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Operator: Good day, everyone, and welcome to the Q1 2025 Transocean Earnings Call. At this time, all participants are in a listen-only mode. Later, there will be a question-and-answer session. [Operator Instructions] Please be advised that today’s call is being recorded [Operator Instructions] I’d like to turn the floor over to the Director of Investor Relations, Alison Johnson. Please go ahead.

Alison Johnson: Thank you. Jamie. Good morning and welcome to Transocean’s first 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 Jeremy Thigpen, Chief Executive Officer; Keelan Adamson, President and Chief Operating 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 Jeremy, 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 Jeremy.

Jeremy Thigpen: Thank you. Alison, and welcome to our employees, customers, investors, and analysts participating on today’s call. Before diving into our first quarter results, I am pleased to announce that Keelan Adamson will officially become Transocean’s President and CEO, effective May 1. While that technically provides me a few more days in the role, we believe that it’s prudent to begin the handover a few days early. And Keelan, the honor of leading today’s call. Most of you know Keelan, but for those of you who do not, he started in operations here at Transocean nearly 30 years ago and has progressed his way through the organization and the executive ranks, where he served as our President and Chief Operating Officer for the past several years.

I’ve had the distinct pleasure of working closely with Keelan in various capacities since I became CEO, 10 years ago, and I can assure you that Keelan possesses a comprehensive understanding of the offshore drilling business and Transocean. Importantly, he recognizes and appreciates the challenges that we constantly face in this business and embraces the oftentimes difficult decisions that are required to persevere, overcome, and succeed. Keelan is a very well rounded, thoughtful, courageous, inspiring, and humble leader, whose depth of experience will be a key attribute and serve him well as he enhances Transocean’s leadership position by safely optimizing performance, introducing innovative technologies, and maximizing shareholder returns.

While transitioning out of the CEO role is certainly bittersweet. I will continue as a Board member with the company through our Annual General Meeting on May 30, where shareholders are asked to elect Keelan to the Board, elect our current Board Chair, Chad Deaton, as a Director, and elect me as Chairman. At that time, Chad will transition to the role of Lead Independent Director. Irrespective of the market conditions we may encounter, I am confident we have the right team assembled under Keelan’s leadership to meet any challenge. With that, I’ll turn it over to Keelan.

Keelan Adamson: Thank you, Jeremy, and thank you for those very kind comments. As reported in yesterday’s earnings release for the first quarter. Transocean delivered adjusted EBITDA of $244 million on $906 million of contract drilling revenues, resulting in an adjusted EBITDA margin of approximately 27%. After we released our fleet status report on April 16, we signed a priced option on the Deepwater Asgard that if exercised, will extend its second firm period by one year. Additionally, over the weekend, the next two options on the Transocean Equinox were exercised at $540,000 per day. This extends the rigs firm period through August 2026, and represents $40 million of backlog. Operationally, so far this year, we have commenced two programs ahead of schedule on rigs moving to contracts with new customers.

The Transocean Barents started in the Black Sea with OMV Petrom 10 days earlier than planned, and the Deepwater Invictus commenced its work with BP in the U.S. Gulf, 15 days ahead of its planned start. Now, I’d like to take a few minutes to discuss industry and recent macro dynamics. As expected, we have observed a couple of relatively quiet quarters for drilling fixtures. This is evidence of our customers continued capital discipline, supply chain delays and business restructuring activities. Importantly, our customers have unambiguously pivoted to once again endorsing hydrocarbons as a core business, and the priority investment for the future. For example, at Shell’s Capital Markets Day last month, its management highlighted the superior returns generated by its deepwater assets and underscored its strong deepwater resource base relative to its peers.

