Thank you for standing by. My name is Bailey, and I will be your conference operator today. At this time, I would like to welcome everyone to the Noble Corporation First Quarter 2025 Earnings Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, again, press star and one. I would now like to turn 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 in 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. 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 day rate 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. Both contracts have four one-year options following the firm's four-year term at mutually agreed day rates. As part of the Shell contracts, we will be making certain upgrades to the rigs, including increasing the derrick hook load from 2.5 million to 2.8 million pounds, adding a controlled mudline system, which is essentially an alternative approach to managed 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 drillships in the world for the remaining life of the assets. In total, these upgrades are expected to comprise $60 million -$70 million of CapEx per rig, which we anticipate being spread among 2025, 2026, and 2027. 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 base and scale and expertise. Each of these new long-term contracts in Suriname and 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 "normal" operational performance on these contracts can yield a significant amount of incentive revenue capture. 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 Discoverer at its existing day rate, which we expect will extend this campaign into August 2026 and keeps the Discoverer 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 will 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 2nd 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. We also derive strength and stability from our alignment with a large swath of customers that have generally resilient capital programs and less squishy 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. 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 day rate 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 the Noble Black Rhino 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 Black Rhino for near-term jobs. Turning to our 6th-gen rigs, our 3D 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 contract 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 day rate 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 Intrepid's 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 NCS. 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 for 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 costs of $40,000-$50,000 per day on a combined basis, as well as bring in net proceeds of over $35 million. As summarized on page five of the earnings presentation slides, our total backlog as of April 28 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-$3.45 billion, adjusted EBITDA between $1.05 billion-$1.15 billion, and capital expenditures, which excludes customer reimbursements, are between $375 million-$425 million. As it relates to the adjusted EBITDA guidance range, we're 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 SPS, which is expected to take 60 days all 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. 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 supports the 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, proving 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, but 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. At this time, I would like to remind everyone in order to ask a question, press star and the number one on your telephone keypad. Your first question comes from the line of David Smith, Pickering Energy Partners. Your line is open. Hey, 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 TotalEnergies contracts. 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 drill ships in Guyana? And is it fair to think that performance component risk has a lot to do with the duration of the programs and maybe the marginality 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. To your point, it definitely does not 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 have 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. We got to a place that we think works for both sides. I would say, I guess, that we mentioned the word strategic. That is obviously deliberate. Our approach here, I think, was very strategic, not only in the structure that we have described a little bit, but also in where that structure is applied to basins, the type of program, etc. I appreciate that color. 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 for the drill ship and Suriname? There appears to be 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 was it? Six or seven, eight years ago, longer maybe now. 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. We have had this come up in certain other kinds of nuances that go into rates, whether it's types of costs or taxes or whatever. It is flexible enough to also take into account this type of structure. We have not had this conversation yet, so I do not want to really say anything more than that. It is a mutually agreed rate that we get together and decide on every six months. Both sides put in data as both sides see it, and we take that data and mutually agree. As you know, to the extent that we have trouble with that, sometimes we will bring a third party in as well. 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. We're going to have to go through some type of that as we move through the CEA. Perfect. Really appreciate it. Thanks. Your next question comes from the line of Arun Jayaram with JP Morgan. Your line is open. Yeah. 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? Talk to us about opportunities for these really interesting opportunities with Shell. Yeah. The Suriname contracts are obviously incremental. The Shell contracts in the U.S., that's a key basin for them. 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 decade-plus without really having to make a substantial mobilization. When we say strategic, that's a big piece of it for us. These rigs are getting to be about a little over 10 years old. If you think about accounting lives, etc., 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, that this is not incremental right now. For us, the bigger piece of this was the longevity of the potential work here. Great. Maybe my follow-up. Richard, you went through kind of the sequential changes in your OpEx expectations. Can you maybe elaborate on what you see in 2Q 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. Yeah. Sure. Very good. Quick question, Arun. We noted in the prepared remarks that obviously we had a $20 million impact from the Regina Allen. That was a net against cost. Obviously, that's not going to reoccur, if you will, in Q2 going on. If you back that out, our operating costs, if you will, on the income statement, I think would have been about $480 million, $485 million. Inflation is real. 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. 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. Really, cost management is really what's driving that. We're obviously very focused on managing costs here and 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. 