Thank you for your patience. My name is Kathleen, and I will be your conference operator today. I would like to welcome everyone to the Seadrill First Quarter Earnings Call. I will now turn the call over to Lydia Mabry, Director of Investor Relations. Please proceed.

Thank you, operator. Welcome to Seadrill's First Quarter 2024 Earnings Call. Today's call will feature prepared remarks from Simon Johnson, our President and Chief Executive Officer; Grant Creed, Executive Vice President and Chief Financial Officer; and Samir Ali, Executive Vice President and Chief Commercial Officer. Also joining us on the call is Marcel Wieggers, Senior Vice President of Operations. Today's call may include forward-looking statements that involve risks and uncertainties. Actual results may differ materially. No one should assume these forward-looking statements remain valid later in the quarter or year, and we assume no obligation to update. Our latest Forms 20-F and 6-K filed with the U.S. Securities and Exchange Commission provide a more detailed discussion of our forward-looking statements and the risk factors affecting our business. During the call, we may also refer to non-GAAP measures. Our earnings release filed with the SEC includes reconciliations to the nearest corresponding GAAP measures and is available on our website. Our use of the term EBITDA on today's call corresponds with the term adjusted EBITDA as defined in our earnings release. Now let me turn the call over to Simon.

Thank you for joining us for our quarterly conference call. Seadrill had a strong start to the year. In the first quarter, we recorded $367 million in revenue, $124 million in EBITDA and returned to a 33.8% EBITDA margin. We delivered safe, efficient operations to our E&P customers, and our results benefited from strong uptime. We recently announced the highest day rate of the current upcycle, securing the one-well contract at a clean rate of approximately $545,000 per day, marking consistent improvement from the benchmark rates we announced last quarter as we strive to maintain top quartile pricing across our floater fleet. As an organization, we continue to make progress in several key areas. First, we reintegrated the West Polaris and the West Auriga into the Seadrill rig fleet, terminating their third-party manager following their recent contract completions, and we'll do the same with the West Capella and the West Vela this year. In March, we began preparing the Polaris and Auriga for the Petrobras contracts in Brazil. Less than two years ago, we moved four rigs into Brazil, three for Petrobras and one for Equinor. So, we have near-term familiarity with the customer and country acceptance and approval processes and have the systems and experience to recognize and act upon any early indicators of potential issues. While we acknowledge the risks inherent in any large project, we are committed to managing and executing those contract preparations effectively so that rigs can start generating EBITDA and cash flow full year-end are scheduled. Next, we continue our efforts to sell our three Qatar jack-up rigs, keenly aware that a potential divestiture will further focus our enterprise on our core market segment for floating rigs. We'll provide an update on this transaction when available. Lastly, we continue to deliver solid shareholder returns through both our equity performance and our share repurchase program. Since initiating the $500 million program in September of last year, we have repurchased a total of $442 million or nearly 12.5% of our issued share count, we consider capital returns a fundamental part of our value proposition. And consistent with our capital allocation policy, we intend to return excess capital to shareholders once we've ensured the strength of our balance sheet, invested in the competitiveness of our active rig fleet and evaluated potentially accretive growth opportunities. We remain consistent in our offshore market outlook, encouraged by the strength of fundamentals that underpin it. We believe deepwater will remain an attractive source of oil and gas production with its expansive reserves, high rates of return and advantageous emissions profiles. The current offshore rig market remains buoyant, with marketed utilization for deepwater floaters exceeding 90%. Since 2015, 170 floaters have left the market. Over the same period, precious few rigs have entered. Some rigs remain in the shipyard or at stack locations but still require significant amounts of money and time to be reactivated for contract. We believe sidelined stack capacity may only trickle into the market going forward, if at all, when their owners secure contracts that can justify reactivation costs that almost always exceed $100 million on the low side and approach or exceed $200 million on the high side. The longer these rigs have been inactive, the more challenging the issues for their reactivation become, and the less likely it is that they will return to work. The drilling industry's recovery has been largely supply-driven thus far, and a continued upswelling of demand across a broadening base supports further market development. The Golden Triangle remains the engine room of deepwater production, but incremental demand is increasingly distributed across geographies. It is not limited to a single epicenter, so the market will continue to grind higher. That said, we do not expect net sequencing of supply and demand. One of the most challenging aspects of today's market is timing. E&P preference for growing cash flow over production can cloud market visibility. Aside from some unique instances of extensive term contracts, most customers appear to be seeking contracts for a maximum of two to three-year terms. Discrete delays around permitting, supply chain challenges and even efficient operations can affect rig schedules and contracting, further contributing to momentary mismatches in supply and demand that may result in intense market activity within a relatively compressed window. As an industry, offshore drillers simply do not have the same level of visibility we enjoyed in past cycles. So, while the day rate environment improves, there's nonetheless potential for volatility in rig utilization that may result in a delay or dislocation of demand. In this environment, our balance sheet strength and positioning provides stability. Operating a premium floater fleet in advantaged geographies resilient to changes in oil price and general market conditions further supports our ability to generate durable earnings and cash flow, ensuring the continuity of our rig operations maximizes the potential of this earnings power. As the cycle progresses and day rates trend higher, the opportunity cost of unplanned unpaid downtime rises, and the more we can minimize out of service time, the better. Our commercial team continues to improve terms and conditions to maximize uptime, earning back some of the protections drilling contractors lost during the downturn. We're advocating for contracts that address higher allowances for repair and maintenance, raise the threshold for potential downtime triggers, and secure better rate percentages for non-drilling days spent on activities like standby, repair and waiting on weather. Meanwhile, our operations and project teams aim to schedule and perform necessary equipment recertifications, maintenance and upgrades in a manner that minimizes the impact on rig contracts to the extent practicable. As we move towards maintaining and investing in our fleet on a continuous rather than a periodic basis, the timing of our capital expenditures may begin to change, providing explicit guidance range on spending for a typical special periodic survey or SBS, beyond the $2 million to $5 million related to class flag and coastal state compliance can become misleading. For example, we will begin upgrading the West Neptune with managed pressure drilling capabilities during a planned out-of-service period later this year, taking advantage of the already scheduled downtime to make her the 10th MPD-capable rig in our fleet, the additional investment will enhance traditional SBS spending. Meanwhile, the four drillships we operate in Brazil underwent extensive contract preparation before mobilizing less than two years ago. When they reach their 10-year anniversary date, they should only require minimal spending and no associated out of service days beyond what's accounted for in their contract. This discrepancy across individual rig spending on five-year increments, along with the targeted effort to move towards continuous equipment classification may change how we discuss SBS spending moving forward. Regardless of what we label it or how we schedule this out-of-service spending, rest assured, we will maintain the competitiveness of our rig fleet so that we can deliver the safe, efficient operations our customers expect and demand from Seadrill. I'm proud of our continued operational and commercial achievements and the teams that have delivered them. To the Seadrill employees, thank you. I appreciate all that you continue to do to strengthen our position in the marketplace as a leading deepwater driller. We remain encouraged by the market outlook. Admittedly, the temptation in an improving market is to focus solely on the top line. But at Seadrill, we take a holistic view of the business, ensuring we maximize shareholder returns. We are continuing our efforts to improve our cost performance, quality of service delivery and general efficiency in supporting our operations. As previously mentioned, we believe the business could be characterized by increased volatility, and we remain ever mindful of the importance of having an appropriate cost culture to ensure that the company is ready to meet any changes in demand. With that, I'll pass the call to Grant.

