Earnings Call Transcript
Transocean Ltd. (RIG)
Earnings Call Transcript - RIG Q1 2024
Operator, Operator
Good day, everyone, and welcome to today's Q1 2024 Transocean Earnings Call. Please note this call is being recorded, and I will be standing by if you should need any assistance. It is now my pleasure to turn the conference over to Allison Johnson, Director of Investor Relations.
Allison Johnson, Director of Investor Relations
Thank you, everyone. 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 our 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 will now turn the call over to Jeremy.
Jeremy Thigpen, CEO
Thank you, Allison, 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 U.S. Gulf of Mexico. The program is expected to commence in June 2024 and is a direct continuation of the recent 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 of approximately $184 million. As part of the agreement, we will be upgrading the rig's blow-out preventers with Kinetic Pressure Control Blowout Stopper units, or K-BOS. As we have previously highlighted, K-BOS is a device that improves blow-out 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 filling the wellbore in less than 1 second. Over the past several years, Transocean has worked closely with Kinetic Pressure Control on the development and testing of K-BOS, as well as with the regulator, the Bureau of Safety and Environment Enforcement, to earn their support and approval. I am proud to report that this will mark the third unit that we have introduced to our fleet. We are encouraged by the positive feedback received from our customers and BESI and are pleased to see an increased willingness from our customers to pay for this transformational technology. Also in the U.S. Gulf of Mexico, we just signed a contract for an additional 4 wells of 15,000 work on the Deepwater Atlas at a 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 exercised its remaining option on the Deepwater Skyros at $400,000 per day. While this option, which was negotiated well before the most 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, InteliWell, and others that we developed, tested, and proved during the downturn, but were unable to fully deploy due to 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 day rates increasing and 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. 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, 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 1 to 3 years. All indications continue to suggest heightened demand for at least the next several years. In its independent assessment, Rystad anticipates deepwater greenfield CapEx in 2025 will be the highest in 12 years, and that by 2027, total deepwater investments 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 U.S. Gulf of Mexico, Shell's Bonga North in Nigeria, TotalEnergies' Kaminho discovery in Angola, Venus discovery in Namibia, and ExxonMobil's Whiptail in Guyana, which was approved earlier this month. These predictions 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, President and COO
Thanks, Jeremy, and good morning, everyone. Jumping directly into the various regions. In the U.S. 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 timelines. 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 6-month firm term commencing in the first half of 2025 with two 6-month options. The other is for 6 to 9 months of work commencing in the third quarter of 2025. Additionally, there are two major E&P companies currently out to market for multi-year programs. In Brazil, last month, Petrobras provided an update to its expected demand for floating rig requirements through 2030. This demand forecast suggests Petrobras may absorb up to 30 rigs through 2030, aligning with our expectations that 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. Earlier this month, and for the second time this year, Petrobras disclosed another discovery. Our confidence that Petrobras will require at least 30 rigs improves with each new discovery. The Roncador tender for up to 2 rigs is expected to be awarded in the third quarter, with commencement next year. The Cepea tender for up to 3 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 3 resale blocks in the Campos 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 4 rigs will be required from outside the region. Tenders include ExxonMobil's 2-year firm opportunity and Shell's 1-year firm opportunity in Nigeria, among others. Both of these have multi-year 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. With the recently revised commencement window, our KG1 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 U.S. Gulf of Mexico, tenders are being utilized less frequently in favor of direct negotiations. As an example of customers booking further into the future, we just signed a letter of intent, subject to final partner approval, for the extension of the Transocean Spitsbergen by 3 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 onward, including Inpex 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 6 floaters currently in the country are likely to be occupied in that time frame, including our 2 rigs, the Transocean Equinox and Transocean Endurance, 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 in 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 20,000 BOP. The BOP was pulled back to the surface. Following an evaluation, we concluded the most efficient path forward was to redeploy the rig's first 20,000 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 technology deployment, it is not uncommon to experience some early life performance issues. However, Transocean has extensive experience in 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 event, it is important to note that 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 one-time 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.