Additionally, in February, BP reiterated the strategic role its U.S. Gulf assets play in maintaining its position as one of the leading upstream companies globally. The emphasis on deepwater is illustrative of a broader strategic shift, among particularly the European major integrated operators, many of which have already rebalanced their portfolios to emphasize their core oil and gas operations. In recent weeks, trade tensions and OPEC announcements have heightened volatility and introduced broad market uncertainty that we haven’t seen since the COVID pandemic. Like everyone else, we continue to evaluate the potential impact of these developments on our business. However, we think it is important to remember two things; one, market and commodity volatility while unnerving to some has not materially impacted our business and has as yet we have not seen a planned program delayed or canceled as a result.

Our fleet, and particularly our backlog provide us with the ability to better withstand market disruptions should they arise. Looking beyond general market volatility, we are confident in the future of deepwater drilling. Our outlook reflects the shifts in our customers focus and constructive industry fundamentals, reinforced by third-party projections. For example, when Mackenzie projects a 40% increase in deepwater investment by 2030 as more than 90% of deepwater of 2P proven and probable reserves are economic above $50 per barrel. With that, I’ll now cover the market outlook for the geographic regions. In the U.S. Gulf, we are expecting up to six programs to commence in the second and third quarters of 2026 for durations ranging between six months to four years each.

Of these, we believe three will come out as public tenders in the next two quarters. The remainder are already in direct discussions pending final award or just recently announced. Additionally, nine projects are expected to reach final investment decision in the next three years, including three 20K prospect’s BP’s Guadalupe and Tiber; and Beacons, Shenandoah South. In Brazil, Petrobras has been steadily increasing its rig count over the past couple of years and is expected to reach more than 30 active rigs by the end of this year and plan to keep the same number of rigs on contract in the foreseeable future. Consistent with our prior projections, Petrobras recently released the tender for its next Buzios program. The program will require a minimum of one and possibly up to three or four rigs for four years each.

Additionally, we are awaiting a tender for its Mero program in the coming weeks. Both programs will likely be filled by rigs they already have on contract in country. Also in Brazil, we anticipate Shell will come to the market in the next few months for its recently FID-ed Gato do Mato project. The program is currently set to commence in late 2026 for two years firm. Now to Africa. In Nigeria, as expected, Shell recently awarded a rig for its Bonga South program. We expect Exxon and Chevron to follow in the next several quarters with each awarding one rig by the end of the year for commencements in late 2026, early 2027. In the Ivory Coast in Ghana, three programs will likely be awarded in the coming months, commencements between late this year and mid next year for between six to 12 months each.

Namibia exploration activity continues, and we expect development programs will materialize from this work in 2027 and 2028. And lastly, in Mozambique, three long-term programs are currently set to commence in 2027, all of which are expected to bring incremental rigs to the region. In the Mediterranean, despite the geopolitical situation, we continue to see our customers move ahead with their programs. Among other opportunities, BP is out to tender for a minimum one-year program in Egypt that is expected to commence as early as the fourth quarter this year. By the end of 2026, we expect at least five rigs will be on contract in the region and incremental two to three rigs to current supply. Moving further east, in India, ONGC is expected to tender for its 18-month two-rig program commencing late 2026.

In Malaysia, PTTEP recently reissued the market survey for its program, and we believe it will release the tender later this quarter. And in Indonesia, ENI issued a market survey for eight wells commencing late 2026 to early 2027. In Australia, bids were recently submitted for Chevron’s Gorgon Phase II tender. We expect them to issue the award sometime in the fourth quarter for 12 to 24 months of work beginning late 2026. INPEX is expected to tender later this month for its five-year program commencing the second quarter of 2027. With the current demand, including opportunities with the local independents, our two rigs, the Transocean Equinox and Transocean Endurance are well placed and could remain in Australia beyond their current programs.

Shifting now to the traditional harsh environment regions. Our four rigs in Norway, Transocean Spitsbergen, Transocean Norge, Transocean Encourage and Transocean Enabler are on contract into 2027. Given projected demand which suggests two incremental rigs will be required in Norway in 2027 and the push from Norwegian regulators for more exploration and development activities, we are confident our rigs will be placed on programs directly following their current contracts. In the U.K., BP released its West of Shetland tender, which will require one rig for a firm duration of three years beginning the first quarter of 2027. And finally in Canada. Suncor recently tendered for its one year Terra Nova program beginning in 2027. In summary, we remain optimistic about the global offshore drilling market and are encouraged by our continued conversations with customers.

