Seadrill Limited (NYSE:SDRL) Q1 2024 Earnings Call Transcript

Seadrill Limited (NYSE:SDRL) Q1 2024 Earnings Call Transcript May 15, 2024

Operator: 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. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. I would now like to turn the call over to, Lydia Mabry, Director of Investor Relations. Please go ahead.

Lydia Mabry: 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 uncertainty. 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 obligations 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.

Simon Johnson: Thank you for joining us for our quarterly conference call. Seadrill’s 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 dayrate of the current up-cycle, securing a 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 later this year. In March, we began preparing the Polaris and the Auriga for 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’re committed to managing and executing these contract preparations effectively so that rigs can start generating EBITDA and cash flow before year-end as 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, the 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 and 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 sidelined stack capacity may only trickle into the market going forwards, 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 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 up-swelling 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 neat 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 of two to three year terms. Discrete delays around permitting, supply chain challenges, and even efficient operations can affect group 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 dayrate environment proves, 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 dayrates 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 in the depth of 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 re-certifications, 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 SPS, 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 rig in our fleet.

The additional investment out scopes traditional SPS spend. Meanwhile, the four drillships we operate in Brazil underwent extensive contract preparation before mobilizing less than two 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 five year increments, along with the targeted effort to move towards continuous equipment classification, may change how we talk about SPS spending going forwards. Regardless of what we name or how we time this out-of-service spending, rest assured, we’ll 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 improving market is to focus solely on the topline. But at Seadrill, we take a holistic view of the business, ensuring we maximize shareholder returns. We’re 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 make any changes in demand.

With that, I’ll pass the call to, Grant.

Grant Creed: 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. A decline in contract drilling revenues accounts 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 three rigs of contract for varying durations. The Sevan Louisiana completed its work for Talos in the U.S. Gulf of Mexico in late December, then underwent a planned out-of-service period for its 10 year special periodic survey and required maintenance.

The West Polaris completed its ONGC 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 and Seadrill fleet and mobilized them to shipyards to begin 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 the 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 repeat in the first quarter and therefore explains partially improved performance. First quarter results also include adjustments to back out $4 million of non-recurring 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 in 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 one.

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 of non-cash net amortized mobilization expense and approximately $70 million of reimbursable revenues and expenses. With that, I will pass the line to, Samir.

Samir Ali: Thank you, Grant. I’ll start by reviewing our contracting activities 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 MPD 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 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 rig 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 rig commenced intervention 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 the Louisiana. Turning to Norway, the precarious market balance of Norwegian North Sea will influence the fortunes of the West Phoenix. Norway is either one rig over-supplied or one rig under-supplied, an evolving situation that will 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 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 contract, we remain confident in the market, encouraged by rig supply limitations, demand dispersion across markets and dayrate progression. Specifically for our rigs, we believe both the West Capella and the Sevan Louisiana are advantage in the markets where they operate. Since the Capella benefits from near-term availability and MPD capabilities and the Louisiana’s unique hull design allows it to target niche applications. And, we are already in advanced dialogue to fill the remainder of the West Vela’s dance card when the rig completes its existing program in mid-2025. The three rigs we operate through our Sonangol joint venture, the West Gemini, the Quenguela and the 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 schedule, not by design. Fortunately, we believe there is enough demand 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 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.

Q&A Session

Operator: Thank you. We will now begin the question-and-answer session. [Operator Instructions] Your first question comes from the line of Ben Nolan of Stifel. Please go ahead.

Ben Nolan: Thanks, and good morning, guys. So, 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 dayrate. 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? Are you wanting to eventually move it back to one of your three core markets? Any color around that?

Samir Ali: 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.

Ben Nolan: Okay. And any thoughts on how quickly that might would develop?

Samir Ali: Yes. 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.

Ben Nolan: Okay. Appreciate that. And then, I was a little bit curious about your commentary in the West Phoenix and the opportunity in a harsh environment either being a little over-supplied or a little under-supplied. And then, if you’re unable to get a contract that you would stack the rig. I’m 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?

Samir Ali: Yes. So, we’re definitely looking at benign environments as well. So for us, we’re not limiting ourselves just too harsh. 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 her 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 are not opposed to looking at benign environments as well.

Ben Nolan: Okay. All right. I appreciate it. Thank you.

Simon Johnson: Thanks for the question, Ben.

Operator: Your next question comes from the line of Greg Lewis of BTIG. Please go ahead.