Jeremy Thigpen, CEO
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 InteliWell 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 U.S. Gulf of Mexico. We also achieved a milestone with our robotic riser system. We have handled more than 2,000 joints of a riser across our 3 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 multi-year upcycle. Lastly, for Mark, personally, I think these transactions represent an excellent capstone to an exceptionally successful career. This professionalism truly is something we witness across our organization as a whole day in and day out. For that, I would like to thank each member of the Transocean team's unwavering commitment to delivering safe, reliable, and efficient operations for our customers and value for our shareholders. Change and continuous improvement are constants in our industry, and our team has continuously demonstrated an ability to adapt as we progress further into the sustained cycle. In conclusion, the outlook for our assets and services remains strong. With the tightness of supply, the active negotiations, and the $500,000 per-day glass ceiling now broken in multiple jurisdictions, 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 Mey, CFO
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 the 8% senior notes due 2027. The remaining outstanding balance on the ladder notes is approximately $525 million. Approximately $92 million of the 11.5% senior guaranteed notes that were not tendered remain outstanding until the end of July, at which time funds placed into irrevocable escrow accounts will be utilized to pay down 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, enhance our financial flexibility. On the ladder 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. Concurrent with the aforementioned transactions, Moody's upgraded Transocean's corporate family rating to B3 from Caa1, reflecting the improved 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 an 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 payroll-related 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 advance preparation of the Transocean Equinox during the quarter. Negative free cash flow of $169 million in the first quarter reflects the 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 7th gen-plus newbuild Deepwater Aquila 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 his prepared comments, including delayed contract commencements of the 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 expenses 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 reserved 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%. The quarter-over-quarter increase is mainly due to the incremental activity for Transocean Endurance and Deepwater Orion operating for a full quarter, the Transocean Equinox and KG1 starting their respective contracts during the quarter, and higher revenue efficiency following the resolution of the downtime event in the Deepwater Titan in the first quarter. This is partially offset by reductions in activity on the Transocean Barents and 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 4 rigs and to an increase in in-service 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 for the debt refinancing and a voluntary early retirement program that was offered to longtime employees. Net interest expense for the second quarter is forecasted 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 the 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 be at 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 3 factors: the aforementioned delays in contract commencement on the Transocean Endurance, Deepwater Orion, and 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 costs 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 credit facility and is inclusive of restricted cash of approximately $395 million, most of which is reserved for debt service. This liquidity forecast includes 2024 CapEx expectations of $231 million, of which approximately $34 million is related to the Deepwater Aquila and approximately $97 million for sustaining and contract preparation CapEx. As I sign off for the last time, I'd like to reiterate my gratitude to the entire Transocean organization that 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's 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 continue to serve Transocean and its shareholders well. Congratulations, again, Thad. This concludes my prepared comments. I'll now turn the call back over to Allison to introduce questions and answers.
Allison Johnson, Director of Investor Relations
Thank you, Thad, for your contributions over the years. Your strategic thinking, financial discipline, and extensive knowledge of the offshore drilling market will greatly support a smooth transition. I believe you will continue to benefit Transocean and its shareholders. Congratulations once again. This wraps up my remarks, and I will now hand the call back to Allison for the Q&A session.
Operator, Operator
And we'll take our first question from Kurt Hallead with Benchmark.
Kurt Hallead, Analyst
Mark, congrats again, and good luck on what's next.
Mark Mey, CFO
Thanks, Kurt.
Kurt Hallead, Analyst
I think it's always a bit unpredictable when it comes to preparing rigs for work and getting them ready for contracts. That’s just part of this business. As you assess risks related to start-ups and timing, could you provide some insight into your process so we can better understand the dynamics from an outside perspective?
Mark Mey, CFO
Yes, Kurt. I wouldn't really say it's fits and starts. We go through a multi-phase process. We call them milestones whereby we evaluate the project, we build out a timeline, we build out a team, we start ordering all the materials for that, and then we execute. But things happen because when you try and assess a rig's ability, you're doing it rather blind. Once you start getting onto 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. Now you find things. And that causes you to expand your scope. In our case, especially, towing 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 6 weeks and delayed getting into the country. That is now being resolved and behind us. So going forward, we expect to be able to get rigs in pretty comfortably. But I don't want you to think that contract prep is a random off-the-cuff type thing. It is very well-planned, and most times, very well-executed.
Jeremy Thigpen, CEO
The other thing I'd add is we've had a lot of rig moves here over the years. And most of those are getting behind us, where we're going on long-term contracts in these jurisdictions. 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. I think that is going to lead to better financial results as we get into 2025 and beyond.
Keelan Adamson, President and COO
Yes, it's Keelan here. I would like to add some details. One important aspect is the risk management involved in moving a rig, preparing it for a contract, and navigating the regulatory and customer acceptance processes, which can change over time. More importantly, it's crucial to ensure that the rig operates reliably, efficiently, and safely after this process. I'm pleased to report that the rigs we've worked on have seen great success. For example, the KG2 is performing well; it has recently become one of the top-performing rigs for Petrobras in Brazil after just a few months. I echo Mark's earlier comments about our strong project planning process for these events. The delays we've encountered are not due to discovering new tasks, but rather unusual events related to logistics. For instance, in India, we faced a local fishermen strike that blocked access to the rig for a couple of weeks. Some situations are tough to manage, and it's important to recognize that there is always risk involved.
