Transocean Ltd. (NYSE:RIG) Q3 2024 Earnings Call Transcript

Transocean Ltd. (NYSE:RIG) Q3 2024 Earnings Call Transcript October 31, 2024

Operator: Good day, everyone, and welcome to today’s Third Quarter 2024 Transocean Earnings Call. At this time, all participants are in a listen-only mode. Later, you will have the opportunity to ask questions during the question-and-answer session. [Operator Instructions] Please note this call is being recorded and I will be standing by if you should need any assistance. It is now my pleasure to turn the conference over to Director of Investor Relations, Alison Johnson.

Alison Johnson: Thank you, Madison. Good morning, and welcome to Transocean’s third quarter 2024 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. During this time to give more participants an opportunity to speak, please limit yourself to one initial question and one follow-up. Thank you very much. I’ll now turn the call over to Jeremy.

Jeremy D. Thigpen: Thank you, Alison, and welcome to our employees, customers, investors and analysts participating on today’s call. As reported in yesterday’s earnings release, for the third quarter 2024, Transocean delivered adjusted EBITDA of $342 million on $948 million of contract drilling revenues, resulting in an adjusted EBITDA margin of approximately 36%. During the quarter, our marketing team was once again exceptionally busy, securing new contracts and extensions across the fleet. With these new contracts, our current pipeline of opportunities, 2024 is shaping up to be a very strong contracting year for Transocean, ensuring excellent fleet utilization for the coming 12 months to 18 months. In U.S. Gulf of Mexico, BP awarded the Deepwater Atlas a one year contract at a rate of $635,000 per day with no additional services provided under the contract.

The contract is expected to commence in the second quarter of 2028 and includes a one year option at the same rate and given our current understanding of the customer’s program, we expect that this option will ultimately be exercised. Additionally, the Deepwater Invictus was awarded two contract extensions that are currently expected to keep the rig working into November of this year. With these extensions, our active fleet is now essentially fully contracted in 2024. Lastly for the Gulf, the Deepwater Conqueror was awarded a one year contract at a rate of $530,000 per day including additional services. This program is expected to commence in October of 2025. In India, Reliance Industries awarded the KG1 a six well contract at a rate of $410,000 per day, excluding additional services.

The program is expected to commence in the second quarter of 2026 and includes multiple options into 2029. Moving to the harsh environment fleet. In Norway, Equinor exercised a three-well option on the Transocean Spitsbergen at a current rate of $483,000 per day. Assuming all remaining options are exercised, the current well schedule extends through the fourth quarter of 2027. Equinor also exercised three one-well options on the Transocean Enabler at a current rate of $438,000 per day. The estimated 105 to 150 day extension extends the firm term into the third quarter of 2026. In Australia, Woodside exercised two options for a total of six additional wells at a rate of $390,000 per day. The firm period now runs through August of 2026 and with the remaining options, the rig is expected to remain in Australia through at least October of 2026.

As I mentioned, the Transocean fleet is now solidly booked for the vast majority of 2025 and well into 2026. In fact, based on today’s backlog, our active fleet utilization for 2025 exceeds 97% and remains at roughly 86% through the first half of 2026. Through our 23 fixtures awarded so far this year, we have steadily eliminated utilization concerns through next year, successfully avoiding the so-called white space issues that most of our competitors have discussed over the past several months. We believe that our unique position relative to our peer group results from the following: We own and operate the highest capability fleet in the industry. We consistently deliver safe, reliable and efficient operations for our customers. And, we have a comprehensive understanding of the global market and use this advantage to maximize value creation from our portfolio of high specification assets.

On my last point before I hand it over to Keelan, I’d like to spend some time on asset quality. We have gradually but continuously optimized our portfolio of assets since 2014 resulting in a fleet that is technologically differentiated from that of our peers. Through the cycles, owning and operating the highest specification rig fleet has consistently proven to be the winning strategy. As you’re well aware, Transocean owns the only two eighth generation ultra-deepwater drillships in the world, Deepwater Atlas and the Deepwater Titan. These rigs are equipped with 1,700 short-ton hoisting capability and 20,000-psi well control equipment. We also own eight of the twelve 1,400 short-ton drillships. Of the remaining four, two are essentially permanently deployed in the end going market, one is committed to Shell for five years and one was just awarded a three year contract with Petrobras.

The result of this is that in the medium-term, we have the only marketable assets in this sought after class. As we’ve discussed in previous calls, hookload is important to customers as it characterizes the rig’s capability to run longer and heavier casing streams. This capability permits our customers to optimize their well designs, thereby reducing the number of days required to drill their wells and if reservoir performance dynamics allow, facilitate greater well productivity due to the preservation of the wellbore diameter. As evidenced by our $1.3 billion in recent contract awards, our now $9.3 billion in total backlog, which by the way represents a 7.5% sequential increase from our July 2024 fleet status report, and our 2025 contract coverage relative to our peer group, our portfolio of high specification ultra-deepwater and harsh environment rigs, all else being equal, seems to be clearly preferred by our customers, leading to higher full cycle utilization and enabling us to fix industry-leading day rates.

