Transocean Ltd. (NYSE:RIG) Q1 2024 Earnings Call Transcript

Transocean Ltd. (NYSE:RIG) Q1 2024 Earnings Call Transcript April 30, 2024

Transocean Ltd. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good day, everyone, and welcome to today’s Q1 2024 Transocean’s Earnings Call. At this time, all participants are in a listen-only mode. Later, you will have the opportunity to ask questions during the question-and-answer session. [Operator Instructions] Please note, this call is being recorded and I’ll be standing by if you should need any assistance. It is now my pleasure to turn the conference over to Alison Johnson, Director of Investor Relations.

Alison Johnson: Thank you, Shelby. Good morning and welcome to Transocean’s first quarter 2024 earnings conference call. A copy of our press release covering financial results, along with supporting statements and schedules, including reconciliations and disclosures regarding non-GAAP financial measures, are posted on our website at deepwater.com. Joining me on this morning’s call are Jeremy Thigpen, Chief Executive Officer; Keelan Adamson, President and Chief Operating Officer; Mark Mey, Executive Vice President and Chief Financial Officer; and Roddie Mackenzie, Executive Vice President and Chief Commercial Officer. During the course of this call, Transocean management may make certain forward-looking statements regarding various matters related to our business and company that are not historical facts.

Such statements are based upon current expectations and certain assumptions and therefore, are subject to certain risks and uncertainties. Many factors could cause actual results to differ materially. Please refer to our SEC filings for our forward-looking statements and for more information regarding certain risks and uncertainties that could impact future results. Also, please note that the company undertakes no duty to update or revise forward-looking statements. Following Jeremy, Keelan and Mark’s prepared comments, we will conduct a question-and-answer session with our team. During this time, to give more participants an opportunity to speak, please limit yourself to one initial question and one follow-up. Thank you very much. I’ll now turn the call over to Jeremy.

Jeremy Thigpen: Thank you, Alison, and welcome to our employees, customers, investors and analysts participating on today’s call. As reported in yesterday’s earnings release, for the first quarter, Transocean delivered adjusted EBITDA of $199 million on $767 million of adjusted contract drilling revenues, resulting in an adjusted EBITDA margin of approximately 26%. While the pace of contract awards has moderated somewhat from this time last year, demand for high-specification ultra-deepwater drillships and harsh environment semisubmersibles remains extremely strong with improving day rates and lengthening terms. In fact, earlier this month, we announced a 365-day contract extension for the Deepwater Asgard with an independent operator in the US Gulf of Mexico.

The program is expected to commence in June 2024 and direct continuation of the — program and includes additional services. The total contract value of approximately $195 million included a $10.9 million lump sum payment, which is not included in the estimated backlog approximately $184 million. As part of the agreement, we will be upgrading the rigs blowout preventer with Kinetic Pressure Control Blowout Stopper units or K-BOS. As we previously highlighted, K-BOS is a device that improves blowout preventer sharing capability and is retrofittable to existing BOPs. Importantly, it also significantly shortens the time for the rig to complete an emergency disconnect, which facilitates the ability to expand the minimum operating water depths of deepwater floaters.

Certain configurations of the device are capable of sharing any tubular and sealing the wellbore in less than one second. Over the past several years, Transocean has worked closely with Kinetic Pressure Control Development and testing of K-BOS as well as with the regulator, the Bureau of Safety and Environment Enforcement or BSEE to earn their support and approval. And I’m proud to report that this will mark the third unit that we’ve introduced to our fleet. We are encouraged by the positive feedback received from our customers and BSEE and are pleased to see an increased willingness from our customers to pay for this transformational technology. Also in the US, Gulf of Mexico, we just signed a contract for an additional four wells of 15K work on the Deepwater Atlas at our day rate of $505,000 per day in direct continuation of its current program expected to last between 240 and 360 days.

We also announced TotalEnergies exercise it’s remaining option on the Deepwater Skyros at $400,000 per day. While this option, which was negotiated well before those recent market acceleration is materially below current market rates, we are pleased to continue our long-standing and mutually beneficial relationship with TotalEnergies. As we move through the next several months, we expect numerous long-term contracts to be awarded at increasing day rates, reflecting industry participants’ recognition of the tightness in the market. Healthy contract durations are one of many factors supporting improved supply/demand dynamics. Excluding the TotalEnergies 10-year contract award, which we consider to be something of an anomaly, contract durations for new ultra-deepwater fixtures reached a robust 511 days in the quarter, largely in line with the 2023 average of 526 days and up from 302 days in 2022.