Kurt Hallead, Analyst
Yes. I appreciate all that color. And it's kind of why I ask because I know it's never straightforward as it may seem on a piece of paper, right? Okay. So look, it looks like you got your contract durations extending, and your day rates continue to rise. I guess my question really relates back to the overall market outlook. 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?
Roddie Mackenzie, Chief Commercial Officer
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. We're looking at, I think, actually barring not in every single region for rigs that they have to date. So at the moment, what's happening is there's a run on the active fleet. 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. From that point of view, my view is that 2024 will see pretty much the entire active fleet sold out for 2 to 3 years going forward. As we get towards the end of '24, that's when the call on the stacked fleet is going to happen. Of course, we've reiterated this many times that while there are active rigs available, we will not be rushing stacked rigs into that mix. We'll bide our time and wait until the economics are right for that. 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.
Operator, Operator
And we'll take our next question from Eddie Kim with Barclays.
Eddie Kim, Analyst
Just wanted 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 towards the end of the year?
Roddie Mackenzie, Chief Commercial Officer
Yes, I think this is actually just a pretty standard operating procedure. With Petrobras pushing out by a couple of months, that's very typical. We believe that the rigs that are going to win those tenders are either already active rigs in the country or are 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 '24. 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, Analyst
And then just a question on your 2 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 2 rigs? And if you could comment on kind of work prospects or opportunities for those rigs?
Keelan Adamson, President and COO
Yes, Eddie, 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, Chief Commercial Officer
Yes. 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 work. So at the moment, we're quite comfortable keeping them where they are until they get the right opportunity.
Eddie Kim, Analyst
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?
Mark Mey, CFO
Yes, Eddie, we can take that offline. If you could speak to Allison, she can walk you through it. It's a pretty lengthy response.
Operator, Operator
And we'll take our next question from Doug Becker with Capital One.
Doug Becker, Analyst
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, CEO
I'm going to hand that to Roddie because he is neck-deep in this conversation right now.
Roddie Mackenzie, Chief Commercial Officer
Yes, so we've got a lot of interest in that rig. This was a prospect that we had with the current operator for some time. It looks like a really good rate, but I have to say it was set a while ago when we got into negotiations on that. The transition for her to go to the 20,000 is probably going to take place in the next contract. 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. After that, we're transitioning into the much more attractive work. That's good. That's basically the second rig in the Gulf that's contracted above $500,000. With the Asgard and the Atlas now contracted above $500,000, 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 4 to 5 additional awards in the Gulf of Mexico above $500,000 a day.
Doug Becker, Analyst
It's definitely encouraging. Maybe just could you expand on the BOP issues with the Titan and really kind of thinking about it in the context of, is there a similar risk with the Atlas?
Keelan Adamson, President and COO
The Titan's first BOP has been deployed and the rig has been fully operational since mid-March. We identified an issue with a specific component on the second BOP, which was not a problem with the first BOP. We have removed those components, taken them back to town to collaborate with our OEM provider for disassembly and inspection, and we expect to have more information on that issue in the coming weeks. Based on our observations and the functioning of the other stack, we have no concerns about this affecting the other stacks. It is simply a matter of component reliability that we will resolve and return to the rig.
Doug Becker, Analyst
Sounds good. And Mark, congratulations.
Mark Mey, CFO
Thanks, Doug.
Operator, Operator
And we'll take our next question from Fredrik Stene with Clarksons Securities.
Fredrik Stene, Analyst
You talk a bit about the market here. I was also on the back of those discussions already. Wanting to hear what you're thinking about 7Gs versus 6Gs 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 Invictus, 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 6G rigs in the future?
Roddie Mackenzie, Chief Commercial Officer
Yes. So I think you see several of our 6th-gen rigs have got very attractive rates just in the right markets. If the market requires a certain specification and the 6th-gen rigs qualify for that, then they achieve very well. At the moment, there's a lot of activity around the high-specification rigs. 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. 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 are left. 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 operators around securing the highest specification assets they can get their hands on.
Jeremy Thigpen, CEO
Yes. And 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 load rigs in the market other than the Atlas and the Titan, and started setting day rates with those rigs. It's lifted all the 1,250-tonne rigs, where now our competitors are also pushing for $500,000 a day and then some. You'll definitely see a step change once we move to the new 20,000 contracts on the Atlas and the Titan.
Fredrik Stene, Analyst
That's very helpful. You mentioned quite a lot of long-term opportunities that you foresee will materialize now over the next couple of months or quarters. There have been different approaches with different owners regarding how we should price long-term work. Some will accept a lower rate just because they would like the visibility of a longer-term contract, while others, and you being the best example of that, have 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? Should the market expect to be disappointed by some of these direct points, or should we see them all pulling in the same direction or being 450-plus in almost all awards?
