Transocean Ltd. (NYSE:RIG) Q4 2024 Earnings Call Transcript

Transocean Ltd. (NYSE:RIG) Q4 2024 Earnings Call Transcript February 18, 2025

Operator: Good day, everyone, and welcome to today’s Q4 2024 Transocean 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. You may register to ask a question at any time by pressing the star. Please note today’s conference is being recorded. I will be standing by if you should need any assistance. It is my pleasure to turn the conference over to Alison Johnson, Director of Investor Relations. Please go ahead.

Alison Johnson: Thank you, Margo. Good morning, and welcome to Transocean’s fourth 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, Thaddeus Vayda, 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 Thad’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. As disclosed in yesterday’s earnings release, for the fourth quarter, Transocean reported adjusted EBITDA of $323 million on $952 million of adjusted contract drilling revenues, resulting in an adjusted EBITDA margin of approximately 34%. For the full year 2024, we delivered adjusted EBITDA of $1.15 billion on approximately $3.5 billion of adjusted contract drilling revenues, resulting in an adjusted EBITDA margin of approximately 33%. 2024 was a year that once again demonstrated the strong trust our customers have for Transocean’s industry-leading high specification fleet and services. I do not believe that there’s been a single moment in the previous decade that has better illustrated our industry leadership and the trust our customers place in Transocean as clearly as in the past year.

We outlined in great detail on the third quarter earnings call, throughout the year Transocean continued to book market-leading rates even as excess capacity was obviously emerging among our competitors. While our customers, who are extremely astute, observed an upcoming availability of assets, they still awarded us with several contracts approaching and exceeding $500,000 per day for our high hook load seventh gen plus assets and more than $600,000 per day for our eighth gen 20k assets. Clearly demonstrating their recognition of the value that Transocean creates in the delivery of their wells. In addition to many of our headline-grabbing announcements, elsewhere in the fleet in December, we announced that Reliance Industries exercised a four-well option for the KG1 in India at a rate of $410,000 per day.

The rig is now expected to remain in India on its firm program through the end of 2027 and will generate strong cash flow throughout that period, representing very good value for both us and our customer. And in January, an eight-day option was exercised on the Transocean Endurance by its customer in Australia at a rate of $390,000 per day. Given that our active fleet is near full utilization through 2026, we are primarily focused on opportunities that commence in mid to late 2026, and I’m pleased to report that we are in direct discussions with a number of customers on multiyear term opportunities on our rigs with availability in 2026. Before I cover those specific opportunities and our view of the market by region, I will hand it over to Keelan to review key operational milestones and technology deployments over the past year.

Keelan Adamson: Thanks, Jeremy, and good day, everyone. We achieved a number of significant operational milestones in 2024. We delivered our best-ever occupational and process safety performance ending the year with a total recordable incident rate of 0.15, and more importantly, with zero serious injury cases or lost time injuries. The safety of all personnel aboard our rigs is our highest priority, and we take great pride in our commitment to maintaining the highest standards and continuously striving for an incident-free workplace, all the time, everywhere. In April, we commenced operations on Transocean Equinox in Australia. The rig recently completed its contract several months ahead of the planned program schedule, creating significant value for our customer.

The early completion has enabled the rig to progress to its higher day rate follow-on program earlier than we expected. In June, we commenced operations on the Deepwater Aquila, the latest 1,400 short ton drillship added to our fleet, just nine months after we acquired the outstanding interest in that joint venture that owned the rig. The Aquila is currently on contract with Petrobras until mid-2027. Perhaps most notably from a technology perspective, during the year we installed the first two 20k subsea completions in the history of the offshore drilling industry with our two eighth generation drillships, the Deepwater Atlas and the Deepwater Titan. These completions are significant milestones in the process of achieving first oil for our customers in each of the high pressure, high temperature reservoirs, and we are exceptionally proud to contribute to these landmark developments.

We express our sincere gratitude to Chevron and Beacon Offshore for their trust in our expertise to execute this important work. In 2024, we continued to deploy new technologies to enhance our operational performance and further differentiate our fleet by improving the safety, reliability, and efficiency of our operations. We expanded the use of drilling automation in the fleet, achieving an industry first on the Transocean Norge. Using the IntelliWell automation platform, which is installed in two rigs, we simultaneously conducted fully automated casing running and offline stand building operations. On these rigs, we tripped over one and a half million feet of drill pipe with no personnel in the red zone. And lastly, we co-developed the rotary multi-tool to eliminate other manual tasks on the drill floor.