For Transocean, this is especially important as with longer terms, our customers are finally willing to co-invest in the deployment of some of the new technologies like K-BOS, HaloGuard, Robotic Riser Systems Intelli-Wealth, and others that we developed, tested improved during the downturn, but we’re unable to fully deploy given obvious financial constraints. While some analysts and investors continue to express concerns over the pace of contract awards, I’d like to reiterate two points on that topic I make frequently. First, with dayrates increasing in terms extending, the financial commitment from our customers is becoming far more substantial, requiring far more approvals within our customers’ organizations and with their partners, which obviously adds time to the process.

And second, our active fleet is largely contracted through the end of the year. And based on active negotiations, we anticipate filling at least a portion of the remaining availability. As one example, well intervention operations on the Deepwater Invictus have extended significantly with the rig now scheduled to complete that work scope in July. We are also in active discussions for additional opportunities to commence in direct continuation of this work. Additionally, and to emphasize the confidence that our customers have in the duration of this upside, we are actively engaged in conversations for rigs that are not scheduled to roll off contract for one to three years. In fact, all indications continue to suggest heightened demand for at least the next several years.

In its independent assessment, but an assessment that is fully supportive of our view, Rystad anticipates deepwater greenfield CapEx in 2025 will be the highest in 12 years. And that by 2027, total deepwater investment will reach nearly $130 billion, an increase of approximately 40% from 2023. Additionally, there are many important deepwater projects expected to reach final investment decision this year, including BP’s Atlantis 4 and 20K Kaskida fields in the US Gulf of Mexico, Shell Bonga North in Nigeria, TotalEnergy’s Kaminho discovery in Angola and Venus Discovery in Namibia and ExxonMobil’s Whiptail in Guyana, which was approved earlier this month. These predications reinforce our confidence there will be sustained market tightness for the foreseeable future.

With that, I’ll hand it over to Keelan to provide a bit more regional color in detail.

Keelan Adamson: Thanks, Jeremy, and good morning, everyone. Jumping directly into the various regions. In the US Gulf of Mexico, the rig supply/demand balance is such that in our analysis, the region could be short one rig in 2025. Customer behavior indicates that they understand they need to secure rigs quickly to avoid missing their project time lines. Notably, we are observing elevated demand from independent operators, both in the form of tenders and direct negotiations. Last month, two independent operators issued tenders for new programs that were not previously in our outlook. One includes a six-month firm term commencing in the first half of 2025 with two, six-month options. The other is for six to nine months of work commencing in the third quarter of 2025.

Additionally, there are two major E&P companies currently out to market for multiyear programs. In Brazil, last month, Petrobras provided an update to its expected demand for floating rig 2030 requirements. This demand forecast suggests Petrobras may absorb up to 30 rigs through 2030, in line with our expectations that as a region for both Petrobras and the international oil companies, Brazil could require 36 floaters as soon as 2025. Part of this forecast is contingent upon discoveries in frontier areas, such as the equatorial margin for earlier this month and for the second time this year, Petrobras disclosed another discovery. Obviously, our confidence that Petrobras will require at least 30 rig proves with each new discovery. The Roncador tender for up to two rigs is expected to be awarded in the third quarter with a commencement next year.

The Sépia tender for up to three rigs is also slightly delayed as commercial proposals are now due mid-May. Petrobras also recently received approval of its discovery evaluation plan for one of its three pre-salt blocks in the campus and Santos basins and is expected to drill an appraisal well in 2024 or 2025. Positive results from the appraisal would likely solidify future development and provide additional support that Petrobras will be at the higher end of its demand expectations. Moving to Africa. if demand materializes as currently expected, Africa could be the region to absorb most of the remaining available active floating fleet and once again play a significant role in the Golden Triangle. In order to satisfy the demand expected by 2025, we believe at least four rigs will be required from outside the region.

Tenders include ExxonMobil’s two-year firm opportunity and Shell’s one-year firm opportunity in Nigeria, among others. Both of these have multiyear options. Southeast Asia currently offers a variety of opportunities, such as PTTEP in Malaysia and Brunei, E&I in Indonesia and Shell in Malaysia. There could be a shortage of one floater in the region to fulfill these programs, if they are all awarded as anticipated in late 2024 or early 2025. In India, Reliance is out to tender for up to 2 years of work with options. And with the recently revised commencement do, RKG 1 could be well placed to secure this opportunity. Switching over now to the high-specification harsh environment market and specifically Norway. The local high-spec semi fleet remains effectively sold out through 2025.

We have also observed a shift in customer procurement processes for future projects. Similar to what we’ve seen in other regions like the US, Gulf of Mexico, tenders are being utilized less frequently in favor of direct negotiations. As an example of customers looking further into the future, we just signed a letter of intent, subject to final partner approval for the extension of the Transocean Spitsbergen by three wells estimated at 150 days plus 6 priced option wells in direct continuation, which is currently anticipated to be July 2025. We will disclose full details once the extension becomes a fully binding contract. In Australia, known requirements are expected to commence in 2026 and onwards, including Impax and Chevron’s next phase in some of their respective field developments.

