Transocean Ltd (Switzerland)

Please stand by, your program is about to begin. If you need audio assistance during today's program, please press star zero. 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, then the one key on your telephone keypad. You may withdraw yourself from the queue by pressing the star two key. Please note today's conference is being recorded. 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. Please go ahead.

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 Sigpen, Chief Executive Officer, Keelan Adamson, President and Chief Operating Officer, Chad Beta, Executive Vice President and Chief Financial Officer, and Roddy McKenzie, 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 Chad'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.

Thank you, Allison, and welcome to our employees, customers, investors and analysts participating on today's call. As disclosed in yesterday's earnings release, for the fourth quarter TransOcean reported an 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 preference 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. As 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' fleets. 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 hookload, 7th Gen Plus assets, and more than $600,000 per day for our 8th 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 KG-1 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 mid-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 -year-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.

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 the Trans-Ocean 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 -day-rate follow-on program earlier than we expected. In June, we commenced operations on the Deepwater Aquila, the latest -short-ton drill ship 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 drill ships, 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 continue 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 Trans Ocean 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 1.5 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 Trans Ocean Enabler. We are actively using industrial robotics on three of our ultra-deepwater drills. 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. The Kinetic Blowout Stopper, a tubular shearing technology that is retrofittable 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 Deep Shadow, 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. 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, including 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 hookload drillships, including workscopes that require the 20K completions capability of our eighth generation drillship. As such, we believe that our assets in the US Gulf will remain in high demand for the foreseeable future. In Latin America, we expect the active rig count to remain relatively stable. In Guiana, demand forecast suggests the five rigs currently on contract will remain working until at least 2028. In Cernam, 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 a commencement window beginning in late 2026 and to maintain the number of rigs that it's 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 multi-year 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. While 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, some of which may have a late 2025 commencement. In Norway, Equinor is out of the tender for multiple rig lines with commencements 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 drill ship later this year. To fulfill these requirements, we'd 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, and 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 drain. We are also encouraged by recent fleet rationalization announcements made by competitors. In our view, both of these are strong indications of healthy industry dynamics. From a macro perspective, our customers are increasingly focused on their traditional oil. This was reinforced earlier this month when Equinor communicated that it expects to grow its production by 10% between 2024 and 2025, while concurrently reducing investment in renewables and other low-carbon technology by $5 billion, half its previous target over that same period. According to RISDAT 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 upcycle. With our active fleet largely contracted for the next 18 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 that revenue to cash. With that, that will now discuss our financial results. Beth.

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 controlling interest of $7 million, or a net loss of 11 cents per 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 11 in our forthcoming annual report for additional information regarding the effects of our convertible debt instruments on net income. During 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 made 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 $435,000. 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 non-critical and service maintenance activities for our active fleet, delayed contract reparation costs for the transition balance, and a favorable resolution of old contingencies. J&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 here. 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 .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 and $65 million of additional services and reimbursable expenses. Please recall that these additional services and customer reimbursables generally carry low single-digit margins. The -over-quarter decrease in contract drilling revenues is primarily caused by lower activity within the active fleet due to mobilization, -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 -over-quarter increase is primarily due to -of-service and contract preparation periods, including those on the Spitsbergen, Invictus, Equinox, and Endurance. We expect G&A expense for the first quarter to fall within a range of approximately $50 to $55 million. This -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 and $100, comprising interest expense and interest income of about $150 million and between $5 and $10 million, respectively. Capital expenditures for the first quarter are forecast to be approximately $59 million, and cash taxes to be paid are expected to be about $13 million. For the full year 2025, we currently forecast contract drilling revenues to be between $3.85 billion and $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 -than-expected activity for the deepwater spuros, the result of the customer changing its well schedule, and unfavorable foreign exchange movement impacting the remeasurement of our local currency contracts in Brazil, which is largely offset in our O&M costs 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 costs to be between $190 million and $200 million. For the full year, we're anticipating net interest expense between $550 and $555 million, comprising interest expense and interest income of about $580 million and between $25 and $30 million, respectively. Cash taxes for the year are forecasted to be between $65 and $70 million. Our projected liquidity at year-end 2025 is currently forecasted to be reflecting our revenue and cost guidance and including our undrawn revolving credit facility and restricted cash of approximately $380 million, most of which is reserved for debt service. This liquidity forecast includes 2025 CapEx expectations of approximately $150 million, of which approximately $70 million is related to customer-required capital upgrades for upcoming projects and capital spares, and approximately $60 million of sustaining capital and dough. 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 Jerry mentioned, we are fully committed to efficiently converting our backlog to revenue and that 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 we can make the most of our savings without compromising our ability to provide safe, reliable, and the most efficient operations possible. This 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 now turn the call back to Jeremy for some concluding comments before we start Q&A.

