Transocean Ltd. Aktie

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.

Good day, everyone, and welcome to today's Q2 2025 Transocean's Earnings Call. [Operator Instructions] Please note this call may be recorded. [Operator Instructions] It is now my pleasure to turn the conference over to Alison Johnson, Director of Investor Relations. Please go ahead.

Thank you, Stephanie. Good morning, and welcome to Transocean's Second 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. n

Joining me on this morning's call are Keelan Adamson, President and Chief Executive Officer; Thad Vayda, Executive Vice President and Chief Financial Officer; 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. [Operator Instructions]

Thank you very much. I'll now turn the call over to Keelan.

Thanks, Alison, and welcome, everyone, to our second quarter conference call. As always, we greatly appreciate your interest in Transocean. I want to open today's call by sharing a few of Transocean's key priorities. We are intently focused on several interrelated objectives with outcomes that are entirely within our control, and we are addressing them with urgency and agility.

First, and foundational for everything we do is delivering best-in-class services for our customers. Transocean is the partner of choice for operators, requiring expertise in the most technically challenging ultra-deepwater and harsh environment regions of the world, and we are committed to providing the safest, most reliable and efficient operations everywhere all the time. Next, we will continue to manage our portfolio of high-spec rigs in a disciplined and selective manner, endeavoring to extract the greatest value possible from our unique fleet.

And lastly, but also of paramount importance, we will continue to improve our overall financial flexibility. To do this, we will achieve and maintain the most efficient cost structure possible. We will reduce total debt as rapidly as we can, minimize interest expense and ultimately simplify our balance sheet. Transocean is differentiated from the competition by both its people and its assets, and our customers trust us to deliver in the world's most technically demanding environments.

Operators select Transocean because of the exceptional synergies created by our people and our assets, leveraging our technology and innovations to drive consistently high performance. This powerful combination is our value proposition, differentiating our product for both customers and investors. We take exceptional pride in being the preferred offshore drilling provider and being recognized for delivering the highest quality and most efficient solutions. Just last week, Beacon Offshore Energy announced it commenced production from the Shenandoah field, which was drilled by one of our 2 eighth-generation 20,000 psi drillships, the Deepwater Atlas. This is the second 20,000 psi reservoir to come online using Transocean's ships.

We are excited to be part of this achievement and thank Beacon for placing its trust in Transocean to accomplish this important milestone. Our high-specification ultra-deepwater and harsh environment fleet is unmatched, attracting an industry-leading backlog of approximately $7 billion. Under all market conditions, our fleet has maintained higher average utilization and premium day rates. We believe that we have a very effective and successful commercial strategy. We are continually evaluating market dynamics from a supply and demand perspective, carefully assessing individual opportunities to ensure we are deploying each asset into the right project at the right time.

You should expect us to continue to be disciplined and strategic in applying this portfolio approach to the management of our fleet to maximize EBITDA and cash flow. Regarding our efforts to improve our financial flexibility, recall that last quarter, we announced a plan to sustainably reduce our cash costs by about $100 million in each of 2025 and 2026. This reduction is primarily from our fleet operating and maintenance expense, and we are on track to deliver these savings. As should be the case, we strive for continuous improvement. And accordingly, we have taken additional steps to improve the efficiency of our shore-based organization and expect to reduce these costs by approximately $50 million on an annual basis beginning in 2026.

Importantly, these actions will not, in any way, compromise safety, customer service or the reliability of our rigs. We understand the importance of financial resilience to effectively weather the inevitable cycles in this business and generate appropriate returns for our shareholders. We have a clear path to delever significantly over the next few years, addressing our debt obligations by efficiently converting our industry-leading backlog to revenue and maximizing cash flow to equity. We remain on track to reduce debt by more than $700 million this year. We will continue to take a disciplined approach to managing our balance sheet, carefully assessing how each action fits into our long-term financial strategy.

Moving now to our outlook for the global market. With an active fleet mostly contracted through the middle of next year, we are actively working on opportunities for the second half of 2026. While the pace of contracting activity has been measured since the middle of last year, all projections suggest we are nearing the end of this temporary slowdown. Indeed, we are engaged in multiple conversations with customers on attractive opportunities for work well into the future and have a line of sight to a number of forthcoming tenders, which I will discuss after a brief recap of our recent fixtures.