We believe at least one additional rig will be required to fulfill these programs as all six floaters currently in country are likely to be occupied in that time frame. Including our two rigs, the Transocean Equinox and Transocean [indiscernible], which we believe are well positioned to pick up further work in country at the end of their respective programs. Now I’d like to take a few moments to discuss our operational performance and provide some insight into the themes that contributed to our first quarter revenue falling short of guidance. As Mark will elaborate upon in his comments, the drivers behind our first quarter revenue results are primarily attributable to delays to rig start-ups in Australia and Brazil due to longer-than-anticipated mobilizations, extensive customer acceptance, processes and operational start-up issues, as well as extended contract preparation for the KG1 in India, extreme adverse weather impacting our operations in Norway and lastly, downtime on the Deepwater Titan.

Regarding the Titan, the rig experienced a downtime event related to the initial deployment of its second 20K BOP. The BOP was pulled back to surface and following an evaluation, we concluded the most efficient path forward was to redeploy the rig’s first 20K BOP, which had already been utilized successfully in operations following completion of its scheduled maintenance. The rig returned to full operational status during March and has performed well as it did since it commenced its initial contract in mid-2023. As with any new equipment or new technology deployment, it is not uncommon to experience some early life performance issues. However, Transocean has extensive experience and safely and efficiently bringing new equipment and technology to the market, which includes a tried and tested playbook on how to work closely and collaboratively with our OEM partners to identify and correct any reliability related issues in a timely and effective manner.

While we are certainly disappointed to have suffered this downtime, it is important to note the safety of our operation was never compromised. Understandably, the previously discussed challenges had a significant impact on our quarterly results, leading to an unusual and disappointing revenue efficiency of 92.9%. However, as they are largely onetime discrete events and with the rest of our fleet continuing to operate with impressive reliability, we remain confident in our ability to consistently deliver safe, reliable and efficient operations across our fleet. I’ll now hand the call back to Jeremy.

End of Q&A:

Jeremy Thigpen: Thanks, Keelan. As part of our efforts to improve the consistency, efficiency and repeatability of our operations, we continue to make progress with our automation initiatives in the first quarter. We achieved another milestone with our jointly owned Intelli-Wealth system as we performed simultaneous fully automated online drilling, tripping and offline stand building operations on the Transocean Norge in Norway. And we are currently preparing for an upcoming deployment in the US Gulf of Mexico. We also achieved a milestone with our Robotic Riser system. We have handled more than 2,000 joints of Riser across our three installed systems. In addition to supporting the consistency of our operations, Robotic Riser also limits the exposure of our personnel to high-risk areas on the drill floor.

Another way to think about this is we have now added over 1,100 working hours where our personnel were not exposed to red zone risk. Finally, before handing it over to him, I just want to recognize and thank Mark and the rest of the Transocean team who earlier this month worked together to complete a tremendous $1.8 billion refinancing in conjunction with amending our revolving credit facility. Needless to say, these are very important transactions, which extended our liquidity runway and started the process of simplifying our balance sheet as we position ourselves for what we believe to be a multiyear up-cycle. And for Mark, personally, I think these transactions represent an excellent capstone to an exceptionally successful career. This professionalism isn’t truly something we witnessed across our organization as a whole day in and day out.

And for that, I would like to thank each member of the Transocean team and wavering commitment to delivering safe, reliable and efficient operations for our customers and value for our shareholders. Change in continuous improvement are the constants in our industry, and are team has continuously demonstrated an ability to adapt as we progress further into the sustained — In conclusion, the outlook for our assets and services remain strong. With the tightness of supply, the active negotiations and the $500,000 per day glass ceiling now broken in multiple jurisdictions around — we are confident that we will continue to grow our backlog throughout the year. As we work towards securing more contract awards, we remain entirely committed to our operational execution with a focus on efficiently converting our $8.9 billion of backlog to revenue and cash flow.

With that, I will now turn the call over to Mark for what I can’t believe will be the last time he will discuss our financial results. Mark?

Mark Mey: Thank you, Jeremy, and good day to all. During today’s call, I will briefly recap our first quarter results and then provide guidance for the second quarter. I will conclude with an update on our expectations for the full year 2024, including our latest liquidity forecast. Before I get to the results, as Jeremy mentioned, we recently completed refinancing transactions totaling $1.8 billion, upsized by $300 million from our initial offering of $1.5 billion. The proceeds from the bond offering were utilized to fully redeem the 7.25% senior notes due 2025 and a 7.5% senior notes due 2026 and partially redeemed 8% senior notes due 2027. With remaining outstanding balance on the ladder notes is approximately $525 million.