Thank you, Thad. Before we move to Q&A, I would also like to share the following. April 22nd will mark my 10th 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, Reidy McKenzie to Executive Vice President and Chief Commercial Officer, Brady Long to Executive Vice President and Chief Legal Officer, and last year, Thad Veda to Executive Vice President and Chief Financial Officer. As you will have read in this morning's press release, today I am pleased to announce that we will continue the progression of this succession plan by soon naming Keelan Adamson TransOcean's next President and Chief Executive Officer. Over 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 would like to thank the board and the entire TransOcean team for their trust and support these past 10 years. While at an incredibly challenging time in offshore drilling, I am proud of the fact that we are the only publicly traded offshore drilling company to have survived the downturn without restructuring and are now on a path to materially de-level the balance sheet. I am also proud of the transformation in our fleet and that we continue to introduce innovative technology to the industry, which improves safety and drilling efficiency. But most of all, I am proud of the team and culture we built at TransOcean. And I could not be more excited about transitioning the leadership of this company to Keelan, a man who has spent the past three decades of his life with the company, starting out 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 transition 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 TransOcean team. It is my honor to work alongside of all of you. Allison?

Thanks, Jeremy. Margo, we are now ready to take questions. And as a reminder to the participants, please limit yourself to one initial question and one follow-up question.

Thank you, Ms. Johnson. At this time, if you would like to ask a question, please press the star 1 on your telephone keypads. You may withdraw yourself from the queue at any time by pressing star 2. And once again, that is star 1 to ask a question. We will take our first question from Eddie Kim with Barclays. Please go ahead.

Hey, good morning. Jeremy, I suppose it's only been 10 years, but some years are much longer than others. So congratulations on what all call maybe an effective 20-year career at TransOcean. And well deserved transition away from having to speak to guys like us all the time.

Thanks, Eddie. I appreciate it.

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

Yeah, Eddie, I think I'll take that one. This is Roddy. 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 perhaps not on the table, if you know what I mean. So I think it's possible that you might see some day rates dip down into the threes for the commodity seventh-gen rigs. I don't think you're going to 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 26 or 27 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 going to see that many of these low fixtures. Certainly we haven't seen very many published so far.

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

Yeah, good question, Eddie. We continue to evaluate our fleet. It's not even a quarterly exercise. It's more frequent than that. And of course, take into account how long the rig has 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 going to come back into the market and at what day rate? And so we will continue that process, could or could not lead to changes in the fleet over time. But I would say the three seventh-gen rigs, we still believe are very good. But we're going to be disciplined. If the customer is 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.

Got it. Thank you for that call. I'll turn it back.

Thank you. And our next question comes from Kurt Halleid with Benchmark. Please go ahead.

Hey, good morning. Good morning, Kurt. I don't mean to one-up Eddie on this, but in this business it's probably more like dog year. So 10 years is like 70. I certainly look at Kurt. You have now. Not quite. But hey, congrats. And I know it's been a tough road. And you guys took a solo path on trying to preserve as much shareholder equity as possible. And it looks like you're on the verge of seeing that to fruition. So kudos on that front for sure. Keelan, be careful what you wish for, man. The wolves are howling, man. We're coming after you.

Appreciate that, Kurt. Thanks, Kurt.

Got it. 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 Roddy gave on commodity 7G. So it sounds like we have yet another layer to consider or another tier to consider in the context of 7G drillship. So Roddy, can you once again help us kind of how do you define a commodity 7G drillship and how do we think about the tiers right now?

Yeah, fair enough. Commodity 7G, we kind of consider that the non-high hook load rigs, other rigs with single view. 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, we call them 7G plus, because they basically have the super high hook load. They also typically have larger mud handling capacities and those kind of things as well. So what that means is that the operators for the well designs and certainly the size of the casing runs that 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 10 years is to really invest in 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 1400 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?

Yeah, I appreciate that. And then maybe the one follow up then, Jeremy, you referenced having a number of different discussions for potential projects in 26 and into 2027. Can you give us some sense on how you're kind of navigating those discussions from a pricing standpoint and how much are your customers saying, well, look, if we're going to give you this deal in 26, you've got to give us 2025 pricing. How's that discussion evolving?

Yeah, good question, Kurt. I would say kind of adding on to Roddy's point, we're talking about the high specification rigs and we control most of them, fortunately. And so as we think about the ultra deep water market and the harsh environment market, we are talking to these customers about rigs that we know that they need. And so that kind of frames how we approach the contracting the day rates. So 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 going to price it accordingly.

Got it. All right. Thanks again. Congrats, Keelan, and good luck in the next role, Jeremy. Thank you, Kurt.

Thanks, Kurt.

Our next question comes from Frederick Stena with Clarkson Securities. Please go ahead.

Hey, Jeremy and team, and congratulations again to you, Jeremy and Keelan. I don't know what's longer than dog year, so I'll just leave it at that. But we'd be interested to hear what you think about 2025, 2026, and 2027 in general. You get some good commentary here in your prepared remarks. But for 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 anything in your discussions now, maybe particularly around the work in 2026 and 2027 that gives you confidence that these things will actually materialize in your course or in your current expected timelines. Thank you.

