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President and Chief Executive Officer — Keelan I. Adamson
Executive Vice President and Chief Financial Officer — Thaddeus Vayda
Executive Vice President and Chief Operating Officer — Roderick J. Mackenzie
Head of Investor Relations — David Kiddington
Keelan I. 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, Thaddeus will make a few comments on our financial results and guidance. First, the quarter. Operational performance was very strong, with 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 Barron 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 Barron 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 sixth gen and one seventh 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 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 Ltd.'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 remains 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 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 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 multiyear 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 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 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 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 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 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 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 Ltd. 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 Ltd.'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 Thaddeus to provide some brief comments on our financial performance and guidance. Thaddeus?
Thaddeus Vayda: 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 90.5%. 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 cost, 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 4. Our earnings report includes guidance for the second quarter and only slightly updated guidance for the full year for Transocean Ltd. 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 or 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 Barron 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. 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%–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, that 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 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 twelve-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 standalone 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?
Keelan I. Adamson: Thanks, Thaddeus. 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 will now open the call for questions.
Operator: Thank you, Mr. Adamson. Ladies and gentlemen, at this time, if you do have any questions, please press 1. Additionally, you can remove yourself from the queue by pressing 2. As a reminder, we do ask that you please limit yourself to one question and one follow-up. We will go first this morning to Eddie Kim with Barclays.
Eddie Kim: 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 feels like the market is tightening based on 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, 2020 and 2021 were extremely challenging years for the market, but things started to turn in a big way in 2022 and 2023. By mid-2023, leading-edge rates were in the mid-$400,000s with an expectation that pricing could exceed $500,000 a day by the end of that year.
Unfortunately, we ran into some industry white space which halted that trajectory, but nonetheless 2023 was a very strong market environment. Based on how you see things now and the customer conversations you are having, do you think the market environment next year in 2027 could be as good, if not better, than it was in 2023?
Keelan I. Adamson: Good morning, Eddie. Thanks for the question. As you look at the business and the current situation in the world, we are not seeing an impact per se of what is happening today. What we are seeing is the development of a market that we were forecasting prior to any of the recent conflicts. As an industry, we have been talking about improved tendering opportunities, growth in the market, a real concern about hydrocarbon demand and more so about hydrocarbon supply, and many of our customers starting to lean into the exploration activity that needs to progress. We are seeing the results of that in the number of awards that have been announced year to date.
The term of those awards has nearly doubled, and we are starting to see what we expected to happen with respect to rig utilization into 2027. We said we expected 90% utilization into 2027 and then improvement from there. The activity and the forecast are being realized from our perspective. The continual concern with energy security is a real topic of conversation around the world and is amplifying the need for further investment in the offshore space, particularly in deepwater. Utilization is building, backlog is building, and the rate progression will reflect the supply and demand dynamics that exist in the industry and the visibility for future work. Roddie, would you like to add anything to that?
Roderick J. Mackenzie: Yes, probably just to pick up on one of the things that you mentioned. In the previous run-up, we kind of stalled out—yes, we posted a few rates above $500,000, but the context is important. We hit a bit of a global economic bump that coincided with a moment when many of the majors were focused on capital discipline, and part of that was their push for M&A. That created white space. The difference now is that at that time there was still a heavy skew towards shale, but now everything is pointing towards offshore. Offshore CapEx is going to be a much larger chunk of the pie, going 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. In that context, the upside for us is very significant. There are not as many M&A opportunities available on the operator side, and to Keelan’s point, everybody is now looking at exploration. Basins that were previously explored and had discoveries are now shifting to development, and on top of that, we are adding a lot of exploration work.
Eddie Kim: Got it. That is very helpful color, and that is a great point on the changing mindset of the majors. My follow-up is on the Petrobras blend-and-extends. They 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. Was there some intentionality behind that decision on your end to not lock in your high-spec asset on a multiyear deal in a rising dayrate environment?
Roderick J. Mackenzie: Yes. As we have always alluded to, it is very important to us that we get appropriate value for our assets. The sixth gens are workhorses of the fleet and do a fantastic job, and Petrobras were very keen to extend the rigs. It is an interesting moment because Petrobras is traditionally the barometer of where things are going, so when you see them go long, that is a pretty good sign for us. In that instance, note the delta between the average dayrates between the sixth and seventh gen, somewhere in the region of $50,000 to $70,000. That is a fairly big deal. In our view, the market tightness is not projected; it is already here.
A few quarters back, we were talking about things that were going to happen; now the scoreboard has fixtures on it, and they are prolific. As Keelan pointed out earlier, we are a third of the way through the year, and we have 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 is before we consider direct negotiations that are not necessarily on the market. You are spot on in that strategy.
We have always taken a portfolio view on the fleet—very keen to see those sixth gens go long and give us a bit of optionality on the higher-spec units as we move forward.
Operator: Thank you. We will go next to Fredrik Stene with Clarksons Securities.
