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 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, 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 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 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 zero 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 five 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 one-third of this backlog increase is related to a three-year contract on the Transocean Barents with Vår 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 Vår Energi. In Brazil, three of our ultra-deepwater ships, two 6th-gen and one 7th-gen, were awarded contract extensions by Petrobras.

The sixth-generation drillships, the Deepwater Orion and Deepwater Corcovado, were each awarded three-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 one-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 five-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 multi-year programs improving meaningfully. 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 US 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 five 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 one to two years. In Mozambique, one multi-year program has already been awarded by Eni, with two 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.

In the Ivory Coast, Eni has issued a one-rig tender for a three-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 seven 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 five rig lines to a market that currently only has one 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 four drillships and two 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 Vår Energi, Equinor, and Aker BP. Most operators are already in the market to secure capacity from 2028 onward, 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 multi-year 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 seven 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 US 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 standalone 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 1.5 times 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, I will only make a few remarks this morning.

Our performance during the first three 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 standalone basis. There are only two 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, 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 with 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 Skiros, 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 rigs. Recall that we have escalation provisions in certain contracts to permit some cost recovery.

Where 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 airfreight 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 logistic 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 3.1 times, 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 obligations. Based upon the consensus EBITDA, this would imply a ratio of about 3.3 times 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 standalone basis, in absence of 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.

Hi, good morning. 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 four or five 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 in '23.

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 whitespace which sort of halted that trajectory.

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?

Good morning, Eddie. Thanks for the question.

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.

I think if you recall, 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. Many of our customers starting to lean into the exploration activity that everybody needs to progress.

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. 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 of the world is only amplifying the need for further investment in the offshore space and particularly in deepwater. 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.

Roddie, would you like to add anything to that?

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'd posted a few rates above 500 and what have you, but the context is really important.

What happened at that time is 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. Part of that was part of their push for M&A on their side.

You kind of had this whitespace 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's 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. Basically CapEx spend in offshore and deepwater is expected to approach $100 billion annually by 2030.

If we do it in that context, then I think the upside for us is very significant. There's not as many M&A opportunities available on the operator side, and to Keelan's point, everybody is now looking at exploration.

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 three years, but the 7G rig, the Aquila, was only extended for one year. Just curious if there was some intentionality behind that decision on your end to not lock in your high-spec asset on a multi-year contract in a rising dayrate environment.

I'll take that one. As we've always kind of alluded to, that it's very important to us that we get appropriate value for our assets.

The 6th gens are the 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 are traditionally the barometer of where things are going to go.

When you see those guys go long, that's a pretty good sign for us. Basically in that instance, if you notice how the delta between the average dayrates is pretty significant between the 6th and the 7th gen there.

We're talking somewhere in the region of $50,000 to $70,000. 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.

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.

Now the scoreboard has got fixtures on it, and they're prolific. As Keelan pointed out earlier, we're a third 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. That's before we consider direct negotiations that are not necessarily on the market.

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 6th gens go long and gives us a bit of optionality on the higher-spec units as we move forward.

Great. Thanks for that color, Roddie.

I'll turn it back.

Hey, team. Hope you are well.

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 we've had, even above 2023 levels. Something is happening, and I'm happy to see that.

Today, my question relates more to the M&A process, the acquisition of Valaris. You gave some color on that in your prepared remarks, Keelan, but I was hoping that you could potentially elaborate a bit more on what this second request actually means.

I guess, my question and potential questions from investors as well is implications on potential deal risk. You still said confidence in the second-half closing, but is that timeline potentially a bit delayed now compared to what was the case before, or what does this potentially mean for remedy sales, etc.?

I'm not trying to kind of be a devil's advocate here, just trying to get clarity on what this actually means, even though it seems like most deals that have received second requests ends up going through anyway. Any color you could give would be super helpful and appreciated.

Thank you.

Sure, Fredrik, and thanks for the question. 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. 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 US Gulf and the market worldwide. Those conversations have been going very well.

No, there's no read-through. I would suggest to you that when we declared what timeline we believe this transaction would close in, we're still in that window and very much believe 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.

Right. Thank you very much.

Just as a follow-up, I think you said Saudi and Trinidad, you'd cleared approval already, and then in addition to the US, it was Angola, Australia, Brazil, and Egypt. Are there any risks 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 were already having are, call it on the track that you originally perceived?

Fredrik. It's following the exact process and timeline 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.

All right. Very very helpful color, appreciate that.

That's all for me. Thank you.

Thanks, Fredrik.

Hey, thanks. Good morning, guys.

Ian Kutz here from Morgan Stanley. I just wanted to ask, you guys had shared a couple 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 would be to reactivate a rig, the timeline, and potentially what type of contract terms or macro backdrop you would need to see to move forward with that decision. Thank you.

Good morning, Ian. Thanks for the question.

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-stack reactivation of a deepwater drillship right now.

In a few years, maybe slightly different. I would say to you from a cost perspective, we're still in that $100 $100 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 timeline it would take to bring one of them back to market. We're still in the 12 12- to 15-month range, I would imagine, to reactivate and bring one of those rigs back to service.

