Transocean Ltd. Aktie

Hello, and welcome, everyone, joining today's Q2 2026 Transocean Earnings Call. [Operator Instructions] Please note this call is being recorded, and we are standing by.

It is now my pleasure to turn the meeting over to David Keddington, Vice President and Treasurer. Please go ahead.

Thank you, Madison, and good morning, everyone. Welcome to Transocean's Second Quarter Earnings Call. Leading today's call will be Transocean's President and Chief Executive Officer, Keelan Adamson; Keelan will be joined by Chief Financial Officer, Thad Vayda; and Chief Commercial Officer, Rodie Mackenzie.

In addition to the comments that will be shared on today's call, we'd like to direct you to our earnings release, fleet status report and associated 8-Ks filed yesterday that contain additional information, all of which is available on Transocean's website at www.deepwater.com. [Operator Instructions] I'd like to remind everyone that today's call will include forward-looking statements, which are subject to risks and uncertainties that could cause actual results to differ materially.

With that, I'll hand the call over to Transocean's CEO, Keelan Adamson.

Good morning, everyone. Thanks for joining us. This is what I will cover today. First, I'll summarize our operational performance. Next, I'll provide some thoughts on the industry and market and why we continue to see strong demand for our assets. And lastly, I will update you on our Valaris acquisition, which we expect to close later this year. Let's get started.

The Transocean team again delivered exceptional operational performance in the second quarter, beating our guidance on both revenue and costs and generating a solid adjusted EBITDA margin of 32%. During the quarter, our fleet uptime was an exceptional 98%, an important driver in our continued focus to deliver superior customer service. At quarter end, net debt approximated $4.3 billion, a significant decrease of nearly $1.7 billion in the past 18 months.

We also strengthened backlog by about $300 million, securing work for several of our assets with near-term availability. This figure excludes the $1 billion in prospective backlog awarded by Equinor and pending approval by its partners, which we expect to receive in Q3. Including this Equinor work, we have added $3.1 billion in contracts this year so far, a very positive indication. With the exception of the KG2, which is currently bid on multiple opportunities, all our active drillships are now on contract or mobilizing to new contracts, improving our coverage to 94% for the remainder of 2026 and 81% for 2027.

In the U.S. Gulf, we recently extended the Deepwater Conqueror with its current customer at the same rate. The Deepwater Proteus, which was briefly idle, is now contracted and has commenced operations. As we had speculated on our Q1 earnings call, in the context of higher commodity prices, this E&P operator has taken advantage of an open period on this high-performing rig to accomplish more work in 2026 than originally planned. Both rigs are expected to continue working in the U.S. Gulf into early 2027. Finally, the Deepwater Skyros has been extended by her customer to perform additional appraisal work on a recently announced discovery in the Ivory Coast. This work allows the rig to move directly to our next contract in Australia with limited off-hire time related to contract preparation and mobilization.

In addition to drillship utilization tightening in 2027, the outlook for high-specification harsh environment assets is very robust well into 2028, supported by the announcement of new fixtures for several of our rigs. In Norway, the Transocean Norge was awarded a 5-well contract by Harbour Energy, adding about $149 million of backlog. The program is expected to commence in the first quarter of 2028. Notably, we entered into an agreement with Equinor for 7 years of work on 3 of our Cat D harsh environment semis, the Transocean Enabler, Transocean Encourage and Transocean Endurance. We are pleased to have the opportunity to strategically relocate the Endurance from Australia to Norway.

For these fixtures, the base day rate, excluding third-party services, will likely exceed $400,000 a day when the contracts commence as a result of escalation provisions. The Transocean Spitsbergen is now the only Transocean harsh environment semi available in Norway before 2029, and she is scheduled to complete her existing contract at the end of 2027.

In Australia, the Transocean Equinox was awarded a 2-well contract with Santos, adding approximately $36 million of backlog. The program should commence in the second quarter of 2027. If all options are exercised, this rig continues with this customer through most of 2027 as well. We are encouraged by the fact that operators are beginning to make awards for multiyear offshore programs. Importantly, they are doing this while remaining disciplined, but with a reprioritization of capital towards offshore and deepwater activities, supporting our constructive outlook.

As rig availability tightens, we expect customers to continue securing rigs for longer durations to ensure they have access to the required rig capacity for their upcoming programs. Once again, this supports our view that we are in a constructive period for the deepwater drilling sector. Operators are also starting to allocate more rig time to exploration and appraisal activities. Rystad Energy recently cited that the number of countries with at least 1 exploration well is on the rise from 35 in 2025 to an estimated 51 by 2028, a 65% increase. This geographic expansion is significant, and we expect customers to grow their portfolios in less developed regions in the coming years.

Our customers select suppliers offering products and services that best align with their value creation objectives. This is where Transocean is distinctly advantaged, offering the optimal combination of differentiated assets, people and processes to deliver exceptional service in the form of highly reliable, efficient operations that consistently exceed customer expectations. We look forward to delivering similar performance across a broader fleet and a customer base when the Valaris transaction is concluded.

I'll now take you through an overview of market opportunities around the world. We saw a high number of contract awards and tendering opportunities in the first half of the year. S&P Petrodata cited almost 100 rig years added year-to-date and operators are evaluating approximately 40 open tenders, representing another 75 to 80 additional rig years. These statistics underpin our expectation for deepwater utilization to approach 100% by the end of 2027, with several rigs relocating from well-established areas to emerging regions to meet incremental rig demand.

Looking first at the U.S. Gulf, long-term demand fundamentals remain constructive with several operators securing capacity for future activity. As demand levels rise globally, we are also seeing strong overseas interest in U.S. units that currently don't have long-term commitments. We believe the number of deepwater rigs in the U.S. will continue to decline in the short term with 2 to 4 units already scheduled or expected to depart the region. This redistribution of global rig supply will satisfy increasing contract requirements in other geographies.

In Brazil, Petrobras recently completed one of its largest contracting cycles in years and continues to evaluate future rig requirements for its major development projects. Supported by IOC demand, the overall rig count in Brazil is expected to remain stable between 30 to 33 rigs over the next 5 years.

Africa is reestablishing itself as a key deepwater region. Operator activity continues to grow across multiple basins, which should drive the rig count from roughly 15 units to at least 20 to 25 units over the next 18 months. Multiyear awards are expected in Ghana, Mozambique, Namibia and Nigeria, fueled by an uptick in recent discoveries and work resulting from successful exploration campaigns over the past few years.

In the mid, with recent contracts for drilling programs starting in 2027 and a number of new discoveries that will call on rig capacity, we expect the future rig count to increase to around 10 to 12 units.

In Southeast Asia and India, we expect domestic exploration and production initiatives to drive a material increase in activity beginning in 2027. Indonesia, for example, could potentially add 10 rig years across 5 rig lines to a region that currently has only 1 rig operating. India is expected to expand activity by up to 4 drillships in 2027, potentially adding around 10 incremental rig years.

In Norway, utilization of high-specification harsh environment semisubmersibles is strong through 2028, supported by recent awards from Var Energi, Equinor and Aker BP. Most operators are already in the market to secure capacity from 2028 onwards, suggesting that future utilization for this region should remain near 100%.

Additionally, work in Canada for Equinor and Cenovus could further tighten harsh environment supply in 2028 onward.

In summary, the combination of sanctioned development programs, increased exploration spending and major discoveries continues to drive a compelling outlook for deepwater and harsh environment offshore drilling.

Now a quick update on the Valaris transaction, which is expected to close in the fourth quarter. We continue to operate as separate companies, but are rapidly advancing integration planning and have recently achieved some key milestones. In June, we received CFIUS approval, satisfying an important U.S. national security clearance condition. Recall that we required regulatory clearance from a total of 7 jurisdictions, and we have previously received clearance from Saudi Arabia and Trinidad and Tobago. In July, we received clearance from Egypt and Australia. And just yesterday, we received clearance from Angola. Currently, we continue to await clearance in 2 countries, Brazil and the U.S., both are progressing as expected. We continue to believe that this combination will benefit customers and shareholders alike.

I'll now hand the call over to Thad for comments on the quarter and our guidance. Thad?

Thanks, Keelan, and good day, everyone. As Keelan highlighted, our second quarter financial results reflect strong operating performance and also exceeded the guidance we provided to you in May. Revenue for the second quarter was $966 million at the upper end of our guidance range and primarily the result of the Deepwater Skyros continuing to work the entire quarter, 1 month longer than we forecast and additional recharge revenue. Contractual cost escalation provisions becoming effective for certain rigs also contributed.

O&M expense was $608 million and capital expenditures were $24 million, both below the low end of our guidance ranges, primarily due to timing and deferrals in maintenance and out-of-service expenditures. At $56 million, G&A exceeded our guidance. However, this figure includes about $11 million of acquisition costs associated with the Valaris transaction. Adjusting for this expense, our result is in line at a quarterly run rate of about $45 million. Our adjusted EBITDA was $312 million, implying margin of about 32%.

Free cash flow of $212 million carried a margin of 22%, which while primarily the product of strong operational performance was complemented by favorable changes in working capital. Recall that last quarter's cash flow was detrimentally affected by the timing of both collections and payments. Our trailing 12-month net debt-to-EBITDA ratio, inclusive of restricted cash primarily for debt repayment, is now 2.8x, a more than 2 turn improvement when contrasted with the 5.2x ratio at the beginning of 2025.

We finished the quarter with about $510 million in unrestricted cash, up sequentially from $330 million. Our total liquidity, inclusive of the undrawn revolving credit facility, was approximately $1.3 billion. We intend to use some of this cash to reduce leverage and continue to simplify the balance sheet. In this regard, we expect to call the remaining $200 million of outstanding principal on our 8% Deepwater Aquila notes at the end of the third quarter after the next reduction in the notes call premium. Including this early retirement, which will save approximately $22 million in interest expense through maturity, we expect to end the year with less than $4.8 billion of gross debt. We also forecast our total liquidity to be $1.25 billion to $1.35 billion.

Over the next 12 months, we will consider refinancing additional secured debt into unsecured instruments, reflecting improved debt capital market conditions and the tight trading levels observed in our debt complex over the last several quarters. As you probably know, we recently earned ratings upgrades from both S&P and Moody's to B- and B2, respectively, and we're on positive outlook for further upgrades pending the closing of the Valaris acquisition.

You'll note in our earnings release that we've increased our 2026 revenue guidance to reflect contract extensions on several rigs that we previously expected to roll off this year as well as the new contract on the Deepwater Proteus. Similar to last quarter, the upper end of our guidance range assumes that existing contracts continue longer than shown in our fleet status report with the low end reflecting certain contractual options not being exercised by our customers.

As a result of this incremental activity, we have also increased our full year cost guidance slightly. G&A guidance of $170 million to $180 million for the full year is unchanged since the last update. However, this range ignores transaction-related costs, which would typically be excluded from adjusted EBITDA. I also note that our full year interest expense guidance of approximately $475 million consists of Q1 and Q2 results that include the rather unpredictable mark-to-market effect of the bifurcated exchange feature and our 2029 exchangeable bonds plus our forecast for second half interest expense, approximately $113 million per quarter, which is unadjusted for any effects of these bonds.

Revisiting a topic we discussed last quarter, we are observing only minor inflationary frictions, mainly in logistics and fuel despite the persistent conflict in the Middle East. Fuel costs remain 20% to 40% above pre-war levels, but I remind you that we are typically only responsible for fuel when our rigs are off-hire, limiting the impact on our costs. Logistics costs have also increased slightly, but are not materially affecting our O&M expenditures. Finally, while we will monitor the effect of the latest view of tariffs, at the present time, we do not anticipate that they will have a meaningful impact on our cost structure.

This concludes my prepared remarks. Keelan?

Before opening the line for questions, let me recap today's highlights. Transocean is executing exceptionally well today across the enterprise. Our people continue to provide our customers with superior service from the industry's high-spec fleet. As a result, we have successfully filled most of our open availability in 2026, allowing us to enhance our full year outlook. Supply disruptions around the world, continued growth in oil and gas CapEx and strong demand for our rigs all reinforce our view that we are in a multiyear upcycle for offshore drilling. The combination of Transocean and Valaris will further enhance our ability to provide superior service to our customers in all key oil and gas producing regions and deliver exceptional value to shareholders.

We'll now open the line for questions.

[Operator Instructions] And we will take our first question from Eddie Kim with Barclays.

So your outlook was very constructive with the expectation to see utilization of high-spec rigs exceeding 90% next year and approaching 100% by the end of next year. It also feels like leading edge day rates are now firmly in the sort of mid-400s as indicated by your recent contract announcements as well as from your peers. Is there any reason to believe that leading edge day rates shouldn't continue to move higher next year just given the tightness in the market? And if not, what would be the potential roadblocks from preventing that from happening?

Eddie, this is Roddie. Yes. So the first thing that we're seeing now is the kind of the filling of white space and that diminished availability. And then the second kind of thing that we're in the mode of here is we're beginning to observe a lot of repositioning of the fleet, as Keelan mentioned in his comments. And that's really going to help get the rigs in the right spots for the long term. And as those 2 things happen, then clearly, we enter like an improved business environment. We also get to lower cost because we've got rigs in the right places, and we're not moving rigs anymore. So I think you're going to see an improved business environment in general over the next 12 to 18 months.

Yes,. Maybe just a quick add for myself. Our customers are obviously very focused on project execution. They want to ensure that they're working with partners that can deliver against those expectations. We're well positioned in that regard with our fleet and the way we perform. And as the market tightens, and we're looking at utilization to stack and see how the fleet, the industry fleet looks over a period of time. And it's a supply and demand balance. It's when the customers want to come for the work. And at the end of the day, we'll see where that takes us when it comes to rigs.

Got it. Great. Speaking of repositioning of rigs, I just want to touch on the Cat D rigs that you signed up with Equinor. So a few years ago, you moved a couple of those Cat D rigs from Norway to Australia. Now they're moving back to Norway. Is this a sign of increasing demand in Norway or softening demand in Australia or maybe a little bit of both?

Yes. I think the movement in the first place was because the Norwegian market had gone soft, no question. So several years ago, that was a reality for us. The beauty of this fleet is they are genuinely attractive all over the world. So it's the nature of running a fleet of this level of specification. Specifically, those rigs that are coming back, this is an indication of how strong the market is in Norway. It's a very attractive market for us for many years, but particularly now as the -- this is kind of the beginning of seeing so many more long-term contracts on offer. So strategically moving the rigs back to long-term contracts is great.

