeps the Discover well-positioned for additional development opportunities following the largest gas discovery in the history of Colombia. Additionally, we recently announced new short-term contracts for the Noble Viking, Noble Intrepid, and Noble Regina Allen, which are detailed in our earnings release and fleet status report. Combined, these 15 total rig years of new awards bring our current backlog to $7.5 billion, which represents an increase of 30% since last quarter and marks the first crucial step in the significant backlog inflection that we have been anticipating and forecasting over our past couple of earnings calls. We are also eyeing several opportunities for additional contract awards to build on these recent bookings, and we'll look forward to bringing you more news on this front in the not-too-distant future. Now, for a word on the markets more broadly. The first thing I would say is that obviously, throughout an incredible amount of market volatility recently across virtually all risk assets and commodities, throughout all this turmoil, not only has offshore drilling remained open for business, so too has our commercial pipeline remained very much intact as our customers around the world appear to remain engaged and active in sourcing their rig needs for 2026 and 2027. While we certainly see signs that our customer base is reacting to near-term oil prices by taking actions with their 2025 spending. It is very important to note that long-term strip pricing for Brent crude has remained in the mid-to-high 60s as the curve has flipped into Contango. This is not a throwaway fact as it relates to long-cycle offshore FID planning. We generally see that the middle part of the strip is the most relevant indicator for the economics of our business. And this price range in the mid-60s per barrel is only down by about $5 versus a year ago, and still quite supportive of project economics in most cases. I would also note that over 90% of the 15 rig years' worth of backlog we've just announced were signed after the April 2 market correction. No one here is glib about the state of financial markets, and we are, of course, concerned like everyone else about looming tariff effects on global demand. But we also derive strength and stability from our alignment with a large swath of customers that have generally resilient capital programs and less pushy planning factors when it comes to offshore projects. We still see a choppy spot market for deepwater and jackups throughout 2025 and into 2026. But we also believe the medium to long-term fundamentals are actually enhanced by every month of curtailed investment and spare capacity unwind. Contracted UDW utilization has been flat with total rig count having dipped only slightly from 100 rigs to 99 rigs since the time of our last earnings call, offset by a two-rig reduction in marketed supply, leaving marketed utilization essentially unchanged at 90%. We still expect this contracted rig count to sag a bit lower through the rest of this year, with an anticipated inflection sometime in 2026. Although, admittedly, forecasting precision is definitely hampered right now. But again, we do have decent visibility for some additional work for our own fleet, which would support a materially improved contracted position by next year. In the meantime, recent contract awards indicate dayrate resilience for high-end deepwater rigs firmly in the low-to-high 400s per day, with long-term visibility, which we think is completely at odds with prevailing market pessimism. We remain committed to managing our costs and marginal idle capacity in a prudent manner. As a first mover in what is likely to become a broader scrapping cycle for uncompetitive idle assets, recall that we recently announced the disposal of our cold-stacked drillships, Meltem and Scirocco. We have now entered into a definitive agreement to sell these vessels in a manner intended to effectively retire them, and we expect to finalize this transaction mid-year. Now, I'll provide a little more color on the status and outlook for our rigs with near-term market exposure. In the U.S. Gulf, the Noble Valiant has recently completed its contract and Noble BlackRhino is due to roll off contract in July. We are in active discussions with customers for both of these units for a limited amount of 2025 jobs as well as a larger 2026 opportunity set. While we will also work to fill 2026 availability for the recently committed Noble Voyager ahead of its Shell program, that rig is more likely to be warm-stacked in 2025 as we prioritize the Valiant and BlackRhino for near-term jobs. Turning to our sixth-gen rigs. Our three D-class semis have a promising outlook with the Developer and Discoverer both well contracted in the Americas and the Deliverer looking well-aligned for multiple prospective contracts that are expected to start in 2026. In contrast, the Ocean GreatWhite's near-term outlook is softer. And we anticipate the rig will be idled for the balance of the year following the conclusion of its campaign in the U.K. North Sea in late May. However, there are long-term programs worldwide that align with the rig's high-spec ultra-harsh capabilities with start dates in 2026 and 2027. Looking at our Globetrotter ships, we are still pursuing various intervention scopes globally and expect to have a clearer outlook for these opportunities fairly soon. If it's not a green light scenario for both units, we would likely then move to a cold stack or retirement decision on one of the units. Lastly, with respect to the moored floaters Apex and Endeavor, which are scheduled to roll off contracts this summer, we remain encouraged by a healthy amount of harsh environment P&A activity in the pipeline that is well-aligned for both of these assets. Now on the jackups. The headwinds from the Saudi suspensions and dayrate concessions continue to pressure the international benign environment jackup market, while the harsh jackup market, where our fleet primarily competes has remained insulated from these specific dynamics. That said, there has been a recent downtick in demand in the Southern North Sea of a couple of rigs. And we do expect softer utilization across our jackup fleet in 2025 compared to 2024. A recent bright spot has been the recent contract award from DNO, which will mark that rig's re-entry into the Norwegian market, which is still relatively subdued, albeit ticking up a bit as we get back up to three of our CJ70 jackups contracted in the MCS. So with that, I'll pause here and turn it over to Richard now to discuss the financials.