Greg Lewis: Yes. Hi. Thank you, and good morning, and thanks for taking my questions. 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?

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

Greg Lewis: Well, let’s assume base case it stays in North Sea.

Simon Johnson: 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 UKCS for instance. So, at this stage, we 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 a 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 cost.

Greg Lewis: Yes, super helpful. So, just then as I kind of think about the low-end and 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 yours, someone else’s. So, it seems like that if there is a pickup in activity, we’re going to need non-traditional 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’s a sixth gen rig, not a seventh average kind of rate for drilling, any kind of well intervention versus discount drilling versus spread?

Simon Johnson: 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 half 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 great strength of the 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 two types of work effortlessly. 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 the well intervention work into better paid conventional drilling. Samir, anything to add?

Samir Ali: Yes. No, I think that, 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 more profitable work here shortly.

Greg Lewis: Super helpful. Thank you very much.

Operator: Your next question comes from the line of Kurt Hallead from Benchmark. Please go ahead.

Kurt Hallead: Hey, good morning everybody.

Samir Ali: Good morning.

Kurt Hallead: So, I was 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 them 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, when you have limited availability that’s currently operating, you have high cost assets sitting on the sidelines. What’s your sense when you talk to customers and like how do they understand how tight the market is? Do they 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 can give us some context around that.

Simon Johnson: Yes. 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 being in fears about market direction and momentum, the rates have continuously grinded 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’s 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 based 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 aren’t currently working now, but maybe reactivated in 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 got a good long-term operating future.

So, I think the customers understand that, but they were going to be reluctant to pay for it. Anything to add, Samir?

Samir Ali: 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.

Simon Johnson: Yes.

Samir Ali: It will come, it’s just going to take a little more time.

Simon Johnson: 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 the markets heading in the right direction.

Kurt Hallead: Okay. That’s great. I appreciate that 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, per day dollar value of MPD services? And then, how frequently are those services deployed during the course of a program?

Samir Ali: Yes. So, I’ll take that one to start and pass to Marcel, a little bit. But, I’d say starting with the second question, it depends on the well, right? So, certain wells require 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 contract 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.

Marcel Wieggers: Yes. So, it depends a little bit the area where you’re operating as well. So, going forward five over six weeks operating in Brazil will be equipped with MPD equipment. On the other side in Angola, don’t know, but rigs are equipped with MPD equipment. But as a company, we’re currently drilling our 99 MPD well, by this summer we will spud up 100 MPD well. So, we’ve got a huge experience which will give us a competitive edge in that respect as well.

Kurt Hallead: Okay. That’s great. I appreciate it. Thank you.

Simon Johnson: Thanks Kurt.

Operator: Your next question comes from the line of Josh Jayne from Daniel Energy Partners. Please go ahead.

Josh Jayne: Thanks. Good morning.

Simon Johnson: Hi, Josh.

Samir Ali: Hi, Josh.

Josh Jayne: First one, just to touch again on the Louisiana. I know you talked about the fact that, it likely moves to higher price drilling work shortly 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?

Samir Ali: Sure. I think there’s that potential. She is designed as a drilling rig, so we’d like to pursue drilling opportunities with her 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.

Simon Johnson: One thing I would add, Josh, is that the differential between intervention work and conventional drilling has been compressing. And, I think as P&L 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 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 called 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 the affordability of the unit to progress a broader range of work.

Josh Jayne: 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?

Samir Ali: 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.

Simon Johnson: I would add Kurt, to 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 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.

Josh Jayne: Okay. Thank you. I’ll turn it back.

Simon Johnson: Thank you.

Operator: Your next question comes from the line of Doug Becker of Capital One. Please go ahead.

Doug Becker: Thank you. 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 shade expectations toward the higher-end of the range that’s been laid out?

Grant Creed: When we think about well, first of all, high targets, 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 or the bottom, but it’s considering a bunch of factors though.

Doug Becker: Yes, fair. And just to clarify, it is included in your expectations for adjusted EBITDA?

Grant Creed: It is, yes.

Doug Becker: Got it. And, lots of questions about the Louisiana, maybe just one more. There’s a report saying the rig is heading to 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?

Samir Ali: So, we’re marketing in all markets around the world. So, is that a potential? Absolutely. Could you stay 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.

Simon Johnson: Yes. 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.

Doug Becker: Thank you.