We're very excited about the deal and so is our customer. The headline rate was very important to them, but there was also some pretty significant improvements for us. So we think about these kind of long-term opportunities as making sure they generate as much cash as possible. So contract improvements, escalation provisions and the exclusion of any third-party services in those numbers, plus the fact that it's 7 years of backlog make that an extremely attractive move for us. So it's definitely a case of Norway is offering some very attractive terms and conditions and duration of contract at the moment.

Yes. Maybe just one more piece on that. I mean, obviously, Equinor has objectives to maintain production at current levels right through to 2035 against the backdrop of declining production. So there's a lot of work in Norway, and that's definitely been a pickup since we moved those rigs out of the area. So it really is about Norway and not the rest of the world.

And we'll move next to Greg Lewis with BTIG.

I wanted to talk a little bit more about the opportunity set in Southeast Asia and India. It sounds like we could see multiple rigs start -- multiple floaters start up in that part of the world. I mean, I guess my question is around really, clearly, there's a bifurcation between sixth and seventh gen rigs. Traditionally, India and parts of Southeast Asia have been sixth gen. It looks like the sixth gen market is about to get pretty tight pretty quickly as those go higher. So I guess what I'm wondering is, could we start to see sixth-gen, seventh-gen pricing converge.

That's a very interesting question. So you're probably well aware, Greg, that our strategy has been to make sure that we fully utilize those sixth-gen assets. Of course, the fixtures that we made in Brazil earlier this year were a very solid step on that track. Yes, traditionally, Southeast Asia has indeed consumed a lot of sixth-gen rigs. But I think at this stage in the game, it doesn't really matter between sixth and seventh gen where they go. I think they're capable of going anywhere in the world, and we've performed well on all of these prospects.

So to your point about Southeast Asia, I mean, there's a lot of stuff going on. Indonesia has multiple tenders; Malaysia, Brunei to mention just a few. And of course, India being a very big opportunity here. ONGC just opened their multi-rig tender and there aren't that many rigs on offer. So I think it's already tightening up. I don't think you see a huge difference in those day rates. Certainly, from our point of view, we're very keen to perhaps be slightly countercyclical here that it would be great in this upturn that we're in to have some of the higher specification rigs available to us to take advantage of that later in the game.

As you know, traditionally, a lot of high-spec rigs are the first to get booked up. But we're trying to balance that out a little bit because we have a very, very capable sixth-gen fleet. They're doing a fantastic job for the customers, and they're very fit for purpose. So to your point about Southeast Asia, it really is blowing up in terms of contracting, and we're very pleased if we have the opportunity to place some more sixth-gen rigs there.

Okay. Great. And then realizing we're not disclosing rates on -- there's like price or a price option. I guess what my question is around, as we think about priced options and whether we're -- let's assume we're not disclosing those rates, which is why we -- which is why I asked the question. I mean, I guess at a minimum, when we think about priced options, should we assume that they're flattish or more likely up? Or could we actually be seeing priced options in out years at lower rates?

Yes. I wouldn't necessarily say they're flattish. I can't really say a lot about that for obvious reasons. But I would think about it in terms of the provisions and what have you in the contracts mean that those options are going to be very satisfactory to us in the long run. I'll just kind of leave it at that.

And we will move next to Keith Beckman with Pickering Energy Partners.

I just kind of wanted to ask around -- and you guys gave very helpful commentary kind of around the globe, but I wanted to ask maybe more particularly around the Gulf into next year. You guys did a really good job at winning some awards here this year to fill up capacity. Some of that stuff rolling off in early '27. I think you guys expect the Gulf to be down a little bit from commentary very earlier into next year. Where do you think those rigs potentially land? Do you think they move to West Africa or potentially some of yours in particular, potentially get extended? Just trying to get a sense of maybe how you're thinking about your fleet and then maybe more macro-wise as well.

Yes. So I think to your point there, we're very pleased to extend a couple of rigs in the Gulf this quarter. Again, a lot of those things are kind of in the pipeline for some time. We do think that the fleet that's in the Gulf is typically very, very attractive in any basin. So what we're seeing is that as long as those rigs are performing well, they've got solid opportunities elsewhere. So if we get towards the end of these programs, then it's a relatively easy pivot to move them on to the next location. So that's kind of the point that Keelan was making about the redistribution of the fleet is that we've already seen that.

So even with a couple of our rigs, we've moved these high-spec rigs to other jurisdictions, and we expect them to do real well there as well. Certainly, there's the potential for more of that to happen in the Gulf as a few of them are rolling off. Although I did see, I think, just this week, there was another -- one of the Seadrill rigs was extended to stay here, which is good. But I think you see a little shuffling of the deck there. But I don't think we are going to experience much white space on that at all. So we're quite happy to see that happen.

Yes, Keith, I mean, it's we've got rigs moving out. We've got rigs moving in. I mean the long-term prospects for the U.S. Gulf are very strong, obviously, with Paleogene and many of the prospects that are out there. So it will always be a good basin. I think it's just a bit of a timing thing more than anything else. West Africa is picking up and Asia and India and that area is picking up as well. And so there's only -- these assets that have availability will move to satisfy those requirements. So as we said, it's a little balancing. But long term, it's still a very productive area to be very constructive area to be in the U.S. Gulf.

Awesome. I really appreciate that. And then my follow-up question is just, are you guys seeing any change in operator behavior kind of assuming the stronger 2027 recovery that we agree with here? Are they trying to lock in rigs for longer term potentially what may be better day rates? And then the follow-up to that is, do you think energy security is still kind of a topic of conversation with a lot of these NOCs here? And has that potentially pushed projects up the pipeline from what you guys have seen at all or maybe a little bit more urgency there?

Yes, Keith, I'll take that. you're absolutely spot on. What we're seeing right now is somewhat typical of what we see at the start of these up cycles and where our NOCs are typically the first to move. They typically have the most term to offer. They can secure good deals on a number of assets. Petrobras obviously, is a great example of that. Equinor, the deal we just did with them, E&I are moving as well. And so what you start to see is the NOCs moving at the beginning and taking volume and ensuring that they get a competitive deal for that. And then the majors obviously are really disciplined, and they're going to manage their portfolios as they best see fit and address their priorities accordingly. And I think we're seeing that play out at this point in time. It's exactly as you indicate. Rody, do you have anything you want to add?

Yes. I would just add, you mentioned there about the energy security. And that definitely plays into a kind of a shift towards domestic production. But I want to make it really clear. So far, we've had a fabulous year in terms of contracting over $3 billion worth of rig time already, but none of that was predicated on elevated oil prices. All of those fixtures are predicated on breakevens that are calculated in the $30, $40 range. Nobody -- none of the operators today are executing on a higher oil price. They are very disciplined in that regard.

So I think what you're seeing is the shift of capital towards deepwater is in a disciplined manner. So that speaks really well for the long term because it means that the decisions that are being made today that are tightening up our market are decisions that will last through ups and downs of the oil price. So I think it's a really important distinction to make is that energy security is definitely a factor. But all of the stuff that we're seeing, and we're expecting that there could be up to 150 rig years awarded across the fleet this year. That's a very substantial number, bigger than it's been in a number of years, but it's not predicated on short-term oil prices. This is predicated on a long-term view of very conservative, disciplined investing by our customers, which we welcome.

And we'll move next to Fredrik Stene with Clarksons Securities.

Congratulations first and foremost on a strong quarter and super happy to hear that the work on the Valaris is progressing well as well. I wanted to touch a bit on specific rigs. You have already kind of talked a bit about the goal for the Conqueror and Proteus, which you seem very optimistic about. But with the backdrop you gave on Norway in particular, maybe on the strength that we're seeing there on the harsh environment market, how do you, for example, tend to go about the Spitsbergen, which is the rig that you have available first? Do you think the strength there is enough to see that rig potentially extended with the contract award this year? Or are you trying to play it cool and potentially get more of an upside if the market sees even higher?

I think we're always trying to play it cool. But realistically about the Spitsbergen, yes, great rig. doing a fabulous job for Equinor. -- love working for Equinor there. It's always our preference to keep the rigs exactly where they are and continue on with the customers with. We're in constant dialogue with Equinor on a number of different things, as you saw our recent announcement. So yes, definitely our preference to keep it with Equinor and continue that relationship has gone really well so far.

And also wanted to touch upon the Mykonos, which we're keeping now with a non-Petrobras company in Brazil. Given your outlook on that region and country maybe in particular, do you think it's possible that that will be kept in Brazil as well? Or is that one of those rigs that you might move yourself to potentially satisfy demand in West Africa, Southeast Asia? Just interested to hear any color on lead and work that you might be looking at for that particular unit.

Yes. Good question. So Brazil has gone through a massive contracting effort in the last year, including the Mykonos with non-Petrobras operator. Yes, there's a distinct possibility that continues there. But it's also very interesting that class of rig is ideally suited to a lot of the work that's come up in Southeast Asia. And India, for example, she would be a great candidate for India for some of the tenders that are coming up. Again, it's always our preference to keep the rigs where they are, but we'll just have to wait and see how that plays out. But I don't think she will have any shortage of opportunities elsewhere if for whatever reason, Brazil doesn't follow through on that. But I do think there's a pretty high desire to keep it in Brazil.

And maybe just one last quick one for Thad, if possible. You guys have been working diligently to be as cost efficient as you can lately. And obviously, in the second quarter, you did very well on the cost side. I was wondering if you had any updated commentary on how that cost work is progressing and now I'm talking about Transocean stand-alone, first and foremost. And maybe second, if you have during the integration planning, identified any more cost savings opportunities when the deal closes?

So second question first, I got no additional comments or guidance with respect to the combination. We are moving ahead with all of the integration. And certainly, we're finding new opportunities that we didn't think existed prior to the process. But as we get closer to consummation of that transaction, we'll provide additional information.

With respect to Transocean on a stand-alone basis, all of the cost savings initiatives have been implemented. We are seeing the results in our liquidity and it's facilitating additional reduction in debt going forward. We are, as I said, sort of on the road to about $200 million, $250 million in aggregate between 2026 and 2027. It is, as you would expect, sort of a constant battle to make sure that we are saving everywhere that we possibly can, but we have been, I think, pretty successful in achieving our goals. Now as we move towards the end of 2027, since some of the cost savings are associated with deferrals and things of that nature, we're going to have to find other areas to economize on just to make sure that we can maintain the cost structure that we have today.

And we'll move next to Noel Parks of Tuohy Brothers.

I just wonder if you could maybe talk a little bit more about what you're seeing. You noting expected tender activity in Ghana, Mozambique, Namibia and Nigeria. And I guess, similar to some of the other regional questions you've been discussing, what do you think Transocean and sort of the industries are going to sort of meet the needs of projects there within sort of the other competing regions?

Yes. Quite happy to fill in some of the details on that. Look, what I'd say is -- so Africa in general is actually the largest growth region that we have in our chart today. So as we go through the list of opportunities, we're looking at 12-plus multiyear developments that are going to require rigs. There's at least 6 long-term tenders that are ongoing right now. And I won't go through all the details, but I mean, you're basically looking at every country that you mentioned plus a couple of others have something going on in terms of incremental rig demand. So it's very encouraging to see because a lot of the stuff is the long-term stuff. So when we think about where we are overall, we're definitely on average, greater than a year for each one of the prospects that we're looking at. And in West Africa, it's kind of even more so. So I think some of the shorter stuff is maybe like 1 year long, but we're looking at least a half dozen opportunities that are 2 or more years, some as long as 3 and 4 years.

So just overall, yes, there's already been some awards in Nigeria. There's more to come. There's potentially 3, 4 rigs to add there. There's a lot going on in Mozambique. There's at least a couple or 3 potential opportunities there. Then you go into the details of some of the other places, it's changing certainly on a monthly basis, if not a weekly basis. So yes, real strong in West Africa just now. And I do think when we were describing the whole redistribution of the fleet, there's a distinct possibility that some of the idle rigs today will end up over there. So all good on the West Africa front.

Terrific. And that statistic you mentioned 35 countries looking to do some sort of exploration or appraisal rising to 51. I just wonder if you could kind of maybe characterize the plays that are the motivation behind many of these. I'm just wondering roughly what proportion you would guess are essentially just picking up on past discoveries that didn't get funded for further exploration versus maybe new concepts that have been arrived at through better 3D seismic or reprocessing and so forth.

Yes. So look, there's been a relatively strong period of exploration success over the last 12 months, which is good. But don't forget, we've kind of gone through a relatively down period in our market. And of course, during that time, you had many of the operators have great prospects in the wings. So there's kind of like prospects on the shelf, so to speak. And as the outlook overall for global oil and gas consumption has improved, that's just allowed a lot of those things to come to the fore. So I would describe it as genuinely a mixed bag.

There's probably several of these developments, Namibia springs to mind, the number of discoveries made a few years ago and now there's developments ongoing there. So whether that's something that attracts some of our rigs or perhaps more likely some of our competitors' rigs move to Namibia, there's also a number of exploration successes elsewhere. Most recently, we just talked about the Ivory Coast, for example. So as we went through kind of all those countries there, I think you could probably say there has been a new discovery in one of those countries, almost every single one, if not in the last 12 months, certainly in the previous up cycle that's now coming to the market. So I'd say you got a pretty good split on that.

And we'll take our next question from Jeff LeBlanc with TPH Research.

I wanted to see if you could talk about drilling efficiency gains and how you expect continued efficiency gains could impact future floater demand.

Jeff, I think your question is around drilling efficiency and how that impacts future growth. Yes. I would simply say this is probably the single most focus area of the drilling community and the customers with respect to delivering against these project execution imperatives that our customers have, right? So in a world of a disciplined capital allocation, having confidence in our ability to deliver against those projects reliably and none of them are easy. They're all challenging. There is a real push to ensure that we can drive more and more efficiency from the industry fleet.

I think the areas of automation are developing by the day. We, for one, are installing automation across our fleet on the drill floors. It drives greater consistency and performance efficiency and a lot more predictability and ensures that not only are we drilling efficiently but our people are doing what they need to do operationally and keeping an eye on all aspects of the operation as opposed to just operating equipment. I think it's a really great development for our industry. It's going to drive an awful lot more efficiency. And of course, the more efficient we are, the more capital that will be allocated against the business. And we're finding that on the back of our performance, we're getting more work. We're not drilling ourselves out of work. We're finding that that is enabling more opportunities. And I think this is an important point in time as we move into this constructive up cycle that we're able to deliver that level of performance across a wide fleet.

