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Thank you for standing by. My name is Kathleen, and I will be your conference operator today. At this time, I would like to welcome everyone to the Seadrill First Quarter Earnings Call. [Operator Instructions] I would now like to turn the call over to Lydia Mabry, Director of Investor Relations. Please go ahead.
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 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 up cycle, 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 West Capella and the West Vela this year. In March, we began preparing the Polaris and Auriga, the Petrobras contracts in Brazil. Less than 2 years ago, we moved 4 rigs into Brazil, 3 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 3 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 material amounts of money and time to be entered into service and be prepared for contract. We believe sideline stack capacity may only trickle into the market going forward, if at all, when they're owner 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 material, the challenges to their reactivation and the less likely it is that they will return to work. The drilling industry's recovery has been largely supply-driven thus far, 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, most customers appear to be seeking contracts for a maximum 2- to 3-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, whilst 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 solidity. 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 and the depth of the downturn. We're advocating the contracts that address higher allowances for repair and maintenance, raise the threshold for potential downtime triggers and secure better rate percentages for nondrilling 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 way that minimizes the intrusion to rig contracts to the extent practicable. As we move towards maintaining, investing in our fleet on a continuous rather than a periodic basis, the timing of our capital expenditures may begin to change, providing an explicit guidance range on spend 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 falsely precise. 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 reckon our fleet, the additional investment out scopes traditional SPS spend. Meanwhile, the 4 [ drillships ] we operate in Brazil underwent extensive contract preparation before mobilizing less than 2 years ago. And when they reach their 10-year anniversary date, they should only require minimal spend and no associated out of service days beyond what's accounted for in their contract. This discrepancy across individual rig spending on 5-year increments, along with the targeted effort to move towards continuous equipment classification may change how we talk about SBS spending going forward. Regardless of what we name or how we time 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 and 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 with which we support 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 because of fewer operating days, partially offset by improved economic utilization. We had 3 rigs off contract for varying durations. The Sevan Louisiana completed its work for Thales in the U.S. Gulf of Mexico in late December that 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 Seadrill's fleet and mobilize them to shipyards to be in preparation for their upcoming Petrobras contracts. EBITDA for the first quarter was $124 million, $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 in relation to 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 noncash accruals. A -- these did not repeat in the first quarter and therefore, explains part of 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 consolidation of our corporate headquarters in Houston and $2 million in relation to the Aquadrill integration costs. EBITDA margin, net of reimbursable revenue and expenses was 35.7%. Now turning to the cash flow and 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 and a $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 noncash net amortized mobilization expense and approximately $70 million of reimbursable revenues and expenses. With that, I will pass the line to man.
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, 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 up cycle 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 6-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 wanted to prove we could participate in the segment traditionally not serviced by drilling rigs, if compelling opportunities present themselves. In April, the recommence 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 on the Norwegian North Sea will influence the fortunes of the West Phoenix. Norway is either 1 rig oversupplied or 1 rig undersupply, an evolving situation that influence 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 attack 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 the contract, 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. And we are already in advanced dialogue to fill the remainder of the West Vela tankard when the rig completes its existing program in mid-2025. the Quenguala and Libongos, all 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 scheduled, not by design. Fortunately, we believe there is an option percolating in Angola in other West African markets that all 3 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 and demand that we have previously highlighted, we consistently punch above our weight 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. [Operator Instructions] Your first question comes from the line of Ben Nolan of Stifel.
So, I appreciate the color. I wanted to ask, first of all, on the West Capella doing the 1 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 1 of your 3 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. But 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. And she's one of the few rigs that's in that market that's got MPD. So, for us, 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 would 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. So we're definitely looking at benign environments as well. So for us, we're not limiting ourselves just too harsh. So I don't want you to feel -- or take that away. I think for us, there is an investment required in the rig for various different markets that we could put it to work in. And what we're doing right now is evaluating if we make that investment, do we get a return on our capital. And if we don't, then we'll look to stack the rig. But given the capabilities of the Phoenix, harsh environment is probably the most logical, but we're not opposed to looking at benign environments as well.
Your next question comes from the line of Greg Lewis of BTIG.
I guess, Simon or Samir, just following up on Ben's question on the Phoenix. In the event that, that rig were to get a contract just given its 15-year special survey, what kind of -- like, say, we see a contract in the next couple of months, how long should we expect that rig to be in the shipyard to undergo that survey?
It really depends, Greg, on where the rig is going to be deployed. The...
Some base case, it stays in the north saying.