Good morning or good afternoon, all. In my prepared remarks today, I will briefly review our first quarter results, provide an update on our integration progress, and then discuss our outlook for the remainder of the year. Starting with our quarterly results. Contract drilling services revenue for the first quarter totaled $832 million, adjusted EBITDA was $338 million, and adjusted EBITDA margin was 39%. Adjusted EBITDA was positively impacted by approximately $20 million related to insurance proceeds, the legacy repair work on the Noble Regina Allen, which is accounted for as a reduction in operating expense, as well as overall strong cost management. Q1 cash flow from operations was $271 million, net capital expenditures were $98 million, and free cash flow was $173 million. We continue to remain focused on controlling costs, which includes managing our stacking costs accordingly. To that end, the sale of the Meltem and Scirocco will eliminate associated stacking cost of $40,000 to $50,000 per day on a combined basis, as well as bring in net proceeds of over $35 million. As summarized on Page 5 of the earnings presentation slides, our total backlog as of April 28th stands at $7.5 billion, up approximately 30% versus the prior quarter. This includes approximately $1.9 billion that is scheduled for revenue conversion over the remainder of 2025, and on the back of our recently announced contract awards. This now includes approximately $2.1 billion and $1.5 billion scheduled for revenue conversion during 2026 and 2027. As a reminder, our backlog excludes reimbursable revenue, as well as revenue from ancillary services. Our integration remains on track, and we continue to expect to realize $100 million of annual cost synergies on a run-rate basis by the end of the year. As of the end of the first quarter, we have achieved approximately $70 million of synergies. A tremendous amount of hard work is being done throughout the organization, and I'd like to extend my gratitude to everyone who is contributing to the great progress on the integration to date. Referring to Page 10 of the earnings slides, we are maintaining our full year guidance ranges, including total revenue between $3.25 billion to $3.45 billion, adjusted EBITDA between $1.05 billion to $1.15 billion, and capital expenditures, which excludes customer reimbursements of between $375 million and $425 million. As it relates to the adjusted EBITDA guidance range, we are currently approximately 95% contracted at the midpoint of this range based on year-to-date results and remaining backlog for 2025. Illustratively, if you include options, then the midpoint would essentially be fully contracted. Due to strong cost management, the midpoint of the EBITDA range corresponds to the low part of the revenue guidance range. It's worth noting and clarifying here that our legacy Diamond BOP lease payments, approximately $26 million this year are booked as part of operating expenses. As we look ahead, we anticipate Q2 adjusted EBITDA to track down quarter-on-quarter when excluding the Q1 impact of the Regina Allen insurance proceeds. This expected decrease in Q2 is primarily due to fewer operating days resulting from contract rollovers on the Valiant, Intrepid and Regina Allen, as well as the planned out-of-service time for the Noble Sam Croft FPS, which is expected to take 60 days during Q2. On the tariff front, the situation remains very fluid. We are confident in our ability to navigate these uncertainties as they evolve by leveraging our supply chain and procurement capabilities. While it is clearly dynamic and everything can change quickly, we currently expect the tariffs to have less than a $15 million cost impact in 2025, and this is incorporated into our guidance. So, in summary, a solid start to the year from a financial perspective has set us up well for the remainder of 2025 despite the macro uncertainty and the recent suite of strong contract awards to post a constructive long-term view for our market. With that, I'll pass the call back to Robert for closing remarks.