In June, we issued a press release disclosing that a 2-well option was exercised on the Transocean Spitsbergen. The option, which was struck at a rate of $395,000 per day, ensures the rig has continuous work through August 2027. Next, in Brazil, the Deepwater Mykonos was awarded a 60-day contract extension. The agreement also includes multiple options, which, if exercised, would keep the rig working into next year.

And finally, in the Ivory Coast, Murphy awarded the Deepwater Skyros, a 3-well contract. The program is expected to commence late this year and includes a 1-well option that, if exercised, would keep the rig working into the second quarter next year. We continue to expect the market to tighten by late 2026 and into early 2027, at which point we expect the global active ultra-deepwater fleet will once again approach utilization exceeding 90%. This should result in upward pressure on day rates. Third-party analyst data supports our view. Wood Mackenzie's latest analysis shows deepwater and ultra-deepwater development CapEx rising from $64 billion in 2025 to $79 billion in 2027, a 23% increase. And in their latest commentary, both Fearnley Offshore and Westwood Global Energy Group noted that commencement dates for pent-up demand have firmed up and for the most part, stopped sliding to the right.

For the ultra-deepwater drillship market, the primary source of incremental demand is still expected to come from Africa, the Mediterranean Sea and Asia. If known programs materialize as currently projected, there could be an incremental 4 drillships working in Africa in 2027 and an additional 2 in the Mediterranean. We are optimistic that commencement windows for these programs will continue to remain generally stable as many of them are progressing through the tender process. For example, of the 3 multiyear opportunities set to commence in Mozambique in 2027, has been released, one is in the RFI stage and one is pending release, which is expected by the end of September.

Moving east to the Asia Pacific region, current tenders indicate up to 4 incremental drillships will be required in the next 2 years, including the Chevron Gorgon prospect in Australia, which is expected to commence in the first quarter of 2027. This will be the first time in 7 years a drillship has operated in country. Demand in India also points to additional drillship as ONGC, Reliance and Cairn each have programs in this time frame.

And finally, tenders for the remainder of Asia will likely require the rig count to move up from 3 active drillships today to 5 in 2027. Activity levels in the U.S. Gulf, Latin America and Brazil are expected to remain relatively stable. Since our first quarter 2025 earnings calls, bids were submitted for Petrobras' Buzios program and Petrobras released the tender for its Merrill project, which is a firm duration of nearly 4 years, expected to commence in the first half of 2027 for at least 1 rig.

With respect to the previously mentioned Buzios tender, it is possible that 4 rigs could now be awarded rather than up to the 3 originally anticipated. Additionally, Shell is currently evaluating bids for the Gato do Mato development and Equinor released an RFI for a 1-year program with commencement likely in the first half of 2026. Furthermore, just this week, BP announced their biggest discovery in 25 years at the Bumerangue block in the Santos Basin and indicated its intention to perform additional appraisal activities. The projected demand for harsh environment semisubmersibles remains strong in Norway and elsewhere internationally.

As a reminder, our 4 rigs in Norway, the Transocean Spitsbergen, Transocean Norge, Transocean Encourage and Transocean Enabler are fully committed into 2027. In the U.K., on top of BP West of Shetlands, Ithaca is also looking for 1 rig for its Campbell development, a 900-day program that starts in the same time frame. In the Orange Basin, meaning Namibia and South Africa, operators will soon begin the development phases of their discoveries, which will require at least one additional harsh environment semisubmersible. We expect a tighter global market to develop in the next 2 years. However, at this time, we do not see a compelling case for reactivations of cold stacked units. Hence, our decision in the second quarter to remove 4 lower specification rigs from our fleet.

We continuously assess the option value of our cold stacked rigs to ensure we maintain the best and most competitive fleet to meet our customers' requirements. All else being equal, supply rationalization structurally improves industry dynamics. Including 4 of our own, a total of 11 rigs have been retired from the global fleet this year, and we believe it is reasonable to expect additional attrition in the near term. Industry consolidation could help facilitate further reduction in rig supply, which would contribute to a more balanced industry.

With that, I will now hand it over to Thad to discuss our results and guidance. Thad?

Thanks, Keelan, and good day to everyone. During today's call, I will briefly recap our second quarter results, provide guidance for the third quarter and conclude with an update of our expectations for the full year.

During the second quarter, we delivered contract drilling revenues of $988 million, in line with our guidance at an average daily revenue of approximately $459,000. At $599 million, our operating and maintenance expense in the second quarter was below our guidance, primarily due to lower costs resulting from delays in in-service maintenance across the fleet and lower-than-expected costs for out-of-service projects on Transocean Endurance and Deepwater Invictus.