This is now on its initial deployment on the Transocean Enabler. We are actively using industrial robotics on three of our ultra-deepwater drillships. The robotic riser bolting system automates the riser joint connection process, one of the most taxing and hazardous activities we perform offshore. The system removes personnel from the red zone during riser handling operations. To date, we’ve handled over 3,000 riser joints using the system, greatly enhancing safety and efficiency, and are experiencing a significant surge of interest for additional customer-driven deployments across the globe. In addition to the robotic systems, I would like to highlight two other safety-enhancing technologies that we deployed in 2024. A kinetic blowout stopper, a tubular shearing technology that is retrofitable to existing blowout preventers, and HaloGuard, a monitoring and control system designed to stop drill floor moving equipment when traveling in close proximity to personnel.

The latter technology is now operational on eight of our rigs, resulting in even greater protection for our offshore teams. We are in discussions with a number of our customers for more installations of these and other products. Significantly, we recently signed an agreement with Petrobras for a customer-funded installation of robotic riser on the Deepwater Atlas and are nearing completion of an agreement to implement HaloGuard on four of our six rigs currently in contract in Brazil. And finally, in 2024, we were granted 22 patent applications around the world, once again demonstrating Transocean’s industry leadership in innovation and technological development. I’m proud of the work our team does each and every day. Their commitment to operational excellence and innovation drives our success and the delivery of outstanding results for our customers.

I’ll now hand the call back to Jeremy.

Jeremy Thigpen: Thanks, Keelan. Looking at the various regions, starting in the US Gulf, our analysis of the market suggests that most of the major contracts for work commencing in 2025 have already been awarded and that rigs concluding work this year will likely remain available until at least 2026 unless they’re mobilized elsewhere. Fortunately, we are at present somewhat insulated from this market dynamic in the short term and remain encouraged by the future outlook. We continue to be engaged in multiple conversations across the customer spectrum for programs starting in 2026 and 2027 that specifically require our high specification high hook load drillships, including work scopes that require the 20k completions capability of our eighth generation drillships.

As such, we believe that our assets in the U.S. Gulf will remain in high demand for the foreseeable future. In Latin America, we expect the active rig count to remain relatively stable. In Guyana, demand forecasts suggest the five rigs currently on contract will remain working until at least 2028. In Suriname, Total recently tendered for a program requiring one drillship commencing in late 2026 for approximately two years. In Brazil, we expect Petrobras to issue another multi-rig tender with commitment windows beginning in late 2026 and to maintain the number of rigs it has contracted for the foreseeable future. The company is scheduled to host a future scenario meeting with the drilling contractors later this week to provide an update on its activity outlook.

We anticipate that this meeting will provide incremental clarity on the company’s plans. With Petrobras’ keen interest in our technology, we believe our assets are well-positioned for its future programs. Importantly, other operators in Brazil are beginning to investigate rig availability for their programs commencing during the next several years. Most notably, Shell is planning to make its final investment decision within the next month for a multiyear development program commencing in 2027 for its Gato de Mato project. Additionally, BP is expected to move ahead with a short exploration campaign in late 2026. In Africa, we have not seen much change in demand over the last three months and expect there will be a short-term supply-driven imbalance as rigs roll off contract before new programs commence.

We believe much of this work will start in 2026 and 2027, several operators are in tender process and or direct discussions for various programs in and around the West African coast, of which may have a late 2025 commitment. In Norway, Equinor is out to tender for multiple rig lines with commencement dates between the end of 2026 and beginning of 2027. We expect this work to be awarded in the second quarter. This combined with demand from other operators in Norway will require up to two rigs to return from outside the country in 2026. Additionally, the Norwegian Ministry of Petroleum and Energy plans to offer 76 blocks on the Norwegian Continental Shelf in the AP 2025 licensing. This is up from 53 licenses in the 2024 round. Farther East, more programs are beginning to materialize in Australia for late 2026 and 2027.