Thank you, Richard. To wrap up, I'd just like to emphasize that our first choice offshore strategy remains at the core of everything we do at Noble. We've been working very hard over the past four years at taking the company to the next level. And now we are really beginning to see the fruits of our labor. Throughout today's call, we've highlighted a number of proof points. Significantly increasing and enhancing our backlog with strategic contract awards, moving up our integration synergies, delivering customer programs with a focus on safety and efficiency, and reaffirming the resiliency of our cash flow and dividend. On the latter point, we're now eclipsing $1 billion of capital return to shareholders over the past couple of years, which represents almost one-third of our market cap from where we sit today. We also acknowledge the challenges of an exceptionally volatile macroeconomic environment. We're doing what we can to demonstrate reliability for our customers and shareholders. With the crucial backlog inflection now at hand and additional tangible contracting opportunities also within view, we remain confident about the medium to long-term fundamentals for our business. And recent fixture activity in the low-to-high 400s is solid. With our demonstrated commitment to the dividend and its current nearly 10% yield, the recent 30% increase in our backlog, over $1 billion in capital returns thus far, and tangible results building up from our scale and first choice offshore strategy, it seems the value proposition in Noble is compelling to say the least. Operator, we're ready to go to questions now.

Your first question comes from the line of David Smith, Pickering Energy Partners. Please proceed.

Hi, good morning. Congratulations on the strong quarter and the very impressive backlog addition.

Thank you.

I wanted to ask about the relatively large performance bonus opportunity in the Shell and Total Energies contracts. And is it fair to think that your willingness to take some rate risk on the performance component might be somewhat informed by your lived experience generating some pretty strong efficiency gains with your drillships in Guyana? And is it fair to think that performance component risk is - yes, has a lot to do with the duration of the programs and maybe the homogeneity of the drilling program? So we might not necessarily be expecting these kinds of performance bonus opportunities for shorter duration or multi-basin type programs?

It's a great question. What I would say is, first of all, we're extremely happy with both of these programs and very honored to have been entrusted with them. This is something we've been looking at for quite some time, and we think our customers have wanted something like this for even longer. I would repeat what we said earlier. We see it very much as a win-win. But to your point that it definitely doesn't work in every scenario. In fact, I would say that it only works in a relative few scenarios from what you see globally. We mentioned in the remarks, but we've spent a lot of time looking at our own performance data and getting our organization to a place where we were comfortable not only analyzing our capability but also projecting those capabilities against programs like this. And we got to a place that we think works for both sides. And I'd say, I guess, that these are - we mentioned the word strategic; that's obviously deliberate. These were very - our approach here, I think, is very, very strategic, not only in the structure that we've described a little bit, but also in where that structure is applied to basins, the type of program, et cetera.

Appreciate that color. And the follow-up, if I may. If we start to see more performance-based contracts industry-wide, can you talk about how the CEA index pricing mechanism takes performance-based contracts into account, right, for, yes, the drillship in Suriname, right? There appears to be a - maybe about a $140,000 a day spread between the base rate and the full bonus potential. Where on that spectrum would we look for the rate that contributes to the CEA-indexed rate?

It's also a good question. Not one obviously that was forecasted or contemplated when we came up with this, when it was six or seven, eight years ago, longer maybe now. So, I guess what I would say is that mechanism is not mechanical. It was designed to be flexible and it was designed to take in a number of different market considerations at each six-month turn. And so, we've had this come up in certain other nuances that they go into rates, whether it's types of costs or taxes or whatever. And it's flexible enough to also take into account this type of structure. And so, we haven't had this conversation yet. So I don't want to really say anything more than that. But it is a mutually agreed rate that we get together and decide on every six months. We both sides put in data as both sides see it, and we take that data and mutually agree. And as to the extent that we have trouble with that, sometimes we'll bring a third-party in as well. So we spent a fair amount of time on the prepared remarks, giving some thoughts and ideas as to where we think we could land on achieving these larger performance components. And we're going to have to go through some type of that as we move through the CEA.