Thank you, Simon. I'll review our first quarter financial results before speaking on our cash flow, balance sheet, and full-year guidance. In the first quarter, we delivered total operating revenues of $367 million. The decline in contract drilling revenues accounted for almost all the sequential difference. At $275 million, contract drilling revenues were $40 million lower than the previous quarter, primarily due to fewer operating days, partially offset by improved economic utilization. We had three rigs off contract for varying durations. The Sevan Louisiana completed its work for Thales in the U.S. Gulf of Mexico in late December, underwent a planned out-of-service period for its 10-year special periodic survey and required maintenance. The West Polaris completed a TGC campaign in late January, and the West Auriga completed its work with BP in the U.S. Gulf of Mexico in late February. As Simon mentioned earlier, in March, we reintegrated the Polaris and the Auriga into Seadrill's fleet and mobilized them to shipyards to prepare for their upcoming Petrobras contracts. EBITDA for the first quarter was $124 million, a $24 million sequential increase relative to Q4 primarily related to strong economic utilization of 97% during the quarter, partially offset by the reduced rig activity described above regarding Louisiana, Polaris, and Auriga, and a $16 million benefit related to the recovery of historical import duties in the form of tax credits that we expect will translate into cash benefits from 2025. Additionally, as we mentioned in our prior quarterly call, Q4 was negatively impacted by the timing of certain repairs and maintenance spending and $15 million of non-cash accruals. These did not recur in Q1, which partly explains the improved performance. First quarter results also include adjustments to back out $4 million of nonrecurring costs in the SG&A line related to the closure of the company's London office and the consolidation of our corporate headquarters in Houston, and $2 million related to the Aquadrill integration costs. EBITDA margin, net of reimbursable revenue and expenses was 35.7%. Now turning to cash flow and the balance sheet, cash flow from operations was $29 million for the quarter after deducting $29 million of long-term maintenance CapEx. Cash flow from operations was impacted by annual employee incentive payments made in the first quarter and the biannual payment of interest on the secured bond. Capital upgrades captured and investing cash flows were $23 million for the quarter, resulting in free cash flow of $6 million. In the first quarter, we made $119 million of share repurchases. To date, we have returned a total of $442 million to shareholders with $58 million remaining under our current repurchase authorization. We maintain a strong balance sheet and financial position. At the end of the quarter, we had total gross debt of $625 million, inclusive of the $50 million convertible bond, a cash position of $612 million, including $28 million in restricted cash and an additional $225 million in available borrowings from our undrawn revolving credit facility. Net debt was $13 million, consistent with our desire to maintain net leverage of less than 1. As we think about the year, we maintain our full-year guidance previously shared on our fourth quarter earnings call. That is $1.47 billion to $1.52 billion in revenue, $400 million to $450 million in EBITDA and $400 million to $450 million in capital expenditures. Our guidance includes $5 million in non-cash net amortized mobilization expense and approximately $70 million of reimbursable revenues and expenses. With that, I will pass the line to Samir.