It's not based on an individual rig performance basis. It's based on a standard operating procedure. It's based on using tools like automation and technology that really drive a consistent delivery. We want to be predictable. We want to be a high-performing, predictable service to our customers. And I think our customers appreciate that, and it's very helpful in the investment -- thesis and investment decisions that our major customers go through to determine whether to unlock some capital for these developments and then free up capital importantly for reserve replacement objectives in exploration and appraisal. So I think it's a really important point in time, and we embrace it fully, and we're seeing the benefits of it.

Yes. I'll just add on top of that to say S&P recently said that they expect deepwater production to increase by about 60% from '24 levels into 2030, which is great, but that's driven exactly by the stuff that Keelan is describing. So our ability to execute on this stuff in a much more efficient manner, a, produces more from these basins, but it absolutely drives activity. We unlock stuff because we are more efficient than that. So we're all violently aligned on that with our customers and the other operators of drilling rigs to deliver that best possible value deepwater.

At this time, this concludes our question-and-answer session. I will now turn the meeting back to David Keddington for any additional or closing remarks.

All right. Thanks. We'd like to thank everyone who participated in our earnings call today, and we invite you to follow up with us for any additional inquiries. With that, we'll close the call.

This concludes today's meeting. We appreciate your time and participation. You may now disconnect. Thank you.

Good morning, everyone. Welcome to today's Transocean First Quarter 2026 Earnings Conference Call. [Operator Instructions]

Please note today's call is being recorded, and I will be standing by if you should need any assistance.

It is now my pleasure to turn the meeting over to Mr. David Keddington, Vice President and Treasurer. Mr. Keddington, please go ahead.

Thank you, Bo, and good morning, everyone. Welcome to Transocean's first quarter earnings call. Leading today's call will be Transocean's President and Chief Executive Officer, Keelan Adamson. Keelan will be joined by other members of Transocean's executive management team, Chief Financial Officer, Thad Vayda; and Chief Commercial Officer, Roddy McKenzie.

In addition to the comments that will be shared on today's call, we'd like to direct you to our earnings release, fleet status report and 8-Ks filed yesterday that contain additional information, all of which is available on Transocean's website at www.deepwater.com.

Following our prepared comments, we will open the conference line for questions. Please limit your inquiries to one question and one follow-up as this will allow for more participants.

Before we begin, I'd like to remind everyone that today's call will include forward-looking statements, which are subject to risks and uncertainties that could cause actual results to differ materially.

With that, I'll hand it over to Transocean's CEO, Keelan Adamson.

Good morning, and welcome to our first quarter conference call. Today, we will address several topics. First, an overview of our accomplishments in the first quarter.

Next, I will provide some market updates, including a few thoughts on the impact of events in the Middle East on our business. Then, I will update you on the pending acquisition of Valaris. And finally, Thad will make a few comments on our financial results and guidance.

First, the quarter. Operational performance was very strong with an uptime of 98%. Adjusted EBITDA was $440 million, implying a solid margin of over 40%. Our average daily revenue in the period was $476,000, the highest in over a decade.

These results were accomplished while working safely and efficiently with 0 life-changing injuries or operational integrity events. This exceptional performance is due to our team's dedication to providing best-in-class service to our customers.

We are committed to eliminating costs from our business and are on track to deliver versus a 2024 baseline savings of $250 million in aggregate through 2026. As we have discussed, these savings are associated with continuous improvements in how we run our rig operations, removing idle and stacked assets from the fleet, more efficient maintenance spending and a reduction in shore-based support infrastructure.

Since our February call, we have announced approximately $1.6 billion of backlog, including new contracts and contract extensions on 5 rigs in Norway, Brazil and the Eastern Mediterranean, increasing our backlog to over $7 billion, as reflected in our fleet status report published yesterday.

Nearly 1/3 of this backlog increase is related to a 3-year contract on the Transocean Barents with Var Energi in Norway at a rate of $450,000 per day. The program is expected to start in mid-2027 and includes options that if fully exercised, could keep the Barents working in Norway into 2034. We are very excited to be commencing a new long-term strategic relationship with Var Energi.

In Brazil, 3 of our ultra-deepwater ships, 2 sixth-gen and 1 seventh-gen were awarded contract extensions by Petrobras. The sixth generation drillships, the Deepwater Orion and Deepwater Corcovado were each awarded 3-year contract extensions, collectively contributing about $845 million in incremental backlog, committing the rigs into 2030.

The seventh generation drillship Deepwater Aquila was awarded a 1-year extension, contributing about $160 million in incremental backlog, committing the rig through mid-2028.

Lastly, in the Eastern Med, the Deepwater Asgard was awarded a 5-well contract contributing about $158 million in backlog and committing the rig through the end of 2027. Including these announcements, our firm full year 2026 and 2027 contract coverage is currently 86% and 73%, respectively, providing a strong base for future cash flow and a line of sight to continued debt and interest expense reduction.

On a related note and as previously disclosed, we retired the balance of the Deepwater Titan notes, reducing debt by $358 million in excess of our scheduled maturities. This is consistent with our commitment to delever, simplify the balance sheet and reduce interest expense as quickly as possible.

Moving to our outlook for the business. We continue to see improving demand for our rigs and services. While not directly affecting Transocean's operations, recent events in the Middle East have further exposed the vulnerability of the global energy supply chain and at an absolute minimum, have amplified the energy security imperative around the globe.

This reinforces our thesis that offshore exploration and development will comprise an essential component of oil and natural gas supply for the foreseeable future.

I will now provide a summary of developing opportunities around the world. The number of contract awards and tendering opportunities during the quarter remain high, with visibility into multiyear programs improving meaningfully.

So far in 2026, S&P Petrodata has cited 80 rig years added across 61 newly signed floater fixtures. Assuming opportunities materialize as expected, we now see deepwater utilization approaching nearly 100% by the end of 2027, setting the stage for a significantly improved business environment.

Looking first at the U.S. Gulf, long-term demand remains stable, supported by recent lease awards. In the near term, any softness may result in some high-specification assets incurring idle time before securing new work.

However, with elevated crude pricing, we would not be surprised if certain customers operating in this market chose to take advantage of this short-term opportunity.

In Brazil, following the recent blend and extend negotiations, Petrobras awarded approximately 38 rig years, securing its strategic capacity for the coming years. We expect Petrobras to return to the market later this year to secure additional capacity for the second half of 2027 onward to satisfy additional exploration and production activity.

Supported by incremental IOC demand, the overall rig count in Brazil is expected to remain stable between 30 to 33 rigs over the next 5 years at least.

As we highlighted last quarter, Africa is finally showing measurable and more consistent growth. We expect the regional count to increase from roughly 15 units today to at least 20 over the next 1 to 2 years.

In Mozambique, 1 multiyear program has already been awarded by Eni with 2 additional awards expected this year from Exxon and Total. In Nigeria, Shell, Chevron and Exxon have recently awarded their development programs, while Total has just issued a new tender for a multi-well program starting in the second half of 2026.

In Namibia, we continue to expect more activity as several majors, including most recently BP, evaluate opportunities in the country. And in the Ivory Coast, Eni has issued a 1-rig tender for a 3-year program beginning in early 2027.

In the Med, our recent fixture for the Deepwater Asgard satisfies a portion of increasing demand in the region with several other awards expected soon for drilling programs starting in 2027. Rig count in the region is expected to stabilize at around 7 units going forward.

Turning now to Southeast Asia and India. We expect domestic production and exploration initiatives to drive a material increase in activity beginning in 2027. In Indonesia, programs are currently being tendered, adding potentially 10 rig years across 5 rig lines to a market that currently only has 1 rig operating.

As previously discussed on our last call, in India, ONGC and Oil India are expected to substantially expand the regional fleet by up to 4 drillships and 2 semisubmersibles in 2027, potentially adding 20 incremental rig years.

In Norway, utilization of high-specification harsh environment semisubmersibles remains robust through 2028, supported by recent awards from Var Energi, Equinor and Aker BP. Most operators are already in the market to secure capacity from 2028 onwards, suggesting that utilization for these units should remain near 100% in the coming years.

In summary, both the development of known reserves and the call for new exploration continue to build strong momentum as evidenced by the recent increase in award announcements and numerous ongoing tenders for multiyear opportunities, our fleet is ideally positioned to capture value in this improving business environment.

Finally, regarding the acquisition of Valaris, we are required to seek antitrust approval in 7 countries and we have received that approval in Saudi Arabia and Trinidad and Tobago. As of yesterday, we received a second request for additional information from the U.S. Department of Justice as a continuation of their antitrust review.

Further, we continue to work with antitrust agencies for approval in Angola, Australia, Brazil and Egypt. We remain confident that the outcome of the global regulatory review will be favorable and that we are on track to close the transaction in the second half of 2026.

We remain excited about the capabilities and potential of the combined company. Until the transaction closes, we will continue to conduct business as separate companies. However, we have materially progressed our integration and business continuity planning.

We remain confident in our ability to achieve over $200 million in cost synergies, incremental to our stand-alone cost reduction initiatives of approximately $250 million that I mentioned earlier.

On a pro forma basis, Transocean is expected to have about $12 billion in backlog. The combined company's robust cash flow will continue to accelerate the reduction of gross debt, resulting in leverage of approximately 1.5x EBITDA within about 24 months of closing.

The acquisition of Valaris is fundamentally aligned with Transocean's strategic priorities. We will be an industry leader with the scale, scope and geographic reach that allows us to effectively support our customers in the cost-effective delivery of hydrocarbons from the world's offshore reserves.

I will now hand the call over to Thad to provide some brief comments on our financial performance and guidance. Thad?

Thank you, Keelan, and good day to everyone. Most of the information you should need to update your models is provided in the materials we published last night, so I will only make a few remarks this morning.

Our performance during the first 3 months of the year exceeded our forecast and the guidance range we provided to you in February. As Keelan pointed out, contract drilling revenues of $1.08 billion reflected outstanding operations in the quarter, including revenue efficiency in excess of 97% versus our guidance of 96.5%. This is worth about $9 million in the quarter.

Also included in the top line is $18 million of revenue recognized due to the early contract conclusion of the Deepwater Proteus. Additionally, higher recharge revenue and favorable foreign exchange effects, which are largely offset in our O&M costs totaled about $18 million in the period.

Operating and maintenance and G&A expense were $606 million and $49 million, respectively. Adjusted EBITDA of $440 million translated into a margin of over 40% and cash flow from operations was $164 million.

Free cash flow of $136 million reflects operating cash flow net of $28 million of capital expenditures in the period. Lower sequential free cash flow in the first quarter of the year is not unusual for us and is typically related to, among other items, the timing of collections and higher payroll obligations.

We closed the quarter with an unrestricted cash balance of $330 million, which has since increased to about $495 million as of May 4th.

Our earnings report includes guidance for the second quarter and only slightly updated guidance for the full year for Transocean on a stand-alone basis. There are only 2 changes to note in our annual guidance.

First, the upper end of our full year revenue range has been reduced by $50 million to $3.9 billion, primarily to reflect the passage of time. While there are a number of negotiations ongoing, this includes the Cape. Given necessary lead times to plan and commence work, there is a somewhat lower probability of filling certain gaps in our 2026 contract schedule.

As we discussed in February, our revenue guidance is otherwise based primarily on firm contracts with the upper range reflecting the possibility of new contracts commencing slightly ahead of schedule and the extension of existing contracts. The lower end of our revenue range assumes that no additional fixtures of the 2026 commencement dates are secured.

Second, we have increased our capital expenditure expectations for the year by $20 million due to certain customer requirements that were not anticipated in our initial guidance. Approximately half of this increase is related to environmental upgrades to exhaust systems on a rig operating in Norway.

We will substantially recover the cost of this upgrade by the end of the year through specific contract provisions.

As we highlighted in February, our cost guidance for the full year reflects our ongoing cost efficiency initiatives and also contemplates slightly lower levels of activity in 2026 versus 2025 with idle time assumed on certain rigs with contracts ending this year.

This includes the KG2, Deepwater Proteus and Deepwater Skyros as well as costs associated with the mobilization and preparation of the Deepwater Asgard and Transocean Barents for contracts we have recently announced.

As you might assume, given the dynamic nature of the market, we may incur incremental expense to position and prepare idle rigs to pursue work. These new opportunities, likely commencing primarily in 2027 will increase utilization, revenue and cash flow. To the extent that this occurs, we will provide updated cost guidance.

With respect to inflationary trends resulting from events in the Middle East, we are just now beginning to observe some small effects on our costs, mostly as it relates to scheduled projects rather than on our active rates. Recall that we have escalation provisions in certain contracts that permit some cost recovery.

While prices for fuel have nearly doubled, our customers are generally responsible for providing it, which means we are only affected by this increase for our idle rigs for which fuel currently amounts to less than 1% of O&M expense.

Ocean and air freight costs are also up as much as 30% and 50%, respectively, but logistics in general comprise only 2% to 3% of our annual O&M costs. We do expect that over time, higher energy and logistics costs will influence the pricing of goods and services we procure, but for now this does not warrant modification of our guidance.

As Keelan noted, in March, we opportunistically retired the 8.375% notes due 2028 that were secured by the Deepwater Titan, reducing debt by $358 million and saving nearly $40 million in interest expense. Right now we have about $5.1 billion of debt principal remaining.

At the end of 2024, we were forecasting a principal balance of $6 billion of debt remaining at the end of the first quarter of 2026, meaning we are currently over $900 million ahead of schedule in our efforts to reduce debt and strengthen the balance sheet.

We ended the quarter with a trailing 12-month net debt to adjusted EBITDA ratio of approximately 3.1x and we expect to retire at least $750 million in total debt in 2026, ending the year with a principal balance of around $4.9 billion, excluding our capital lease obligation.

Based upon the consensus EBITDA, this would imply a ratio of about 3.3x at the end of this year. We will continue to evaluate opportunities to accelerate debt repayment and reduce interest expense.

We closed the first quarter with total liquidity of approximately $1.1 billion, adjusting for the effect of the Deepwater Titan note retirement. This includes unrestricted cash and cash equivalents of $330 million, restricted cash of $285 million after the reduction of $87 million associated with the debt service reserve for the notes and $510 million of capacity from our undrawn credit facility.

On a stand-alone basis and absent any additional early retirement of debt, we expect to end the year with between $1.25 billion and $1.35 billion of total liquidity, inclusive of our undrawn credit facility. This range is consistent with our previous liquidity guidance when adjusted for the early repayment of the Deepwater Titan notes.