These include a one-year program, a two-year program, and a five-year program. In India, ONGC is expected to tender for one semi-submersible and one drillship later this year. To fulfill these requirements would require rigs from outside the region. Finally, in Malaysia, PTTEP will retender for its program with a revised start date of mid-2026. Overall, our outlook remains upbeat given our position of near 100% utilization throughout 2025, particularly positive for a tighter market in 2026 and beyond. Thus far, day rates have been fairly resilient in the context of an anticipated temporary rig supply. In our view, both of these are strong indications of healthy industry dynamics. From a macro perspective, our customers are increasingly focused on the traditional oil.

This was reinforced earlier this month when Equinor communicated that expected gross production by 10% between 2024 and 2028, while concurrently reducing investment in renewables and other low carbon technology by $5 billion, half its previous target, over that same period. According to Rystad Energy, Deepwater CapEx sanctioning is projected to rebound in 2026 and 2027, more than doubling from 2025 estimates. These projections are consistent with the conversations we have with our customers, and our view that we continue to be in a sustained up cycle. With our active fleet largely contracted for the next eighteen months, our main focus for 2025 is on operational execution to maximize the conversion of our remaining $3.1 billion in backlog during the year into revenue and then net revenue to cash.

With that, Thad will now discuss our financial results.

Thaddeus Vayda: Thank you, Jeremy, and good day to everyone. During today’s call, I will briefly recap our fourth quarter results, provide guidance for the first quarter of 2025, and conclude with an update of our expectations for the full year. As disclosed in our press release, for the fourth quarter, we reported a net income attributable to controlling interest of $7 million or a net loss of $0.11 diluted share. The net loss per share is caused by the impact of certain financial instruments related to value changes in our exchangeable bonds. Please refer to note eleven in our forthcoming annual report for additional information regarding the effects of our convertible debt instruments on net income. The quarter, we generated adjusted EBITDA of $323 million and cash flow from operations of approximately $206 million.

Positive unlevered free cash flow of $177 million reflects the $206 million of operating cash flow, net of $29 million of capital expenditures. During the fourth quarter, we delivered contract drilling revenues of $952 million, within our guidance range at an average daily revenue of approximately $445,000. Operating and maintenance expense in the fourth quarter was $579 million. This fell slightly below the lower end of our forecast range primarily due to the delay of noncritical in-service maintenance activities for our active fleet, way contract preparation costs for the Transocean Balance, and a favorable resolution of old contingencies. G&A expense in the fourth quarter was $56 million. We ended the fourth quarter with total liquidity of approximately $1.5 billion.

This includes unrestricted cash and cash equivalents of $560 million, about $381 million of restricted cash, the majority of which is reserved for debt service, and $576 million of capacity from our undrawn credit facility. I’ll now provide guidance ranges for the first quarter of 2025 and an update on our expectations for the full year. As always, our guidance excludes speculative reactivations and upgrades. For the first quarter, we expect contract drilling revenues to be between $870 million and $890 million based upon an average fleet-wide revenue efficiency of 96.5% on our working rigs, which as you know can vary based upon uptime performance, weather, and other factors. This estimate always includes between $55 million and $65 million of additional services and reimbursable expenses.

Please recall that these additional services and customer reimbursements. The quarter-over-quarter decrease in contract drilling revenues is primarily caused by lower activity within the active fleet due to mobilization out of service activities and contract preparation periods. We expect first quarter O&M expense to be within a range of approximately $610 million to $630 million. This quarter-over-quarter increase is primarily due to out of service and contract preparation periods, including those on the Pittsburgh and Invictus, Equinox, and Endurance. We expect G&A expense for the first quarter to fall within the range of $50 million to $55 million. This quarter-over-quarter decrease is primarily due to higher legal fees incurred in the fourth quarter of 2024 that we do not expect to repeat.

Net interest expense for the first quarter is forecast to be between $140 million and $150 million, comprising interest expense and interest income of about $150 million and between $5 million and $10 million respectively. Capital expenditures for the first quarter are forecasted to be expected to be about $13 million. For the full year 2025, we currently forecast contract drilling revenues to be between $3.85 billion and $3.95 billion. The range primarily reflects potential variances in revenue efficiency and the limited availability of our fleet. Our guidance includes between $230 million and $245 million of additional services and reimbursable expenses. These expectations vary somewhat from the preliminary guidance we provided in the third quarter 2024 earnings call, mainly due to shorter than expected activity for the Deepwater Scuros, the result of the customer changing its well schedule.