Thank you, Grant. I'll start by reviewing our contracting activity since the last call and then provide a brief update on the market. In Korea, the West Capella secured work at a clean rate of $545,000 per day. Note this rate does not include BD or mobilization, both of which will be covered by an additional charge. The contract represents the highest rate achieved in the current upcycle and is an encouraging indication of the market's potential rate progression in 2025 and beyond. The West Capella is scheduled to complete its current campaign in Indonesia in mid-August and should begin its new contract in December. Closer to home, we continue to build on our decade-long partnership with LLOG in the U.S. Gulf of Mexico. The operator awarded the West Neptune a six-month extension that secures the rig fully through 2025. When this work begins next summer, the Neptune will earn $475,000 per day plus an additional rate for MPD as it becomes the 10th rig in our fleet to offer these capabilities, future-proofing the marketability of the unit. Also in the Gulf, the Sevan Louisiana secured a short contract for well intervention work, testing a new application of riserless intervention. We believe this could be an interesting market for the Louisiana and want to prove we could participate in the segment traditionally not serviced by drilling rigs if compelling opportunities present themselves. In April, we recommenced interventional work that should continue through May. We anticipate it will move to a higher-priced drilling contract shortly thereafter, pending final approvals. Even with this pending work, the rig will potentially have white space in 2024, though we believe we still have time to fill it since the Gulf of Mexico has short contracting lead times for an asset like Louisiana. Turning to Norway, the precarious market balance in the Norwegian North Sea will influence the fortunes of the West Phoenix. Norway is either one rig oversupplied or one rig undersupplied, an evolving situation that influences whether we can secure work for it in Norway or other markets. If we fail to secure a suitable contract that generates competitive returns, our intention is to stack the rig. Looking ahead into 2025, we are 66% contracted as of today. As Simon mentioned earlier, despite some uncertainties on the timing of demand, including the conversion from discussions to contracts, we remain confident in the market, encouraged by rig supply limitations, demand dispersion across markets, and day rate progression. Specifically for our rigs, we believe both the West Capella and the Sevan Louisiana are advantaged in the markets where they operate. Since the Capella benefits from near-term availability and MPD capabilities, and Louisiana's unique Hall design allows it to target niche applications. We are already in advanced dialogue to fill the remainder of the West Vela's tankard when the rig completes its existing program in mid-2025. The Quenguala and Libongos will also become available in mid-2025. While we prefer to stagger our rig contracts, so we are not competing against ourselves for work, that is not the case here, primarily due to the slips in well scheduling, not by design. Fortunately, we believe there are opportunities percolating in Angola and other West African markets that all three rigs should be able to secure work in the area. To sum it up, we continue to believe in the long-term fundamentals of our business. Despite some air pockets in demand that we have previously highlighted, we consistently outperform and are positioned well for the recovery as it continues to unfold. Operator, we'd now like to open the call for questions.