This has been demonstrated throughout the year by our market-leading contracts across the fleet, including for example, the recent award for the Deepwater Conqueror. Although the commencement date for this specific program falls within a window during which the fleet utilization of each of our competitors is expected to be below 60%, the rig still commanded a very strong day rate that even when adjusted for additional services is in excess of $500,000 per day, a clear indicator that our customers recognize and appreciate the value of Transocean’s assets and services. Even in the context of low global floater fleet utilization, we have continually demonstrated that premium assets attract premium day rates as operators consistently elect to contract rigs that afford them the greatest well program efficiency and flexibility.

In other words, operators will utilize the most value adding assets at every point in the cycle. With that, I’ll now turn it over to Keelan.

Keelan Adamson: Thanks, Jeremy, and good morning, everyone. Our confidence in the longevity of this up cycle is supported by our market studies and other third-party analysis, validated by recent contract awards and further confirmed by the discussions and negotiations with our customers. At just under $500 billion per year for the next several years, Wood Mackenzie forecasts global upstream CapEx to remain relatively flat. However, and importantly, because the long-term economics of our customers’ offshore projects are so compelling, the share of investment in deepwater and ultra-deepwater is expected to grow from 12% of that $500 billion in 2024 to 15% in 2026. In addition, per Rystad Energy’s latest analysis, more than 75% of new projects sanctioning for each of the major operators is economically viable below $60 a barrel.

As such, it should come as no surprise that we are in advanced discussions with numerous customers for projects beginning in 2026 and beyond. With minimal availability in our active fleet over the next 15 months, much of our focus has moved to the market in 2026. In the Gulf of Mexico, the Deepwater Proteus and Deepwater Asgard, both 1,400 ton hookload rigs will conclude their existing contracts in mid-2026. And as you might expect, we are actively engaged in direct negotiations with customers for work that would commence an immediate continuation of their current contracts. In Africa and the Mediterranean, we currently expect between 10 and 15 programs with an average duration of about 12 months to commence in 2026. This demand is driven by development programs in Nigeria, Angola, Ivory Coast and Ghana.

Each of these opportunities also have associated long-term options. Moving into 2027, we believe more units may be required in the region as programs in Mozambique and Namibia are expected to commence. In Brazil, Petrobras’ [pool three] (ph) tender results are expected imminently, and we continue to believe they will award four rigs, scheduled to begin operations between the end of 2025 and early 2026. Additionally, the Sépia program is expected to be awarded by the end of the year for up to three rigs commencing early 2026. We also anticipate Petrobras will release another tender by year-end. We think that these developments are well aligned with Petrobras’ strategic plan, which requires 30 rigs through 2030. Looking now at the high specification harsh environment market, the Norwegian market is currently sold out, but in balance.

That said, we expect rig demand could outstrip local supply as early as the fourth quarter. Accordingly, we are in the early stages of direct negotiations for our rigs that are scheduled to roll off contract in 2026 and 2027. Additionally, Equinor is currently out to tender for up to two incremental semis commencing in this timeframe. Moving to our operations, we continue to make significant progress with respect to operational discipline and the reliability of our fleet. In 2022, we started to implement Critical Operations Authorization Centers, or COAs, in Houston and in Stavanger. The COAs are staffed around the clock by teams of subject matter experts from our offshore workforce. These shore based teams provide additional verification and assurance as our offshore operations crews perform critical tasks, driving the required discipline to execute our operations safely, efficiently and correctly.

Over the past several years, we have focused on and emphasized procedural discipline in the execution of our operation. Since we established our COA process and centers, we have delivered a 20% improvement in our operational reliability, benefiting both the customer and Transocean. Simply said, we continue to identify, measure and improve upon those things which are solely within our control, striving to differentiate the service we provide our customers from our peers. Unfortunately, and notwithstanding this significant progress, over the past several months, we have experienced some unique reliability issues related to our new 20,000-psi BOPs. Given the revolutionary nature of this first issue equipment, such reliability issues are not unexpected.

And, as we have demonstrated many times before, when deploying new enabling technology, the technical strength and capability of Transocean and our OEM partners will quickly resolve these issues. This is the primary driver for our uptime performance and revenue efficiency falling slightly year-over-year. We will continue to focus on all aspects of our operational execution to best serve our customers, the company and our shareholders. I’ll now hand the call back to, Jeremy.