Unfavorable foreign exchange movement impacting the remeasurement of our local currency contract in Brazil. This is largely offset in our O&M cost due to transactions that are settled in local currencies. We expect our full year O&M expense to be between $2.3 billion and $2.4 billion in line with our previous guidance. And we still anticipate G&A cost to be between $190 million and $200 million. For the full year, we’re anticipating net interest expense between $550 million and $555 million, comprising interest expense and interest income about $580 million and between $25 million and $30 million respectively. Cash taxes for the year are forecasted to be between $65 million and $70 million. Our projected liquidity at year-end 2025 is currently forecasted to be protecting our revenue and cost guidance and including our undrawn revolving credit facility and restricted cash of approximately $1.35 billion to $1.45 billion, most of which is reserved for debt service.

This liquidity forecast includes 2025 CapEx expectations of approximately $130 million, of which approximately $70 million is related to customer acquired capital upgrades for upcoming projects and capital spares, and approximately $60 million of sustaining capital investment. As a reminder, for the terms of our credit agreement, the capacity of the facility declined to $510 million from $576 million effective late June 2025. As Jeremy mentioned, we are fully committed to efficiently converting our backlog to revenue and revenue to cash. So in addition to our intense focus on providing superior operational execution for our customers, we are exploring ways to materially improve our cost structure. At the outset of this year, we commenced an enterprise-wide evaluation to identify areas in which without compromising our ability to provide safe, reliable, and the most efficient operations possible.

Which creates value for both our customers and our shareholders and we will use this savings to accelerate the leveraging of our balance sheet. Once this evaluation is complete, we will provide a definitive savings target and timeline for achieving it. And we expect to provide this guidance when we report our first quarter 2025 results in April. That concludes my prepared remarks, and I’ll now turn the call back to Jeremy for some concluding comments before we start Q&A.

Jeremy Thigpen: Thank you, Thad. Before we move to Q&A, I would also like to share the following. April 22nd will mark my tenth year as the CEO of Transocean. Over the past several years, we, management, and the board, have worked diligently to define and execute succession plans with the objective of developing and recognizing our incredibly deep bench of internal talent while simultaneously maintaining business and leadership continuity. Over those years, just looking around the room, we promoted and expanded the responsibilities of Keelan Adamson to the position of President and Chief Operating Officer, Roddie Mackenzie to Executive Vice President and Chief Commercial Officer, Brady Long to Executive Vice President and Chief Legal Officer, and last year, Thad Vayda to Executive Vice President and Chief Financial Officer.

As you will have read in this morning’s press release, today I’m pleased to announce that we will continue the progression of this succession plan by soon naming Keelan Adamson Transocean’s President and Chief Executive Officer. The next few months, I will assist Keelan with the transition, which we expect will take place during the second quarter of 2025. And I will continue as a board member through our 2025 annual general meeting, where shareholders will be asked to elect Keelan to the board, elect our current board chair, Chad Deaton, as a director, and elect me as Executive Chairman. At that time, Chad will transition to the role of Lead Independent Director. I’d like to thank the board and the entire Transocean team for their trust and support these past ten years.

An incredibly challenging time in offshore drilling. I am proud of the fact that we are the only publicly traded offshore drilling company to survive the downturn without restructuring and are now on a path to materially delever the balance sheet. I’m also proud of the transformation on our fleet and that we continue to introduce innovative technology to the industry, which improves safety and drilling efficiency. But most of all, I’m proud of the team and culture we built to transition. I could not be more excited about transitioning the leadership of this company to Keelan, a man who spent the past three decades of his life with the company, starting on the drill floor and progressing all the way to the executive ranks. There is no one more capable or deserving of this opportunity and I look forward to the positive impact he and the team will have on the company as they further Transocean’s position as the undisputed leader in offshore drilling.

Before we move to Q&A, I just want to once again thank the board and the transition team. It is my honor to work alongside all of you.

Alison Johnson: Thanks, Jeremy. Margo, we’re now ready to take questions. And as a reminder to the participants, please limit yourself to one initial question.

Operator: Thank you, Ms. Johnson. At this time, if you would like to ask a question, please press star one. We’ll take our first question from Eddie Kim with Barclays. Please go ahead.

Eddie Kim: Hey, good morning. Jeremy, I thought it’s only been ten years, but some years are much longer than others. So congratulations on what I’ll call maybe an effective twenty-year career at Transocean. And well-deserved transition away from having to speak to guys like us all the time.