At this point, we do not believe that present macroeconomic uncertainty will cause delays to the programs we expect to be awarded to the industry over the next several quarters. Many of which are linked to long-term developments, independent projections and key industry metrics continue to point towards increasing offshore drilling activity across the board, with growth coming from deepwater basins. According to Fearnley Offshore. The combined proved reserves of the majors have declined from approximately 93 billion barrels in 2012 to around 76 billion barrels at the end of last year, while the majors collective reserve to production ratio declined by approximately 20% over this same period. As we progress through 2025, our priorities remain largely the same.

We are committed to delivering safe, reliable and efficient operations for our customers and are focused on the conversion of our $7.9 billion of backlog to revenue, and that revenue to cash to create sustainable value for our shareholders. With that, I will now hand it over to Thad to discuss our results and guidance. Thad.

Thaddeus Vayda: Thank you, Keelan, and good day to everyone. During today’s call, I will briefly recap our first quarter results, provide guidance for the second quarter, and conclude with an update of our expectations for the full year, as disclosed in our press release. For the first quarter, we reported a net loss attributable to controlling interest of $79 million, or a net loss of $0.11 per diluted share. During the quarter, we generated EBITDA of $244 million and cash flow from operating activities of $26 million. Free cash flow of negative $34 million reflects the $26 million of cash flow, net of $60 million of capital expenditures during the first quarter, we delivered contract drilling revenues of $906 million at an average daily revenue of approximately $444,000.

Contract drilling revenues exceeded our guidance range, due primarily to higher than anticipated utilization on the Transocean Spitsbergen and Transocean Endurance. As a result of delayed out-of-service periods and the early commencement of the Transocean Barents. At $618 million, operating and maintenance, or O&M expense in the first quarter was within our guidance range. Lower costs related to the aforementioned delays in-out of service periods were offset by an unfavorable conclusion to a customer dispute that resulted in a $34 million non-cash charge associated with the write-off of an uncollected receivable during the period. G&A expense in the first quarter was $50 million. We ended the first quarter with total liquidity of approximately $1.3 billion.

This includes unrestricted cash and cash equivalents of $263 million, $428 million of restricted cash. The majority of which is reserved for debt service and $576 million of liquidity from our undrawn credit facility. I will now provide guidance ranges for the second quarter and an update on our expectations for the full year. For the second quarter, we expect contract drilling revenues to be between $970 million and $990 million, based upon an average fleet wide revenue efficiency of 96.5% on our working rigs. As you know, revenue efficiency can vary based upon uptime, performance, weather, and other factors. This estimate also includes between $55 million and $65 million of additional services and reimbursable expenses. Please recall that these additional services and customer reimbursables generally carry low single-digit margins.

The expected quarter-over-quarter increase in contract drilling revenues is primarily due to higher activity on the Barents and the Deepwater Invictus, and our expectation for improved revenue efficiency and more operating days in the quarter, partially offset by the scheduled unpaid out of-service period on the Spitsbergen. We expect second quarter O&M expense to be within a range of approximately $610 million to $630 million. This slight quarter over quarter increase is primarily due to additional costs incurred during due to out-of-service periods on the Spitsbergen and Endurance, and the timing of in-service maintenance across the fleet partially offset by the write off associated with the customer dispute that I mentioned a moment ago.

We expect G&A expense for the second quarter to fall within a range of $45 million to $50 million. Net cash interest expense for the second quarter is forecasted to be approximately $140 million, comprising interest expense and interest income of about $147 million and approximately $7 million, respectively. Capital expenditures for the second quarter are forecasted to be approximately $20 million, and cash taxes to be paid are expected to be approximately $30 million. For the full year 2025, contract drilling revenues are still expected to be between $3.85 billion and $3.95 billion. The range primarily reflects potential variances in revenue efficiency. Our guidance also includes between $235 million and $245 million of additional services, and reimbursable expenses.