We will now begin the question-and-answer session. Your first question comes from Ben Nolan of Stifel.

I appreciate the color. I wanted to ask, first of all, on the West Capella doing the one rig in South Korea. It's an unusual location. And congratulations on the day. Is there any opportunity that there might be another well behind that? Or how are you thinking about sort of where the West Capella ends up, you're wanting to eventually move it back to one of your three core markets. Any color around that?

Sure. So, it was a great little contract win for us, and we're quite proud of that. Could it stay there a little longer potentially? For us, we would look to either move it back to one of our core markets, but there is also opportunity for it in Southeast Asia. So, we are looking at the broader market and saying, 'Hey, we could bring it back to a core market or if we find the right opportunity that justifies staying in Southeast Asia, we'll happily stay there as well.'

Okay. And any thoughts on how quickly that might develop?

I'd say we're in dialogue right now for that. So, most of that's going to be after the Korea work, however long that takes. But we are in advanced dialogue right now, but nothing to announce at this point.

Okay. I appreciate that. And then I was a little bit curious about your commentary on the West Phoenix and the opportunity in a harsh environment, either being a little over solid or a little undersupplied. And then if you're unable to get a contract that you would stack the rig, curious why you would choose to go that direction as opposed to maybe trying to redeploy it to a benign environment just to keep it running.

Yes, we are definitely considering benign environments as well. We are not limiting ourselves only to harsh conditions, so I want to clarify that. For us, there is an investment needed in the rig for various markets where it could be utilized. Currently, we are assessing whether making that investment would yield a return on our capital. If it doesn’t, we will consider stacking the rig. While the capabilities of the Phoenix make a harsh environment seem the most logical choice, we are also open to exploring benign environments.

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

I would like to follow up on Ben's question regarding the Phoenix. If the rig secures a contract, considering its 15-year special survey, how long should we anticipate it will be in the shipyard to complete that survey?

It really depends, Greg, on where the rig is going to be deployed.

Some base case, it stays in the North Sea.

If it remains in Norway, it will be a larger project than if it is working in the U.K. Currently, we have purchased many long lead items that will enable us to conduct that survey once the current contract concludes. However, we haven't confirmed the timing yet. We are hesitant to make commitments regarding the outstanding capital expenditures until we have more clarity about our future work. In recent years, one notable trend in the NCS has been an increase in the costs associated with conducting these surveys and ensuring compliance with regulators' requirements, especially concerning new equipment guidelines. Therefore, we need to ensure there is enough work to justify that commitment and expense.

Yes, that's very helpful. As I consider the low and high ends of our guidance, I recognize we may not have the Phoenix fully operational after its current contract. The key factors will likely center around opportunities in Louisiana. I understand you may not want to discuss the drilling work, but it was encouraging to see the well intervention efforts. A significant well intervention asset has been relocated to West Africa. This indicates that if there's an increase in activity, we will require nontraditional intervention assets to accommodate that. How should we be assessing the pricing differences between well intervention contracts, regular drilling, and potentially lower-tier options, particularly considering differences in rig generations?

Yes. I understand your point, Greg. The rates are indeed lower than what we see in the core deepwater market. In that regard, they are less than what we typically receive for conventional drilling jobs, but this segment is becoming increasingly vital in mature basins such as the Gulf of Mexico. One of Louisiana’s significant advantages is its capability for dynamic positioning in shallow water, which is where much of this work will be generated. We are eager to explore this opportunity. Additionally, due to its unique hull design and capabilities, Louisiana can seamlessly transition between different types of work. In fact, I believe one of the primary attractions for the client in this situation was our ability to offer that flexibility. We are optimistic about moving from well intervention projects to more lucrative conventional drilling opportunities. Samir, do you have anything to add?

Yes. No, I think as Simon said, right, the Louisiana can hit those low water depths. And for us, it's getting the resume that we can do well intervention work. We tested out a new technology as well while we're doing it. And we view it as a bridge into drilling work that is pending approval at this point. So we will transition to more profitable work here shortly.

Super helpful. Thank you very much.

Your next question comes from the line of Kurt Hallead from Benchmark.