Q&A Session

Jeremy Thigpen: Thanks, Eddie. I appreciate it.

Eddie Kim: My first question is just around the potential day rate we could see on contracts later this year. Obviously, Transocean is very well insulated. But we’ve had, you know, wide space concerns industry-wide. Any regional commentary also suggests, you know, some temporary supply-demand imbalance this year. So in light of that, do you think we could see a contract announcement for a 7G drillship at a day rate, maybe even as low as $350,000 a day? Just curious about your thoughts there.

Roddie Mackenzie: Yeah. Eddie, I think I’ll take that one. This is Roddie. So look, I mean, what we see at the moment is there’s not that many opportunities available in 2025. So we actually think it’s pretty unlikely that you’re going to see many fixtures at significantly lower rates. There may be one or two, but in all honesty, I think unless those opportunities are in direct continuation, the drilling community is unlikely to sacrifice a kind of a longer-term deal at a lower rate to try and plug a gap that’s, you know, perhaps not on the table, if you know what I mean. So I think it’s possible that you might see some data dip down into the threes for the, you know, the kind of commodity seventh gen rigs, but I don’t think you’re gonna see any of that, especially for the higher spec units.

I also think that because there’s not that many opportunities in 2025, I think a lot of the drillers will be patient in that regard. And most of the work that we’re looking at just now, as Jeremy had mentioned in his prepared comments, is for multiple years. So the concept of starting something in 2026 or 2027 for two or three years and doing it based on a temporary short-term dip in the market doesn’t really make sense to me, certainly. So I’m not sure you’re gonna see that many of these low fixtures. Certainly, we haven’t seen very many published so far.

Eddie Kim: Got it. Understood. And my follow-up is just on your three seventh generation cold stacked rigs, the Belos, Athena, and Apollo. One of your peers, as you mentioned, just announced their time at of their 7G stacked rig, which isn’t necessarily the best indicator of forward demand. There are also a handful of other 7G cold stacked rigs contractors could be more motivated in putting their rigs back to work. So in light of that, how are you reactivation of your 7G rigs? And do you think it’s likely that we could see one of them working before 2028?

Jeremy Thigpen: Yeah. Good question, Eddie. We continue to evaluate our fleet. Not even a quarterly exercise. It’s more frequent than that. And, of course, take into account how long the rig’s been stacked, what do we think the cost to reactivate, and, of course, that tends to go up the longer they’ve been stacked, and then when do we think they’re gonna come back into the market, and what day rate. And so we will continue that process. Could or could not lead to, you know, changes in the fleet over time. But I would say the three seventh gen rigs, we still believe are valuable, but we’re gonna be disciplined. If the customer’s not willing to pay for the reactivation in the first contract with a decent return for us, then we won’t move forward, and we’ll just continue to evaluate their future on an ongoing basis.

Eddie Kim: Got it. Thank you for that call, and I’ll turn it back.

Operator: Thank you. And our next question comes from Kurt Hallead with Benchmark. Please go ahead.

Kurt Hallead: Hey. Good morning, and good morning, Kurt.

Jeremy Thigpen: Nope.

Kurt Hallead: Don’t mean to one-up Eddie on this, but in this business, it’s probably more like dog years. So ten years is, like, seventy. So who knows?

Jeremy Thigpen: I certainly look at Curt. No. No.

Kurt Hallead: No. Not quite. But hey. Congrats. And I know it’s been a tough road, and you guys took, you know, a solo path on trying to preserve, you know, as much shareholder equity as possible. It looks like you’re on the verge of seeing that to fruition. So kudos on that front for sure. And, Keelan, be careful what you wish for, man. The walls are howling, man. They’re coming after you.

Keelan Adamson: Appreciate that, Curt. Thanks, Curt.

Kurt Hallead: Got it. No. Alright. So, yeah, great summary here on what’s going on with the market dynamics, but maybe coming back around to one of the answers that Roddie gave on, you know, commodity 7G. So it sounds like we have yet, you know, another layer to consider or another tier to consider in the context of 7G drillship. So, Roddie, can you again help us, you know, kinda how do you define a commodity 7G drillship and how do we think about the tiers right now?