G&A expense in the second quarter was $49 million, again, in line with our expectations, and we ended the quarter with total liquidity of approximately $1.3 billion. This includes unrestricted cash and cash equivalents of $377 million, $395 million of restricted cash, the majority of which is reserved for debt service and $510 million of liquidity from our undrawn credit facility.

I'll now provide guidance ranges for the third quarter and an update on our expectations for the full year. For the third quarter, we expect contract drilling revenues to be between $1 billion and $1.02 billion based upon an average fleet-wide revenue efficiency of 96.5% on our working rigs. As you know, revenue efficiency is affected by uptime performance, weather and other factors. This revenue estimate also includes between $60 million and $70 million of additional services and reimbursable expenses, which tend to carry low single-digit margins. The expected sequential increase in contract drilling revenues is primarily due to additional in-service days for the Transocean Spitsbergen as it completed its 15-year SPS in June and 1 additional calendar day in the third quarter.

These are partially offset by lower projected activity for the Deepwater Skyros and Deepwater Conqueror in the period. We expect third quarter O&M expense to be within a range of $600 million to $620 million. This slight quarter-over-quarter increase is primarily due to the timing of in-service maintenance across the fleet, partially offset by completion of Transocean Spitsbergen's 15-year SPS in the second quarter. We expect G&A expense for the third quarter to fall within a range of $50 million to $55 million. Net cash interest expense for the third quarter is forecasted to be approximately $136 million, comprising interest expense and interest income of about $143 million and approximately $7 million, respectively.

Capital expenditures for the third quarter are expected to fall between $25 million and $30 million, and cash taxes to be paid are expected to be approximately $16 million. For the full year 2025, contract drilling revenues are now expected to fall between $3.9 billion and $3.95 billion, primarily reflecting potential variances in revenue efficiency. Our guidance also includes between $255 million and $265 million of additional services and reimbursable expenses. We expect our full year O&M expense to be between $2.375 billion and $2.425 billion. This is somewhat higher than our previous guidance, primarily due to increased reimbursables and the effects of foreign exchange. Both of these expenses are offset by increases in revenue.

G&A costs in 2025 are expected to be between $190 million and $200 million, slightly higher than previously forecast, primarily due to certain performance-related accruals. For the full year, we are anticipating net cash interest expense between $540 million and $545 million, comprising interest expense and interest income of about $575 million and between $30 million and $35 million, respectively. This excludes any impact from the bifurcated exchange feature of our 2029 exchangeable bonds. Cash taxes for the full year are forecasted to be between $70 million and $75 million. We now expect 2025 capital expenditures to be approximately $120 million, slightly above our prior guidance due to customer upgrades that are fully reimbursed.

Of this, approximately $55 million is related to customer required capital upgrades for upcoming projects and capital spares and approximately $65 million in sustaining capital investment. Our liquidity at year-end is forecasted to be between $1.45 billion and $1.55 billion, consistent with my prior guidance. This reflects our revenue, cost and capital expenditure expectations and includes the impact of our cost savings initiative, our undrawn revolving credit facility and restricted cash of approximately $440 million.

In late June, we announced we had entered into separate agreements with certain holders of our 4% senior exchangeable bonds due in December of this year to exchange an aggregate principal amount of $157 million. Upon completion of these transactions, 59.4 million shares were issued. Approximately $77 million in aggregate principal amount of the bonds remains outstanding. Our liquidity forecast currently assumes convertible instruments are equitized at maturity. But as the remaining 25 EBs are out of the money, we will evaluate the various options available to us to address this stuff.

With respect to tariffs, we continue to monitor this fluid situation and have not included any potential impact in our guidance because we currently do not expect the impact of either direct or indirect tariffs to be material. This concludes my prepared remarks, and I'll now turn the call back to Keelan for his final comments before we begin Q&A.

Thanks, Thad. Before opening up the line for questions, I want to reiterate that we are focused on addressing several key priorities with urgency and agility. Our team is committed to best-in-class services for our customers. We worked hard to earn their trust, and we intend to keep it. Our asset portfolio is unrivaled. We will continue to take a long-term view on the market and remain disciplined as we consider future contract opportunities.