Good morning, everyone. I'm curious about some market dynamics you mentioned, Simon, regarding idle assets and the increasing costs associated with bringing them back online, even as demand remains solid and the outlook looks favorable. Given the limited availability of operating assets and the high-cost assets that are currently sidelined, what feedback are you receiving from customers? Do they grasp how tight the market is and the associated costs and timeline? It seems that recently, there hasn't been as much urgency compared to previous cycles. I would appreciate any context you can provide on this.

Yes. No, I think that's a really interesting point, Kurt. I mean, one observation I have looking back on the last 12 months is that despite fears about the market direction and momentum, the rates have continuously ground higher, and that's been consistent with our expectations, but not always with the views of market spectators through time. So, I think directionally, we've been correct in our estimation of where the market is going. I think when you think about the cost of reactivating rigs, there's definitely more cost and more risk associated with that than we've seen in the past. These modern rigs are a much more complicated beast than the rigs we're operating 20 years ago. And I think there's a period of adjustment as people come back and start surveying the space from the investor base; I think there's a bit of a catch-up on the education required to help people understand what those costs look like and how significant they are. The biggest issue for me is that we just don't have the visibility to commit to large chunks of capital expenditure without certainty that we're going to be able to recoup that in an acceptable period of time. I think the good thing that we're seeing at the moment is across the drillers, there's generally speaking, not always, but generally speaking, there's a great fiscal rectitude, and people are acting rationally. So, when we think about the rigs we have that are currently working now, but may be reactivated in the future, we're adamant we're not going to pour a whole bunch of our shareholders' money into those projects unless we know that the rig has a good long-term operating future. So, I think the customers understand that, but we're going to be reluctant to pay for it. Anything to add, Samir?

No. I mean, I think the only thing I'd add to that is I think clients are quite keenly aware, but you still have some capacity available to them in the market that's hot and active. Until you absorb that capacity, clients aren't really going to step up to invest in a reactivation at this point. It will come. It's just going to take a little more time.

Yes. I mean, we remain very positive about the development of the market. We see consistent improvement in demand through time. Our customers are telling us that deepwater production is an increasingly important part of the hydrocarbon mix, lifting costs are low, and profitability is extremely high for our clients. So, it's a really good macro story, and we're starting to see the base of demand broaden as well. So, we think the market's headed in a great direction.

Okay. That's great. I appreciate that color. Now maybe getting a little granular, right? You guys referenced a couple of new contracts with base rates and not including the MPD services and so on. So how should we think about, number one, the dollar per day value of MPD services? And then how frequently are those services deployed during the course of a program?

Yes. I'll start with that question and then pass it to Marcel. Regarding the second question, it depends on the well. Some wells require managed pressure drilling (MPD) throughout the entire formation, while others do not, so it varies. Currently, we believe we are performing well, earning between $40,000 to $45,000 a day for MPD on the contracts we announced, which is higher than the market average. This is partly due to our extensive experience with MPD; we have conducted more MPD wells than many others, allowing us to command a premium. Now, I'll let Marcel provide more detail about our capabilities in MPD.

Yes. So, it depends a little bit on the area where you're operating as well. So going forward, five out of six weeks operating in Brazil will be equipped with MPD equipment. On the other side, in Angola with MPD equipment. But as a company, we're currently drilling our 99 MPD well. By this summer, we'll all spread out our 100th MPD well. So, we've got a huge experience, which will give us a competitive edge in that respect as well.

That's great. I appreciate it. Thank you.

Your next question comes from the line of Josh Jayne from Daniel Energy Partners.

First, I wanted to revisit the Louisiana situation. I know you've mentioned that it will likely transition to higher-priced drilling work soon after the intervention phase. However, I'm curious about your long-term perspective on the asset. Do you see potential opportunities for intervention in the Gulf of Mexico market? Could you elaborate on that a bit?

Sure. I think there's that potential. She is designed as a drilling rig. So we'd like to pursue drilling opportunities with that if we can. But intervention by its nature, is usually quicker. It is not term work for the most part. There are some clients that have enough wells where they could sign up a term intervention vessel. But for us, the focus is going to continue to be drilling with Louisiana if we can get it.

One thing I would add, Josh, is that the differential between intervention work and conventional drilling has been compressing. And I think as P&A liabilities and well intervention becomes a more important part of operators' portfolio in the Gulf of Mexico, the ability to switch between the two is attractive. Most operators lack the resources these days to handle multiple rig strings. So, the ability to have an asset that is something of a Swiss army knife, we believe is going to be attractive. The Louisiana, in terms of specification, is at the lower end of the spectrum of capability in that particular market, but we see that as a plus in terms of increasing affordability of the unit to progress a broader range of work.