This concludes my prepared remarks. Keelan, do you have any final thoughts?

Thanks, Thad. To conclude, we will continue to focus intently on achieving our strategic priorities, including optimizing the value of our differentiated asset portfolio in this improving market to maximize free cash flow, reduce total debt and interest expense and simplify our balance sheet to create a sustainable and resilient capital structure.

This is our 100th year in business and we are striving to be the most attractive offshore drilling investment for those desiring exposure to increasingly favorable energy and industry dynamics.

We'll now open the line for questions.

[Operator Instructions] We'll go first this morning to Eddie Kim with Barclays.

I wanted to start off with a bigger picture question. The world has clearly changed since your last earnings call in mid-February. It does feel like the market is tightening based on just the number of fixtures announced year-to-date.

You also raised your utilization expectation next year to approach 100% versus 90% previously. If I go back 4, 5 years ago, obviously, 2020 and 2021 were extremely challenging years for the market, but things started to turn in a big way in '22 and '23.

And by mid-2023, leading-edge rates were sort of in the mid-400s with an expectation that pricing could exceed $500,000 a day by the end of that year, by the end of '23. Unfortunately, we ran into some industry white space, which sort of halted that trajectory.

But nonetheless, 2023 was a very strong market environment. Based on how you see things now and just the customer conversations you're having, do you think the market environment next year in '27 could be as good, if not better, than it was in 2023?

I think as you look at the business and the current situation in the world, we're not seeing an impact per se of what's actually happening today. What we're actually seeing is the development of a market that we were forecasting prior to any of the recent conflict.

So I think if you recall, we've been -- I think, as an industry, we've been talking about improved tendering opportunities, growth in the market, a real concern about hydrocarbon demand and probably more so about hydrocarbon supply and many of our customers starting to lean into the exploration activity that everybody needs to progress.

And I think we're seeing the results of that in the number of awards that have been announced in the first quarter this year or year-to-date. The term of those awards is nearly doubled.

And we're starting to see what we expected to happen with respect to rig utilization into 2027. I think we said we expected 90% utilization as we went into 2027 and then we were going to improve from there. So the activity and the forecast is being realized from our perspective.

Obviously, the continual concern now with energy security, and it's a real topic of conversation around the nations in the world, is only amplifying the need for further investment in the offshore space and particularly in deepwater. And so I think the utilization is building.

The backlog is building. The rate progression will obviously reflect the supply and demand dynamics that exist in the industry and the visibility for the future work.

Rod, would you like to add anything to that?

Yes. Probably just pick up on one of the things that you mentioned there, Eddie, was in the previous run-up there, we kind of stalled out, as you said, we posted a few rates above 500 and what have you, but the context is really important.

So what happened at that time as we hit a little bit of an economic bump globally, that also coincided with a moment in time where many of the majors were focused on capital discipline. And part of that was -- part of their push for M&A on their side. So you kind of had this white space created by that capital discipline.

I think the difference here that we're talking about now is at that time, there was still a heavy skew towards shale and what have you. But now everything is pointing towards offshore CapEx is now going to be a much larger chunk of the pie.

We're talking about something that went from about 13% of total CapEx to nearly 30% by 2028. So basically, CapEx spend in offshore and deepwater is expected to approach $100 billion annually by 2030. So if we do it in that context, then I think the upside for us is very significant.

So there's not as many M&A opportunities available on the operator side. And to Keelan's point, everybody is now looking at exploration. So as we look at basins around the world that we talked about before, a lot of those that were previously explored and had discoveries are now shifting to development. And on top of that, we're adding a lot of exploration work.

Got it. That's very helpful color. And that's a great point on the kind of changing mindset and attitude of the majors. That's great. My follow-up is just on the Petrobras blend and extends.

You extended both of the 6G rigs, the Orion and Corcovado for 3 years, but the 7G rig, the Aquila was only extended for 1 year. Just curious if there was some intentionality behind that decision on your end to not lock in your high-spec asset on a multiyear contract in a rising dayrate environment?

Okay. Yes, I'll take that one. Yes. So as we've always kind of alluded to, it's very important to us that we get appropriate value for our assets. And the sixth-gens are workhorses of the fleet, do a fantastic job and Petrobras were very keen to extend the rigs.

I think it's a really interesting moment in time because Petrobras is traditionally the barometer of where things are going to go. So when you see those guys go along, that's a pretty good sign for us.

So basically, in that instance, if you notice how the delta between the average dayrates is pretty significant between the sixth and seventh gen there. So we're talking somewhere in the region of $50,000 to $70,000. So that's a fairly big deal.

And to your point, in our view, we think there's a significant tightening of the market, not projected. It's already here. So as we think about all these fixtures, we're talking about fixtures. If you think just a few quarters back, we were talking about things that were going to happen.

So now the scoreboard has got fixtures on it and they're prolific. And as Keelan pointed out earlier, we're 1/3 of the way through the year and we've already significantly eclipsed what happened in all of 2025. So 2026 is shaping up to be something potentially as big as 150 rig years awarded.

And that's before we consider direct negotiations that are not necessarily on the market. So you're kind of spot on in that strategy, but we've always kind of taken the portfolio view on the fleet, very keen to see those sixth-gens go along and give us a bit of optionality on the higher spec units as we move forward.

We go next now to Fredrik Stene with Clarksons Securities.

I wanted to -- or first, happy to see that the market is looking better. And I think according to my own numbers here, we're having the highest kind of market-wide visibility contracting-wise that even above 2023 levels.

So something is happening and I'm happy to see that. But today, my question relates more to the M&A process, the acquisition of Valaris. And you gave some color on that in your prepared remarks, Q1, but I was hoping that you could potentially elaborate a bit more on what this second request actually means.

And I guess my question and potential question from investors as well is implications on potential deal risk. You still said confidence in the second half closing. But is that time line potentially a bit delayed now compared to what was the case before?

Or how does this -- or what does this potentially mean for remedy sales, et cetera? And I'm not trying to kind of be a devil's advocate, just trying to get clarity on what this actually means, even though it seems like most deals that have received second request ends up going through anyway. So any color you could give would be super helpful and appreciated.

Yes. Sure, Fredrik. No, I think we remain confident that the DOJ will approve the transaction. The second request is part of the process. And if you think about the deal of this nature, it's simply a case of needing a little bit more time to really understand the competitive dynamics post-close. So we've been heavily engaged with the DOJ.

We've been working very productively with them answering their questions and helping them understand the nature of our business, the specific nature of our business in the U.S. Gulf and the market worldwide. And those conversations have been going very well.

So no, there's no read-through. I would suggest to you that when we declared what time line we believe this transaction would close in, we're still in that window and very much believe so. So we're very happy with the progress we're making in those communications, those conversations and we will continue to work with the DOJ as they assess the situation.

Great. And just as a follow-up, I think you said Saudi and Trinidad, you cleared approval already and then in addition to the U.S., it was Angola, Australia, Brazil and Egypt. Are there any risk of similar second requests or hurdles in the conversations you're having in those countries?

Or do you feel confident that those progressions and discussions that you're already having are, call it, on the track that you originally perceived?

Yes, Fredrik, I mean, it's following the exact process and time line that we would have expected to go through the regulatory approval process. Some are further along than others and we're engaged with all of those countries and everything is moving as we would have expected at this point in time.

We'll go next now to [ Ian Kutz ] with Morgan Stanley.

Ian Kutz here from Morgan Stanley. So I just wanted to ask, you guys had shared a couple of years ago or probably more recently some of the terms and components around reactivating a cold-stacked rig.

I was just wondering if you could refresh us with your latest thoughts on what the cost will be to reactivate a rig, the time line and potentially what type of contract terms or macro backdrop you would need to see to move forward with that decision?

It's quite timely really when we're starting to talk about a constructive market going forward. However, we are a little bit away from, I think, a situation where either the market needs it or the economics are present for a cold-stacked reactivation of the deepwater drillship right now.

In a few years, maybe slightly different. But I would say to you, from a cost perspective, we're still in that $100 million to $150 million range to reactivate one of these assets.

We're actually really comfortable with the stacked fleet we've got, the condition that they're in and we have a pretty good handle on the time line it would take to bring one of them back to market. We're still in the 12- to 15-month range, I would imagine to reactivate and bring one of those rigs back to service.

So when you think about the sort of macro and the market dynamics that are needed to support that sort of -- remember, we're not going to do that speculatively.

We're going to want a contract that fully recovers that cost and returns -- and a return on top of that. So the market visibility, the future term, the time line and the lag it takes us to get that rig ready, we're not quite there yet.

And I think what we would look for is a 100% utilization on the drillship market with visibility to what the market programs are looking like in order to justify bringing that out. And so you can imagine that we will be looking for term and productive dayrate for that to happen. Roddie?

Yes. I would just add to that. You talk about the term and the return economics being very important. So I mean, we're basically at this point in the year, the average award has been 480 days, which is double what it was all of 2025.

But that's still not enough in our view to bring out one of the cold-stacked assets. So it's really encouraging to see a doubling of duration and effectively like a 4x multiple on how many fixtures are in the market and being fixed today. But we still think there's plenty of room to run before we reactivate and stack the cold-stacked fleet.

Great. All very helpful. And then maybe kind of a higher-level question. I think you guys answered kind of some components of this. But just wondering, as you kind of did your tour of the world and pointed to areas where you see potential for incremental tendering or incremental activity, you kind of highlighted some regions where that was just kind of what you saw a quarter or a couple of quarters ago and it was just kind of the macro playing out as expected.

But I'm wondering if there's any areas that you point to where your customer conversations or the incremental activity you see is more related to events that have transpired over the last 2 months in the Middle East? And any customers or incremental activity that seems more related to building strategic reserves or reducing reliance on Middle East exports.

I guess just looking at Southeast Asia and India, where you kind of flagged that the ONGC and the India activity was something that you discussed on your last call, but you're throwing out some pretty big numbers in Indonesia. So yes, just wondering if you could parse out any areas where you see incremental kind of need or incremental demand that's more related to diversifying away from Middle East exports?

Yes. I think, obviously, the conflict is not that long at the present moment in time, but nations around the world are really reassessing their own energy security and what they're thinking from a policy point of view of energy supply in their own countries.

And I think you probably highlighted a couple that come to mind straight away from India. I think India, Prime Minister Modi has obviously set his government in motion with a mission to establish what the nature of their reserves in country are.

And I think that's what is driving the ONGC and Oil India action at this point in time. It was a bit of a surprise when it came, when we announced it last earnings call. And from our conversations in country with both the ministry and the oil companies, this is not a short-term effort.

This is a significant investment that, that country as one country alone is going to make with several years of CapEx commitment to establish what their position is from an offshore oil and gas reserve and supply perspective. That's just one country that is really thinking about it right now that we know of, obviously, Indonesia.

And I think when you look around the world and what the IOCs are looking at, they're always focused on ensuring that there's a diversified global supply. And so you look at the major developments that are going through sanction right now between Suriname, Namibia, Mozambique and into the Med and West Africa, the importance of a globally diversified supply is only more heightened now for the secure, reliable and affordable energy supply to the world. Roddie?

Yes. I love to add to that, again, we've already exceeded last year's fixtures and rig year awards. And obviously, none of that was based on the Middle East conflict or anything surrounding that.

And the tenders that are on the market today, which collectively, we think with the awards already and then what else is to come is going to be somewhere in the region of 150 rig years awarded this year, maybe even more than that, none of those are predicated on stuff that happened in the Middle East today. It's all based on the macro shift over the past kind of 12 months.

So again, like the shift towards deepwater, our customers ramping up their activities for exploration and development and moving beyond a little bit of the capital discipline mantra, that's the real reason that we're seeing this uptick. So all of that was predicated on $60, $70 a barrel outlook. But now we're obviously in a much different position.

So I think that's going to be fantastic for our customers in terms of earnings in the near term. But all of the pictures that you've seen and all the stuff that we're working on today is predicated on long-term mid-range oil prices, not elevated oil prices.

So we haven't even seen the impact in our business of a prolonged increased oil price. All of the stuff that we have is predicated on oil prices of 6 months ago, 9 months ago.

We'll go next now to Greg Lewis with BTIG.

I was hoping to spend a little time talking about the harsh weather market. Clearly, it was good to see the Barents move back to Norway. It's interesting, right, because we have the traditional North Sea, but you have -- there was a rig that kind of just won some work over in Canada.

We have Australia. You always hear about other pockets maybe in the Falklands. Just kind of curious, that's a market that one too many -- like any market, but there's just not a lot of supply.

So really, as you think about positioning or Transocean's harsh weather fleet, not necessarily for '26, but as we think about '27, '28 should we -- are we expecting more of a return to the North Sea? Are there going to be opportunities to kind of keep this fleet spread and beyond rig, but like the other players in this market to kind of keep everybody busy?

And there was another company that had to spend a bunch of money to upgrade a rig. Like how tight could we be for the harsh market as we approach like 2028?

Yes, so the harsh environment is a market that we've obviously been forecasting for a while to -- while it's in balance currently, it was expected to get tighter based on the projects that were getting sanctioned and the activity that was growing around the world. And you're right, the harsh environment market is no longer just Norway and it's returning to places like Canada and Australia, but also rigs that can be used with the loss of so many of our older semisubmersibles that used to conduct a lot of activity in not necessarily harsh environments, but other shallower water environments, the actual opportunity for the harsh environment fleet is a little bit more global now and we're not even considering what could happen in Namibia.

So we're seeing, obviously, with the licensing rounds and the imperatives of Equinor, Aker BP, Var Energi, the energy security conversation in Europe, Norway is going to get busier. And so the opportunity presented itself for us to take the Barents back to Norway.

We're very pleased to beginning that relationship with Var Energi again. And we will continue to keep our assets to the most strategic locations that we can and ensure that we're available to the market upswing that we're expecting in the harsh environment area. Roddie?

Yes. To add to that, on the harsh environment side, I think the name of the game over the last few years was for a lot of the operators to retain some optionality on rigs. So not necessarily in a position to put a large commitment on their balance sheet.

But the dynamic has definitely shifted with awards in Canada being made. There's another tender out for an incremental rig there or a follow-on of the existing rig. And then you've seen within Norway itself all the big guys making commitments, so far, Aker BP and then Equinor going through their NCS 2035 plans.

The number of wells, the longevity of the program, it basically speaks to the Norwegian government making the commitment to sustain energy security in Europe.