Roddie Mackenzie, Chief Commercial Officer
Yes. I would say 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, you're clearly going to see rates well above 450. Even for term work, I think you're going to see that there might be 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%. 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. Some long-term stuff will be awarded above that $500 marker. Overall, as Jeremy has said, we've been very purposeful about which rigs get placed on which opportunities. For our top-spec assets, we'll ensure that they are on very positive contracts with strategic importance to us as well, not just dollars.
Mark Mey, CFO
Thanks, Fredrik.
Operator, Operator
And our next question comes from Arun Jayaram with J.P. Morgan.
Arun Jayaram, Analyst
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 globally. 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?
Roddie Mackenzie, Chief Commercial Officer
Yes, sure. You've basically got 4, possibly 5 operators that are active or going to be in the 20,000 market as we would describe it. 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 that also believe that this is a trend that will continue in the future. So as we go 4, 5, 6 years in the future, 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. Operators see value in both the equipment and the expertise, so we're well placed for both of our rigs at the moment.
Jeremy Thigpen, CEO
Yes. And Arun, I think your other question was how many are capable of 20,000. There are only 2 rigs in the world with 20,000 BOP, which are the Titan and the Atlas. So we're in a very good position there.
Arun Jayaram, Analyst
It's a nice mix. Just broadly, can 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.
Roddie Mackenzie, Chief Commercial Officer
Yes, absolutely. McKinsey's recent report described what's happening in upstream investments expected in West Africa. If you take specifically the deepwater sector, they expect to see an increase of 80% in spending between 2023 and 2027. As we go through our chart of available opportunities in West Africa, that is the one piece of the Golden Triangle that's finally gaining traction. North America is performing well, the Gulf of Mexico is thriving, and of course, South America has seen a lot of rigs moving in. However, this last quarter, we've really seen a lot of positive movement in West Africa. It's not just one or two countries, it's across several different areas. I won't go through all the details on that, but certainly, the traditional players in Nigeria are back with 4 tenders. Angola's contracting activity has been solid, and there are still a couple more to be awarded. As we go through Mozambique and Ghana, there's still plenty more scope there. We believe all the fleet that's currently in West Africa will either be renewed, extended, or put onto different programs, plus we will need 2 to 3 additional rigs in the next couple of years. West Africa looks very positive at the moment.
Operator, Operator
And we'll take our last question from David Smith with Pickering Energy Partners.
David Smith, Analyst
If I review the data from a year ago regarding forward availability for the deepwater fleet, I see that a significantly higher percentage of drillship availability has been contracted compared to the benign deepwater semis. I was hoping to hear your thoughts on what you're hearing from customers about the interest in drillships compared to benign semis. Also, how should we consider the natural pricing premium for an average 6th-generation drillship versus that of an average 6th-generation benign semi?
Keelan Adamson, President and COO
I'll take a shot at answering that question, David, and then Roddie can add his insights. From what we are observing with our customers, there has been a shift in perspective over the years. Previously, it was believed that semis were more suitable for field developments while drillships were better for exploratory work. However, this view has evolved significantly over the last 5 to 10 years. Drillships have become much more versatile, and our customers are quite comfortable using them for field developments. They appreciate the redundancies in space, size, and capabilities that drillships offer compared to semis. While semis do have benefits in shallower waters and can be moved easily and positioned dynamically if needed, drillships are currently the preferred option based on customer feedback. I’ll let Roddie provide further insights on this.
Roddie Mackenzie, Chief Commercial Officer
Yes. No, I think that's spot on, Keelan. There are certain basins where we still have significant interest in the semis. There are a couple of programs starting in '25 that will require, exactly as Keelan described, where you have this combination of a moved unit that can also do DP work. 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, Analyst
Very much appreciate the color. If I could add one more on the market outlook. Totally agree on the future call on more rigs. Maybe one small partial solution is getting more out of the existing fleet with better calendar scheduling, right, with some rigs having 2 or 3 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, Chief Commercial Officer
Yes. The #1 driver for that is the tightness in the market, right? As we described, we're in this transition over the past 6 months and certainly the next 6 months. Many of the fleet are moving to longer-term contracts. By necessity, in a downturn, you may have to move the rig frequently to keep her busy from one customer to the next, and 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 over the last couple of years. You're going to see that transition, and we're not going to be exposed to nearly as many movements of rigs. That's going to tidy up very nicely for us for the remainder of this year and into next year.
Operator, Operator
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.
Allison Johnson, Director of Investor Relations
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, Operator
That concludes today's teleconference. Thank you for your participation. You may now disconnect.