We expect our full year O&M expense to be between $2.3 billion and $2.4 billion, in line with our previous guidance, and we anticipate G&A costs to be between $185 million and $195 million, $5 million lower than previously forecasted. For the full year, we are anticipating net cash interest expense between $550 million and $555 million, comprising interest expense and interest income of about $580 million and between $25 million and $30 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 $75 million and $80 million, somewhat higher than our earlier guidance due to longer than expected activity and higher tax jurisdictions.

We now expect 2025 capital expenditures to be approximately $115 million, reduced from our prior guidance of $130 million, of which approximately $50 million is related to customer required capital upgrades for upcoming projects and capital spares and approximately $65 million of sustaining capital investment. Our projected liquidity at year end 2025 is now forecasted to be between $1.45 billion and $1.55 billion. This reflects our revenue, cost and capital expenditure guidance, and includes the impact of our cost savings initiative to date, our undrawn revolving credit facility and restricted cash of approximately $450 million. As a reminder, for the terms of our credit agreement, the capacity of the facility declined to $510 million from $576 million effective late June 2025.

At the present time, we have not explicitly included the potential impact of tariffs in our guidance. As you know, the situation is continuously evolving and highly uncertain. We anticipate that any tariff exposure will fall into two broad categories, direct, meaning directly related to our importation of materials into the U.S. from foreign countries, and indirect, which relates to additional costs our U.S. based suppliers pay to import the goods and materials needed to manufacture the products they supply. We currently do not expect our exposure to direct tariffs to be significant or likely to drive a meaningful increase in our costs. A significant portion of our sourcing is already done in the jurisdictions in which we operate. For example, roughly 87% of the goods used in our U.S. operations are procured domestically.

We are also able to utilize foreign trade zones for certain components. Further and coincidentally, as part of our cost savings initiative, which I will discuss shortly, we have already increased local procurement in other countries and continue to make significant progress in this regard. As evidenced by Brazil, our second largest operating area. Our local content is over 60% today, up from about 30% in 2023. In relation to our indirect exposure to tariffs, we have observed some preemptive supplier price increases, intended to mitigate the potential impact of tariffs on their own supply chains. This is not yet widespread, as most of our suppliers still appear to be assessing the situation. We think that any indirect or pass through cost increases have a greater potential to affect our cost structure over the longer run, if reciprocal tariffs are not curtailed.

We continuously engage with our suppliers to understand the potential impact of the tariff regimes and work to mitigate increases wherever possible. We also continue to review our contracts with customers to determine our eligibility for relief, through cost escalation or change in law provisions. Finally, as I mentioned when we spoke in February on our 2024 year-end call, we had initiated an enterprise wide evaluation to identify areas in which we can reduce our costs without compromising our ability to provide safe and reliable operations. Thus far, we have identified approximately $100 million of cash cost savings that we expect to be realized over the course of 2025, predominantly in the second half of the year, with a similar quantum of savings expected in 2026.

As this effort is ongoing, we expect to identify additional opportunities to improve efficiencies and our cost structure. Our CapEx and overhead guidance reflect a portion of these anticipated savings. However, our 2025 O&M guidance range is currently unchanged from last quarter, due in part to embedded and offsetting non-cash charges and accounting accruals. The full impact of these cash cost savings is most clearly visible in our current liquidity forecast, which we have increased by approximately $100 million. As we discussed previously, we anticipate using a portion of these cost savings to accelerate the deleveraging of our balance sheet. This concludes my prepared remarks, and I’ll now turn the call back to Keelan, for additional comments, before we start Q&A.