Jeremy D. Thigpen: Thanks, Keelan. Our high-quality backlog and a limited near-term availability of our active fleet are the direct result of our understanding of the market, unique quality of our assets and our reputation for operational excellence. We are proud to be recognized as the leader in offshore drilling and are grateful for the trust our customers place in us. As we’ve consistently stated, our immediate focus is on the efficient conversion of our approximately $9.3 billion of backlog to revenue and then that revenue to cash. With newbuild CapEx largely behind us, we can deploy more free cash to organically de-lever the balance sheet and enhance our financial stability. In fact, based on current internal forecasts, we believe we will approach a debt level sufficient to consider shareholder distributions approaching the end of 2026.

In summary, the outlook for our assets and services remains strong. We have successfully insulated ourselves from near-term utilization concerns as our contracting this year bridged us to the mid-2026 timeframe when the market is expected to continue its upward trajectory for our high specification rigs. We are continually encouraged by conversations with our customers for programs well into the future as these discussions reinforce our confidence that we continue to participate in a sustained up cycle. And, as you are aware, our current backlog provides clear visibility to future free cash flows to be used to meaningfully de-lever the balance sheet. With that, I’ll now turn the call over to Thad, to review our financial results.

Thaddeus Vayda: Thank you, Jeremy, and good day to everyone. During today’s call, I will briefly recap our third quarter results, provide guidance for the fourth quarter and conclude with our preliminary expectations for the full-year of 2025. As is our practice, we will provide updated and more specific guidance when we report our 2024 results in February of next year. As disclosed in our press release, for the third quarter, we reported a net loss attributable to controlling interest of $494 million or a net loss of $0.58 per diluted share. During the quarter, we generated adjusted EBITDA of $342 million and cash flow from operations of approximately $194 million. Positive unlevered free cash flow of $136 million reflects the $194 million of operating cash flow, net of $58 million of capital expenditures.

Capital expenditures for the quarter included $32 million related to the newbuild at Deepwater Aquila with the balance associated with various other projects across the fleet. During the third quarter, we delivered contract drilling revenues of $948 million at an average daily revenue of approximately [$437,000] (ph). Contract drilling revenues are slightly above our guidance mainly due to extended operations of the Deepwater Invictus and shorter out-of-service durations for the Deepwater Atlas and the Petrobras 10000. These factors were offset by lower than expected fleet revenue efficiency due largely to downtime caused by the reliability challenges on our new 20,000-psi blowout preventers, as Keelan just highlighted. Operating and maintenance expense in the third quarter was $563 million.

This is below our guidance, primarily due to the delay of non-critical in service maintenance activities in the active fleet and the favorable resolution of old contingencies. G&A expense in the third quarter was $47 million. This is slightly below our guidance mainly due to delays in the provision of professional and IT related services, which are currently expected to occur in the fourth quarter. We ended the third quarter with total liquidity of approximately $1.4 billion. This includes unrestricted cash and cash equivalents of $435 million about $365 million of restricted cash, the majority of which is reserved for debt service and $576 million of capacity from our undrawn revolving credit facility. I will now provide guidance ranges for the fourth quarter of 2024 and preliminary guidance ranges for the full-year 2025.

As always, our guidance excludes speculative reactivations and upgrades. For the fourth quarter, we expect contract drilling revenues to be between $950 million and $970 million based upon an average fleet-wide midpoint revenue efficiency of 96.5% which as you know can vary based upon uptime performance, weather and other factors including equipment challenges similar to those I mentioned a moment ago. This estimate also includes between $55 million and $60 million of additional services and reimbursable expenses. Please recall that the additional services and customer reimbursables generally carry low-single-digit margins. We expect fourth quarter O&M expense to be within a range of approximately $585 million [technical difficulty]. This quarter-over-quarter increase is primarily due to an increase of in-service maintenance costs due to activity deferred from earlier in the year and a net increase in out-of-service costs including those related to contract preparation for the Deepwater Invictus and the Transocean Barents.

These are partially offset by lower costs for the Petrobras 10000 which completed its special periodic survey in the third quarter. We expect G&A expense for the fourth quarter to fall within a range of approximately $50 million to [$55 million] (ph) [technical difficulty]. This quarter-over-quarter increase is primarily related to the aforementioned delay in professional and IT related services that are now expected in the fourth quarter. Net interest expense is forecast to be approximately $144 million for the fourth quarter, comprising interest expense and interest income of about $153 million and $9 million respectively. Capital expenditures and cash taxes are expected to be approximately $35 million and $9 million respectively. Finally, we currently estimate that we should end the year with liquidity in the $1.35 billion area, including the approximately $576 million capacity of our undrawn revolving credit facility.