Fredrik Stene: Hey, team. Hope you are well. Happy to see that the market is looking better. According to my numbers, we have the highest market-wide visibility contracting-wise, even above 2023 levels. Something is happening, and I am happy to see that. Today, my question relates more to the M&A process—the acquisition of Valaris. You gave some color in your prepared remarks, Keelan, but could you elaborate a bit more on what this second request actually means and the implications for potential deal risk? You still said confidence in second-half closing, but is that timeline potentially delayed now compared to before? And what does this potentially mean for remedy sales, etc.?
I am not trying to be a devil's advocate; I am just trying to get clarity on what this actually means, even though it seems like most deals that receive a second request end up going through. Any color would be helpful.
Keelan I. Adamson: Sure, Fredrik, and thanks for the question. We remain confident that the DOJ will approve the transaction. The second request is part of the process. For a deal of this nature, it is simply a case of needing a little bit more time to understand the competitive dynamics post-close. We have been heavily engaged with the DOJ, working productively with them, answering their questions, and helping them understand the nature of our business in the U.S. Gulf and the market worldwide. Those conversations have been going very well. There is no read-through I would suggest to you that changes our expectations.
When we declared the timeline we believe this transaction would close in, we are still in that window and very much believe so. We are happy with the progress we are making and will continue to work with the DOJ as they assess the situation.
Fredrik Stene: Thank you very much. As a follow-up, I think you said Saudi and Trinidad and Tobago have cleared approval already. In addition to the U.S., it was Australia, Brazil, and Egypt. Are there any risks of similar second requests or hurdles in those countries, or do you feel confident that those discussions are on the track you originally perceived?
Keelan I. Adamson: It is following the exact process and timeline that we would have expected to go through the regulatory approval process. Some are further along than others. We are engaged with all of those countries, and everything is moving as we would have expected at this point in time.
Operator: Thank you. We will go next to an analyst from Morgan Stanley.
Analyst: Hey, thanks. Good morning, guys. I wanted to ask: you shared a couple of years ago, or more recently, some of the terms and components around reactivating a cold-stacked rig. Could you refresh us with your latest thoughts on the cost to reactivate a rig, the timeline, and what type of contract terms or macro backdrop you would need to move forward with that decision?
Keelan I. Adamson: Good morning, and thanks for the question. It is timely as we talk about a constructive market going forward. However, we are a little bit away from 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, it may be slightly different. From a cost perspective, we are still in the $100 million to $150 million range to reactivate one of these assets.
We are comfortable with the stacked fleet we have, the condition they are in, and we have a good handle on the timeline it would take to bring one back to market; we are still in the 12 to 15 month range to reactivate and bring one of those rigs back to service. We will not do that speculatively. We will want a contract that fully recovers that cost and provides a return on top. We are not quite there yet. We would look for 100% utilization in the drillship market, with visibility into market programs, to justify bringing one out. You can imagine we will be looking for term and productive dayrate for that to happen.
Roderick J. Mackenzie: To add to that, term and return economics are very important. At this point in the year, the average award has been 480 days, which is double what it was in all of 2025. But that is still not enough, in our view, to bring out one of the cold-stacked assets. It is encouraging to see a doubling of duration and effectively a four-times multiple on how many fixtures are being made today, but we still think there is room to run before we reactivate the cold-stacked fleet.
Analyst: Great, that is helpful. A higher-level question: as you toured the world and pointed to areas where you see potential for incremental tendering, are there any areas where customer conversations or incremental activity are more related to events over the last two months in the Middle East—more related to building strategic reserves or reducing reliance on Middle East exports? You highlighted Southeast Asia and India previously, and you mentioned some big numbers in Indonesia. Can you parse out any areas where incremental need or demand is more related to diversifying away from Middle East exports?
Keelan I. Adamson: The conflict is not that old at this moment, but nations around the world are reassessing their energy security and policies for energy supply. You highlighted a couple that come to mind straight away. In India, Prime Minister Modi has set his government in motion with a mission to establish the nature of their reserves in country. That is driving ONGC and Oil India action. It was a bit of a surprise when it came—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 with several years of CapEx commitment to establish their position from an offshore oil and gas reserve and supply perspective. That is just one country. In Indonesia as well, and when you look around the world at what the IOCs are looking at, they are focused on ensuring a diversified global supply—major developments going through sanction right now in Suriname, Namibia, Mozambique, into the Med and West Africa. The importance of a globally diversified supply is only more heightened now for secure, reliable, and affordable energy.
Roderick J. Mackenzie: We have already exceeded last year’s fixtures and rig-year awards, and none of that was based on the Middle East conflict. The tenders on the market today—collectively we think somewhere in the region of 150 rig years awarded this year, maybe more—are not predicated on what happened in the Middle East. It is based on the macro shift over the past 12 months: the shift towards deepwater, customers ramping up exploration and development, moving beyond the strict capital discipline mantra. All of that was predicated on $60–$70 per barrel outlooks. Now we are in a different position, which is good for our customers’ earnings near term, but our fixtures are predicated on mid-range oil prices, not elevated prices.
We have not yet seen the impact in our business of a prolonged increased oil price; our current work is predicated on oil prices of six to nine months ago.