Roddie Mackenzie: Yes. Fair enough. Commodity 7G, we kind of consider that the non-high hook load rigs. Other rigs, you know, with single BOPs. So, typically, you’ve got a bit of a split in the higher specifications. Normally, that line is pretty bright between sixth generation and seventh generation. But within the seventh generation, you have what we call 7G plus because they basically have a super high throughput. They also typically have, you know, larger mud handling capacities and those kind of things as well. So what that means is that the operators, for the well design and certainly the size of the casing runs, they can deploy are significantly larger and therefore more efficient than the lower hook load rigs. So that’s typically been our strategy over the past ten years is to really focus on that class of asset because we believe that is the most desirable asset.

And I think that has definitely shown up in our results in terms of utilization of those assets. Today, right now, I don’t think there is a single 1,400-ton rig with any availability in 2025. So if you take it from that point of view, there’s clearly a difference between those big rigs that are more capable and can unlock greater efficiencies for the customers versus the rest of the seventh gen. Does that make sense?

Kurt Hallead: Yeah. No. I appreciate that. And then maybe the one follow-up then, Jeremy, you referenced having a number of different discussions for potential projects in 2026 and into 2027. Can you give us some sense on how you’re kinda navigating those discussions from a pricing standpoint and how much, you know, how much are your customers saying, well, look, you know, if we’re gonna give you this deal in 2026, you gotta give us 2025 pricing. How’s that discussion evolving?

Jeremy Thigpen: Yeah. Good question, Kurt. I would say kind of adding on to Roddie’s point. We’re talking about the high specification rigs and we control most of them, fortunately. So as we think about the ultra-deepwater market and the harsh environment market, we are talking to these customers about rigs that we know that they need. And so that kinda frames how we approach the contracting and the day rates. So, you know, this little blip is certainly not helpful because our customers will use every advantage they can possibly get in negotiations. But we also know that our assets are of value to them, our services are of value to them, and we’re gonna price it accordingly.

Kurt Hallead: Got it. Alright. Thanks again. Congrats, Keelan, and good luck in the next role, Jeremy.

Jeremy Thigpen: Thank you, Kurt. Thanks, Kurt.

Operator: Our next question comes from Fredrik Stene with Clarkson Securities. Please go ahead.

Fredrik Stene: Hey, Jeremy and team. And congratulations again to Jeremy and Keelan. I don’t know what’s longer than dog years, so I’ll just leave it at that. But we’d be interested to hear what you think about, you know, 2025, 2026, and 2027 in general. You gave some good commentary here in your prepared remarks. From my own discussions with investors, it seems like one of the key fears is that programs just continue to slip to the right and slip to the right and slip to the right. So I was wondering if there’s, you know, anything in your discussions now, maybe that gives you confidence that these things will actually materialize in, you know, due course or in your current expected timelines? Thank you.

Jeremy Thigpen: Sure. I’ll let Roddie answer, but I’ll just start. I think what’s been most important to us throughout the years, they’re all kinda about what could happen in the macro. There are all kinds of concerns about how it would impact oil prices and how that would impact demand for our assets and services. And from my perspective, I tend not to get caught up in those conversations. I tend to think more about what our customers are doing and what they’re telling us and what they’re pushing forward toward. And everything that we’re seeing right now suggests, yes, there is a slight lull in 2025. But our customers are moving forward with these negotiations and these programs that are commencing in late 2026 and in 2027, and they’re multiyear opportunities.

And so all of that to me inspires confidence. Could it push to the right? Of course. I mean, who knows what can happen on the horizon? But everything we’re seeing today seems to demonstrate they have resolved around these programs moving forward. And with that, I’ll hand it over to Roddie because he’s certainly neck deep in all of these discussions.

Roddie Mackenzie: Yeah. Sure. So, I mean, apart from the macro, which we’re not gonna touch on too much, but the macro in general is extremely healthy and has been for some time. And will continue to be. So I think I’ll leave that up to the other analysts to reference the cases. But if you go look at anybody’s case, I think production of oil and gas is gonna be significant going forward. Your deepwater and harsh environment appear to be the most economical places to do that. So thinking about, you know, where we are in terms of 2025 and 2026 and 2027, we think about where we were this time last year or let’s say this time in 2023, looking into 2024, we basically had 77% utilization on the book. In 2024, looking at sorry. In 2023, looking at 2024, stood at 88%.