As you can tell from today's comments, our outlook for late 2026 and beyond is very constructive. Lastly, we are strengthening our balance sheet and improving our capital structure. We have high confidence in our ability to add to our backlog, and we intend to efficiently convert it into revenue, maximizing cash flow to reduce our debt as quickly as possible. In conclusion, we are deeply committed to delivering for our customers and shareholders. We have a strong team focused on executing a clear plan to create long-term value.

Alison, please open the line for questions.

Thanks, Keelan. Stephanie, we are now ready to take questions. [Operator Instructions]

[Operator Instructions]

Our first question will come from Eddie Kim with Barclays.

Just wanted to ask about your expectation on the trajectory of leading -edge day rates here. We've been in sort of the mid- to high 400s for some time now, but have recently seen a moderation into the low 400s level. You provided a very constructive market outlook and mentioned in your prepared remarks, you do see utilization of drillships reaching 90% by, I think, late next year. So fair to say you expect leading-edge day rates to return back to that mid- to high 400s level by end of next year? Or just curious on your thoughts on the trajectory there.

Ed, thanks for your question. As you know, we have a history of being very judicious in how we apply and select and deploy our assets into whichever project. And I think what you're seeing today is some of the white space that we all anticipated. It's no surprise to us that we were there, that some of those rates are probably a little bit lower than what we've seen in the past. And I think what we're going to see going forward is that capacity being absorbed. The future projections for activity is very, very positive. We're going to see more of the active fleet being contracted.

And as we move out into the end of this year and into 2026, we're going to see a lot more contracting activity and tendering activity for the out years of '26 and beyond. As it pertains to rates, I'll let Roddie pertain -- let him express his view on where the rates we think will go right now.

Eddie, yes, so just to follow up on Keelan's comments there. So as we think about the utilization, as you mentioned, we dipped down a little bit here. We're actually expecting that the bottom of this [ V ] is practically speaking, upon us. So we think that utilization is going to bottom out somewhere in the mid-80s as a percentage which is only for a relatively short period of time. And I think if you look at all the projections and certainly a lot of the things that Keelan touched on, we would expect things to recover from there.

One of the things that we mentioned about day rates is not just being very disciplined on what we're bidding, but it's the overall economic package on these tenders that we're evaluating. We have a very robust process between our various groups, our engineering group, our operations group and several other departments of the company. But it's very important to us that we take the holistic view that we look at all of the expenses that are associated with these tenders. And typically, the bottom of the [ V ] is when the worst deals are made. So we apologize for not making as many long-term deals right now. We're much more focused on gap fillers at the moment. But certainly to drive long-term value for the company, we don't think now is the time to aggressively pursue long-term deals, especially those you've seen some recently announced that had a very significant amount of upgrades required. But rest assured, we'll remain disciplined in that regard and make sure that we're very aware of all of the expenses associated with projects and upgrades.

Yes. Maybe just to add to that, Eddie, as you rightly point out, utilization needs to bridge that 90% mark, maybe a little below that before we start seeing good pressure on day rates. So as we move through the year and the contracting continues, you should expect the rates to improve. Certainly, from our side, we'll be looking at it strategically from a term and location and a customer perspective to drive the best value that we can get from our unique fleet.

Got it. My follow-up is just on the Proteus and the Conqueror, 2 of the drillships that are currently in the Gulf of Mexico and set to come off contract kind of mid to late next year. We've seen a handful of multiyear contracts signed by your peers in the Gulf of Mexico recently. And just based on your outlook for that region to be kind of stable going forward, do you expect it's likely that those rigs will stay in the Gulf? Or could they move elsewhere?

I think Roddie is jumping at that one.

Yes, we do expect them to stay in the Gulf of Mexico. We have customers who are quite interested in that class of asset, and we're pursuing a couple of different things at the moment. So we are cautiously optimistic that those rigs will be extended right where they are.

And maybe just to add to that, Eddie. You're talking about 2 of our highest spec units in the fleet and in the world's industry. The Conqueror is right at the top, right behind our eighth generation units and the Proteus has obviously been performing really well for our customers. So our crews, our operation from those rigs is stellar. And I'm sure there'll be a significant demand for those 2 assets.

Our next question will come from Doug Becker with Capital One.

Maybe a couple for Thad. Just curious on potential proceeds from some of the rigs that are slated for disposal. And just what are the assumptions embedded in the liquidity expectations that were laid out?