Sure. I'll let Roddy answer, but I'll just start. I think what's been most important to us throughout the years, there are all kinds of concerns 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 26 and 27, and they're multi-year 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 Roddy because he's certainly neck deep in all of these discussions. Yeah, sure.

So, I mean, apart from the macro, which we're not going to touch on too much, 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 going to be significant going forward. Deep water and harsh environment appear to be the most economical places to do that. So thinking about where we are in terms of 25, 26, 27, if we think about where we were this time last year, or let's say this time in 23, looking into 24, we basically had 77 percent utilization on the book. In 24, looking into, sorry, in 23, looking at 24, we stood at 88 percent. Today, looking into 25 for the year, we're looking at 96 percent plus. So if you think about where we are in that perspective, 25 looks extremely healthy, arguably healthier than any of the previous years have looked in the past 10 years. In addition to that, as we think about entering 26, our utilization is about 93 percent entering 26. And 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 90 percentile range for utilization throughout 26. So as I think about 25, we are extremely solid. As I think about 26, we're extremely optimistic that we'll be, everybody's good. And you also mentioned 27. I have to tell you that a lot of the programs that we're working on just now are actually starting in 27, so either starting late 26 or 27. 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 multi-year jobs that start two years from now, I think that's a very healthy position to be in.

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

I'm sorry, so you want the full guidance for 2025? No,

just the liquidity year end guidance. Oh, I'm

sorry. 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 that given the circumstances, we are pursuing some with the amenities.

Thank you very much. That's it from me. Have a good day.

Thank you. Our next question comes from Arun Jirayam with JP Morgan. Please go ahead.

Yeah, good morning. I was wondering if you could 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 recount with some potential for demand increases as you push towards late 2026. You also mentioned that there's kind of a meeting, a scenario meeting going on later this week with the drilling contractors. 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 rig demand in country?

Yeah, I think I'll say that one. Yeah, so Petrobras have been 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, from 23 to 24, there was a rig count grew from 19 to 24 rigs. So that's a healthy increase. Then from 24, going into 24, we went up to 29 rigs. And now, about a second half of 25 are expected to be somewhere between 32 to 33 rigs in Brazil. So that's really positive growth there across the board. We think Petrobras themselves are going to 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 is 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 acknowledgement that they need all of the rigs they currently have under contract. So I'm not going to say that they're going to 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.

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 the 2025 O&M cost guide? Does that contemplate some of the cost efficiency things that are contemplated by rig today?

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 going to refer you to the K. But suffice it to say that's associated with an asbestos settlement that we received earlier.

Okay. Thanks a lot, Jeremy. Best of luck to you. Thank you very much.

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

Hey, thank you and good morning, everybody, and thanks for taking my question. Jeremy, congratulations. It's been fun, Keelan. Good luck. I'm looking forward to talking to you a little bit more. I guess my first question is, everybody's hearing a lot about longer-term, multi-year contracts coming. When we think about those, should we expect six, nine-month lead times for a working rig versus any kind of guidance versus, if it's a hot, warm rig, how much time should we think about that versus a rig maybe that has been sitting on the sidelines for six, nine, 12 months or even longer?

Yeah, 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 a warm rig, depending on the regulatory environment, where it's going and the customer requirements, it's probably going to take three to six months, I suppose, getting a rig ready for that sort of work compared to, in our mind, a closed-stack unit that is still probably 12 to 18 months to get ready for activity. In terms of active rig, obviously, again, it kind of fits with the same requirements as the customer regularly needs, but obviously

much quicker.

Okay, great. And then just obviously one of your competitors made a decision to remove a couple of rigs that have been on the sidelines that probably would be kind of on the higher-end spectrum. Just as you look across your fleet, and I apologize if you maybe already answered this, but as you look at rigs maybe like the Americas or the Champions, how are you thinking about maybe being aggressive and 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.

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, one, we've been the most aggressive in the space at retiring assets. Of course, we had 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 they 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.

And I'll take our last question from Josh Jane with Daniel Energy Partners. Please go ahead.

Thanks. Good morning. First one, we've talked a lot over the last year about Halo Guard, and Jeremy, this is something you've been big on the last few years, removing people from the rig floor, keeping them safe. Maybe 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? 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 Halo Guard, and we're looking to get that much wider deployment across our fleet. And we have opportunities where the customer will fund those as we go forward. And with the ongoing process, we look at where our major accidents, hazards, and activities take place and what we're 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 critical decisions moment by moment and day by day, that's where we've been focusing our efforts in technology going forward.

And as my follow-up talked about in the prepared remarks, Gulf of Mexico opportunities over the course of this year 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?

Yeah, I think with a favorable administration, that's obviously good for us. But these are long-dated projects. They take a while to materialize, a lot of sanction. And so even with favorable regulation, it's probably going to take a little bit of time to push projects forward and to increase demand. And 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.

Thanks. I'll turn it back.

Thank you. And I'd like to turn the call over to Allison Johnson for any final or closing remarks.

Thank you, Margot. And thank you, everyone, for your participation on today's call. We look forward to speaking with you again when we report our first quarter of 2025 results. Have a good day.

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