Okay. And maybe just one other one. You talked about the three JV rigs in West Africa, and Samir mentioned all three could continue to work there in 2025. Could you just offer a bit more detail about maybe if you don't want to touch on where you are in discussions, but maybe just the outlook for that market over the next couple of years would be helpful.

Yes, sure. So, you're seeing demand pop up across the West African coast and candidly, a little bit into East Africa as well. So, there are active programs. We've got some clients that are looking openly for work in Nigeria. You've got some in Namibia that are starting to heat up. You've got Angola. So overall, late ‘25, ‘26 feels pretty good in the African market.

I would add, Kurt, too, that the JV activity footprint is not limited to Angola. We've seen a lot of activity, including some really important discoveries in the adjacent geography and in Namibia. So a lot of the service companies that are supporting those drilling operations in Namibia are mobilizing straight out of Angola or being supported directly from Angola. So we think that strategically, those rigs in that joint venture may well be pursuing work nearby, not necessarily just in Angola.

Your next question comes from the line of Doug Becker of Capital One.

Just curious how one-time items of the $16 million benefit from the recovery of import duties is handled in guidance, really kind of thinking about it, does it shape expectations toward the higher end of the range that's been laid out?

I think when we set guidance last quarter and reiterated it this quarter, we considered various opportunities and risks. We aren't specifying exact points, but it's clearly an element to consider. Now that it's materialized this quarter, we keep it in mind when reiterating guidance. However, I'm hesitant to say whether it leans towards the top or the bottom, as it takes into account several factors.

And just to clarify, it is included in your expectations for adjusted EBITDA.

It is, yes.

Got it. And then lots of questions about Louisiana. Maybe just one more. There's a report saying the rig heading in Angola once the shorter-term Gulf of Mexico work is done. Are you able to provide any color there? And maybe more broadly, when we're thinking about white space for the rig this year, should we be thinking about a mobilization?

We're marketing in all markets around the world. So is that a potential? Absolutely. Could it stand in the Gulf of Mexico? Absolutely. We see work in both markets, and we see work in other markets for the Louisiana as well. So that white space could be mobilization or it could be just time between contracts here in the Gulf of Mexico. But I would say we are marketing that asset globally right now.

I think the Louisiana has a proud track record of surprising to the upside. I mean, I don't think many people understood that it's on contract until we made that clear. And as we think about the range of opportunities for the rig, there's plenty of opportunities for it in the Gulf, both with the existing and other operators. So, but we are marketing internationally as Samir says.

Your next question comes from the line of Hamed Khorsand from BWS Financial.

So my first question is about Africa. You've been speaking highly of it, but where has the market not met your expectations? Where have the lead times been extended? It still seems like the market is developing, even though Africa is showing positive signs.

Yes. I would say that in our key regions, the area where we have noticed some delays is likely Brazil. There has been a slight postponement in some of the tenders there. Honestly, this has probably worked to our advantage since that demand has not coincided with when we have rig availability. However, I would mention that this is a market where you've probably observed some delays, and that's not due to poor geology or lack of demand from the client. They are simply waiting on other factors like FPSOs or wellheads that have caused their timelines to extend. Nonetheless, I'd emphasize that this situation has actually benefited us because that demand has now aligned with our rig availability.

So that was going to be actually my follow-up on it for a different reason. Petrobras CEO has changed this morning. Any commentary as to how that would benefit Seadrill in the industry or how it would not, given the ownership?

Yes. I don't think it's going to have a huge impact, candidly. I mean, you've got a relatively supportive government who wants to continue drilling for hydrocarbons in Brazil and building that out. So, I don't think it really changes the day-to-day for us.

Your next question comes from the line of Noel Parks from Touhy Brothers.

I have a couple of questions. You mentioned earlier that some customers still see available capacity. I'm curious if it’s fair to say that the urgency of the situation hasn't been felt by all customers yet. It seems like the situation is clear, but are there still some who might be overly optimistic about availability and pricing at this point?