So that's -- those are really good fundamentals underpinning that market. That means we will be there for a long time and we're about to enter a period of, as you said, a very tight market, but this is because there's a shift towards longer-term contracting.

So that kind of showed up in some of the numbers already, but we think that's going to be even more prolific as the operators need to secure those assets because there aren't that many of them. So we're feeling really strong about that.

And the -- to your point, there's a very high chance that more rigs will return to Norway because the demand is simply well beyond the fleet that's currently in Norway. So I think it's almost necessary.

We'll go next now to Noel Parks with Tuohy Brothers.

I was intrigued about what you were saying about exploration conducted long ago, some of those projects actually now heading for development. And just for perspective on that, just off the top of your head, can you sort of think of what may be the oldest, longest in the tooth past exploratory project that you're now seeing being greenlighted for development?

That's a good question. Probably trying to think off the top of my head on that one, I'm going to say that a lot of stuff in Nigeria, for example. So Nigeria is expected to go up to 5 rigs, and they've gone down to like 1 rig.

So a lot of the stuff that is now being triggered that's basically going to have all these incremental rigs going there is all based on exploration that took place some time ago. So that -- some of that may even be as long as 8, 10 years ago. But certainly, it's stuff that was done at least 5 years ago. So that's probably a great example there.

Kind of a shorter example of that on the opposite end of the scale might be something like Namibia. So you would have seen lots of announcements about discoveries in Namibia. And then there was kind of like a lull in activity as all the results were digested.

And now we're seeing several long-term tenders there that are all based on development. But it is interesting on the whole concept of development versus exploration is that even in places like Namibia that's moving towards development, there's still several exploration wells on the books to be drilled. So it's kind of like it's a treadmill effect. You have to keep discovering. You have to keep exploring. Petrobras are very vocal about that, that they must contribute a significant portion of the portfolio every single year to exploration.

If you take your foot off the gas for a moment on exploration, you're going to find your reserves dwindling very, very quickly. And I think that's kind of the case across the board here that reserve replacement is now becoming much more of an issue. And the only way you can do that is get out there and explore.

Great. And I was wondering if you have any sense around with energy security, of course, coming to the fore and the different ripple effects in terms of various importing countries and maybe the plans they're going to be making going forward, I was just wondering if the improved economics assume that we do have sustained higher oil prices?

Are there any regions where you can anticipate that maybe the opportunity -- the economic opportunity can become so compelling at higher oil prices that it can actually maybe overcome some political inertia or even opposition to moving forward? I don't know if there are any examples of that, that come to mind, but I was just wondering.

Yes. So it's definitely a theme, right? So I would say that as you see the war break out in the Middle East there, I actually think it just reinforces the decisions that have already been taken. So for the last several years, that's kind of been the process that all the big guys are going through and in particular, the NOCs, looking at what they have within their own borders and that domestic production makes all the sense in the world because you retain all the taxes, you employ your people, you basically reduce your dependency on others.

So there's definitely an element to that. But yes, I think overall, that energy security question is kind of -- it's important.

But if -- I think it's more a case of reinforcing good decisions that were made for domestic exploration. To Keelan's point, you made a great point about India, that's a top one there. But even in places like the U.K., I think you're going to see a u-turn on that stuff because, yes, they've been cutting back on activities for quite some time now, but it's almost inevitable that we'll -- that will shift in the near term.

But I also think the Norway thing is a great example, right? That's linked to energy security, but also linked to basically providing energy for Europe and they are the biggest producer in Europe. So all of the activity increase will have an element of that security to it, but I think it's just overall acceptance that hydrocarbons are here for a very long time. There is no peak oil concept this side of 2050. So time to just get on with it.

Yes. Maybe just to add to that, I think what we need to continue to highlight is that the deepwater business especially is very long. And the economics of it are very compelling at much lower oil prices than we're at today.

And so the activity we're getting today is based on the fundamentals regarding supply and demand of hydrocarbons, the concern on replacement of reserves and then the need to explore to do that. And then we layer in or amplify the case with energy security and it will continue, we believe, to promote more investment in the offshore space.

And obviously, it's a very good place to get affordable, secure and reliable energy and we continue to see it playing that role going forward.

Thank you. And gentlemen, it appears we have no further questions this morning. Mr. Keddington, I'd like to turn things back to you, sir, for any closing comments.

Great. We'd like to thank everyone who participated in our earnings call today, and we invite you to follow up with us for any additional inquiries. With that, we'll close the call.

Thank you, Mr. Keddington. Ladies and gentlemen, again, this does conclude the Transocean First Quarter 2026 Earnings Conference Call. Thank you all so much for joining us and we wish you all a great day. Good-bye.

Hello, and welcome, everyone, joining today's Q4 2025 Transocean Earnings Call. [Operator Instructions] Please note this call is being recorded. [Operator Instructions] It is now my pleasure to turn the meeting over to David Kennington, Vice President, Treasurer. Please go ahead.

Thank you, Nickie, and good morning, everyone. Welcome to Transocean's Fourth Quarter Earnings Call.

Leading today's call will be Transocean President and CEO, Keelan Adamson. Keelan will be joined by other members of Transocean's executive management team, Chief Financial Officer, Thad Vayda; and Chief Commercial Officer, Roddie Mackenzie.

In addition to the comments that will be shared on today's call, we'd like to direct you to our earnings release and fleet status report filed yesterday that contain additional information, all of which is available on Transocean's website, www.deepwater.com. Following our prepared comments, we will open the conference line for questions. Please limit your inquiries to 1 question and 1 follow-up as this will allow us to hear from more participants.

Before we begin, I'd like to remind everyone that today's call will include forward-looking statements, which are subject to risks and uncertainties that could cause actual results to differ materially.

With that, I'll hand the call over to Transocean's CEO, Keelan Adamson.

Thanks, David, and welcome, everyone, to our fourth quarter and year-end 2025 conference call. We appreciate your interest in Transocean.

I will cover several topics today. First, I'll recap our key accomplishments over the last year. Next, I'll cover our 2026 priorities. Third, I'll quickly recap the highlights of our recently announced definitive agreement to acquire Valaris and why we are excited about this transformational combination. And lastly, I'll close out with some market updates from around the world.

Let's get started. 2025 was an important year for Transocean. The company executed very well, both operationally and financially. Yesterday, we reported our fourth quarter results, including solid adjusted EBITDA of $385 million and free cash flow of $321 million. Year-on-year, our results improved significantly with adjusted EBITDA of $1.37 billion, up nearly 20% and a significant increase in free cash flow to $626 million.

During the year, we materially strengthened the balance sheet, retiring about $1.3 billion in debt. We executed 2 key capital market transactions to delever and improve both our liquidity and the timing of our debt maturities. These actions and the additional debt payments made in 2025 reduced our annual interest expense by nearly $90 million, enhanced our financial flexibility and increased the value of our equity currency, ultimately enabling the recently announced transaction with Valaris.

We sustainably improved our cost structure by removing about $100 million in costs and are on track to decrease our costs by an additional $150 million in 2026. We took the difficult but necessary steps to rationalize shore-based support around the world, reduce G&A costs and restructure the organization to drive efficiencies without adversely impacting our operational performance. Today, we are leaner, more efficient and more profitable.

The operational performance of our rigs and more importantly, our people were superb. Once again, we demonstrated why Transocean is an industry leader. We achieved record uptime performance just shy of 98%. We had 0 operational integrity events and 0 lost time incidents across our entire fleet. Our process and occupational safety performance was exceptional. We completed 5 major planned out-of-service projects on time and on budget, and we continued to rightsize and high-grade the technical capability of our fleet. We recycled 6 rigs in 2025 with 1 more completed earlier this year.

We entered 2026, Transocean's 100th anniversary year, with strong momentum across the business. Now let's review Transocean's key objectives. Our first priority is to optimize the value of our differentiated assets. Transocean through our people and fleet has unparalleled capabilities. We strive every day to deliver best-in-class performance with the most experienced and proven team of professionals, maximizing the capabilities of our high-specification fleet. We have an exceptionally capable drillship fleet and a high-spec fleet of semisubmersibles capable of executing in the harshest environment.

As the technology leader in the offshore rig business, we continually innovate to improve the safety, reliability and efficiency of our operations. Second, we are focused on generating industry-leading free cash flow. We have roughly $6 billion in backlog that will efficiently convert into cash, the key measure of value in our business. The more we generate, the faster we can reduce our leverage, which will materially benefit our shareholders.

And third, as we continue to reduce our total debt, we will establish a stronger, more simplified capital structure that provides financial resilience and the ability to weather the cycles of this business.

Moving now to our recently announced definitive agreement to acquire Valaris. We are incredibly excited about the capabilities of our combined business. As we head into what we anticipate will be a very constructive period for the offshore drilling business, we believe that this transaction is well timed, and know it is perfectly aligned with all of our strategic priorities. It positions us to be a leader combining the best fleet with the best team working diligently every day to provide our customers with the best most disciplined execution in the industry.

Our geographic footprint and customer base will expand. Wherever our customers go offshore to find and develop reserves, we will be able to provide a rig solution to fit their requirements from a broader high-quality asset base. We've identified more than $200 million in cost synergies on top of our ongoing cost reduction initiatives. Our pro forma combined backlog of nearly $11 billion and cash flow-generating capability are expected to accelerate debt reduction, resulting in leverage of around 1.5x within 24 months of closing.

We strongly believe that this combination will enhance returns for shareholders and create an exceptional opportunity for investors desiring exposure to the offshore rig business. We expect to close the transaction in the second half of 2026, and we look forward to sharing more information on our progress in the coming months.

I'll now provide a brief market update. While we had seen some near-term moderation in tendering activity, the underlying outlook for deepwater offshore drilling is strengthening. In fact, tendering activity is growing with opportunities developing in most major basins. In this market environment, we expect deepwater utilization to move meaningfully higher and to greater than 90% through 2027, setting the stage for an increasingly constructive business environment.

Looking regionally, in the U.S. Gulf, long-term demand remains robust, driven by the Palogene plays and the new lease awards with improved fiscal terms. Any apparent short-term softness will likely result in preferred assets, repositioning to other increasingly active markets elsewhere.

In Brazil, we expect rig activity to remain stable. Any reduction in Petrobras' projected fleet count will be small and temporary, offset by increased demand from international operators. We anticipate that Petrobras will conclude its blend and extend renegotiations by the end of the quarter, which will add multiple years of backlog.

Africa continues to exhibit considerable growth potential. We expect the region's rig count to increase from roughly 15 today to at least 20 over the next year or two. In Mozambique, we anticipate 3 multiyear program awards from each of Eni, Exxon and Total, all scheduled to start in 2027 and 2028. In Nigeria, Shell has already awarded its 2-year program with additional awards expected shortly from Exxon and Chevron. In addition, Total is preparing to tender this quarter. Collectively, this implies 4 rig lines from 2027 onwards. In Angola, activity remains solid, supported by anticipated and announced extensions for rigs currently operating with Azule, Total and Exxon. We also understand Shell will reenter the basin for a material exploration program in 2027.

In Namibia, we are now seeing the first results from recent exploration success with Total launching a major tender for the venous development, 2 rigs, 3 years each, beginning in early 2028. We also expect further development activity as operators assess their recent discoveries for commercial viability.

And in the Ivory Coast, we understand Eni is preparing to issue a 1 rig tender for 3 years of work beginning in early 2027.

In the Mediterranean, activity has returned to pre-Covid levels, driven by strong regional gas demand in Egypt, Israel and Cyprus. Rig count is expected to increase to around 8 units. In Israel, we expect 2 rig fixtures to support the recently sanctioned Chevron and Energy in developments. In Egypt, Shell and BP will add new programs starting this year and in Cypress, Eni's Cronos development is expected to begin drilling in early 2027.

Moving now to Southeast Asia and primarily Indonesia, we anticipate incremental demand of 3 to 4 rigs between Eni, Harbour Energy, Mubadala and INPEX. In India, momentum is building with the government's objective to drill 50 deepwater wells per year going forward. In addition to the recently awarded 1 incremental fixture in the region, ONGC have just issued a new tender for 3 drillships and 2 semisubmersibles with contract durations of 4 years each beginning in the first half of 2027.

In Australia, the Deepwater Skyros will commence a minimum 1-year development program in early 2027. We see stable activity from all our semisubmersible customers with programs currently out for tender by Woodside, Santos and Impex.

In Norway, utilization of the high-specification harsh environment semisubmersible fleet, will remain robust through 2028, supported by recent awards from Equinor and Aker BP. Other operators are also seeking high-spec harsh environment units for 2027 starts which is expected to drive utilization of these units to nearly 100%.

In closing, tendering activity is increasing. Multiyear opportunities are now in the market and visibility into 2027 and beyond continues to improve. As operators move ahead with new developments and meaningful exploration programs, we are well positioned to capitalize on improving demand.

I'll now hand the call over to Thad for some brief comments on the quarter and our guidance. Thad?

Thank you, Keelan, and good day to everyone. Our performance during the fourth quarter and for the full year 2026 was very much in line with our expectations and the guidance ranges that we provided to you in November.

In the fourth quarter, we generated contract drilling revenues of $1.04 billion at an average daily revenue of approximately $461,000, which is generally consistent with the average daily revenue achieved in the last several quarters. Operating and maintenance expense and G&A expense was $605 million and $50 million, respectively.

Adjusted EBITDA was $385 million, implying a very healthy margin of 37% and cash flow from operations was approximately $349 million, a sequential increase of 42%. Free cash flow of $321 million reflects $349 million of operating cash flow, net of $28 million of capital expenditures. Our free cash flow margin was notable at 31%. I highlight that this is the best quarterly free cash flow we have generated in several years and is a direct result of excellent operational performance, execution on our cost savings initiatives, lower cash interest expense and effective management of our working capital.

We ended the fourth quarter with total liquidity of approximately $1.5 billion. This includes unrestricted cash and cash equivalents of $620 million, about $377 million of restricted cash and $510 million of capacity from our undrawn credit facility.

In addition to now issuing our Fleet Status Report concurrently with our quarterly results, we have slightly changed the presentation and content of the press release. Going forward, in addition to some format and tabular modifications, the release will include our guidance ranges. This report provides guidance for the first quarter and full year 2026 for Transocean on a stand-alone basis as will be the case until the Valaris transaction closes expected later this year. The guidance ranges provided include the effects of our cost reduction initiatives and reflect slightly lower levels of activity versus 2025, specifically assuming some idle time on several rigs, including the KG2, the Deepwater Proteus and the Deepwater Skyros.