Approximately $92 million of the 11.5% senior guaranteed — that were not tendered will remain outstanding until the end of July at, which time funds be placed into irrevocable escrow accounts will be utilized to put the many balance and fully retire the issue. These transactions improve our unsecured debt maturity profile, simplify our capital structure and combined with the recent extension of our revolving credit facility through mid-2028 enhanced our financial flexibility. On the latter point, we are pleased that the current formulation of the credit facility permits us at a point in the future the flexibility to make restricted payments, including distributions to shareholders and share repurchases. On currently aforementioned transactions, Moody’s upgraded transaction’s corporate family rating to B3 from Caa1, reflecting the improvement in the AHS outlook for the company and its business.

We are confident we will continue to demonstrate the qualities necessary to receive further ratings upgrades as we continue to delever our balance sheet through the sustained cycle. As we reported in our press release, which includes additional detail on our results for the first quarter, we reported net income attributable to controlling interest of $98 million or $0.11 per diluted share. After certain adjustments, we reported adjusted net loss of $22 million. During the quarter, we generated EBITDA of $199 million, as is typical in the first quarter of the year, operating cash flows were negative at $86 million, largely due to payments for a payroll rated costs and interest payments. In addition, we continue to incur substantial contract preparation costs, as we return the Deepwater Orion and Transocean Endurance to operations and advanced preparation of the Transocean Equinox during the quarter.

Negative free cash flow of $169 million in the first quarter reflects aforementioned negative $86 million of operating cash flow and $83 million of capital expenditures. Capital expenditures for the quarter included $45 million related to the seventh-gen plus newbuild Deepwater killer under construction as it prepares for the inaugural contract for Petrobras in Brazil. Looking closely at our results. During the first quarter, we delivered adjusted contract drilling revenues of $767 million, at an average daily revenue of approximately $408,000. This is below our previous guidance, mainly due to the reasons Keelan mentioned in the prepared comments, including delayed contract commencements with Transocean Endurance, Deepwater Orion and KG1. Low revenue efficiency for the Deepwater Titan, and the impact of adverse weather on operations in Norway.

Operating and maintenance expense in the first quarter was $523 million. This is below our guidance, primarily due to the delay of in-service maintenance in the active fleet and delayed contract preparation costs. G&A expense in the first quarter was $52 million. Turning to cash flow and the balance sheet. We ended the first quarter with total liquidity of approximately $1.3 billion, including unrestricted cash and cash equivalents of $446 million, approximately $240 million of restricted cash for debt service and $600 million from our undrawn revolving credit facility. I will now provide an update on our expectations of financial performance for the second quarter and full year 2024. As always, our guidance reflects only contract related rig reactivations and/or upgrades.

For the second quarter of 2024, we expect adjusted contract drilling revenue of approximately $866 million, based upon an average fleet-wide revenue efficiency of 96.5%. This quarter-over-quarter increase is mainly due to the incremental activity with Transocean Endurance and Deepwater Orion operating for a full quarter, the Transocean Equinox and KGI starting their respective contracts during the quarter and higher revenue efficiency following the resolution of the downtown event and the Deepwater Titan in the first quarter. This is partially offset by reduction activity on the Transocean Barents in KG2, as the rigs began contract preparations. We expect second quarter O&M expense to be approximately $570 million. This quarter-over-quarter increase is largely due to incremental activity related to the previously mentioned four rigs and to an increase in in-source maintenance costs.

We expect G&A expense for the second quarter to be approximately $60 million. This quarter-over-quarter increase is primarily related to transaction fees or the debt financing, debt refinancing and entry earlier retirement program that was offered to longtime employees. Net interest expense for the second quarter is forecast to be approximately $138 million. This includes capitalized interest of approximately $8 million. Capital expenditures for the second quarter are forecast to be approximately $92 million, including approximately $55 million related to preparation of Deepwater Aquila for its 3-year contract with Petrobras in Brazil. Cash taxes are expected to be $17 million. Now, I’ll provide an updated guidance for the full year 2024. At approximately $3.6 billion, we now expect our adjusted revenue to the lower end of the range provided on our previous conference call in mid-February.

This includes approximately $215 million of additional services and reimbursable expenses. This change in expectation is due mainly to three factors. There are four mentioned delays in contract commencement on the Transocean endurance, Deepwater Orion, KG1, the downtime on the Deepwater Titan and the longer-than-expected well programs in the Deepwater Atlas and KG2, which delays the rig’s transitions to higher day rate contracts in the second quarter. We now expect our full year O&M expense to be between $2.2 billion and $2.3 billion. The higher end of this range is primarily the result of anticipated higher reimbursable expenses. Finally, we anticipate G&A cost to be around $210 million. Our projected liquidity at the end of year 2024 is approximately $1.4 billion, reflecting our revenue and cost guidance and including the $575 million capacity of our newly amended and extended and undrawn revolving facility and is inclusive of restricted cash of approximately $395 million most of which is reserved for that service.