Keelan Adamson: Thanks, Thad. Before we move to Q&A, I will take this opportunity to recognize and thank Jeremy for his exceptional leadership over the past ten years. Jeremy’s tenure as CEO of Transocean was nothing short of transformational. Upon his arrival in 2015, he quickly developed a strong understanding of this business, established a clear vision and strategy, and successfully guided the company through arguably the worst downturn in the history of the offshore drilling industry. He protected the interests of our shareholders and had the foresight to take proactive actions to position the company for even greater success, when the industry recovered. In this regard, he presided over a significant restructuring of our asset base.

He embraced the unique and singular objective of building the most differentiated and highest capability, pure play floater fleet in the industry. One that, when operated and supported by the men and women of Transocean, has and continues to deliver outstanding performance to our customers, generate leading edge day rates and an industry leading backlog. But the outside world has seen are simply the outcomes of his leadership skills and style. As important to the longevity and future success of the company are things that don’t necessarily make headlines, such as his commitment to developing talent and building high performance teams. His inspirational leadership unlocks potential, motivates, and mobilizes our global workforce and empowers his team to execute.

Every CEO wants to leave a company in better shape than they found it. I believe Jeremy can move to the next chapter in his career knowing that he absolutely achieved that. Jeremy. Thank you sincerely for all you have done for Transocean over the past ten years, and we look forward to your continued guidance on our Board of Directors. And now I will turn the call back to Alison for Q&As.

Alison Johnson: Thanks, Keelan. Jamie. We’re now ready to take questions. And as a reminder to the participants, please limit yourself to one initial question and one follow up question.

Operator: Thank you. [Operator instructions] We’ll hear first from Eddie Kim with Barclays. Please go ahead.

Eddie Kim: Hi. Good morning. And Jeremy, congratulations again for guiding the company through an incredibly difficult time. And wish you all the best in whatever comes next.

Jeremy Thigpen: Thanks, Eddie.

Eddie Kim: My first question is on, kind of contract announcement timing. You laid out a very constructive outlook as you went through the region by region, on the upcoming tenders and programs, mostly with 2026 start dates. And I know it’s always difficult to predict when these contracts will be announced, but what’s your best estimate on that timing? Should we see most of these to be announced around mid-year or more towards the end of this year or early next year? Just your thoughts on when that, contract announcement timing could take place?

Roddie Mackenzie: Hi, Eddie, this is, Roddie. I’ll take that one. Yes. So, I think we’ve said this a few quarters in a row that, we do expect a lot of contract announcements this year. Last quarter and the quarter before were a bit quiet. But I think you just saw noble announcing several long term contracts yesterday. And then, we believe that many of the things that Keelan and I discussed in these comments, there will be awarded pretty soon. We think essentially there will be several awards over the summer period, but also all the way up towards the end of the year. In fact, we think the second half of the year could be, very prolific in terms of long term awards. And as you pointed out, there’s not a whole lot of stuff for 2025. But we’re currently 97% booked in 2025. So we feel pretty good about that and through the year from this point forward, we’re 93%, contracted. So, yes, a lot of the stuff starts in 2026. But, we think that suits us very well, actually.

Eddie Kim: Got it, got it. That sounds great. My follow up is just on, expected kind of day rates on those contracts we should expect in the second half of this year. Up until now, I mean, leading edge, voters are still kind of in that mid to high 400 range. But there’s a lot more idle rigs today than there were six months ago. So just curious if you expect, we might see some day rate pressure on these upcoming contracts or if they should, be fairly resilient at current levels.

Roddie Mackenzie: Yes. So look. The way that we look at it is, if you think about, 2025 projections are give or take about 120 working rigs, floaters, and that’s sharply increases to 130 in 2027 and goes up to like 142 in 2029. So our view on the rates are that, you could probably see some near-term pressure for short-term work, but we think for long-term work, it makes a lot more sense that, we continue at rates similar to what we’ve seen over the past year. So certainly that’s been our experience. And a lot of the discussions we’ve had with our customers that the rates are kind of largely unchanged going forward. But it’s definitely possible that you’ll see some near-term pressure for those trying to fill some gaps.