Moving to the full-year 2025, we currently forecast contract drilling revenue to be between $3.85 billion and $4 billion. The range primarily reflects potential variances in revenue efficiency, assuming approximately 96.5% revenue efficiency at the midpoint and the limited availability of our active fleet. Our guidance includes between $220 million and $230 million of additional services and reimbursable expenses. We expect our full-year O&M expense to be between $2.3 billion and $2.45 billion and we currently anticipate G&A costs to be between $190 million and $200 million. Our preliminary projected liquidity at year-end 2025 is between [technical difficulty] reflecting our revenue and cost guidance and including our undrawn revolving credit facility and restricted cash of approximately $440 million most of which is reserved for debt service.

This liquidity forecast includes 2025 CapEx expectations of approximately $130 million of which approximately $60 million is related to customer acquired capital upgrades for upcoming projects and capital spares and approximately $70 million of sustaining capital investment. As a reminder, for the terms of our credit agreement, the capacity of our revolving credit facility declined to $510 million from $576 million effective late June 2025. And again, this is preliminary guidance. We expect to provide updated estimates when we report our year-end 2025 results. Finally, based upon our debt maturity schedule, we expect to reduce debt by a minimum of approximately $715 million in 2025, ending the year with gross debt of approximately $6.2 billion.

As we have discussed previously, we will deploy all excess cash to debt repayment in pursuit of reducing our net debt to EBITDA metric to less than 3.5 times, a prerequisite for us to contemplate distributions to shareholders. Based upon our existing backlog and our visibility to future demand, we currently expect this threshold to be met in late 2026, as Jeremy highlighted in his remarks. However, to support and potentially accelerate this initial deleveraging objective, we will remain focused on operational execution and prudent cost control to ensure that we maximize the conversion of backlog to cash. This concludes my prepared remarks, and I’ll now turn the call back to Alison for Q&A.

Alison Johnson: Thanks, Thad. Madison, 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] And, we will take our first question from Eddie Kim with Barclays. Please go ahead.

Q&A Session

Eddie Kim: Hi, good morning.

Jeremy D. Thigpen: Good morning, Eddie.

Eddie Kim: Good morning. Just wanted to ask about your expectations on the trajectory of day rates for next year. Leading-edge has been in that kind of high-400s range for about 12 to 18 months now. Some exceptions above 500, but for the most part in the high-400s. Just given the utilization headwinds that your peers are faced with next year, not you guys, do you expect Leading-edge could maybe drift lower into the mid-400s maybe before ramping up again in ‘26? Just, how are you thinking about the day rate progression from here?

Roddie Mackenzie: Hey, Eddie, this is Roddie Mackenzie here. Okay. So, look, just I mean, our average fixture for our 1,400 ton class and above in ‘24 has been like 520. So, we’re firmly in the 500s for that class of asset. Our view on where things are, if there’s a little bit of soft spots here and there, what we’ve witnessed is that a lot of these programs that the rigs are on just now, they run a little bit longer. We also know that there’s a lot of direct negotiations that take place that are perhaps not out in the public domain. So, like, we use the example of the Invictus this year for us. So, we think about we didn’t really have a contract past April of this year, but yet the rig is still working right now.

And then, of course, we had the announcement with the long-term BP contract. So, I think there’s a lot of stuff that you perhaps don’t see. My view also is that in terms of day rates for instead of the seventh-gen premium units that we’ve got, maybe the seventh-gen commodity units, there’s no reason why they should dip substantially. I think if some of the sixth-generation or Tier 2 assets are to go idle, then I think there’s a very strong possibility many of them will be sidelined. In fact, that’s probably time for them to kind of retire. So, I actually don’t think the active utilization is going to be impacted too much when you think about the right assets. So, I think for a lot of those seventh-gen dual BOP rigs, there shouldn’t be a substantial differential in day rate.

Jeremy D. Thigpen: Yes. Eddie, just to add to that.

Eddie Kim: Okay.

Jeremy D. Thigpen: It doesn’t impact us at all if you think 1,250-ton rigs. Ours are all on longer-term contracts for the most part. And, so we’re not going to be really bidding them for 2026. And, of course the 1,400-ton and 1,700-ton rigs have proven even through the depths of the downturn that we just emerged from that they can secure contracts at premium day rates. And so, we’re not really too concerned about what happens here over the course of the several months in terms of contracting for work in 2025. But, we are certainly keeping a close eye on our competitors and it’ll be interesting to see which ones favor utilization over maximizing day rates. We had no idea how that’s [technical difficulty]. But as Roddie said, I think this could be a great opportunity for the industry, to kind of purge some of the lower spec assets as they roll out contracted by difficult to secure new ones.

Eddie Kim: Got it. That makes sense. But, my follow-up is just on the sideline 7G drillship capacity. There are about 10 that most consider to be viable 7G rigs between cold stacked and stranded newbuilds of which you have three of those 10. Thus far only one of those 10 has secured a contract most recently the title action. I think if you ask most people earlier this year, they would have expected a little more than that. So, just I guess looking ahead to next year, just given the white space concerns that the industry faces and just based on kind of the demand that you’re seeing, how many of the nine remaining sideline rigs would you expect to announce a contract sometime next year? Are we talking maybe two announcements or does that even seem a little too optimistic just based on what you’re seeing?