Well, if it stays in Norway, then there's -- it's going to be a larger project than if it will be working in the U.K. CS for. So, at this stage, we've bought a lot of long lead items that would allow us to do that survey upon conclusion of the current contract. But timing is -- we haven't confirmed that as yet. Really, we're reluctant to make commitment as to the outstanding capital expenditure until we have clarity about our work going forward. I think one of the features that we've seen in the NCS in particular, in recent years has been a growth in the cost of doing these surveys and staying compliant with the regulators' requirements in terms of new equipment guidelines and so forth. So, we really need to be sure that there's a sufficient body of work there to underwrite that commitment and cost.
Yes. Super helpful. So just then as I kind of think about the low end and the high end of guidance realizing maybe we don't have the Phoenix working at all post its existing contract. I guess kind of the swing factors really are going to be opportunities for the Louisiana -- so as we think about the Louisiana and I can appreciate you might not want to talk about the drilling work, but it was good to see the well intervention work. Obviously, a big well intervention asset moved to West Africa, not you or someone else's. So, it seems like that if there is a pickup in activity, we're going to need nontraditional intervention assets to do that. Any kind of way we should be thinking about maybe the spread on what a well intervention type contract pricing looks like versus, say, I don't know, like -- and maybe not leading edge, but kind of realizing that it's a sixth-gen rig, not a seventh average kind of rate for drilling, any kind of well intervention versus discount drilling versus spread.
Yes. No, look, I understand what you're getting at, Greg. So, what I'd say is that the rates are definitely lower than the heart of the deepwater market. So, in that sense, it's less than what we get for a conventional drilling job, but it's becoming increasingly important part of mature basins like the Gulf of Mexico. And I think a great strength for Louisiana is its ability to DP and shallow water where a lot of this work is going to be emanating from. So, we're keen to develop that possibility. And the Louisiana because of its unique whole configuration and capabilities can switch between the 2 types of work fee -- and in fact, I think one of the key attractions for the client in this case was our ability to do just that. And we are hoping to bridge of the well intervention work into better paid conventional drilling. Samir, 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 viewed it as a bridge into drilling work that is pending approval at this point. So we will transition to a 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, everybody. So, I was -- I'm kind of curious, right? Simon, you referenced a couple of dynamics at play in the market where you have some idle assets, the cost of those assets to kind of bring it back in, continue to go up with time. And at the same juncture, right, you do have solid demand. The outlook is very favorable. So, I guess my question is, look, you have limited availability that's currently operating. You have high-cost assets sitting on the sideline. What's your sense when you talk to customers and like how -- do they understand how tight the market is? Do you understand the cost and time that's going to be involved because -- it just seems over the last few months, there really hasn't been as much sense of urgency as we might have seen in other cycles. So just kind of curious if you could give us some context around that.
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 grounded 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 much more complicated beast than the rigs that we're operating 20 years ago. And I think there's a period of adjustment as people come back and start surveilling the space from the investor base, I think there's a bit of a catch-up on the education required to people to understand what those costs look like and how significant they are. And 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 that a 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 that we have that are currently working now, but may be reactivated in the future, we're just -- 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 got 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. And 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 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 these -- 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 dollar value of MPD services? And then how frequently are those services deployed during the course of a program?
Yes. So, I'll take that one to start and then pass to Marcel a little bit. But I'd say starting with the second question, it depends on the well, right? So certain wells required on MPD throughout the whole formation, some don't. So, it really does vary. In terms of what we're getting, we think we're hitting -- we're punching above our weight class there and we're getting between $40,000 to $45,000 a day for MPD on the contracts we announced, which is above market. And part of that is just our experience with MPD. And we've done more MPD wells than most out there. So, we've been able to kind of charge a premium for it, but let Marcel kind of elaborate a little more about our MPD prowess.
Yes. So, it depends a little bit the area where you're operating as well. So going forward, 5 over 6 weeks operating in Brazil will be equipped MPD equipment. On the other side, in Angola [ Donavan ] and MPD equipment. But as a company, we're currently drilling our 99 MPD well. By this summer, we all spread out 100 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 one, just on -- just to touch again on the Louisiana. I know you talked about the fact that it likely moves to higher priced drilling work shortly after this after the intervention piece. But I'm just curious, when you think about the asset longer term, do you think that there are term opportunities for intervention for it in the Gulf of Mexico market? And maybe just expand 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 a 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 2 is -- that's 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 opening -- increasing affordability of the unit to progress a broader range of work.