Jeremy Thigpen: And maybe just add something on top of that. It really depends on when these jobs were bid up and the timing of those jobs, whether they were by tender or direct negotiations. So it could be a bit of a mixed bag in the near term. But as Roddie indicated, we obviously see progression to a higher utilization on the industry’s fleet, by end of 2026, 2027.

Eddie Kim: Got it. Great. Thanks for that color. I’ll turn it back.

Operator: We’ll hear next for Arun Jayaram with JPMorgan. Please go ahead. Your line is open.

Arun Jayaram: Yes. Good morning. I was wondering if you could or getting a few by side questions on the Shell Awards from Noble. I was wondering if you could talk about the implications from Transocean, because you do obviously have a couple of incumbent rigs working for Shell today.

Jeremy Thigpen: Yes, sure. No problems. I’ll take that. First of all, congratulations to Noble for booking up a couple of slots there. Yes. So the way that we view that, obviously we were very involved in the process with Shell, and, we simply took the portfolio view that we weren’t going to kind of go to those levels for this class of asset, but that being said, we actually think, Shell themselves have additional demand required in the Gulf of Mexico. And we’ve had a long relationship with Shell, and we sincerely appreciate all of their work that has been a fabulous partnership through the years. And sure, it’s going to continue. So we think, there’s still plenty of opportunities, as I kind of said in the last question, we chose to take a longer view.

There’s a much higher period of activity just around the corner. And the rigs that we’re talking about in our fleet. Well, the first one off doesn’t finish for more than a year, and the second one for more than two years. So we kind of think about adding four years that will run you into 2030 and 2031 that we would take a longer view on what those rates should be. So in addition to that, we’ve also had a lot of inbounds on this class of rig from other operators in the Gulf and elsewhere. So, we kind of went down this track before with, with Alaska and, we’re very successful in placing her elsewhere, and we’re also excited about starting that project. So I think we’re in very good shape there. And we’re quite pleased to see the beginning of these long-term contracts now being announced.

Keelan Adamson: And maybe just another piece on top of that. I think Shell have obviously looked at their portfolio of assets that they’re using. And based on the programs that they’ve got, have elected to use a wider portfolio of capabilities and in that case, our 7G plus assets, there’s plenty of opportunities for them in the timeframe that these contracts we’re in, and we feel very strongly about keeping them available at that point in time for the right rates and contracts. Shell, are a very, very important customer to us. And we know that they will have activity and perhaps even more activity than they currently have. And we look to continue that relationship going forward.

Arun Jayaram: Great. Maybe just a follow-up. I was wondering if you could elaborate on your activity assumptions for West Africa. You highlighted a couple of opportunities for rigs, but do you see that being a potential growth area late 2026 into 2027?

Jeremy Thigpen: Yes. It’s interesting. You should ask that. You know, in a lot of the stuff we’ve discussed over the past six months or so, we’ve there’s not been a lot in West Africa. Certainly. Brazil. Latin America is very, very strong just now, as is the Gulf of Mexico. But that last piece of the golden triangle is really woken up. So as Keelan had mentioned in his prepared comments, we’re looking at, many countries in West Africa with multiyear opportunities and multi-rig opportunities. So we’re kind of excited about that. We think there’s a few rigs over there that, will benefit from all of that activity. And in fact, we actually predict that, the region will consume a few rigs more than it currently has. So, that’s looking very good. Again, in that, that 2026 timeframe.

Keelan Adamson: And that’s and that’s the third leg of the stool that we’re looking we’re still looking for the golden triangle to, to boost up. And so it’s really upside there in that area of the world for us.

Arun Jayaram: Great. I wanted to pass on my best to Jeremy. Jeremy, if you do write a book on the 2014 to 2016 period, I’d love to read that one.

Jeremy Thigpen: Thanks. I appreciate it.