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'd be great. It's well by well. In actually both contracts, it's well by well. So collection would have happened after. You'd have to do some sort of reconciliation of data, etc., and then have payment terms or whatever. But they are well by well bonuses. Okay. They're fairly frequent throughout the contracts then. Okay. Can you provide some more color on the downtime associated with the rig upgrades required on the Shell contracts? How should we think about finding some shorter-term work for those rigs before the long-term contracts start? Yeah. I think it's kind of a couple of months for us to do the actual work that would pull us out of being able to carry out other work. We said we've got a number of conversations ongoing right now for things that would fit in between. We'll see how that plays out. Yeah, 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. I appreciate the call. Thank you. Thank you. Your next question comes from the line of Eddie Kim with Barclays. Your line is open. Hey, 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? You mentioned that kind of normal operations would more or less equate to achieving around 40% of the performance bonuses of the contracts. Please correct me if I heard that incorrectly. What more would be needed to get closer to realizing the full value of those performance bonuses? Yeah. There are 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. That's where we've spent a lot of time. I'd say I don't want to give any real breakdown or specifics. It's proprietary to our customers as well as us. There's obviously other components to performance, their safety, and other things, all of which we pride ourselves on. I think about a very important driver being the time against the curve on a well. I mean, all of it is where the win-win comes in. In a big development, there is probably more to play with there in terms of the self-funded pool. Got it. That is very helpful. My follow-up was just on the contract expenses or, I guess, contract prep expenses on these. You mentioned the upgrade CapEx on the two rigs with Shell. Are the contract prep expenses for these larger than some of your other multi-year contracts you have announced previously, or are they more or less in line? I was going to say they are much, much more in line. Obviously, the CapEx and capital on the Shell contracts, we have spoken about that. Think about the contract prep expenses as very much in line, Eddie. Okay. Great. Thanks for the caller. I'll turn it back. Your next question comes from the line of Greg Lewis with BTIG. Your line is open. Hey, thank you. Thank you. Thank you. And good morning. 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, 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 a lower oil price against a strong backlog? Just kind of any kind of how is the board thinking about that dividend? Kind of curious on that. Yeah. We are 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. We said in the remarks, we see that ticking up with these contracts we have just announced. 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. There are multiple different paths to that uptick occurring sooner than the start of these contracts. It is too early to tell. I do not want to say too much now, sitting here in early 2025. 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. Yeah, we're pretty confident here in our return of capital structure. Okay. Great. Just on the realizing what's being limited and what we can and cannot say. 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. In the press release, we talk about the Noble V-class rig. Was there something specific about those rigs that the customer wanted, i.e., as opposed to, 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 work? Thanks. Sure. Yeah. Look, I'd say initial pricing happened a little while back. The reality is that final pricing happens effectively when you sign a contract, especially in a volatile market like this. Yeah, I'd say these are 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 won, -- excuse me, rig of the year from Total last year. Both Shell and Total have used the V-ships multiple times through time. They are just big supporters of those rigs. Those really were the preferred vessels. In the case of the U.S., which has a different type of work, requires higher hookload in some instances, there is a more limited number of higher hookload rigs out there. We were really happy to upgrade these as part of that contract. Along with the other few upgrades we mentioned for the U.S. work, these are going to be right there with some of the highest spec rigs on earth. That is going to be something that I mentioned before. We hope to be right where we are for a very long time. That is something also that would be valued by a very wide variety of clients should things change. Yeah, look, everything kind of matched up nicely. They have really high thruster power, so they can hold position in Suriname, which is important. 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. Hey there. I guess it's been said many times already, but congratulations on the very long and very nice contracts. I also have a couple of questions relating to those contracts. 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 these comments then kind of pointed to the Shell and Total work, that there could be more coming down kind of the same line. I was wondering if you could give some additional color on that, because obviously these four rigs will be tied up for three or four years. To me, it's kind of natural to assume that this could be similar long-term programs for maybe other rigs. 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. Any color on what you meant by these comments would be super helpful. Thank you. Sure. Yeah. 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. It's too early to tell and all that. There's obviously competition. We're encouraged with the level of detail and the number of conversations that we're having right now as you look 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. We think that those rigs could stay there a very long time. 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. Yes, we're addressing the, to some extent, we're addressing the issue of efficiency where we get paid for higher efficiency. I think sometimes the unnoticed piece of that is that efficiency leads to more work in and of itself. We are 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. Yeah. 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 day rate 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. Yeah. It's a very good question, actually, now that you've brought it up. No, it's all day rate. There's nothing in there 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. That is where we ended on the wording. No, there is nothing to read between the lines there. These are truly day rate bonuses. All right. That is 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 financial remarks, there was something about lease items left over from the acquisition. Could you just go over those again? Sure. No. It is the Diamond BOP leases. Essentially, just wanted to state that those are running through operating expenses, if you will. Just want to be clear on where that hits on the financial statements. It's about $26 million here in 2025. Great. Thanks for the clarification. I wonder at this point, and I realize, of course, we have a backdrop of uncertainty, any inkling of whether pairs have the potential to move the needle on suppliers' input costs 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. We talked about as it relates to 2025 for Noble, we estimate this will impact less than $5 million, obviously sorry, $15 million. That can change as things play out. On the steel side, that's something we're obviously focused on a lot. Ultimately, we would expect cost increases to generally get passed through to us. We're obviously managing that as well as we can. That is why we wanted to provide some guidance as we see the world today from a 2025 perspective. Obviously, if things change materially from that, 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.