Operator: Your next question comes from the line of Hamed Khorsand from BWS Financial. Please go ahead. Hello, Hamed, your line is now open.

Hamed Khorsand: Can you hear me?

Simon Johnson: Hi, Hamed. How are you?

Hamed Khorsand: Hi, very good morning. 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 you even though Africa is looking good?

Samir Ali: Yes. So, I’d say the place we’ve in 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, because that demand has now 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 that the client has not got the demand. It’s just they’re waiting on other items like FPSOs or well-heads that have pushed their schedules to the right. But, I’d reiterate that’s actually worked in our favor because that demand has now shifted into when our rigs are available.

Hamed Khorsand: 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 and the industry or how it would not given the leadership?

Samir Ali: 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.

Hamed Khorsand: Okay. That was it for me. Thank you.

Simon Johnson: Thanks, Hamed.

Operator: Your next question comes from the line of Noel Parks from Tuohy Brothers. Please go ahead.

Noel Parks: Hi. Good morning or good afternoon, team. Just 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, there I guess I’m wondering, is it fair to say that sort of the full on FOMO, fear-of-missing-out, hasn’t necessarily hit all the customers yet. It sort of feels like, writing’s clearly on the wall, but are there still some who are maybe unrealistically optimistic about availability and pricing at this point?

Simon Johnson: Well, perhaps 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 their business. We are seeing a definitely shift from to higher CapEx in 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’d like to refer to them 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. That’s why you’re 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 to sort of to fall foul of it, I would say. So, I think there’s a lot of cooperation collaboration, but it’s not always perfectly resolved.

Noel Parks: Right, right. Thanks. And, also this is kind of just a different sort of reality check. And, 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 highly supportive of M&A particularly done with stock. And, I feel like the only sort of string from capital discipline 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 raises 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 dividends and their buybacks, but maybe a little less allergic to leverage than they had 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-terms, just maybe seem to be a little less worried about that price tag down the road?

Samir Ali: Yes. Starting to see some clients get a little more comfortable with it, but I wouldn’t say that’s the rule. We’re starting to see a little bit. But overall, clients are still looking at, hey, this is the program that’s been FID or this is the program we want to go drill. So, it’s always that fine balance of going long and locking in a rate versus keeping it short. A good example is our relationship with LLOG 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 re-price it every six months. And, 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 re-price every six months. So, are we seeing clients do it a little bit, but not as much as you would think.

Noel Parks: Great. Thanks for the detail. Bye-bye.

Samir Ali: Thank you.

Operator: [Operator Instructions] And your next question comes from the line of Fredrik Stene of Clarksons Securities. Please go ahead.

Fredrik Stene: Hey, Simon and team. Hope you are well. I think this is a new record of number of questions in the Q&A in the last 10 years of drilling. But, I’ll try to keep it short here in the interest of time. First, on your guidance, 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 pivot that in either direction?

Simon Johnson: Yes. I think, Fred, that 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 Auriga in preparation for the contracts down in Brazil. And, just to provide a bit of color on that if you like. I mean just so people are aware, the Auriga was released earlier than anticipated. We toyed with chasing some fill in work, but we chose instead to de-risk the schedule by starting the Auriga project earlier than perhaps was anticipated. We’re keenly aware of the risk profile of those projects and laser focused on delivering them in the 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 on firmly on schedule today, and we’ll update you as we move forward in the year on that one. But, I think really they’re 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.

Fredrik Stene: Thank you. Very, very helpful. Second, do 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 recontacting those rigs, 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 up somewhere in 2025. I guess my question relates to whether or not you will purposefully mix short-term and long-term contracts just to make sure that it’s even more staggered to the next half? Thanks.

Samir Ali: 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 on the dayrate 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 all goes into the pot, if you will.

Fredrik Stene: Yes. Thank you very much, Samir. And finally, on your CapEx guidance also $400 million to $450 million you are just to make 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 million plus $29 million so far this year. Is that the correct way to think about it just to have an idea of how timing of the CapEx will be for the rest of the year.

Grant Creed: That’s right. I think you’re referring to the cash flow statement of how we present the maintenance elements of CapEx, which is in the cash flows from operations, which is of course $29 million plus $23 million from additions.

Fredrik Stene: Yes. Okay. And, I just wanted to make sure that I understood it correctly. All right. That’s it from me. Thank you so much for the color and have a great day.

Simon Johnson: Thanks very much, Fredrik.

Samir Ali: Hey, Fredrik. Thanks.

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