Doug, we do have some nominal amount included in the liquidity forecast. I don't think we've disclosed the total amount for the rigs. But generally speaking, when rigs go to recycling, it's about a cash breakeven type of a transaction. So in the ballpark of probably $8 million to $12 million per asset, generally speaking.

Certainly, if we have an opportunity to transact and to dispose of those assets into alternative functions, those numbers could be higher, but we would announce that as and when that would happen.

Got it. So don't assume anything beyond kind of breakeven at this point?

That's correct.

And in the past, you've given some color on when we might get to 3.5x net debt to EBITDA. Just any update on those assumptions and certainly appreciate it's been an uncertain market.

Yes. No change. The objective is to achieve that metric as soon as possible so that we have the option to consider distributions to shareholders. Generally speaking, I think we're probably still in the late 2026 time frame for that.

Our next question will come from Greg Lewis with BTIG.

I wanted to pivot a little bit about this. Kind of curious on your views. I want to go back a couple of years ago when you contributed that -- I believe it was the Olympia for deep sea mining. Kind of curious, just given what we're reading in the news more recently over the last couple of months, like what -- where does that -- is that something that Transocean is still involved in? And if so, maybe could you maybe provide some updates around that?

Yes. Thanks, Greg. Yes, we're -- obviously, as you picked up, the Olympia is still in that arrangement that we have. We're seeing a lot of press as you are on deep sea minerals and potentially the U.S. administration pushing to advance their agenda in that regard. I'll push it over to Roddie here. He's responsible in that area, and will answer your question.

Yes. So we continue to pursue our technical solutions for doing this kind of recovery. But yes, having that asset in the JV is very useful for us also gives us that optionality. But these things do take a little bit of time. We have to be honest about that, but we are excited to at least have that adjacency available to us. And should it take off, if it does, then there is the possibility of additional vessels going in there. Typically, there would be our kind of lower specification drilling rigs that are actually perfectly adequate and actually quite well specified for this kind of a venture should it take off at some point in the future.

Yes. And I think, Greg, the -- as Roddie indicated, obviously, it's a fairly elongated process, and it has to go through a lot of regulation. So when you look at our core business and you see what the drilling activity looks like it's projected to do in the next couple of years, we're very focused on the core business and maximizing our opportunities in that.

Okay. Great. And then just realizing your fleet is very well contracted. But I guess there does seem to be -- so I mean, I guess it's not maybe a specific question to Transocean, but maybe about the market, which is kind of indicative of maybe where we're headed. Could you maybe talk about, as you look out over the next 2, 3 quarters, any things we're seeing in terms of spot activity? And are there certain pockets? Is it certain types of customers? Is it exploration? Just kind of if there are any kind of spot tenders or they're not even tenders, right? Spot jobs you're tracking, what's kind of the makeup of those?

Yes, sure. I'll take that one. Yes, so there are a number of spot jobs, and you would have seen that we picked up a couple of them, basically an extension of one of the rigs in Brazil and also picking up the Murphy work in Ivory Coast. As we look at that kind of stuff, there's been several in the Gulf of Mexico that we think are just kind of add in wells. Typically, when you have a mature basin that has a lot of prospects, a lot of development there, there's often work that comes up to kind of do remedial work on wells or recompletions of that kind of stuff or stimulations to increase production.

So we have seen plenty of those happen over the past couple of years. We know that there's several others in places like West Africa, which in general, is actually looking really positive at the moment. We've got -- there's kind of 4 tenders coming up for Nigeria or I think one of them has been awarded already, but Mozambique has got 3 and Ivory Coast has got 2 and Ghana has got 2.

So there seems to be quite a lot of stuff there in terms of decent long-term activity. And we are seeing a number of these kind of 6-month opportunities, just like the one we just signed that pop up in places like that. So it makes a lot of sense for rigs that either have those longer-term contracts available to them or are kind of rolling off hot rigs at that time frame, then it's kind of a win-win between the contractors and the operators to pick up an operational hot rig that's doing well and punch out a few wells.

We'll take our final question from Noel Parks with Tuohy Brothers.

I was just thinking about compared with where things stood heading into 2024 when we had such bullishness around prices and hitting new hurdles on the upside for day rates and where we are now, where you see good visibility to 2026 being hopefully the wrap-up of the slowdown. So with the benefit of hindsight, would you say this sort of slower couple or 3 quarters is more typical of a service driller business cycle? Or would you say it was more kind of like a ripple effect of sort of flow-through from the dislocations of the pandemic. Just curious your thoughts on that.