I note that the potential to achieve the upper regions of the revenue guidance range relates mostly to these rigs being extended beyond their contract end dates or commencing new contracts earlier than anticipated. Even with the assumed idle time on these rigs, we expect free cash flow to be in line with or better than that achieved in 2025 as we continue to reduce cost and interest expense and make additional improvements in the management of our working capital. We also intend to continue to utilize our free cash flow to opportunistically reduce debt in excess of our remaining 2026 scheduled obligations of approximately $380 million, which includes capital lease payments.

This reflects about $130 million in payments we have already made in 2026. Additionally, our stronger credit profile and improved cash flow generation may enable us to refinance some debt instruments at lower interest rates.

Finally, we expect to end 2026 with liquidity of between $1.6 billion and $1.7 billion, which excludes the effect of any incremental opportunistic deleveraging.

This concludes my prepared remarks. Operator, we're ready to take questions.

[Operator Instructions] We'll take our first question from Greg Lewis with BTIG.

Keelan, I guess at this point, the market has definitely had some time to digest the acquisition of Valaris and congrats on that again. And while it was definitely transformational to the balance sheet, Transocean was already the second largest owner of high-spec ultra-deepwater rigs prior to acquiring Valaris. I guess I'd be curious, post the acquisition, does this change the chartering strategy at all? And really, what advantages could the company benefit from just simply from these new potential economies of scale?

Greg, thanks for the question. As we think about consolidation and what it means for our industry and the upstream industry in general, and our customers have been consolidating, as you know, over the last few years, is really driven around driving efficiencies into our business. It's about taking cost out of the chain and looking to provide a better service to our customers and to the consumer. So from our perspective, this combination allows us to address the necessary cost across the combination, it allows us to ensure that our overlap of cost structure is minimized. We drive efficiencies into that structure.

But more importantly, we're starting to look at how do we improve our service provision as a combination across the world and to all of our customers. And ultimately, when I talk to our customers, they always are focused on project execution in a capital disciplined world where they only have a certain amount of CapEx to spend across their opportunities, they want to ensure they're working with partners that can deliver in a reliable and predictable fashion. We're very proud of our operation on the deepwater fleet that we own right now and we have strived to ensure that we can deliver that level of performance no matter where we're working for whoever around the world.

And I see this is a huge opportunity for us to combine 2 excellent operating companies and continue to deliver that sort of level of service, improve our reliability and improve our predictability to our customers that ensures that their projects are delivered on time, on or better than budget, and ultimately reducing the cost of these projects around the world. It will enable more work in the future, and it will obviously help the consumer at the end of the day.

So I think the other aspect of this transaction that helps is the drilling industry has gone through, as you know, a pretty rough time over the last 10 to 15 years. Many companies have had to restructure. We've been carrying a lot of debt through the down cycle. And it doesn't help the industry where companies do not have a sustainable business structure. And I think for the benefit of the upstream as a whole and the benefit for our customers having drilling contractors that are sustainable, robust, can be resilient against the inevitable cycles in this business, I think, is a huge plus, and I think this combination delivers against those.

Okay. Super helpful. And then just -- I did want to talk a little bit about kind of how you're thinking about the jack-up market. It's definitely on a lot of investors' minds. It is -- I mean drilling is drilling, but if you think about the jack-up market, it's more of an NOC heavy market where Petrobras and Equinor side that the deepwater market is more of an IOC market. Just kind of curious how we're thinking about how does that change? Does management have to change a little bit of its view or it's kind of structure in dealing with these NOCs in the Middle East and Asia versus the traditional opportunities that you're seeing with IOCs?

Yes, Greg, another great question. The -- we have been a jackup player in our history, right? We understand and the highly competitive nature of that arena. And as we enter back into the jackup business post close, we're looking forward to embracing the lessons we've learned over time as an operator ourselves. And of course, Valaris has done a great job with running their jackup fleet in the competitive environment with NOCs and international operators around the world. Clearly, it is a business that needs to be run very efficiently to generate good cash from that business. And it's important that companies who run those businesses understand the subtleties of how to manage that cost structure and ensure that they can get the efficiencies and the performance from that jack-up market.

So it's not strange to us. We certainly learned from the past and I see a great opportunity for us to learn from the Valaris team that runs that jackup fleet to continue to deliver exceptional performance and incremental cash to the combined entity going forward.

Our next question comes from Eddie Kim with Barclays.

So this group as a whole often gets a bad rap because the offshore inflection always seems to be about 12 months -- 18 months away. You and your peers have been consistently saying for several quarters now that this inflection will happen in late '26 and into 2027. We don't necessarily disagree with that. But just curious what gives you the confidence that this is going to happen on time this time around? And outside of some sort of oil price collapse, do you see much risk of this getting pushed out?

Eddie, no, I think it really stems from twofold. It stems from our conversations that we have all the time with our customers, and it also stems from the data that comes through from the number of tenders that release, the number of prospects that are going through their field development programs. And some of the public commentary from the oil and gas company executives that are starting to talk a little bit about reserve replacement, declining production and the need to build exploration budgets to ensure that they are able to do that.

So we triangulate around lots of pieces of information, some objectives, some very objective. And that is all triangulating now to, I think what we've said on all along is that we felt like end of 2026 and early 2027, we were certainly going to bridge into over 90% utilization across our drillship fleet and that's continuing to play out. And there's been some recent news that I highlighted in my commentary that was kind of hidden from view at that point in time. Roddie, do you want to add anything to that?

Yes, for sure. So just to pick up what gives us the confidence. So as we look at last year, the number of rigs that were awarded just progressively got better and better quarter-over-quarter. We went from like 12 rig years to 14 to 18 and then 22 rig years in the fourth quarter, which was actually disappointing for us because we were expecting probably double that to be awarded. There were several big awards that slipped into '26. But you will see that from not only our sales, but a lot of our competitors have booked multiyear programs.

So we see a lot of multiyear programs, whereas we only saw a few last year. We see a lot more now. We're actually tracking, I think, it's 32 open tenders that are expected to be awarded over the next few months. So those open tenders, the average length is well beyond a year. So there's just a lot of work being awarded now. I think you saw that period in '25 where a lot of the customers were basically kind of protecting their own balance sheets and not putting on excessive amount of commitment. But as we work through that capital discipline, what we're seeing now is a transition now clearly towards time to develop a lot of these assets that they discover over the last couple of years and a marked increase in exploration budget because the pressure is now on to find replacement reserves.

So we're very confident in terms of the number of awards that have been made. So I would say that's not a forward projection that data that's in the market already. We're definitely through the trough of contracting. And now we're kind of on the other side of things begin to really pick up. So again, just lots of opportunities and they're all much longer in term than they were before.

Got it. That's very helpful color and great to hear you. Just wanted to ask about the Petrobras blend that extends. Those negotiations have taken a little bit longer than we had anticipated. But you said you expect those to conclude by the end of the quarter. Just curious if your full year guidance already bakes in some potential earnings risk related to those blending expense? Or if the results of those negotiations should be seen as an incremental impact to the guidance you've laid out?

Yes. So thanks for the question. The guidance that we provide is representative of our best guess based upon the conversations that we've had. So I wouldn't consider it to be significant incremental upside with respect to the blended extends.

Our next question comes from Fredrik Stene with Clarksons Securities.

I wanted to touch a bit on, I guess, fleet placement in general. I think the way I interpreted your commentary was that the U.S. might -- is robust long term, might face some softness in the near term, but then you have good activity levels in West Africa, for example. I think the ONGC tender which came out yesterday kind of in the new format was incremental to what most of us have expected if you -- at least a couple of months back. So just wondering, do you have any color on how you see your fleet positioned, let's say, a year out in time? Do you expect many rigs to move regions? Or do you think some of that will be sold by the acquisition of Valaris just thinking about you having rigs available to actually compete in most of these long-term fundings?

Yes, Fredrik, thanks for the question. Yes, look, I think what we definitely see is opportunities developing as we've discussed in the Africa and Asia regions. We operate, as you know, in a global worldwide market that's highly competitive. We are able to move our units anywhere around the world that meets that demand. I would say, because we have a very high-spec fleet, our customers are always going to want all else being equal, the higher spec rig that they can find. As we experience the Gulf has been a strong demand. It will continue to be a strong demand, if there's any near-term softness in that area, we will move those rigs to the other opportunities that exist around the world.

Brazil continues to be a high utilization area for drillships. And the Med has been -- it's great to see the Med back. It's great to see a lot of activity building in the Mediterranean. Obviously, the gas and energy security conversation is playing a role there. But yes, that's the way we see the movement. And I'll just pass it over to Roddie, he'll have a couple more comments to add.

Yes. Exactly right, Keelan. And great that you noted the ONGC tender that came out. I mean, that's 20 to 25 rig years in one go that was on nobody's radar. So I think that stuff is extremely interesting. The stuff that's come out of Mozambique, very interesting, the stuff that's coming out of Indonesia, very interesting. And of course, we're engaged in discussions that we're not at liberty to divulge, but there's plenty of other activity going on. And as Keelan pointed out, for these hot rigs that are doing a great job performance-wise, the customers are very interested.

I just think there's no shortage of opportunities. And if there is any near-term softness in the Gulf of Mexico, I mean, at the moment, we're fully utilized. But if that does transpire, then don't think there's any problems in moving those rigs on to other programs. There's certainly enough work around the world for the rigs over the next couple of years. It's just a question of timing and when we move things. But yes, we're super pumped about the opportunities that have just recently been announced that nobody has gotten their model. So I think that's really going to push utilization up.

Yes, I agree. I think that fooled us, or we're going to see probably does something with everybody's mindset about how tight this market can become. Just 1 follow-up which relates to one of the U.S. Gulf rigs. I think you mentioned that the guidance included some idle time on KG2, Proteus and Skyros. But the [indiscernible] that's sort of running off in June this year. Should I -- by adding these 2 things together, assume that Ascar might have some new work coming up for it shortly?

Yes. I don't really have anything I can comment on at this time. But if anything does happen, of course, we'll announce it in due course.

We will move next with Doug Becker with Capital One.

Investors are always voting with their pocket books and it looks like they like the Valaris acquisition. Just curious on the early response from customers.

Yes. Doug, thanks for the question. The feedback I've had from our customers, and I know speaking with my counterpart at one, Valaris has been overwhelmingly positive. They understand the situation in the market. They understand the need to drive costs out of the business. They understand that the opportunity, as they've had to look at consolidation from their business perspective. They understand that it shouldn't -- it doesn't surprise them consolidation would happen in the drilling contractor offshore business as well.

And I think they're very supportive of the potential of the combination. They're very supportive of both companies' operations. There are things to learn from each of us, and we'll look to grab those and where we can improve our service to our customers around the world and in a bigger scale basis, we will be doing that. And so overwhelmingly positive comments directly from the customers that we deal with on an operational basis, I'd be very pleased with that. And they can see where the synergies of these companies will come to benefit them and their project delivery.

No, that's very encouraging. Also wanted to circle back on the blend and extend negotiations with Petrobras. Just trying to think through what would you consider a win-win situation for Petrobras where maybe they get some rate relief in the near term, but to make it a successful negotiation for Transocean as well?

I'll take that one. Yes. So Petrobras is all about basically cost reductions and optimization. So the concept is not just about day rates and what have you, but also a lot around terms and conditions and doing things in the contracts that kind of for want of a better word, reduce mutual waste. So we're feeling pretty good about that in terms of the opportunity to be more efficient with revenue. So we'll get a couple of points up on revenue efficiency, that kind of stuff. But also, this is kind of like the workhorse of the fleet, right?

So you've got the sixth gen rigs down there that provide great service. They do a fantastic job. And we love the idea about putting significant extensions on those because we are talking about quite a lot of rig years. So that's kind of checks everybody's boxes. If we can be a bit more efficient cost-wise for them and at the same time, extend our kind of core sixth-gen fleet and keep them busy for the foreseeable future, that's a real win. So we're excited about that. We hope that does come to fruition. And as we say, we'll definitely update when we have definitive developments there.

And maybe one add on that. I think every drilling contractor understands that continuity is really important for delivering performance over time and Petrobras are -- they have the ability to scale their operations to drive those efficiencies, and they understand the value of continuity with their fleet as well. And so from our perspective, it addresses utilization for our sixth gen and low seven-gen fleet. It allows us to work with our customer to drive their cost down and to improve our Ts and Cs and reclaim some of that benefit to the company in that way.

And we're able then to provide a service for longer on a high continuity basis, which can only be good for our cash flow generation.

thank you. Thank you. We will move next with Keith Backman with Pickering Energy Partners.

I had a question around in a market that's much further along and everything is more positive, capacity is a little bit tighter. Do you have any feel on which of your 3 seventh-gen rigs could potentially come back to market first? And does that change at all with Valaris' three 7 gen stacked rigs as well?

Yes, it's -- look, we're going to be really excited when the utilization gets to that point. But right now, obviously, we've got an active fleet that needs to roll over. We're very encouraged by the market signs that are there right now to continue to find opportunities for the active fleet. We're very happy with the three 7th gen units that we've kept on the sideline and the Valaris units, obviously are high spec as well. So we take the same standpoint. We will not bring one of these units back speculatively and the market would need to be in a position where we could recover the investment of those reactivations inside that contract.

We believe that the longer-term outlook is very strong and the opportunities will present themselves, but we don't see that in the very near term.

Awesome. That's helpful. And then my second question kind of comes back around to the Gulf market again in the back half of the year. Whenever I look at kind of what's in the fleet and could potentially be rolling off. I look at the Conquer, Proteus and Asgard, late this year, potentially needing some work. I just wanted to know if all of those were to win work, I'm assuming there's a little bit of upside to your guidance. Just wanted to get a feel for what's baked into '26 guidance in regards to those 3 rigs?

Yes. So we called out the 3 rigs that we think it makes sense to assume some idle time with upside associated with those under the conditions that I suggested. The other assets that you mentioned, I think, are all probable go back to work. It's sort of what we have thought about. So there is some probability-weighted assumption in the guidance range, but it would definitely move it towards the higher end.

And maybe just some color around those rigs. Obviously, as you know, there are high-spec drillships in the world. There are opportunities for these rigs to pick up additional work. We're fairly confident that the market will develop nicely for those units to grab some utilization. I think it's important to remember that we want to keep these rigs working. We want to keep our utilization up and at the same time, we understand the value of those assets. So we'll be looking to fill it with short-term work, recognizing that the longer term is a little bit more constructive in ensuring that we're keeping our powder dry.