Roddie Mackenzie: Yes. Again, look, we would take that when you think about the three that we have sidelined, we’re in no rush to bring them to market. In fact, if we look at some of the numbers that were kind of kicked around, Jeremy had mentioned like those $500 billion essentially going to be spent every year going forward on upstream investment. If you think about that specifically in Deepwater, the current levels of sanctioning are around about $50 billion per year at the moment. But, in ‘26 and ‘27, that’s actually expected to double according to the latest Rystad projection. So, I just don’t think there’s any need to push those rigs out right now. I think it would actually be far smarter to wait and target the ‘26 and ‘27 timeframe when basically there’s twice as many projects are going to be sanctioned as there is now.

Jeremy D. Thigpen: Yes. And having said that though, I mean these assets are going to take a year plus to bring out of cold stacked. So, you could see decisions made sometime in 2025 for a contract that started in late ‘26 or ‘27. But I wouldn’t I mean you said maybe one, two, maybe three. I think that would be probably about it, for 2025 in terms of contracting of cold stacked assets.

Eddie Kim: Got it. Okay. That makes sense. Great. Thank you both for all that color. I’ll turn it back.

Operator: Thank you. And, we will take our next question from Arun Jayaram with J.P. Morgan. Please go ahead.

Arun Jayaram: Hey, Jeremy and team, I wanted to get your broader thoughts on just the overall industry structure that you see at the premium end of the market. And obviously, there’s been some press reports on a consolidation transaction potentially between Transocean and [Seed] (ph). I was wondering if you could maybe just comment broadly around your thoughts on industry consolidation and if you care to comment on some of the press reports that we’re reading?

Jeremy D. Thigpen: Well, we’re not going to comment on press reports that are out there that are based on speculation. I mean, I find that the media and the press do such a wonderful job of really getting the facts before they print a story. But regardless, I said I think we have been very consistent in our approach to consolidation. We think it is healthy for our piece of the industry. We’ve helped lead that consolidation. Some of our competitors have certainly done that as well. We are in a much healthier piece of the industry now than we were if you go back to 2014, far fewer players in the market, far fewer assets in the market. The industry structure has been much improved over the course of the last eight, nine years, ten years.

And, so I think we’re in a good place as an industry. We still think there’s room for a bit more consolidation in the space and think that would be healthy. There are all kinds of incremental benefit, all kinds of value that can be created through a transaction and a combination. I mean, we could take on 10, 15 additional rigs with very little increase to our shore base support for those rigs. A lot of synergies that can be realized. So, we’re still always looking, but for us it’s going to be around asset quality. It’s going to have to be the right value. And so, I think it’s tough to match everything up and get deals done in the current environment where everybody thinks that we’re up into the right for the foreseeable future.

It may have a little bit of a pause here over the next several months. But, I think consolidation is still a good thing. But, even if there isn’t any consolidation, I think the industry is in a much healthier place today than it was when we started the downturn back in 2014.

Arun Jayaram: Yes, great. Just my follow-up, on the BOP kind of teething issues, could you maybe just elaborate on that? Is this just kind of normal type of commissioning work you do on a new piece of equipment?

Keelan Adamson: Yes, it’s Keelan here. Is it normal? Yes, I guess nothing is really normal when you’re talking about the aspects that have an infant mortality that we’re experiencing in some of these components, pretty standard sort of expectations, stuff that by the very nature of the technology that we’re using, the tolerances reduce significantly. And some of the aspects of that can be tested in qualification and then some don’t really appear until you get into actual operation and see how things work at that time. So, we’re going back through some qualification testing to amend some components to be able to deliver a much more robust reliability from the units going forward. So, not necessarily surprised we experienced some of this before with some of the higher spec 15k BOPs we delivered in the last cycle. And we’re very confident that working with our partners going forward, we’ll resolve these 20ks ones very, very quickly.

Jeremy D. Thigpen: Yes. I mean candidly given the nature of this technology, the fact that we won an entire year without really any issues at all and then we had some piece of the equipment sale a little sooner than we would have hoped. But honestly, it’s been a pretty good run, given the first issue equipment.

Keelan Adamson: Yes. That’s right, Jeremy.

Arun Jayaram: Thanks, gentlemen.

Operator: Thank you. And we will take our next question from Scott Gruber with Citigroup. Please go ahead.

Scott Gruber: Yes, good morning. Thad, what level of underlying cost inflation is embedded in the ‘25 cost guide? We’re just hearing some inflation commentary coming out of Brazil and West Africa. So, just trying to get a sense of where inflation is running these days?