Today, looking into 2025 for the year, we’re looking at 96% plus. So if you think about where we are in that perspective, 2025 looks extremely healthy. Arguably, healthier than any of the previous years have looked in the past ten years. In addition to that, as we think about entering 2026, our utilization is about 93% entering 2026. And, you know, without tipping our hand to all the different things that we’re working on, there’s every opportunity that we could with a few fixtures made between now and say the middle of the year, be, again, in the high ninety percentile range for utilization throughout 2026. So as I think about 2025, we are extremely solid. As I think about 2026, we are extremely optimistic that we’ll be every bit as good. And you also mentioned 2027.

Have to tell you that a lot of the programs that we’re working on just now are actually starting in 2027. So, either starting late 2026 or 2027. So again, if you’re looking for a barometer on how the operators are thinking about the health of the market, the health of the drilling industry in general, if we’re talking about multiyear jobs that start two years from now, I think that’s a very healthy position to be in.

Fredrik Stene: That’s super helpful commentary from both of you. Thank you. Just two quick ones on the back of that. First, Thad, could you repeat liquidity guidance for 2025? Because maybe it was only me who had technical issues, but it kind of dropped out there. And second, any update on the inspiration on the development trailer?

Thaddeus Vayda: I’m sorry. So you want the full guidance for 2025?

Fredrik Stene: No. Just the liquidity year-end guidance. I’m sorry.

Thaddeus Vayda: $1.35 to $1.45 billion. And with respect to your second question, so those two assets had been held for sale in anticipation of a transaction that ultimately did not materialize. We did cancel the sales purchase agreement in mid-January and are holding them as still held for sale for some other opportunities. I’d add to that that given the circumstances, we are pursuing some entities.

Fredrik Stene: Thank you very much, Javier. That’s it for me. Have a good day.

Operator: Thank you. Our next question comes from Arun Jayaram with JPMorgan. Please go ahead.

Arun Jayaram: Yeah. Good morning. I was wondering if you can maybe elaborate on what you’re seeing in the Brazil market, you mentioned that you’d expect Petrobras to hold relatively flat in terms of rig count with some potential for demand to increase as you push towards late 2026. You also mentioned that there’s kind of a scenario meeting going on later this week with the drilling contractor. Maybe I was wondering if you could just give us a sense of how you see the tea leaves progressing in Brazil and any future thoughts on how Petrobras may manage its future in rig demand in-country.

Roddie Mackenzie: Yeah. I think I’ll take that one. Yeah. So Petrobras are being very vocal about their forward-looking investments. So they actually have an update coming later this week. But basically, if we think about where they were, you know, from 2023 to 2024, there was a rig count grew from 19 to 24 rigs. That’s a healthy increase. Then from 2024 going into 2024, we went up to 29 rigs. And now by the second half of 2025, we are expected to be somewhere between 32 to 33 rigs in Brazil. So that’s really, you know, positive growth there across the board. We think Petrobras themselves are gonna be operating something like 32 rigs with a few others in-country. So as high as 35 to 37 rigs in-country. So overall, I think Brazil’s a very positive spot.

We don’t expect them to regress at any point. A lot of the discussions that we have with Petrobras is kind of a full acknowledgment that they need all of the rigs they currently have under contract. So I’m not gonna say that they’re gonna add more, but typically, if you need everything that’s under contract, then there’s a chance that there may be some incremental demand as the year goes on.

Arun Jayaram: Great. And maybe my follow-up is for Thad. Could you maybe elaborate on the insurance recovery you had in the quarter and just thoughts on does the 2025 O&M cost guide, does that contemplate some of the cost efficiency things that are contemplated by rig today?

Thaddeus Vayda: So second question first, it does not. We’ve had this program in place since the beginning of this year, actually, even a little bit before that. We are doing, as I mentioned, a good deal of research identifying different ways to do business differently. I will provide some guidance later on, but it is not included in our guidance. And with respect to the question about the settlement, I’m gonna refer you to the K but suffice it to say that’s associated with an asbestos settlement that we received earlier.

Arun Jayaram: Okay. Thanks a lot, Jeremy. Best of luck to you.

Jeremy Thigpen: Yeah. Thank you very much.

Operator: Thank you. And our next question comes from Greg Lewis with BTIG. Please go ahead.