Yes. Thanks, Noel. No, I wouldn't characterize it as conventional cyclical activity in our business, I don't think. I mean, you have to look at the rates and what we've set, and we're nowhere near those rates that we were in the pandemic period or even before then. The rates are very, very solid, albeit a little less than what we saw in the last couple of years, and that's simply because we have a little white space. There are some rigs rolling off. There's opportunity. I think there's been a lot of capital discipline based on volatility in the market space, whether it's related to tariffs or related to OPEC or related to oil production and needs. So no, not at all.

I think as a reminder, the Deepwater game is a long play. The reserves are big. The investment is large and the lead times for the work and approval process is quite extensive. And so I think the projections are all pointing towards our operators, our customers are starting to get back into the FID process. They look at it with a long view on oil price and what the world's demand for hydrocarbons looks like. And all of those are positive indicators for continued constructive growth right now. Roddie, do you have anything?

Yes. I think I'd just add to that to say from the operator's point of view, there is a significant amount of turmoil and chop on the commodity price these days. So it's a relatively simple decision to push out noncritical investments another quarter, another 2 quarters just to wait and see what happens. But the one thing that, that does is it kind of adds to that pent-up demand. So it kind of puts you in an interesting spot because you have the possibility of a number of the rigs that have white space ahead of them, particularly if they're a little lower specification, then there's a real chance there that those rigs may be retired.

So I think one of the effects you're going to see is rather than the drilling contractors spending a tremendous amount of money on assets that they're trying to bridge a significant period of time, they're far rather more likely to pull those off the market, retire those rigs, which ultimately is going to help the supply and demand and the balance there when we do get a busier time. But I would say, actually, we're looking at the number of tenders that we're answering and we've heard our competitors say the same thing, there really is a tremendous amount of potential out there.

So again, we reiterate that -- there's probably a few bargains to be had in the short term. But for long-term work, it makes all the sense in the world that the day rates will be solid going forward. I can't really see how that would degrade materially. And to Keelan's point, we may have seen a 10%, 15% drop in rates over the last couple of quarters. But already, we see some more solid rates are expected to come out as that '27 time frame gets super busy. We expect to see the pickup beginning late '26. And I think you'll see a lot of those tenders answered and announced in late '25.

Terrific. And I'm just wondering, with the we've been seeing these, I don't know if you call them green shoots of greater exploration activity happening across the industry. And you did touch on exploration briefly a bit earlier. But I was wondering, with the BP Bumerangue find, anything you see as sort of unusual or intriguing about that project? And I wondered if -- other than the general trend of hopefully exploration picking up, do you see any implications from that success for either industry activity, CapEx levels?

Yes. Yes, for sure. I mean if you think about -- just take the Bumerangue discovery. So it's a big discovery, obviously, BP saying it's the largest in 25 years. That's a really interesting position that you find Brazil in now. So Petrobras, as you know, is out to tender on several different things, and they've kind of picked up the pace on that. And I think that's partially in response to how many opportunities there are with the IOCs. So that's a relatively new development in Brazil. But we're looking at tenders from Shell at the moment. We're also expecting BP has some additional work that some of it has already been announced and some will probably come as a result of this latest discovery.

As you know, we are currently in the throes of the Buzios tender and the [ NEO ] tender is out now. I think what's interesting in that is the kind of the indications are that there could be maybe one extra rig than originally thought being used for the Buzios tender. And of course, with the Equinor tender that's out just now, that was kind of incremental demand as well. So you're kind of seeing these green shoots looking very interesting. There is -- to your point about exploration, there is actually a reasonably good increase expected in exploration wells to be drilled in '26 and '27, about a 25% increase each year.

So it appears that as the operators are really shifting their focus back to oil and gas, kind of retooling, if you would, to move into the profitable core business. We are certainly beginning to see those green shoots show up in these kind of prospects.

Yes. And I think exploration activity increasing is great success is even more important and having quite a bit of success recently, BP and some of their exploration activities as are some of our other customers. And that only bodes well for absorbing capacity in the market, whether it's in Brazil or Africa or elsewhere around the world. And so yes, we see it as a big positive.

This does conclude our question-and-answer session. I'd like to now turn it back to Alison Johnson for any additional or closing remarks.

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

Thank you, ladies and gentlemen. This does conclude today's presentation. You may now disconnect.