Perfect. Really appreciate it.

Your next question comes from the line of Arun Jayaram with JPMorgan. Your line is open.

Yes, good morning, gentlemen. Robert, I wondered if you could go through some of the competitive tensions in maybe both of these awards and maybe specifically on the Shell award, is this incremental demand? Are you displacing an incumbent, but talk to us about opportunities for these really interesting opportunities with Shell?

Yes. Well, thanks. So, look, what the Suriname contracts are obviously incremental. The Shell contracts in the U.S., that's a key basin for them. And I think the thing that really was even - as attractive as anything else here for us was that these rigs, if we perform, we've set up a contract that rewards performance. Our customers obviously expect performance out of us. And we firmly believe that if we perform and deliver what's expected of us that these rigs will spend a decade plus without really having to make a substantial mobilization. So when we say strategic, that's a big piece of it for us. These rigs are getting to be - they're about a little over 10 years old. So if you think about accounting lives, et cetera, there's an outside chance that these things can close it out right there in the Gulf of America. We do believe that we're displacing - this is not incremental right now. But for us, the bigger piece of this was the longevity of the potential work here.

Great. And maybe my follow-up. Richard, you went through kind of the sequential changes in your OpEx expectations. Could you maybe elaborate on what you see in Q2 and maybe give us a sense of how you see the back half of the year in terms of OpEx, because that was significantly lower than our model in 1Q?

Yes, sure. Very good question, Arun. So we noted in the prepared remarks that obviously, we had a $20 million impact from the Regina Allen. So I mean, that was a net against cost. Obviously, that's not going to reoccur, if you will, in Q2 going on. So if you back that out, our operating costs, if you will, on the income statement, I think would have been about $480, $485. Inflation is real. So we do expect some inflationary pressure here as we've talked about before in the low mid-single-digit type area through the rest of the year. So I think that kind of guides, if you will, how we think about operating costs for the rest of the year. Obviously, we talked about from a guidance perspective, low end of revenue equals midpoint of EBITDA as well. And really cost management is really what's driving that. So we're obviously very focused on managing cost here, and we would expect, hopefully, to continue to be aggressive from an OpEx perspective going forward.

Great. I'll turn it back. Thanks.

Your next question comes from the line of Scott Gruber with Citigroup. Your line is open.

Yes, good morning, and congrats on the new contracts. And I appreciate your assumption on the bonus capture there. How will the bonuses be paid out if achieved? Are they reviewed after a certain number of wells? Is your performance review kind of on an annual basis? Just some color on when you could collect on the bonuses? That would be great.

It's well by well. In actually, both contracts, it's well by well. So, collection would happen after. You'd have to do some sort of reconciliation of data, et cetera, and then have payment terms or whatever, but they are well by well bonuses.

Okay. They're fairly frequent throughout the contracts, then. Okay. And then can you provide some more color on the downtime associated with the rig upgrades required on the Shell contracts? And then how should we think about finding some shorter-term work for those rates before the long-term contracts start?

I think it's kind of a couple of months to do the actual work that would pull us out of being able to carry out other work. And so, we said we've got a number of conversations ongoing right now for things that would fit in between. And we'll see how that plays out. But yes, in the scenario where we're able to fill substantially all of that time, we would need a couple of months to do the final installations.

Okay. I appreciate those. Thank you.

Thank you.

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

Hi, good morning. Just wanted to ask about the performance-based nature of the contracts, which make up a meaningful proportion of the total potential value of the contract. Could you maybe just give us a sense or an example of what sort of metrics or milestones this is based on? And you mentioned that kind of normal operations would more or less equate to achieving around 40% of the performance bonuses of the contracts? And please correct me if I heard that incorrectly. But what more would be needed to get closer to realizing the full value of those performance bonuses?