This liquidity focus includes 2024 CapEx expectations of $231 million, of which approximately $134 million is related to the Deepwater Aquila and approximately $97 million for sustaining and contract preparation CapEx. As I signed off for the last time, I’d like to reiterate my gratitude to the entire Transocean organization as Jeremy expressed in his remarks. This team is second to none, and I’m immensely proud to have worked with each one of you for the past 9 years. I’m confident in our ability to deliver value for our shareholders and look forward to seeing the progress continue as Thad Vayda assumes the role of CFO. Being worked alongside Thad for almost a decade, it is clear, he is a strategic thinker who brings financial discipline, experience and expertise, along with a deep understanding of the offshore drilling market.

These attributes should ensure a seamless transition, both internally and externally and can you tend to serve Transocean and its shareholders well. Congratulations against that. This concludes my prepared comments. I’ll now turn the call back over to Alison to introduce questions and answers.

Alison Johnson: Thanks Mark. Shelby, we’re now ready to do questions. And as a reminder to the participants, please limit yourself to one initial question and one follow-up question.

Operator: [Operator Instructions] Our first question from Kurt Hallead with Benchmark. Your line is open.

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Q&A Session

Kurt Hallead: Hey. Good morning, everybody.

Jeremy Thigpen: Good morning Kurt.

Kurt Hallead: Hey, Mark. Congrats again, and good luck on what’s next.

Mark Mey: Thanks Kurt.

Kurt Hallead: Yes. I guess I just kind of it’s always kind of fits and starts, right, in the context of rigs ready to work and getting them ready for contract. And I think that’s the photons to the business, right? So as you guys kind of risk is set start-ups and timing and everything else. Could you give us some insight as to how you guys go through the process so that we can kind of get on board with you guys and kind of think about the dynamics ourselves looking from the outside in?

Mark Mey: Yes, I could. I wouldn’t really say, it’s pits and starts. We go through a multi-phase process. We call them stage in whereby we evaluate the project. We built out of timeline. We built out the team. We started ordering all the materials for that and then we execute. But things happen, because when you try and assess the rig’s ability, you’re doing it rather blind. Once you start getting on to the rig and you start testing systems and going into some of the hatches and holes and whatnot on the rig, this is all technical terms, obviously, you find things, and that causes you to expand your scope. In our case, especially, going to Brazil was interesting this time. We’ve taken rigs into Brazil many times over many years.

But for the first time ever, we had an interpretation of customs, which dragged out for six weeks and the latest getting into country. That has now been resolved and behind us. So going forward, we expect to able to get trigs in pretty comfortably. But I don’t want you to think that contract rep is an ad hoc or the cuff type thing. It is very well planned. And most times, it’s very well executed.

Jeremy Thigpen: The other thing I’d add is we’ve had a lot of rig moves here. And most of those are getting behind us. What we’re going on long-term contracts in these jurisdiction. So the costs that you’ve seen us accumulate over the course of the last couple of years with project costs and rig moves and customer acceptance and things like that will largely be behind us. And so I think that latest better financial results as we get into 2025 and beyond.

Keelan Adamson: Yes. Kurt, it’s Keelan here. I maybe just add a little bit more color to that. The one aspect is obviously the risk associated — the risk management associated with moving a rig, preparing a rig for contract, getting it through the regulatory and customer acceptance processes, which do change and do migrate over time. But probably more importantly, ensuring that, that rig works very reliably and efficiently and safely when it comes out of that process. And what I am very pleased about is that the rigs that have gone through this, and we’ve done many of these and they’ve been very successful, KG2 is a fine example of the rig does it quite a lot. And in this particular case in Brazil, she’s working at one of the top-performing rigs in Petrobras just after a few months.

So I think to put Mark’s comments, we have a very robust project planning process for these events. The delays are somewhat not related to the discovery of new scope, but actually some really strange events that Mark alluded to on importation. But for instance, in India, there was a local fishermen strike outside of the harbor that we were moved in and we were blocked from getting in logistics to the rig for a couple of weeks. So there are some things clearly are difficult to manage and you have to understand that there’s always risk with them.

Kurt Hallead: Yes. I appreciate all that color. And it’s kind of why I ask because I know it’s never straightforward it may seem on a piece of paper, right? Okay. So it looks like you got your contract durations extending, your dayrates continue to grind higher. I guess, my question really relates back to the overall market outlook, and what do you think the prospects are to potentially get some, if not all, of your idle rigs back on contract between now and 2030, given the dynamics you put forward for Brazil and Africa, for example?

Jeremy Thigpen: Yes, that’s a really interesting question. As we go through what’s happening around the world, we can say for the first time that every region that we’re currently active in is going to have a call on rigs. So we’re looking at, I think, actually bar none in every single region — rigs than they have to date. So at the moment, what’s happening is there’s a run on the active fleet. So basically, as the guys had alluded to in the prepared comments, there’s a significant number of direct negotiations outside of tenders that are essentially trying to secure the rigs that are already active. So I think from that point of view, my view is that 2024 is going to see pretty much the entire active fleet sold out for two to three years going forward.