We will move next with Noel Parks with Tuohy Brothers.

One thing I was wondering is, as you had mentioned that there has been more public commentary about reserve replacement among producers and the need for exploration. I'm just wondering among the players out there who might have been the latest to the parity in terms of deciding that, yes, we have to address the return to the offshore, I'm just wondering maybe you can kind of characterize what some of the more recent companies approaching you have been have been thinking? I'm just wondering, have they been sort of sitting back and deciding that they're happy to be fast followers? Or are they now feeling like, oh, we've hung on the sidelines too long, and we need to be more aggressive, given the tightness in supply. So I was just wondering about like as I said, the latecomers.

I think this is really a story about many of the companies pivoting back towards oil and gas, particularly offshore and deepwater. So it's really a story about there's less commentary or there's a pivot away from spending a tremendous amount of money in renewables and alternatives and definitely much more of a focus and an acknowledgment, if you would, that the most economic, the most reliable sources of energy are coming from traditional hydrocarbon sources. So I think that's the key shift that we're seeing is there's a pivot back towards the business that we are directly engaged in. And within that, we do offer the most cost effective and the lowest carbon barrels.

So there's a lot of wins there for that. And I think it's really a case of reality governs everything and eventually, we all kind of head towards that path. So that's definitely what we're seeing from our customers is that they're perhaps not spending more money overall in the name of capital discipline, but they're pivoting back towards the stuff that makes the most sense, which is the business that we are focused on.

Right. And related question, does producer M&A and A&D activity, do you see anything particular either announced or on the horizon that you see as potentially exciting opportunity? It seems we're kind of in a mode of basin rationalization but perhaps that's weighted more toward the independents. But even among those, there are quite a few of them that maybe went entirely onshore for a decade or so, but have the legacy of international and offshore operations. Anything you've seen in the sort of state of deals we've seen recently has eventually interesting to you?

Yes. I mean, obviously, we've seen several consolidations there over the past couple of years. I don't see a tremendous number more on the table, but I'm sure whatever it makes sense that's going to happen. For the same reasons that we are going through our consolidation, it's all about bringing those costs down and making ourselves more efficient. So it's actually not necessarily a bad thing because the industry overall with the nature of these consolidations just becomes more efficient. We become more cost effective, and therefore, we attract more dollars towards our type of exploration, our type of development. That's very important for us. So I think the consolidation at various sectors in the industry, it just makes sense from that point of view.

At this time, there are no further questions in queue. I will now turn the meeting back to David.

All right. We'd like to thank everyone who participated in our earnings conference today and invite you to follow up with us for any additional inquiries. And with that, we'll close the call.

Thank you. This brings us to the end of today's meeting. We appreciate your time and participation. You may now disconnect.

Good day, everyone, and welcome to the Third Quarter 2025 Transocean Earnings Call. [Operator Instructions] Please keep in mind, today's call will be recorded and we will be standing by if you should need any assistance.

It is now my pleasure to turn today's conference over to Director of Investor Relations, Alison Johnson.

Thank you, David. Good morning, and welcome to Transocean's Third Quarter 2025 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 Keelan Adamson, President and Chief Executive Officer; Thad 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 Keelan and Thad's prepared comments, we will conduct a question-and-answer session with our team. During this time to get more participants and opportunities 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 Keelan.

Thanks, Alison, and welcome, everyone, to our third quarter conference call. We posted a strong third quarter, demonstrating our collective focus on delivering superior operational performance to our customers.

And I extend my sincere thanks to all of our crews offshore and our operation teams onshore without whom these excellent results would not be possible.

Additionally, we have made notable progress in recent months, reducing our operating costs as evidenced by our strong free cash flow generation in the period and our simplified and improved capital structure.

We completed several important capital markets transactions that advanced our deleveraging efforts and further reduced interest expense to better position the company for the long-term benefit of our shareholders.

Thad will provide more detail, but as the result of our ongoing cost control initiatives and these transactions, we have achieved several important results.

First, by the end of 2025, we will have reduced our debt by approximately $1.2 billion versus our scheduled maturities of $714 million. We believe that a stronger and more flexible balance sheet is essential to improving total shareholder return, making accelerating -- accelerated deleveraging one of our key objectives.

Second, these transactions allowed us to convert one tranche of secured debt to unsecured debt, reducing restricted cash balances that are now being used more efficiently and releasing the Deepwater Poseidon, which is among our highest specification and most capable rigs from the collateral pool.

Third, our annualized interest expense will now be reduced by approximately $87 million versus 2025 with these savings expected to be used for further opportunistic debt reduction. And lastly, we have significantly improved our debt maturity profile and materially reduced our 2027 obligations.

Today, we currently expect to meet our remaining scheduled maturities with cash flow from operations. We will include a slide in our corporate presentation that illustrates this improvement.

We are pleased with the significant progress we have made on our balance sheet so far this year and there is more work to be done. I will remind our listeners that in addition to the providing industry-leading offshore drilling services to our customers, these actions and outcomes are consistent with our previously articulated objectives of reducing debt, reducing interest expense and simplifying our capital structure.

Turning to asset strategy. We continue to refine the composition of our fleet. After a fulsome analysis of the option value of our cold stacked assets, we announced our intention to dispose of 4 drillships and 1 harsh environment semisubmersible from our stacked fleet. Overall, we will retire 9 rigs, including the 4 announced last quarter, a process that should be complete by mid-2026.

Our fleet now consists of 24 contracted ultra-deepwater drillships and high-specification harsh environment semisubmersibles as well as 3 higher specification, seventh gen ultra-deepwater drillships currently cold stacked in Greece.

We have been deliberate in the rationalization of our fleet to maintain a portfolio of the highest specification, most marketable and competitive assets in the industry. The decision to retire these older assets better aligns the company with evolving customer needs while supporting a more balanced industry supply-demand dynamic.

With respect to rig contracting and as we expected, our customers exercised some priced options. In the U.S. Gulf, following the announcement of its final investment decision on the Tiber-Guadalupe development, BP exercised its 1-year $635,000 per day priced option for the Deepwater Atlas.

The program is expected to contribute approximately $232 million in backlog and will keep the rig operating with BP through the second quarter of 2030.

We are grateful for the continued confidence BP places in us to execute its payload [ gene ] programs. In Brazil, Petrobras exercised the first of its 2 options for the Deepwater Mykonos. The program extends the rig's firm term into early 2026.

Moving now to the broader market environment. Given global macro uncertainties and its impact on commodity prices, our customers continue to exhibit capital discipline, prioritizing free cash flow for debt reduction, returning capital to shareholders and taking a measured approach to the amount of capital that they commit to exploration and development activities.

They have also been reducing costs by restructuring their organizations and have largely been sustaining reserves and production levels through acquisitions and consolidation. This has resulted in deferred near-term demand for drilling services and as expected, a slower pace of contracting.

However, industry projections continue to suggest that upstream investment in offshore will increase, particularly in the deepwater segment. Indeed, a number of independent organizations recently observed that the significant decline in operators' reserve to production ratios resulting from their capital discipline is not sustainable, a view with which we agree.

We believe that their efforts to improve this metric will lead to meaningful increases in offshore drilling activity. Notably, and perhaps to the greatest extent we have heard over the past decade, many customers are now indicating a necessity to increase their exploration activity to address this emerging supply imbalance.

Multiple third parties project that demand for deepwater rigs will significantly increase in the coming years and we are encouraged by recent conversations with customers and anticipate contract awards for more programs later this quarter and into 2026.

Based upon known tenders, programs and contract options, we expect the number of contracted floaters to grow by approximately 10% in the next 18 months.

Looking regionally, in the U.S. Gulf, activity is stable as operators continue to extend utilization of rigs they already have on contract. Additionally, 3 short-term programs with independent operators are expected to be awarded in the fourth quarter with one more tender to be released before year-end.

In Brazil, we anticipate the Petrobras Buzios and Mero tenders and Shell's Gato do Mato tender will be publicly awarded in the coming weeks for a total of 23 years of firm work requiring 6 rigs. We believe that these programs will mostly be satisfied with rigs currently in country.

In Africa, we still anticipate demand could increase the working rig count by at least 3 rigs through 2027. In Nigeria, the Exxon and Chevron tenders for multiyear development are well underway and Total's new tender is expected to be released in the coming months.

In the Ivory Coast, we believe Eni's release of its tender for the multiyear Baleine Phase 3 development commencing early 2027 is imminent. In Angola, the rig count is expected to remain relatively stable.

Azule Energy recently released an expression of interest for 2 rigs commencing late 2026 and Shell will go back to the country after many years out by starting a new exploration campaign in 2027. We now expect there will be 5 drillships and 1 semisubmersible working in country by 2027.

In Namibia, most of the operators that are currently active will continue to drill exploration and appraisal wells in 2026 through 2027. We expect the first major development program will be tendered for 2 rigs to begin in 2028.

And finally, in Mozambique, Eni's tender is progressing with Exxon and Total's tenders anticipated to be released soon.

I also note that Total recently lifted force majeure from their $20 billion LNG project there, a decidedly positive development for Mozambique's economic development and for investor confidence as the country continues to develop its energy resources.

In the Mediterranean, current opportunities could require up to 2 incremental rigs in the next 2 years with programs from a number of the major operators as well as local independent energy.

Moving further east to India. The ONGC tender for 1 drillship with a mid-2026 commencement is in progress. And elsewhere in Asia, there are a number of market inquiries, including 2 in Indonesia for multiyear programs starting in 2027.

In Australia, Chevron's Gorgon Phase 3 tender is progressing toward award, which we currently expect in the first quarter of next year. We anticipate there will be 1 drillship and 2 semisubmersibles working in country in 2027.

In Norway, utilization of the high-specification harsh environment semisubmersible fleet is expected to remain robust through 2027 as the award for Equinor's rig tender is expected imminently. This and other projects have commencements in 2027, many of which will utilize contract extensions of the current fleet.

Based upon current planned programs in 2027, the drillship and harsh environment semisubmersible markets are projected to reach active utilization of above 95% and close to 100% respectively.

Operationally, we continue to deliver strong safety and reliability performance for our customers. Indeed, in September, we posted revenue efficiency of 100% and delivered 97.5% for the entire third quarter.

Responsible for these achievements is a uniquely qualified and high-performing team that is focused on delivering the professional and disciplined experience to which our customers have grown accustomed.

Through rigorous procedural discipline, we've built an operational framework that enables us to deliver the same standard of performance on every Transocean rig regardless of where it is operating.

I am also very proud that we continue to set industry firsts. We recently ran the heaviest casing string on record at a hook load of approximately 2.85 million pounds using our eighth generation drillship, the Deepwater Titan.

This achievement showcases what can be delivered with this highly capable generation of asset, unlocking significant well construction and production efficiencies for our customer.

In conclusion, we remain focused on optimizing the value of our assets and services while maintaining a disciplined approach to deploying our high-specification fleet. Our priority is to best serve our customers and continue to generate strong cash flow, supporting our ongoing efforts to strengthen the balance sheet and increase the value of our equity.

We will continue to take steps to optimize our capital structure and financial flexibility.

I'll now turn it over to Thad for further discussion on our transactions, our results and guidance. Thad?

Thank you, Keelan, and good day to everyone. During today's call, I will briefly recap our third quarter results, provide guidance for the fourth quarter and conclude with our preliminary expectations for full year 2026.

As is our practice, we'll provide updated guidance for 2026 when we report our full year 2025 results in February.

During the third quarter, we delivered contract drilling revenues of $1.03 billion with an average daily revenue of approximately $462,000. Contract drilling revenues are slightly above our guidance range due primarily to the Deepwater Skyros, which continued to operate throughout the quarter.

Operating and maintenance expense in the third quarter was $584 million. This is below our guidance range, primarily due to deferred maintenance costs across the fleet and the release of a $10 million provision resulting from the anticipated favorable outcome of a legal dispute, partially offset by severance costs associated with the company's shore-based support reorganization undertaken in August.

Capital expenditures for the quarter were $11 million, also below our guidance range of $25 million to $30 million, primarily due to the timing of payments. G&A expense was $46 million, below expectations due also to timing, but with respect to professional and legal services.

We ended the third quarter with total liquidity of approximately $1.8 billion. This includes unrestricted cash and cash equivalents of $833 million, about $417 million of restricted cash, the majority of which is reserved for debt service and $510 million of capacity from our undrawn revolving credit facility.

All of the proceeds from the recent equity and debt capital markets transactions have since been deployed to reduce and refinance certain debt obligations. Adjusting for these proceeds, our quarter end liquidity would have been approximately $1.2 billion.

I will now provide guidance for the fourth quarter of 2025 and preliminary guidance for the full year of 2026. For the fourth quarter, we expect contract drilling revenues to be between $1.03 billion and $1.05 billion based upon an average fleet-wide midpoint revenue efficiency of 96.5%, which, as you know, can vary based upon uptime performance, weather and other factors.

This guidance includes between $60 million and $70 million of additional services and reimbursable expenses. The slight sequential increase in revenue is mainly due to higher activity on the Deepwater Conqueror, which started its new contract on the 1st of October, partially offset by lower activity on the Deepwater Skyros as it has concluded its work in Angola and is mobilizing to Ivory Coast for its next contract, which starts in December.

We expect fourth quarter O&M expense to be within a range of approximately $595 million to $615 million. This quarter-over-quarter increase is primarily due to the release of the previously mentioned anticipated favorable resolution of a legal dispute, which is not repeated in the fourth quarter and higher in-service and out-of-service maintenance across the fleet, partially offset from the shore-based reorganization implemented in August.

We expect G&A expense for the fourth quarter to fall within a range of approximately $45 million to $50 million. Net cash interest expense is projected to be approximately $122 million for the fourth quarter, comprising interest expense and interest income of about $131 million and $9 million, respectively.

Capital expenditures and cash taxes are expected to be approximately $25 million to $30 million and $18 million, respectively.

Finally, we currently estimate that we should end the year with total liquidity of slightly more than $1.4 billion, including the $510 million capacity of our undrawn credit facility. Versus our prior guidance of $1.45 billion to $1.55 billion, our year-end liquidity reflects the use of approximately $106 million of cash in excess of that provided by the recent transaction to reduce our debt balances.

We expect that at year-end, the remaining debt and capital lease balance will be approximately $5.9 billion, which is net of $80 million of remaining scheduled payments and maturities to be settled with cash.