Greg Lewis: Hey, thank you and good morning everybody. Thank you for taking my question. Jeremy, congratulations. Good luck. Looking forward to talking to you a little bit more. You know, I guess my first question is, you know, where everybody’s hearing a lot about, you know, longer-term multi-year contracts coming. When we think about those, should we expect like, six to nine-month lead times for a working rig versus any kind of guidance versus, you know, the hot warm rig, how much time should we think about that? Versus a rig maybe that has been sitting on the sidelines for, you know, six, nine, twelve months or even longer.

Roddie Mackenzie: Yeah. Good morning, Greg. Maybe I’ll take that one. Obviously, it’s a pretty wide question because it really depends on where the opportunity is and the customer and where the potential opportunity could be. Right? So for one rig, depending on the regulatory environment, we’re going, and the customer requirements. Three to six months, I suppose. Getting the rig ready for that sort of work. Compared to an online, a cold stack unit that is still probably twelve to eighteen months to get ready for activity. In terms of active rig, obviously, again, it kinda sits with the same requirement that the customer regularly needs. That’s obviously much quicker.

Greg Lewis: Okay. Great. And then just, you know, obviously, one of your competitors made a decision to remove a couple rigs that had been on the sidelines that probably would be, you know, kind of on the higher end spectrum. Just as you look across your fleet, and I apologize if you maybe already answered this, as you look at rigs maybe like the Americas or the champions, how are you thinking about, you know, maybe being aggressive when just removing those while they’re not being competitively bid, they kind of sit out there and everybody looks at them and wonders, you know, maybe someday they come back to work. Thank you.

Jeremy Thigpen: Yeah, Greg. Thank you. Yeah. We did answer that a little bit ago, but we can kind of reiterate it. I would say that we’ve been the most aggressive in the space at retiring assets. Of course, we have the largest fleet, but we continue to look at our fleet and analyze the assets that are currently stacked. We look at the cost to reactivate. We look at the time to reactivate. We look at what kind of day rates we think we could get and what kind of term, and constantly assess the fleet. And we’ll continue to do that as we move through the balance of this year.

Operator: And I’ll take our last question from Josh Jayne with Daniel Energy Partners. Please go ahead.

Josh Jayne: Thanks. Good morning. First one, we’ve talked a lot over the last year about HaloGuard, and Jeremy, it’s something you’ve been big on the last few years, removing people from the rig floor, keeping them safe. You could just use this opportunity to talk about where we go from here with respect to technology and rig safety. Sort of what’s next and is there anything major you see implemented over the next couple of years?

Keelan Adamson: Sure. Thanks for the question. I’ll give it over to Keelan on that one. Yeah. That’s a very interesting question. I think obviously some great success with the deployment of HaloGuard, and we’re looking to get that much wider deployment across our fleets. And we have about a customer. We’ll fund those as we go forward. It’s an ongoing process. We look at where a major accident hazard activities take place and what trying to prevent and help our people have the right information at the right time to make decisions. So I would say any technology development that will assist our teams to do those things and prevent themselves from getting in harm’s way or assisting them in a critical decision moment by moment and day by day. That’s where we’ve been focusing our efforts in technology going forward.

Josh Jayne: And as my follow-up, talked about in the prepared remarks, Gulf of Mexico opportunities over the course of this year sort of and in the next year sort of being flattish. There were some thoughts maybe with the new administration might allow for drilling activity to pick up in the Gulf. Maybe your thoughts on what it would take for activity to grind higher there and just what are the puts and takes that could move things potentially higher in the gulf?

Jeremy Thigpen: Yeah. I think with a favorable administration, that’s obviously good for us. But, you know, these are long-dated projects. They take a while to materialize. A lot of sanction. And so even with favorable regulation, it’s probably gonna take a little bit of time to push projects forward and to increase demand in the Gulf. Certainly not a bad thing. It’s a positive thing. It just may take a little time. So I wouldn’t expect anything in the near term to materially move the needle, but over time, it certainly should be helpful.

Josh Jayne: Thanks. I’ll turn it back.

Operator: Thank you. And I’d like to turn the call over to Alison Johnson for any final or closing remarks.

Alison Johnson: Thank you, Margo. Thank you, everyone, for your participation on today’s call. We look forward to speaking with you again when we report our first quarter 2025 results. Have a good day.

Operator: Thank you. And ladies and gentlemen, that does conclude today’s program. We thank you for your participation. You may disconnect at any time.