And as we get towards the end of 2024, that’s when the call on the stacked fleet is going to happen. And, of course, we’ve reiterated this many times that while there are active rigs available, we will not be factoring into that mix. We’ll bide our time and wait until the economics are right for that. And certainly, there’s no rush to do it at the moment. But I think we’ve got a pretty good shot at putting several of those rigs back to work, certainly before the end of the decade.

Kurt Hallead: All right. That’s awesome. Appreciate the color. Thanks guys.

Operator: And we’ll take our next question from Eddie Kim with Barclays. Your line is open.

Eddie Kim: Hi. Good morning. Just want to start off with the Petrobras contracts. Last quarter, you said you expected those to be awarded in the second quarter this year. It looks like that timing has been pushed out a little bit to 3Q at least. Could you just talk about what’s driving that delay? And is there a risk that these contract announcements could get pushed out even further toward the end of the year?

Jeremy Thigpen: Yes. And I think this is actually just a pretty standard operating procedure with Petrobras pushing out by a couple of months, that’s very typical. And actually, we believe that the rigs are going to win those tenders are either already active rigs in country or they’re going to have to pull new rigs in. So it’s possible that pushes out a little further. But certainly, the awards should be made in 2024. But I think it’s for rigs that don’t come off contract for some time yet. There’s no real risk to that.

Eddie Kim: Okay. Got it. And then just a question on your two idle rigs, the Discoverer Inspiration and the DD3. I believe the Inspiration recently mobilized to Las Palmas. Is that rig effectively cold stacked now? Or is that still idle? Just any color on those two rigs? And if you could comment on kind of work prospects or opportunities for those rigs?

Keelan Adamson: Yes, it’s Keelan again. The inspiration essentially is repositioned into the Las Palmas area. She’s not stacked. She’s idle. We’re obviously putting her into plenty of opportunities, particularly in the Africa and Asia regions. The DD3 is idle in Aruba and waiting for its next opportunity. But I’ll let Roddie maybe add some color to the other opportunities.

Roddie Mackenzie: Yes. So we do have several things there, but we’re looking to make sure that we get the right opportunity to put the rigs to work long-term rather than moving them to short term to work. So, at the moment, we’re quite comfortable keeping them where they are until they get the right opportunity.

Eddie Kim: Got it. Got it. Thank you. And if I could just squeeze one last one. Just on the diluted share count this quarter. It looked like a fairly material increase to about 955 million shares. Could you just comment on what drove that increase this quarter?

Jeremy Thigpen: Yes, Andy, we can take that offline and you could speak to Alison, she can walk you through it. It’s a pretty lengthy response.

Eddie Kim: Okay. Understood. Great. Thank you all for the color. I’ll turn it back.

Operator: And we’ll take our next question from Doug Becker with Capital One. Your line is open.

Doug Becker: Thank you. Jeremy, you mentioned the Atlas getting the 15,000 work at 505,000 a day. When do you expect that rig to transition to the higher day rate? And how do you view the prospects for 20,000 work potentially next year?

Jeremy Thigpen: Hey, Doug. Good to hear from me. I’m going to hand that to Roddie because he is neck deep in this conversation right now.

Roddie Mackenzie: Yes. So we’ve got a lot of interest in that rig. And yes, so this was a prospect that we had, had with the current operator for some time. So it looks like a really good rate, but I have to say it was set a while ago when we go into negotiations on and so the transition for her to go to the 20,000 is probably going to take place in the next contract. So basically, we finish out the one that we’re currently on in the Shenandoah development. And then we go into this additional kind of 240 to 360-day program. And I think after that, we’re transitioning into the much more attractive work, so that’s good. And that’s basically the second rig in the Gulf that’s got above a high — sorry, a 500 rate so with the out guard and the Atlas now contracted above 500, we actually hear that many of our competitors are at the same level or even higher, and we expect within the next few months that there will be four to five additional awards in the Gulf of Mexico above 500,000 a day.

Doug Becker: It’s definitely encouraging. Maybe just could you expand on the BOP issues with the Titan and really kind of thinking about in the context of is there a similar risk with the Atlas?

Jeremy Thigpen: Yes. So the BOP, obviously, as I said in the call, the Titans BOP is the first POP is deployed and the rig is operating fully since mid-March. The issue we found was to a particular component on the second BOP. Clearly, that wasn’t an issue on the first BOP and so we’ve taken those components off the stack, we brought them back to town to work with our OEM provider to disassemble and inspect, and we should learn more in the next couple of weeks as to what that particular issue is. I have no — based on what we’ve seen in the operation of the other stack. We have no concerns as to whether that’s anything that would spread the other stacks. It’s simply a component reliability issue that we’ll address and return to the rig.