Thaddeus Vayda: It’s a good question. And it varies based upon jurisdiction, asset, activity to be sure. I mean, what we’ve observed, I think in 2024 was inflation that on average comprised somewhere between 5% and 6%, but it really depended upon what it was, rig floor, things of that nature, labor. We’ve assumed that there is a bit of inflation going forward, typically in the sort of 3 percentage range on average and we’re pretty comfortable that that’s kind of where we’re going to end up. That’s for 2025 and beyond.

Scott Gruber: Got it. I appreciate that color.

Thaddeus Vayda: And then just to add to that, it’s important to note that in our longer term contracts, we build that into the contract and we pass it through the majority of that inflation through to the customer.

Scott Gruber: Got it. Yes, that’s good to know. Thank you. And then just thinking about the incremental demand that could show up in ‘26, Namibia is going to be a big area of focus. What type of rig are customers discussing utilizing on the development projects offshore in Namibia?

Jeremy D. Thigpen: Yes, I think it’s a combination of drillship and semi, but I’ll let Keelan elaborate on that.

Keelan Adamson: Yes. I think it really depends on the aspect of the area of Namibia and the opportunity that the customers are working to in that area. And in some cases, a harsh environment semi is preferred for the environmental conditions. It can be quite extreme down there. And in other close by areas actually, drill ships can survive that weather adequately. It’s as you get closer to the South Africa border, and you tend to get into the more harsh environment areas. So, I would say it’s a solution that’s based on the location of the prospects and also the type of work. If you’re in drilling mode, you probably have a lot more tolerance than perhaps in running completion. So later on a development rig like a semi-submersible for the completion phase of a project would probably be more desired.

Jeremy D. Thigpen: I mean, said simply the Ultra Deepwater drillship is a more efficient drilling machine, but you may have more waiting on weather in certain areas of Namibia. And so it’s in a harsh environment, semisubmersible could stay on location longer. And so that’s what our customers have to weigh.

Scott Gruber: Got you. I was just wondering whether what kind of which direction they were leaning. Appreciate the color. I’ll turn it back.

Operator: Thank you. And we will take our next question from David Smith with Pickering Energy Partners.

David Smith: Hey, congratulations on your successful contracting and premium asset strategy that has insulated you from the white space concerns that your peers are dealing with.

Jeremy D. Thigpen: And Roddie asked me to say that, David.

David Smith: Nobody asked me to say it. It’s impressive.

Jeremy D. Thigpen: Thank you.

David Smith: And I recognize that you’re not facing the decision of whether or not to stack rigs next year. But given your historically strong leadership in reducing excess capacity and pass cycle, I just thought it would be valuable to get your perspective on the decision process of whether or not to stack a rig?

Jeremy D. Thigpen: Yes, David. We do this on I would say quarterly, but it’s more frequent than quarterly. But I mean you’ve seen over the years, we have I don’t know what is it 60 plus floaters that we have retired or scrapped or sold into other purposes over the course of the last decade. And so I think we’ve demonstrated that if we see that the long-term future of a particular asset is not looking very bright, why incur the cost on it? Let’s take the rig out of the supply. I think it’ll be interesting to see I’ll speak for the industry and then a little bit for Transocean for us. As we said earlier on the call, the 1700 ton rigs, the 8th Gen rigs and the 1400 ton rigs, which we call 7G Premium I guess, will certainly continue to work.

You may see small gaps just if customer programs don’t line perfectly, but for the most part those rigs will continue to work. Our other 1250 ton rigs that are currently active are on longer term contracts for the most part or in Brazil where we expect them to hope for they to be re-contracted. Once you get to Brazil, you have a pretty good incumbent position. And so it’s not really a concern for us at the moment. But as we start to look around our peer group, obviously a lot of rigs rolling off contract amongst our peers, all of 1250 ton or even below some of them are 6Gs rigs. And you’ve got to wonder about the demand for some of the lower specification assets. We would create an ideal time to the extent that they don’t secure contracts immediately following these contracts that their existing contract that those rigs get sidelined and maybe even scrapped.

But that’s for our customers to decide. Our approach has always been, hey, what’s the next nearest opportunity for this asset? What do we think that day rate will be? And if it’s a prolonged period of time and it’s uncertain, we make that decision pretty quickly to scrap the asset.

Thaddeus Vayda: Yes, I think I would add to that. I think the strategy for a lot of our competitors on the lower spec assets has been really to wring out everything we possibly can in terms of value from those assets just now. We run them to the end of the contracts, minimal spend on OpEx and CapEx as they go. And then when the time comes, you immediately reduce all of your expense and go idle or probably quickly move them to retirement without the opportunities. But it’s kind of interesting as you go down that track and that’s what happens, then not only do you save the cash of not preserving the rigs or paying stacking fees, but by retiring, you actually high grade your fleet as well and high grade the overall. So, I think everyone benefits from that kind of action.