Well, let me start with that, and then we can pass to Samir. The main issue with the market right now revolves around visibility. Operators are demonstrating strong discipline by choosing to return capital to their shareholders instead of primarily investing in the future of the business. We are definitely observing an increase in capital expenditures year over year. However, they are maintaining a disciplined approach, and the timeframe for making decisions is quite limited. What you are noticing with these gaps or uncertainties is essentially the challenge of aligning availability with that tight timeframe, which inevitably leads to dislocations. I expect this situation to continue. Generally, drilling contractors and operators are collaborating, and there is significant demand in the market that isn't readily visible. Many agreements are being made that aren't public, and they prefer to work together to manage the situation rather than letting it fall apart. Thus, while there is a lot of cooperation and collaboration, it isn't always perfectly resolved.

It seems we are experiencing a different kind of reality check. While it may not be accurate to label it as a widespread trend just yet, the market remains quite supportive of mergers and acquisitions, especially those involving stock, despite overall capital discipline. One observation among operators is the expectation of future interest rate cuts, which appears to have kept bond debt rates from rising as much as anticipated. Companies seem to maintain a strong commitment to dividends and buybacks, but may be becoming slightly more open to leveraging than they have been in the past. I'm curious if you've noticed any indications of this, particularly if customers are showing a willingness to commit to longer terms and appear less concerned about future costs.

You're starting to see some clients get a little more comfortable with it, but I wouldn't say that's the role we're starting to see a little bit. But overall, clients are still looking at, hey, this is a program that's been FID, this is the program we want to go drill. So it's always that fine balance of going along and locking in a right versus keeping it short. A good example is our relationship with a log in the U.S. Gulf of Mexico. I mean they've been with the same rig for 10 years. We've been able to reprice it every six months. In a recovering market, we're happy with that. And I think they're quite happy with that as well because it gives them flexibility, but it allows us to reprice every six months. So are we seeing clients do it a little bit, but not as much as you would think.

And your next question comes from Fredrik Stene of Clarkson Securities.

Simon and team, I hope you are well. I believe this is a new record with a significant number of questions in the Q&A over the last 10 years regarding drilling. I'll try to be brief for time's sake. Regarding your guidance, can you clarify if the difference between $400 million and $450 million on the EBITDA side is solely due to your ability to secure new contracts, or are there also cost elements, bonus elements, or other factors that could influence that range?

Yes. I think some of the levers are obviously around contracting cover on the Louisiana and Phoenix. But I think the other one is obviously the projects that we're currently undertaking on the West Polaris and the West area in preparation for the contracts down in Brazil. I can provide a bit of color on that, if you like. Just so people are aware, the rig was released earlier than anticipated. We toyed with chasing some fill-in work, but we've chosen instead to de-risk the schedule by starting the rig project earlier than perhaps was anticipated. We're keenly aware of the risk profile of those projects and laser focused on delivering them into service before the end of the year. Obviously, that's a potential delta surrounding if we start earlier than anticipated versus if we incur project overruns and start later, that's another factor as well. At the moment, we remain firmly on schedule today. We'll update you as we move forward in the year on that one. But I think really, they are the main ones. It's about contract cover on those two rigs we mentioned and how we go on the projects for contract preparation in Brazil.

Very helpful. Second, you have, as you've discussed, many rigs rolling off in 2025. You've given some color on what you think about certain of those rigs. And I'm just curious when you are re-contracting those rigs, how many of them should we expect to see contracts for announced already this year? And also, are you actively trying to stagger the next round of re-contracting more than what's the case right now since, again, many of those rigs are rolling off somewhere in 2025? I guess my question relates to whether or not you will purposefully mix short- and long-term contracts just to make sure that it's even more staggered the next?

Yes. We definitely aim to stagger the contracts and develop a more balanced portfolio that allows for a smoother roll-off profile. In addition, as Simon mentioned earlier, we are focused on improving the overall quality of our contracts, including the day rate and terms. We need to find the right balance between staggering the expiration of contracts and ensuring that we secure favorable rates and terms. All of these factors are interconnected.

Yes. Samir. And finally, on your CapEx guidance, also $400 million to $450 million, just to be absolutely clear, that would include both the cash flow elements from operations and investments, right? So compared to that guidance, you've incurred, I think, 23% plus 29% so far this year. Is that the correct way to think about it? Just to have an end of how the timing of the capital will be for the rest of the year?

That's right. I think you're referring to the cash flow statement on how we present the maintenance elements of CapEx, which is in the cash flows from operations, which was cost $29 million plus the $23 million from addition...

Yes. Okay. Now I just wanted to make sure that I understood it correctly. All right. That's it for me. Have a great day.

That was our final question. Ladies and gentlemen, that concludes today's call. Thank you all for joining. You may now disconnect.