Okay. And maybe just one other one. You talked about the 3 JV rigs in West Africa, and Samir mentioned all 3 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 is active programs. We've got some clients that are looking openly for work in Nigeria. You've got some in Namibia that's 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 onetime 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 think about -- well, first of all, Doug, it's Grant here. I think when we set guidance last quarter and reiterate this quarter, we're looking at various sort of things and various opportunities and risks. So, we're not pinpointing it. But obviously, it is a factor. And now that it materializes this quarter, we keep it in mind when we reiterate guidance. But yes, I think I'm reluctant to say which direction it pushes towards the top of the bottom, but it's considering a bunch of factors, though.
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 you 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 got 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 was just about Africa. You've been talking about highly about it, but where has the market not worked for you as far as your expectations? Where has the lead times been extended out, you're still sounding like it's -- the market is still developing for even though Africa is looking good.
Yes. So I'd say the place we've -- in kind of our core geographies, where we've seen things move out a little bit is probably Brazil. You've seen a little bit of delay in some of the tenders going on there. Candidly, that's probably worked to our benefit, not against us if that demand has not moved into when we have rig availability. But I'd say that is a market you've probably seen a little bit of slippage and that's not because the geology is not good or the client has not got the demand. It's just they're waiting on other items like FPSOs or wellheads that have pushed their schedules to the right. But I'd reiterate, that's actually work in our favor because that demand has now shifted into when our rigs are available.
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 had a couple of questions. You happened to remark a little while ago that there are customers who still see some capacity available out there and seeing that the -- I guess I'm wondering, is it fair to say that sort of the full on formal if you're missing out, hasn't necessarily hit all the customers yet. It sort of feels like the writing is clearly on the wall. But are there still some who are maybe unrealistically optimistic about availability and pricing at this point?
Well, perhaps I can -- let me start with that, and then we can pass to Samir. I think the big thing with the market at the moment is it gets back to the visibility issue. The operators are showing great discipline in terms of preferring to return capital to their shareholders rather than necessarily investing in the future of the business. We are seeing definitely shift from to higher CapEx on a year-on-year basis. But they are being very disciplined. And -- but the horizon for making decisions is relatively constrained. And so, what you're seeing with these white space or air pockets or whatever you like to refer to the as is really just the difficulty of resolving the availability against that tight time horizon and there's dislocations inevitably result from that. So, I think that will be persistent. I think the drilling contractors and the operators, generally speaking, are working together, and it's way seeing a lot of demand that's not visible in the market. There's a lot of fixtures that are taking place that aren't public, but they're preferring to work together to manage that process rather than and to sort of -- to full fall of it, I would say. So, I think there's a lot of cooperation collaboration, but it's not always perfectly resolved.
Right, right. And also this kind of just a different sort of reality check. I don't know if it's fair to say it's a widespread trend yet. But in the midst of capital discipline, the market has still been -- for operators market has still been a highly supportive of M&A, particularly done with stock. And I feel like the only sort of string from capital and I can kind of detect out there among operators is that, I guess, with the expectation that sooner or later, there are going to be interest rate cuts, it seems that rates on debt on bonds have not been as high in some of the reasons I've seen as I would have expected. And it seems to me I see a little bit of the company still totally committed to their dividend and their buybacks, but maybe a little less allergic to leverage than they have been for a while. And I just wondered if you were seeing any signs of that, especially if customers are openly looking to commit to longer term, just maybe seem to be a little less worried about that price tag down the road.
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, right? I mean they've been with the same rig for 10 years. We've been able to reprice it every 6 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 6 months. So are we seeing clients do it a little bit, but not as much as you would think. Great. Thanks for the detail. Bye-bye. Thank you.
[Operator Instructions] And your next question comes from the line of Fredrik Stene of Clarkson Securities.
Simon and team, hope you are well. I think this is a new record. A number of questions in the Q&A last 10 years for drilling. But I'll try to keep it short here in the interest of time. First, on your guidance, can you -- is the difference between $400 million and $450 million on the EBITDA side only related to your ability to get new contracts or are there any cost elements, bonus elements or other stuff that can help give that in either direction...
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. And just I can provide a bit of color on that, if you like. I mean, 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 derisk 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. So 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. and 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 2 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 rings, how many of them should we expect to see contracts for announced already this year? And also, are you actively trying to call it 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. So we absolutely want to try to stagger them out and create more of a portfolio and kind of a smoother roll-off profile. But on top of that, as Simon mentioned in his prepared remarks, we're also very focused on kind of things below the surface and the day rate and the terms, right, is how do you improve the overall contract quality as well. So it is a balance for us of making sure we can stagger the expiration of the contracts, but also ensure that we're getting the right rate and the right terms on our contracts. But it is a -- it all goes into the pot, if you will.
Yes. Samir. And finally, on your CapEx guidance, also $400 million to $450 million, you are -- 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, [indiscernible]. 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 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.