David Smith: Appreciate the color.

Thaddeus Vayda: I’ll just say this gets to industry structure, a question that was asked earlier on. I just want to emphasize that it is truly I wouldn’t call it a cage fight, but it’s pretty close when we sit around and we have these discussions about assets that are available. You trade off optionality, near-term optionality, long-term optionality. But at the end of the day, scarcity of drilling rigs in general, is better for the stability of the industry through the cycles.

David Smith: Yes, absolutely. I think you have a great playbook. I think the industry will be stronger if your competitors borrow some pages from that playbook. If I could do a quick follow-up, I thought the opening remarks, that commentary about being in maybe being in a position to return cash to shareholders by late ‘26, that was interesting. I wanted to ask if there are any specific metrics that you’re targeting before getting comfortable shifting some of that cash flow to shareholders versus debt reduction?

Thaddeus Vayda: Well, I think the key metric is the one that I mentioned in our credit facility, which was negotiated a couple of years ago. There are some very specific criteria for a point at which come in the form of cash or share repurchases. And the key one where we are able to actually begin to consider is 3.5 turns net debt-to-EBITDA. So, in a hard cold reality, that is the metric that we hope to achieve as quickly as possible so that we can begin that deliberation. Beyond that, of course, paying down debt and we do very much have, if you will, the discipline of debt unlike many of our competitors. It’s just the consequence of not restructuring during the downturn. But I think it’s leading to a lot of very fruitful conversations internally about costs and things of that nature.

There is a price for having assets as highly utilized as ours are. It’s the high specification component and it’s all of the, if you will, bells and whistles and things that improve the efficiency and essentially demand for them by our customers. But it does provide us with, on the positive side, the basis for a very good conversation about where every dollar of cash is deployed. The benefits, of course, of paying down debt will include better credit ratings and so forth. And we’ve always talked about those as sort of an interim measure, achieving that double level, which comes about the same time as the 2.5 turns.

David Smith: Great. I appreciate the color. That’s it for me.

Thaddeus Vayda: Thanks, David.

Operator: Thank you. And we will take our next question from Kurt Hallead with Benchmark. Please go ahead.

Kurt Hallead: Hey, good morning, everybody.

Jeremy D. Thigpen: Hey, Kurt.

Kurt Hallead: Hey, great update. Really appreciate it. So, just maybe one observation, which basically given your contract coverage and everything you said about pricing and how your customers are looking at opportunities out beyond 2025, not really sure why your stock is down 35% year-to-date, but clearly investors are thinking the end of cycle has already come. But nonetheless, I’ll get off that soapbox and get a little bit smarter. Get a little bit smarter about what’s going on in the business. So, I think obviously the biggest issue that investors have right now is a concern about what’s going to transpire with respect to oil supply demand out beyond 2025. And in that context, already, if you will, placing bets that oil companies will be scaling back their investment in these deepwater programs.

So, you referenced very early on that you’ve done extensive conversation or had extensive conversations with your customer base and that’s what you kind of predicated your outlook on as we would expect that to be. So, what is it that we are missing on this side of the table that you guys are picking up on in your conversations? And maybe is there a way that you can help express the conviction that your customers have in the outlook that they are willing to contract a rig for $600,000 a day starting in 2028?

Jeremy D. Thigpen: Yes, Kurt, that was a long question. I would say I know. No, It’s a good question. I certainly get the point. And I understand the concern in the broader market about future demand and supply challenges. What I would say is I don’t spend a lot of time thinking about that. I pay attention to what our customers are telling us and how they are behaving, how they are acting. And I would say that everything that we are seeing from them demonstrates that they are committed for the long-term. These are long-term projects. It’s not a land opportunity. These are longer cycle projects. You’ve got to remember now that the breakeven cost for our customers in deepwater is around $40 a barrel. And so even if oil prices drop a bit, they’re still making some pretty nice returns internally.

We’ve had several customers show us I mean show us presentations that at $50 a barrel they’re making a 20% IRR. So, they’re doing very well at the moment and I think they’re committed to their future program. They do need to replace reserves. The best way to do that is through offshore. What the Street doesn’t see is what we see every day. You guys see tenders and maybe you hear maybe you catch wind of some direct negotiation. The fact that our assets are so unique, the 1700 ton asset, the 1400 ton assets, why go out to tender? I mean they’re going to come to us. And so those are the conversations that we’re having with customers and we are deep in conversations, deep in negotiations on several fronts for multiple years out from now.