Doug Becker: Sounds good. And Mark, congratulations.

Mark Mey: Thanks, Doug.

Operator: And we’ll take our next question from Fredrik Stene with Clarkson Securities. Your line is open.

Fredrik Stene: Hey team. Thanks for taking my question. You talked a bit about the market here. I was also on the back of those discussions already. Wanting to hear what you’re thinking about 70s versus 6G and how the different types of rigs are being approached in the market. You talked about repositioning the inspiration. You talked about some extra work potentially for the indictors et cetera, but also how you’re managing your own fleet within those two subsegments, keeping the Atlas and the Titan kind of away from that discussion for now. Are there any large discrepancy or bifurcation in terms of how rates are bid? Or is it all about having one rig at the right place at the right time that will still yield good rates also for 60 rigs in the future.

Mark Mey: Yes. So I think you see — so several of our 6 gen rigs have got very attractive rates just in the right markets. So if a market requires a certain specification and the 6 gen rigs qualify for that, then they do achieve very well. At the moment, there’s a lot of activity around the high specification rigs. So specifically the Gulf of Mexico and some places in West Africa, that’s where you’ve seen the rates really accelerate because the availability of these high-specification units is becoming more and more scarce. And the net effect of that is essentially we’re securing very solid rates on the high specification 7th gen units, but that also trickles down to the 6th gens when they end up being the only ones that left. So I think you’re going to see a pretty positive outlook for those rigs in the future. But at the moment, we’re really seeing a lot of activity from the operators around securing the highest specification assets they can get their hands on.

Jeremy Thigpen: I think if you look back over the last couple of years, our approach to the market and our strategy around day rates have proven effective. We looked at our 1,400 tonne rigs, the highest looked rigs in the market other than the Atlas and the Titan and started setting day rates with those rigs. And it’s lifted all the 1,250 tonne rigs for now. Our competitors are also pushing for $500,000 a day and then some — and then you’ll definitely see a step change once we move to the 20K — the new 20K contracts on the Atlas and the Titan.

Fredrik Stene: That’s very helpful. Also, you mentioned quite a lot of long-term opportunities that you foresee will materialize now over the next couple of months or quarters. There’s been, I think, different approaches with different owners as to how we should price long-term work. Some will be accept a lower rate just because they would like the visibility of a longer term contract, while others — and maybe you’re solving the best example of that has been very firm on rate expectations also for long-term work. Do you expect a wide spread in the awards that we’re going to see going forward? And I guess my question relates to should the market expect to be disappointed by some of these there points? Or should we see them all pulling in the same direction or being 450-plus in almost all our words?

Mark Mey: Yes. I would say that I think you’ve seen one or two anomalies that may have been disappointing for the market, but those are individual companies with motivations that are definitely not aligned with our own. So, for the majority of the long-term drillers, I think you’re clearly going to see rates well above $450. Even for term work, I think you’re going to see that there’s maybe a small discount for term work, but we’re talking about 10,000, 20,000 a day, we’re not talking about 10% or 15%. So, I think you’ll see plenty of long-term work awarded, but it’s going to be at very healthy rates. They might not be quite 5s, but they’ll be pretty close. Certainly, some long-term stuff will be awarded above that 500 marker.

But overall, the way we view it, as Jeremy has said, we’ve been very purposeful about which rigs get placed on which opportunities. So, needless to say, for our top-spec assets will ensure that they are on very positive contracts with strategic importance to us as well, not just dollars.

Fredrik Stene: All right. Thanks for all that color. And Mark, congratulations and thank you. I think the transaction now in April was a good final milestone.

Mark Mey: Thanks Fredrik.

Operator: Thank you. And our next question comes from Arun Jayaram with JPMorgan. Your line is open.

Arun Jayaram: Yes, good morning. I was wondering if you could comment on just the 20,000 BOP market overall. One of your peers highlighted how the Paleogene in the Gulf of Mexico is one of the fastest growing plays kind of globally. And I’m wondering if you could just maybe talk about what you’re seeing there? How many rigs have that BOP capabilities and what’s the future prospects there?

Jeremy Thigpen: Yes, sure. You’ve basically got four, possibly four operators that are active or going to be active in the 20,000 market as we would describe it. So, there’s plenty of work there to occupy the rigs that we have. But going forward, we think there’s work to keep everything busy at the moment, not necessarily saying there’s a need for adding capacity in that market at the moment. But we’ll see how things shake out. There’s a lot of operators also believe that, that is a trend that will continue in the future. So as we go four, five, six years in the future, that more and more of those frontiers will require the higher pressures. But for the moment, I think we’re in a very good position. We may be slightly undersupplied for that demand at the moment. But certainly, I think the operator see the value in the — not only the equipment, but the expertise and how to do it. So we’re well-placed for both of our rigs at the moment.