Arun Jayaram: Take care.

Operator: We’ll turn now to Fredrik Stene with Clarkson Securities. Please go ahead.

Fredrik Stene: Hi, Team.

Jeremy Thigpen: Hi, Fredrik.

Fredrik Stene: Congratulations, Jeremy. Job well done.

Jeremy Thigpen: Yes. Thank you.

Fredrik Stene: I wanted to — you had a good breakdown of the market and some good color on the previous questions here. Take action. I wanted to touch a bit on the cost savings that you mentioned that. And I just wanted to make sure that I heard it correctly. You talked about $100 million that could be identified in 2025 and then an additional $100 million in 2026? Or was it SEK 100 million in total across those two years? Just want to make sure that I heard correctly?

Thaddeus Vayda: No. You heard — you heard correctly. It’s $100 million that we’ve identified for 2025. And while this is an ongoing process, we continue to assess opportunities here. You know, current expectation is going to be in about the same range. So about $200 million in aggregate over the next two years. Obviously, we’ve not provided specific guidance for 2026 yet, but just to give you an indication of the magnitude of savings that we anticipate.

Fredrik Stene: Yes. And are there will you incur any costs to save those costs.

Jeremy Thigpen: At this point? Good question. At this point, nothing significant. Again, this is the beginning of the process. You know, we have focused mostly on O&M costs. As I mentioned, there is some in SG&A and capital expenditures. But right now this comprises mostly things like renegotiation of contracts with our vendors. Some new technology that was sort of already underway that produces a net savings, using national crews, things of that nature. And then some elements of the capital expenditure related to spares and things of that nature, where we find that we can actually reduce the quantum and the cost over time, given our views of maintenance and things of that nature. So at this point, we’ve not identified any significant costs associated with achieving the savings.

Fredrik Stene: Okay. That’s very helpful. And then I wanted to touch briefly on your fleet as well. And I guess this goes mostly kind of across your island and cold-stacked vessels. First, DD III and the discoverer inspiration. You know, any news on that process? Seems like there’s still held for sale. And also on the cold-stack, assets, particularly on the deepwater, side. You know, do you have any some competitors have started to do scrap cold-stack assets. Are you planning on doing the same or are there any since you still have a legacy balance sheet in a way, some technicalities that would hinder you doing that in terms of impairments et cetera? Thank you.

Jeremy Thigpen: Yes, Fredrik. Same as before — the inspiration the DD III are still held for sale and we are looking at alternative opportunities for those particular two that are warm and idle at the moment. We look at that quarter-by-quarter. With respect to the cold-stack fleet, yes, that’s something that we look at on a quarterly basis. I’ll remind you that, you know, the sustaining cost required to keep them cold-stacked is minimal, provides us with optionality on that fleet. And a lot of the cost to put them into cold-stack is obviously been sunk already. So something we look at and every quarter, and, we’ll continue to do so.

Jeremy Thigpen: And Fredrik, with respect to your question about sort of the mechanics, there’s nothing in any of our debt covenants or accounting policies or anything like that that would encumber the ability to transact with any of these assets.

Roddie Mackenzie: Yes. But I also like add one thing. I think we also hear a similar message from our competitors that, you know, for, uncompetitive assets when they go idle, if they’re not part of a core fleet or a forward looking scenario, then it’s quite possible you’ll see many of these rigs retired from the industry in general.

Fredrik Stene: All right. I appreciate all the answers. With that, I’ll leave it to the next one and wish you all a good day.

Jeremy Thigpen: Thanks.

Roddie Mackenzie: Thanks, Fredrik.

Operator: We’ll take our final question from Noel Parks with Tuohy Brothers. Please go ahead.

Noel Parks: Hi. Good morning. I will kind of come back to one of my recurring questions, which is, in an upside case, I’ve been interested in what you think producers. What producer behavior might be like as they face needing to crowd through the door? There — these recent contracts we heard that are encouraging sound like, some of them are recognizing that they’re advantages to locking in a little sooner rather than later. So, with those now under the industry’s belt, what do you think things look like if, 2026 looks like it’s going to be particularly strong.