Yes. So they're very different - they're different mechanisms, I'd say, between the two contracts for sure. I think the important takeaway here is that both of them have a very heavy component of time drilling, so days per well. And so that's where we spent a lot of time. And, I'd say - I don't want to give any real breakdown or specifics. It's proprietary to our customers as well as us. But, there's obviously other components to performance. There's safety and other things, all of which we pride ourselves on. But I think, think about a very important driver being the time against the curve on a well. And that's really - I mean, all of it is where the win-win comes in. But in a big development, there's probably more to play with there in terms of the self-funded pool.

Got it. Got it. That's very helpful. My follow-up is just on the contract expenses, or I guess, contract prep expenses on these. So you mentioned the upgrade CapEx on the two rigs with Shell, but are the contract prep expenses for these larger than some of your other multi-year contracts you've announced previously, or are they more or less in line?

I was going to say much, much more in line, obviously, the CapEx, the capital on the Shell contracts, we've spoken about that. But think about kind of the contract prep expenses is very much in line, Eddie.

Okay, great. Thanks for the color. I'll turn it back.

Your next question comes from the line of Greg Lewis with BTIG. Your line is open.

Hi, thank you, and good morning, and thanks for taking my question. Robert, we appreciate the decision to maintain the dividend. Obviously, that's a Board decision that you go through frequently. As we think about that over the next two years, three years longer term, as I imagine you're working through the dividend, clearly, this year it's going to be paid out with free cash flow. It looks based on some of the announcements today, that's going to be the case. How do you at a big picture, think about the dividend just balancing all the moving pieces of, you know, are - a lower oil price against a strong backlog. Just kind of like any kind of - how is the Board thinking about that dividend? Kind of curious on that?

Yes. So we're committed to the dividend. I would say, we have got - if you look at our first quarter results and our guidance, you can do the math to put us to about a $250 million per quarter EBITDA run rate here. And we said in the remarks, we see that ticking up with these contracts we've just announced. And I guess the color I would add to that is that we mentioned twice in the script, very deliberately, that we also have line of sight to a number of additional contracts. And so there are multiple different paths to that uptick occurring sooner than the start of these contracts. It's too early to tell, so I don't want to say too much now - sitting here in early 2025, but we're encouraged, frankly, by the level of conversations we're having, by the behavior we're seeing - the contracting behavior we're seeing out there in the market. And so, yes, we're pretty confident here in our return of capital structure.

Okay, great. And then just on the realizing you might be limited in what you can and cannot say. But in terms of the timing of the contracts with Total and with Shell, a question we often get asked is, okay, well, that's great, but when did the negotiation around the pricing actually start? Just kind of any kind of color around that? And then on the - I guess, in the press release, we talked about the Noble V-class rig. Was there something specific about those rigs that the customer wanted, i.e., as opposed to, like, I guess, one of the black rigs is rolling-off and it looks like a rig like that could be able to potentially have been slotted in for that one? Thanks.

Sure. Yes. Look, I'd say initial pricing happened a little while back, but the reality is that final pricing happens effectively when you sign a contract, especially in a volatile market like this. So yes, I'd say these are very, very current - this is very current pricing, the V-ships - both of these customers are very strong supporters of the V-class rigs. The Valiant one - excuse me, rig of the year from Total last year and both Shell and Total had the V-ships multiple times through time. And so they're just big supporters of those rigs, and those really were the preferred vessels. So in the case of the U.S., which has some different - kind of a different type of work required higher - required - excuse me, requires higher hook load in some instances. There is a more limited number of higher hook load rigs out there. So we were really happy to upgrade these as part of that contract. And along with the other few upgrades we mentioned for the U.S. work, these are going to be right there with the - with some of the highest spec rigs on earth. And that's going to be something that I mentioned before, we hope that to be right where we are for a very long time. But that's something also that would be valued by a very wide variety of clients, should things change. And so, yes, look, everything kind of matched up nicely. They have really high thruster power, so they can hold position in Suriname, which is important, but just the specs matched up very nicely for both of these programs.

Great. Super helpful. Thank you.

Your next question comes from the line of Fredrik Stene with Clarksons Securities. Your line is open.