Mark Mey: Yes. And Aaron, I think your other question was how many are capable of 20,000. There are only two rigs in the world with 20,000 BOP — Titan and the Atlas. So we’re in a very good position there.

Arun Jayaram: It’s a nice match. Maybe just broadly, could you talk about West Africa, obviously, Namibia is an area that the market is pretty excited about. But could you talk about kind of demand trends you’re seeing out of West Africa, I know in Halliburton’s call, they mentioned now in 2025, you could see more deepwater activity there next year.

Jeremy Thigpen: Yes, absolutely. So Mackenzie’s recent report was describing what’s going on and upstream investments expected in West Africa. And if you take specifically the deepwater sector, they expect to see an increase of 80% in spending between 2023 and 2027. So as we go through our chart of available opportunities in West Africa. That is the one piece of the golden triangle that’s finally popped. North America was doing great, Gulf of Mexico, and of course, South America, we’ve lamented just how many rigs have gone in there and how many more will, but this last quarter, we’ve really seen a lot of positive movement in West Africa. And it’s not just one or two countries, it’s across several different areas. So I won’t go through all the details on that.

But certainly, the traditional players, Nigeria is back with four tenders. Angola’s contracting activity has been very solid, and there’s still a couple more to be awarded. And then as we go through Mozambique and Ghana and what have you, there’s still plenty more scope to go there. So we do actually think that all the fleet that’s currently in West Africa will either be renewed, extended or put onto different programs, plus we’re going to need two to three additional rigs in the next couple of years. So I think West Africa is looking very positive at the moment.

Arun Jayaram: Thank you.

Operator: And we’ll take our last question from David Smith with Pickering Energy Partners. Your line is open.

David Smith: Good morning, and thank you. If I go to the data from a year ago and look at forward availability for the deepwater fleet, and just see what has been contracted since. It’s a much higher percentage of drillship availability that’s been contracted versus benign deepwater semis, and I was just hoping to get your thoughts on, or what you’re hearing from customers about the relative interest in drillships versus benign semis. And how we should think about the natural pricing premium for the average fixed gen drillship versus the average sixth-gen benign semi?

Keelan Adamson: Maybe I’ll try and answer that one, David, and then Roddie kick in. What we’re seeing from our customers, and it was a traditional view that development rigs were better suited, semis were better suited to fill developments, and drillships were better suited to — opportunities. Obviously, that has changed significantly over the last five to 10 years, and you will find drillships that are now a lot more versatile, our customers are perfectly comfortable developing fields with them, and actually enjoy the redundancy in space and size and capability that they have as opposed to the semis. Where the semis certainly have an advantage is perhaps in shallower water or an area where there’s a nation they prefer to move up that semi, but also have dynamically positioning capability in the event they needed for that particular area.

So I think that speaks to why the situation is what it is right now. I consider the drillships to be the preference from what I speak to customers about. But I’ll let Roddie maybe add a little bit more color to that.

Roddie Mackenzie: Yes. No, I think that’s spot on, Keelan. There are certain basins that we still have significant interest in the semis. So there’s a couple of programs starting in 2025 that will require exactly as Keelan described, where you have this combination of a mode unit that can also do DP work as well. So I think there’s it’s obvious that the drillship market is extremely hot at the moment. The semi market is good. So by comparison, it may not look as good, but it’s still pretty solid.

David Smith: Very much appreciate the color. And if I could add one more on the market outlook, totally agree on the future call on more rigs. Maybe one small partial solution to getting more out of the existing fleet with better calendar scheduling, right, with some rigs having two or three or more months between contracts. I wanted to ask, what do you think contractors and operators can do to better manage those schedules and avoid the downtime between the end of one customer’s program and the start of the next customer’s job.

Roddie Mackenzie: Yes. The number one driver for that is the tightness in the market, right? So as we kind of described, we’re in this transition over the past six months and certainly the next six months, where many of the fleet are moving to longer-term contracts. So, by necessity in a downturn, you may have to move the rig frequently to keep her busy to move from one customer to the next, then go through customer acceptances and those kind of things and mobilization but as we get to this longer-term outlook, our backlog has been growing substantially now over the last couple of years. So, you’re going to see that transition that we’re not going to be exposed to nearly as many movements of rigs. So that’s going to tidy up very nicely for us, certainly the remainder of this year and into next year.

David Smith: Great. Thank you so much.

Operator: Thank you. That concludes the question-and-answer session. I will now turn the program back over to Allison Johnson, Director of Investor Relations for any closing remarks.

Alison Johnson: Thank you, Shelby, and thank you, everyone, for your participation on today’s call. We look forward to talking with you again, when we report our second quarter 2024 results. Have a good day.

Operator: That concludes today’s teleconference. Thank you for your participation. You may now disconnect.