For 2026, we currently forecast contract drilling revenue to be between $3.8 billion and $3.95 billion. Approximately 89% of our forecasted revenue is associated with firm contracts and the range assumes revenue efficiency of approximately 96.5% at the midpoint. Our guidance includes between $230 million and $270 million of additional services and reimbursable expenses.

We expect our full year O&M expense to be between $2.275 billion and $2.4 billion and we currently anticipate G&A costs to be between $170 million and $180 million. We forecast 2026 cash interest expense to be about $480 million.

Our preliminary projected liquidity at year-end 2026 is between $1.6 billion and $1.7 billion, reflecting our revenue and cost guidance, which incorporates the net effect of our ongoing cost savings initiative and includes our $510 million revolving credit facility, which we expect to remain undrawn and anticipated restricted cash of approximately $380 million. This liquidity forecast also includes CapEx expectations of approximately $125 million to $135 million.

I reemphasize our continued focus on strengthening the company's financial position through disciplined management of our capital structure. In utilizing a combination of equity and debt in our recent capital markets transactions, we were able to reduce our gross debt by approximately $1.2 billion versus scheduled maturities of $714 million, an incremental debt retirement of over $0.5 billion.

This is accompanied by a substantial reduction in annualized interest expense of about $87 million.

The sequence of the capital market transactions also allowed us to achieve the best possible rate, 7.875% on the new 5-year $500 million senior priority guaranteed notes due 2029, below that of the now retired 8% notes that matured in 2027.

Additionally, with the retirement of the 2027 notes secured by the Deepwater Poseidon, we were able to utilize cash that would otherwise have been held in our restricted cash accounts in a more productive manner.

Finally, the tender offer for our discounted 2041 and certain 2028 maturities contributed about $105 million of debt reduction to the total $1.2 billion with associated annual interest expense savings of about $9 million.

In conclusion, we remain committed to a thoughtful, measured approach to liability management. With strong backlog conversion generating incremental free cash flow, we anticipate being able to continue accelerating debt reduction in excess of scheduled maturities.

I'll now turn the call back to Alison to launch the Q&A session.

Thanks, Thad. David, we're now ready to take questions. [Operator Instructions]

[Operator Instructions] We'll take our first question from Eddie Kim with Barclays.

Just a bigger picture question on your confidence level in the increase in deepwater utilization. I think you mentioned 95% or even 100%.

I believe that's exiting '26 and into 2027, if you could clarify the timing there. We've seen a few day rates now below $400,000 a day and there's some investor concern around some more negative day rate prints here in the next couple of months.

First, do you think those are coming? And second, how does that impact your view on this activity inflection higher in the back part of next year?

Yes. Good question. And I think the way I would probably approach I think the 2-part question was one on utilization and the second part was more on rates and how that pressure will exert itself.

I would say our view remains the same, Eddie. We believe that as we turn from the end of '26 into '27, the utilization of the ultra-deepwater fleet will bridge over 90%.

And based on the conversations we're having with our customers, the programs, the tenders that we know are out there, with the long-term fundamentals with respect to the upstream CapEx, we expect to start moving towards offshore. The 2025 was a low FID year and so we expect the number of FIDs to increase as we go forward here into next year.

And the need for oil companies to start exploring to a greater extent. And from my conversations with the heads of wells and indeed some CEOs in the last quarter, that sort of period looks like '27, '28, they're going to start releasing some capital to address those supply concerns.

So we're very constructive on the longer term, certainly from 2027 out. Yes, there is some utilization available in 2026. But those rigs that are on the water, there's quite a few opportunities for those to capture some work.

The question on rate, obviously, as the utilization builds from where we are at the moment, which we would consider to be at the bottom of the trough and I'm sure Roddie will add a few more thoughts on this after I'm finished, we certainly believe that as that capacity is absorbed into the awards that are coming, the rates will be competitive. It's a competitive environment right now as the drilling sector starts trying to build their utilization.

But for the timing of our assets rolling towards the second half of next year, we expect a lot of that activity to be absorbed. And so we consider it a really good opportunity for us to roll some of our rigs that are coming available at the end of the second half of next year and going into '27 and '28 prospects.

And so as you know, utilization when it bridges 90%, that's when the upward pressure starts exerting on rate. So we're very constructive on both utilization and our ability to create value from our assets as we move from '27 out.

And with that, perhaps Roddie has a few more comments to make.

Yes, sure. Sure. Eddie, let me add just a couple of notes to that. So as we think about where we are in the cycle, essentially we were kind of at a low point of contract awards in the first quarter of this year with only about 12 rig years awarded. The second quarter was a bit better at 14 rig years. The third quarter was 18 rig years. So we see the steady increase.

And as Keelan has alluded to, in the fourth quarter, like in Brazil alone, we expect to get 23 rig years awarded. If we think about the other regions, we think Q4 is going to be a very strong contracting quarter and that continues into '26.

So if you think about that in terms of actual utilization, we've already gone through the dip in contracting. Therefore, the increase in utilization is already booked. So this utilization is going to happen. It's kind of in the books at the moment and we think it basically accelerates from there.

There was one other thing I was just going to mention real quickly on utilization. So as we entered the year 2025, we did have some white space on certain assets.

And it's just a phenomenon of our business that on the active rigs, typically, the programs will run longer rather than run shorter and that's for a variety of reasons, whether they're well-related or more often, once an operator has an active rig working, it's very cost-effective to add additional wells to that program.

So we saw that kind of several times for us and it's one of the reasons why our results in the third quarter are so good that we contracted beyond the time line that we had stated in the fleet status report.

So I think on that side, utilization is looking only on the way up from this point forward, which is great. And to Keelan's point again about the rates, certainly, for near-term stuff, we're seeing more competitive numbers.

But I think what's interesting is the time frame in which we are rolling over the rigs is going to allow us to continue our very disciplined approach and making sure that we get value for those rigs. And to be honest, having the highest specification rigs available at a moment when we're transitioning into the busiest time, I think, is a really good position to be in.

If I look at the [ Farley ] charts and other charts, '27 looks -- if all of the probable items come through, then we're pretty close to 100% utilization and potentially above it if there's a big release of budget capital, but we have to wait and see how that pans out. But certainly, utilization and day rates are looking pretty solid from this point forward.

Yes. Maybe one more comment, Eddie. I think when we talk about rates and we look at what's been fixed and what's been announced, I think the seventh gen units, there's been a lot of resilience at around $400,000 a day.

And the competitive environment that's available that's present right now is going to also attract some of the lower spec sixth gen units, which is where you will see some more competitive pricing as the drillers start building more utilization on those assets. But we've been pleased with the resilience of the seventh generation assets have shown when it comes to day rate.

And maybe another follow-up on '26. We're still looking to see what our customers are going to release from a budget point of view for next year. I'll be interested to see what that looks like and how that can be transferred over to the drilling market in '26.

Great. Great. That's great to hear and all very helpful color. Just my follow-up is on your rigs coming off contract soon. You have 4 drillships set to come off contract around kind of early to mid next year, the Skyros, Mikonos, KG2 and the Proteus.

Just based on conversations you're having now for these rigs, would it be prudent at this point to assume maybe 1 quarter of idle time after coming off contract? How should we think about the follow-on opportunity for these rigs and the timing around when that next contract is likely to commence?

Yes, I'll take that one. So we are in discussions on all those rigs in various different manners at the moment. So we don't want to tip our hat to that. But yes, we think -- certainly, there's not going to be idle time in all of those rigs.

There's possibility that there could be on 1 or 2. But as I said before, a lot of these programs, especially around finishing up wells going a little bit longer, but we do have active prospects on every one of them. So that's pretty promising.

And I think something that is obviously not readily apparent to everybody in the industry, except for those that are actually bidding for the work is the number of conversations for work is kind of -- it hasn't been this active and busy for our marketing team for a couple of years. So yes, we're pretty confident we'll be putting on some backlog on a number of those rigs.

Yes. Maybe a little bit more color from my side, Eddie. You mentioned a few rig names. Rigs have reputations and the rigs that we have rolling have very strong reputation.

So the Skyros, for example, Transocean and Total's multiple year winner of Rig of the Year. I mean the rig has performed outstanding on that Total contract for 10 years, even performed 10 years without an LTI in its safety performance.

The reputation of that rig is outstanding and there are several inbounds that we get concerning its availability. If you think about the Proteus you mentioned in the Gulf of America, the Proteus is one of the highest spec units in the world, has performed outstanding as well for its Shell campaign.

So we have a variety of rigs that are rolling. Some are more sixth gen nature and some are much more higher spec. So what you'll see from us is certainly looking to build utilization on our lower spec units.

And when it comes to the higher spec units like Proteus, that's an opportunity for us to remain disciplined. I think we've demonstrated that in the past as the market ran up before this particular mid-cycle lull. And I would say we will be very disciplined in how we approach the Proteus and the sort of work and the term that we put on her, obviously, we want to keep her busy.

But if we don't like particularly the economics that are associated at that time, we'll take shorter stint work. And then, of course, that provides opportunity for small amounts of white space. But that is the consequence of a commercially strategic bidding discipline that we employ, especially with our harsh environment -- with our high-spec units.

We'll take our next question from Doug Becker with Capital One.

Some industry reports suggest Petrobras recently had one-on-one meetings with drilling contractors just to discuss ways to reduce costs. Just wanted to get confirmation, did Transocean have such a meeting? And if so what was the outcome?

I'll offer some commentary, and I'm sure Roddie will add his -- some color as well. Yes, we've been engaged with Petrobras on this topic for a while.

I would reiterate our belief that we do not believe that this cost reduction exercise on Petrobras' part is going to materially change the activity that they have in country. We have a lot of experience across our operations of driving cost efficiencies into the operation on behalf of our customers.

And with respect to Petrobras, we are engaged with the lessons we've learned across our fleet and with various different customers on how to reduce that cost structure. And typically, it's built around things like the number of people on board the rig and simple things like that.

So Petrobras are keen to engage with the drillers on this matter. There are efficiencies to be gained and it's very encouraging to see Petrobras open to having these discussions, looking for more efficiencies and allowing drilling contractors to bring their experience to bear in this environment.

So Roddie, do you want to add anything?

Yes. I'd just add, that's exactly the point. This is actually a welcome effort. So yes, to recap on that, basically, they're looking to take about 7% or 8% out of their cost basis.

And they're doing that in a manner, as Keelan said, there are certain things in the Petrobras contracts that have expense to the contractors that are perhaps nice to have, maybe not essential to the contract.

So if we're able to take some of those out and pass on those savings to Petrobras, that makes their wells more competitive, that stimulates more work. So we think that's a positive effort. And of course, we're very interested in that.

And I think it's off the back of news like Ibama give the approval for the drilling exploration campaign in Foz do Amazonas, which is the North Coast of Brazil. So that's very encouraging for future activity.

But yes, I think their statement is they very much are looking to keep all the rigs they have on contract and just seeing where they can be more cost-effective on certain demands that they have. And of course, we're all over that. I think that's quite positive.

Is it fair to say that discussions were much more about those cost reduction efforts outside of rate? Or is there a desire for some type of concession on price or blend and extend?

Yes. I mean, obviously, we can't talk about specific negotiations that we have with them. But the first focus is on the existing contracted rigs and what they can do to reduce the cost basis. If there is opportunity to add term to some of those, then that's an avenue that I'm sure many will be happy to explore.

That makes sense. And then, Thad, maybe one for you. A lot of steps to reduce debt during the third quarter. What would you highlight as the next few steps going forward and maybe in particular, just the potential for another equity raise down the road?

The short answer is, as Keelan had indicated, we anticipate that we're going to meet all of our obligations out of cash flow from operations. A couple of things I'd like to say on the equity raise. Clearly, it is never an easy decision for management to go to the market. And frankly, there's probably never a particularly good price at which one should issue equity.

That said, I think that the company has had a pretty good track record of treating shareholders as well as it can, particularly with respect to those things that are within our control. We didn't restructure, but with that comes this survivor's curse.

When you look at the things that are encumbrances to our share price, it's 2. It's, frankly, the market and the pace and day rates of contracts. And second, depending upon the day of the week, it's the leverage. It's sort of the survivor's curse.

So we took this exercise to heart. We did a lot of analysis and we did our best to ensure that this is something that we really wouldn't have to do in the future. So our expectation now is with our liquidity profile, our debt maturity schedule, the market conditions that we'll be able to meet our obligations at cash flow.

You should expect to see us deploy any excess cash generated by the cash flow savings that we've talked about, the $250-so million that we anticipate in aggregate achieving in 2026 to reduce our debt balance.

And we'll take our last question today from Noel Parks with Tuohy Brothers.

I was wondering, you were talking about there -- just from discussions that you could see exploratory drilling maybe picking up in that 2027, 2028 time frame. I just wonder if you sort of think about lead time and customers' internal capital discussions, do you have any sense as to when they might -- how far in advance they might start looking at trying to commit to rigs on some of those?

Yes. No, it's a good question. As you know, a lot of the activity that we perform on contracted rigs is largely focused on development, but our customers also squeeze in exploration wells that they have approved in their budgets into the program should the time lines align.

I think the difference that we're seeing now is a real conversation in the world about the need to increase the supply of hydrocarbons.

And if I cite the IEA report that was recently published, they speak about over $500 billion of the upstream investment, 90% of that is used every year to just simply replace the reserves that are being produced, right? And that's not taking into account any of the growth that is anticipated for the world.

So as our customers are noticing that the decline rates in their conventional and also in their nonconventional, which is an accelerated decline rate, there isn't more conversation now about how do we produce that supply that's going to be required.

So as we think about the commodity prices, the macro environment, I think our customers are going to continue to find opportunities in their programs of contracted rigs in '26 to put a few exploration wells in. But the conversations are now changing to a major customer talking about building an entire rig line around exploration in '27 and '28.

And there's more and more of those major customers starting to talk about that. And that's what's giving us an awful lot of encouragement with respect to what we think that will transfer to in rig activity in the out years from '27 on. And that's kind of the subtle difference that we're hearing in the conversations I'm having certainly with our customers.

Roddie, do you have anything to add on that?

No, I think that nails it, exactly that it's been a while since we've had this exploration discussion and I think the broader macro commentary really helps that. And of course, we are seeing that directly with the discussions that we're having with some of our customers.

And there are no further questions at this time. I'll turn the program back to Alison Johnson for any additional or closing remarks.

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

This does conclude the Transocean earnings call. Thank you for your participation and you may now disconnect.