Hi there. And I guess it's been said many times already, but congratulations on the very long and very nice contracts. And I also have a couple of questions relating to those contracts. So first, I think you said that on the back of the bookings that you've made so far and my understanding from the prepared remarks was that the comments then kind of pointed to the Shell and the Total work that there could be more coming down on the same line. And I was wondering if you could give some additional color on that because obviously, these four rigs will be tied up for three years or four years. So to me, it's kind of natural to assume that this could be a similar long-term programs for maybe other rigs and Shell, for example; they have other rigs that are rolling off similarly to when the startups are for the two that they've already contracted. So any color on what you meant by these comments would be super helpful. Thank you.

Sure. Yes, I guess the comments in the prepared remarks were really intended to address some more near-term white space in our fleet where we have a number of active conversations right now. And so, too early to tell and all that. And there's obviously competition. But we're encouraged with the level of detail in the number of conversations that we're having right now, as you look kind of at spots with near-term availability in our fleet. I would say - I said earlier kind of my bit about the U.S. Gulf; it's a premium basin. There, we think that those rigs could stay there a very long time. And I would say also our experience elsewhere, perhaps in relation to Suriname, but it really applies anywhere is that in a collaborative setting where the collective team is delivering very strong results, you do open up additional work. So yes, we're addressing the - to some extent, we're addressing the issue of efficiency, where we get paid for higher efficiency. But I think sometimes the unnoticed piece of that is that efficiency leads to more work in and of itself. And so, we're particularly excited really about both of these basins, but especially in really a new basin like Suriname about the potential of really unlocking kind of the maximum amount of work ultimately in the area.

Yes. That's actually very helpful, which brings me to my follow-ups, which goes back to the incentive structures of this. I think for the Shell work, you're talking about the 20% of the base rate that you can earn, and it seems that to be related to the speed of the wells really, but it's worded a bit differently for the Total contract. Does that mean that this potential additional revenue - is that potential additional dayrate revenue for you guys with no additional cost or is it any other type of additional revenue that might be a lower-margin revenue or related to additional services or anything? If you could give some clarity on that, that would also be very helpful. Thanks.

Sure. Yes, it's a very good question, actually, now that you've brought it up. No, it's all dayrate. There's nothing in there that's like - that's margin; it's all 100% margin potential there. The wording is different only because we work with our customers to print what works for all parties and we're - we just - that's where we ended on the wording. But no, there's nothing to read between the lines there. These are truly dayrate bonuses.

All right. That's very clear. Thank you so much. Have a good day.

Thank you.

Your next question comes from the line of Noel Parks with Tuohy Brothers. Your line is open.

Hello. Just wanted to follow up on sort of a housekeeping thing. During the remarks - the financial remarks, there was something about lease items left over from our acquisition. So could you just cover those again?

Sure, Noel. It's - so it's the Diamond BOP leases. So, essentially just wanted to state that those are running through operating expenses, if you will. So just want to be clear on where that hits on the financial statements. So it's about $26 million here in 2025.

Great. Thanks. Thanks for the clarification. And I wonder at this point and I realize, of course, we have a backdrop of uncertainty, any inkling of whether tariffs have the potential to move the needle on suppliers' input costs on to a degree that anything could get passed on as you look out to future projects?

Sure. The short answer is yes, right? It's a very fluid situation right now. And we talked about, as it relates to 2025 for Noble, we estimate this will impact less than $15 million, obviously - sorry, $15 million, and that can change as things play out. So on the steel side, that's something we're obviously focused on a lot. But ultimately, we would expect cost increases to generally get passed through to us. We're obviously managing that as well as we can. And so, that's why we wanted to provide some guidance as we see the world today from a 2025 perspective. But obviously, if things change materially from that, then obviously, we would expect a bigger impact to us here going forward, maybe into 2026 as an example.

Okay, great. Thanks a lot.

There are no further questions at this time. Mr. Robert Eifler, I will hand the call back over to you.

Thanks, everyone, for joining us today. We look forward to catching up with you at the next quarter.

Thank you so much. This concludes today's conference call. You may now disconnect.