Roddie Mackenzie: Hi, I’ll take that one. This is Roddie again. Yes. So, look, as we think about the — we talked about the macro uncertainty. Well, of course, a couple of recent announcements on tariffs and OPEC numbers have caused that short term volatility, but something that’s been kind of overlooked is over the past three months, the majors, particularly the European majors, have basically come out and said we are refocusing on oil and gas. We are going to play to our strengths. We are going to invest in upstream. And specifically, you know, BP, Shell and Equinor, talking about spending more money on exploration. And when you look at what’s projected in terms of CapEx spend, we’re expected to see around a 40% increase for deepwater between 2025 and 2029.

So, — that’s because, as Keelan had mentioned, the investment economics, the returns expected for deepwater developments are superior to most other forms of investment. So, we think that that will play heavily into what’s going to happen in the offshore market today. So, in terms of active utilization, we definitely see — or are aligned with the projections that show we could be adding 20 rigs between now and the next three or four years. We also believe that we will see more exploration that will trigger yet further developments. And this is all driven by the overarching theme that, you know, the IEA, for example, just republished their projections that show oil and gas will increase in consumption to 2050. So, previously, all of those curves came down at some point in 2030s or 2040s.

But the most recent projections show that even in the weakest economic case, oil and gas consumption will continue through the middle of the century. So, for us, we think that’s very solid fundamentals that can only support positive activity and positive day rates going forward.

Noel Parks: Great. Thanks. And so then would you say it would be fair to say that, you know, given the last couple of years have shown these signs based on just very limited, industry supply of high spec rigs, have shown these sides of very positive demand fundamentals. And so is it safe to say at this point that — at this point, new contracts, even in low, mid 400, at that level, sort of is the, the proof point that this is essentially a strong cycle fundamentally as opposed to whatever fears there may have been out there that, oh my gosh, to get, get these rigs signed, we’re going to have to see a big rollback in, in pricing? Would you say that that fear is pretty much off the table now or should be?

Roddie Mackenzie: Yes. I do. I mean, I think there was maybe a moment in time there where there was a tremendous amount of pressure. But I think many of the drillers have, are looking past 2025 looking to 2026, and 2027. So, from our point of view, that’s pretty solid. You may be seeing a floor for those long-term contracts. Again, as we said before, near-term stuff, short-term stuff, yes, I think, there’s many things possible there, but the fundamentals are just too good on a long-term basis. So, certainly would not make sense to lock in premium assets at below market rates.

Jeremy Thigpen: Yes. And when we look at the operators and their decision processes and what they’re looking to do with their portfolios, as Roddie indicated, you know, clearly, you know we believe it’s up and to the right. And when it comes to the assets that are available to work, there are there are barriers to how many assets can actually go to work and the timing of those. And so we think, it’s a very constructive space that we’re heading into. And so each driller, takes a portfolio approach and focuses on their own particular strategies. And in our case, we believe that perhaps now is not necessarily the right time to lock up, for those future years. But, we’ll continue to believe strongly in the future.

Noel Parks: Great. Thanks for the reminder about the timing barriers to getting rigged rig ads done. I think it’s also really important dynamic. Appreciate it. Thanks for the update.

Jeremy Thigpen: Thanks Noel.

Operator: Ladies and gentlemen, that will conclude today’s question-and-answer session. At this time, I’d like to turn the floor back over to Alison Johnson for any additional or closing comments.

Alison Johnson: Thank you, Jamie, and thank you, everyone for your participation on today’s call. We look forward to speaking with you again when we report our second quarter 2025 results. Have a good day.

Operator: Once again, ladies and gentlemen, that will conclude today’s call. Thank you for your participation. You may disconnect at this time and have a wonderful rest of your day.