Operator: Thank you. We will go next to Gregory Robert Lewis with BTIG.
Gregory Robert Lewis: Hey, thank you and good morning. I was hoping to spend a little time talking about the harsh-environment market. It is good to see the Barron move back to Norway. We have the traditional North Sea, but there was a rig that just won work in Canada, we have Australia, you hear about other pockets like the Falklands. This is a market where there is not a lot of supply. As you think about positioning Transocean Ltd.’s harsh-environment fleet for 2027 and 2028, should we expect more of a return to the North Sea, or are there going to be opportunities to keep this fleet spread? How tight could we be for the harsh market as we approach 2028?
Keelan I. Adamson: Good morning, Greg. The harsh-environment market, while in balance currently, was expected to get tighter based on projects being sanctioned and growing activity. You are right—the harsh-environment market is no longer just Norway. It is returning to places like Canada and Australia, and rigs can be used in other, not-necessarily harsh, shallower-water environments. The opportunity set for the harsh-environment fleet is more global now, and we are not even considering yet what could happen in Namibia. With licensing rounds and the imperatives of Equinor, Aker BP, Vår Energi, and the energy security conversation in Europe, Norway is going to get busier. The opportunity presented itself to take the Barron back to Norway.
We are very pleased to begin that relationship with Vår Energi again. We will continue to keep our assets in the most strategic locations and ensure we are available to the market upswing we expect in harsh environment.
Roderick J. Mackenzie: To add, the name of the game over the last few years was operators retaining optionality on rigs without making large commitments, but the dynamic has shifted. Awards in Canada have been made; there is another tender for an incremental rig there. Within Norway, you see commitments—Vår, Aker BP, and Equinor’s NCS 2035 plans. The number of wells and the longevity of the programs speak to the Norwegian government’s commitment to sustain energy security in Europe. Those are strong fundamentals. We are about to enter a period of a very tight market because there is a shift towards longer-term contracting.
That showed up in some numbers already and will be more prolific as operators need to secure assets because there are not many of them. There is a high chance more rigs will return to Norway because demand is well beyond the fleet currently in Norway.
Operator: Thank you. We will go next now to Noel Augustus Parks with Tuohy Brothers.
Noel Augustus Parks: Hi. Good morning. I was intrigued by what you were saying about exploration conducted long ago, with some of those projects now heading for development. For perspective, can you think of what may be the oldest exploratory project that you are now seeing greenlighted for development?
Roderick J. Mackenzie: Good question. A lot of activity in Nigeria fits that description. Nigeria is expected to go up to five rigs; they had gone down to one. Much of what is triggering the incremental rigs now is based on exploration that took place some time ago—some as long as eight to ten years ago, certainly at least five years ago. A shorter example is Namibia. You saw lots of announcements about discoveries, then a lull as results were digested, and now we are seeing several long-term tenders based on development. Even there, there are still several exploration wells on the books. It is a treadmill: you have to keep discovering and exploring.
Petrobras is vocal that they must contribute a significant portion of the portfolio every year to exploration. If you take your foot off the gas on exploration, your reserves dwindle quickly. Reserve replacement is becoming more of an issue, and the only way to address it is to explore.
Noel Augustus Parks: Thanks. With energy security coming to the fore and the ripple effects for importing countries and their plans, assuming sustained higher oil prices, are there any regions where the economic opportunity could become so compelling that it overcomes some political inertia or opposition to moving forward?
Roderick J. Mackenzie: It is definitely a theme. The war in the Middle East reinforces decisions already taken over the last several years, particularly by NOCs, to look at what they have within their own borders. Domestic production makes sense: you retain taxes, employ your people, and reduce dependency. Energy security reinforces domestic exploration. India is a top example. Even in places like the UK, I think you are going to see a U-turn; they have been cutting back for some time, but it is almost inevitable that will shift in the near term. Norway is a great example—linked to energy security and providing energy for Europe as the biggest producer in Europe.
Overall acceptance that hydrocarbons are here for a very long time—there is no peak oil this side of 2050—so time to get on with it.
Keelan I. Adamson: To add, deepwater is a very long-cycle business, and the economics are compelling at much lower oil prices than today. Activity we are seeing is based on fundamentals regarding supply and demand of hydrocarbons, concern on replacement of reserves, and the need to explore. Layering in energy security amplifies the case and will continue to promote more investment in offshore. It is a very good place to get affordable, secure, and reliable energy, and we continue to see it playing that role going forward.
Operator: Thank you. Gentlemen, it appears we have no further questions this morning. David Kiddington, I would like to turn things back to you for any closing comments.
David Kiddington: We would like to thank everyone who participated in our earnings call today. We invite you to follow up with us for any additional inquiries. With that, we will close the call.
Operator: Ladies and gentlemen, this concludes the Transocean Ltd. First Quarter 2026 Earnings Conference Call. Thank you all so much for joining us, and we wish you a great day. Goodbye.
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Transocean (RIG) Q1 2026 Earnings Transcript was originally published by The Motley Fool