When you think about the sort of macro and the market dynamics that are needed to support that sort of one Remember, we're not going to do that speculatively. We're going to want a contract that fully recovers that cost and a return on top of that.

The market visibility, the future term, the timeline, and the lag it takes us to get that rig ready, we're not quite there yet. 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.

You can imagine that we would be looking for term and a productive dayrate for that to happen. Roddie?

I would just add to that, you talk about the term and the return economics being very important. 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.

That's still not enough, in our view, to bring out one of the cold-stacked assets. It's really encouraging to see a doubling of duration and effectively a 4x multiple on how many fixtures are in the market and being fixed today.

We still think there's plenty of room to run before we reactivate the cold-stacked fleet.

Great. All really helpful.

Then maybe kind of a higher-level question. I think you guys have 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 a couple quarters ago and it was just kind of the macro playing out as expected.

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 two months in the Middle East. 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 head-flagged that the ONGC and the India activity was something that you discussed on your last call, but you were throwing out some pretty big numbers in Indonesia. Just wondering if you could parse out any areas where you see incremental kind of need or incremental just demand that's more related to diversifying away from Middle East exports.

Thanks.

Ian, I think, obviously the conflict is not that long at the present moment in time, but the 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. I think you've probably highlighted a couple that come to mind straight away: India, I think Prime Minister Modi is obviously set his government in motion with a mission to establish what the nature of their reserves in-country are.

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 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. 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?

I love to add to that that, again, we're 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. The tenders that are on the market today, which, collectively we think with the awards already and then what else is to come, it's 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.

Again, 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. All of that was predicated on $60, $70 barrel outlook, but now we're obviously in a much different position.

I think that's going to be fantastic for our customers in terms of earnings in the near term. All of the fixtures 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.

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

Great to hear. Thank you all.

I'll turn it back.

Hey, thank you, and good morning. Thanks for taking my question.

I was hoping to spend a little time talking about the harsh weather market. Clearly, it's good to see the Barents move back to Norway.

It's interesting, right? Because we have the traditional North Sea, but yet, 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. Really, as you think about positioning Transocean's harsh weather fleet, not necessarily for '26, but as we think about '27, '28, are we expecting more of a return to the North Sea?

Are there going to be opportunities to kind of keep this fleet spread in and beyond rig, but like the other players in this market, to kind of keep everybody busy? There was another company that had to spend a bunch of money to upgrade a rig.

How tight could we be for the harsh market as we approach 2028?

Good morning, Greg. The harsh environment is a market that we've obviously been forecasting for a while.

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. You're right.

The harsh environment market is no longer just Norway, and it's returning to places like Canada and Australia. 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. We're not even considering what could happen in Namibia.

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

We're very pleased to be beginning that relationship with Vår Energi again. 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?

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. Not necessarily in a position to put a large commitment on the 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 follow-on of existing rig.

Then you've seen within Norway itself all the big guys making commitments, Vår, 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.

Those are really good fundamentals underpinning that market that means we will be there for a long time. 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.

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. We're feeling really strong about that and 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.

I think it's almost a necessity.

Super helpful. Thanks for taking my question.

Thanks, Greg. Thank you.

Hi, good morning. I was intrigued about what you were saying about exploration conducted long ago, some of those projects actually now heading for development.

Just for perspective on that, just top of your head, can you sort of think of what maybe the oldest, longest-in-the-tooth past exploratory project that you're now seeing being green-lighted for development?

That 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. Nigeria is expected to go up to five rigs, and they'd gone down to one rig.

A lot of 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. Some of that may even be as long as eight 10 years ago, but certainly it's stuff that was done, yeah, it's at least five years ago.

That's probably a great example there. Kind of a shorter example on the opposite end of the scale might be something like Namibia.

You would have seen lots of announcements about discoveries in Namibia, and then there was kind of a lull in activity as all the results were digested. Now we're seeing several long-term tenders there that are all based on development.

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. It's the 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.

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, thanks. I was wondering if you had 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'm just wondering if the improved economics, assuming that we do have sustained higher oil prices, are there any regions where you can anticipate that maybe 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 just wondering.

It's definitely a theme, right? I would say that as you see the war breakout in the Middle East there, I actually think it just reinforces the decisions that have already been taken.

For the last several years, that's kind of been the process that all the big guys are going through. 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.

There's definitely an element to that. I think overall that energy security question, it's important, but I think it's more a case of reinforcing good decisions that were made for domestic exploration.

To Keelan's point, he made a great point about India. That's a kind of a top one there.

Even in places like the UK, 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 almost inevitable that will shift in the near term. I also think the Norway thing's 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. 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. Time to just get on with it.

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. The activity we're getting today is based on the fundamentals regarding supply and demand of hydrocarbons, the concern on replacement of reserves and the need to explore to do that.

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. Obviously it's a very good place to get affordable, secure, and reliable energy.

We continue to see it playing that role going forward.

Great, thanks a lot.

Thanks, Noel.

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.