And so all of that gives us confidence. Again, you can’t see that, the Street can’t see that and that’s probably part of what’s weighing on the stock. But I believe we have come through with everything that we have said, maybe it didn’t occur on the timing that we necessarily wanted, maybe it stretched out a quarter or two. But we continue to sign contracts at leading edge day rates and continue to keep utilization at near 100% for our active fleet. And it’s because we believe in these conversations that we’re having with our customers. And with that, I’ll turn it over to Roddie who’s involved in this every day.

Roddie Mackenzie: Yes. So what I would say is, as Jeremy described, the oil price is obviously important, but let’s be honest, we move up and down as a stock with the commodity, but there’s really a threshold by which it would not negatively impact our business. So, our customers, as Jeremy mentioned, are very comfortable moving forward with these developments. And specifically, we are looking at harsh environment and deepwater. So, the true differential in spend is actually continuing to skew towards deepwater because these are much more economical and viable projects. They just happen to take a longer period of time. So, that’s actually a positive for us, again, from the view of your question was why do you think things are going to be good in ‘26 and ‘27.

Well, as we look at our fleet, in ‘27, we already have half of the active fleet booked, right? So, at this point in the cycle, we’re well ahead of the game, and these rigs are booked on projects that will kind of transcend the near term up and down of oil because they were sanctioned at $35, $40 a barrel. So, I think that’s a really important concept for everybody to understand is that the nature of deepwater drilling is long-term. The value that is unlocked through the deepwater drilling is significantly higher than practically any other place you could invest in energy, whether it be renewables or other forms of oil and gas. We represent the best IRR. It just so happens to take a longer period of time. But yes, so I think those are the key elements of why this is not just a long cycle, but a kind of you would have to see a sustained downturn in economic policies and commodity that crashes rather than ebbs and flows.

And the last thing I’ll point out is, as we think about where the commodity is today, we’re talking about, well, oil prices are a little soft. It’s exactly what it was one year ago, which is exactly what it was one year prior to that. So, we’ve kind of had this three year stretch that there’s been highly constructive oil prices even in the dips.

Jeremy D. Thigpen: And maybe one more thing Kurt on that. The other area to look at is the amount of FIDs in deepwater that have been approved, the consumable equipment that’s being ordered, the trees and the wellheads, that’s all long lead. That all needs to go well in front. And we see that data and that supports the decisions that are being made. Also add, we’re seeing an uptick in exploration activity from where we were a few years ago to what our customers are placing our rigs on as a whole going forward, and that increase obviously supports potential future developments as well. So long answer, I guess, from the view.

Kurt Hallead: No, no. Thanks for all that color. Really appreciate it.

Operator: Thank you. And we will take our next question from Fredrik Stene with Clarksons Securities. Please go ahead.

Fredrik Stene: Hey, Jeremy and team. Hope you are all well and thank you for taking my question. So, I wanted to circle back a bit to the M&A questions that were asked previously. And obviously, I totally understand that you can’t comment specifically on everything that’s running around in the press. But in your prepared remarks, you did spend quite a lot on the commentary around your fleet quality and your ability to use that quality and the specifications of your rigs to demand higher rates. So, I was really wondering, should we if you were to participate in M&A at some point, how much should we think about fleet quality to look at potential matches for Transocean? Or would just, call it, the benefit of being larger outweigh that? So, any thinking you can give around that would be very helpful for me. Thank you.

Jeremy D. Thigpen: Hi, Fredrik. Yes, thank you for the question. There is no acquisition we could make that would be accretive to the quality of our fleet. I mean, that’s just true. No one has 8th generation rigs. No one has eight 1400 ton rigs. And so there’s nothing we could add that would be necessarily accretive to our fleet. For us, there’s value obviously, you can immediately grow into your balance sheet and solve some issues there. You can acquire some very good marketable assets that are currently hot and some rolling off contract and ready to be repriced and what we think is a favorable. With our $9.3 billion backlog and our marketing expertise around the globe, we would have the expertise and the patience to place those rigs on the best possible contracts to earn the highest possible return.

And so we think there is some value in all of that. Obviously, there are synergies with respect to SG&A reductions, purchasing power. I mean, and I think just improving the overall quality and consistency of service that we can provide to our customers. There are all kinds of potential benefits from a transaction, but from a fleet quality standpoint itself, there’s nothing we could acquire that would actually improve the quality of our fleet. We have the highest specification assets. It’s not debatable. But getting hot assets that are good marketable 1250 ton assets that are ready to go on to the next contract is certainly a plus because I mean for us to add capacity would require a reactivation of a cold stacked asset which we have told is somewhere between $75 million and $125 million potentially and takes at least 12 months to do.

So, it would enable us to quickly grow and expand our presence and create some real value for our customers and our shareholders.

Fredrik Stene: Thank you. That’s very helpful. Second question, you announced the sale of the Development Driller 3 and the Discoverer Inspiration earlier this fall, and I think the transaction was supposed to be completed in the Q3. And then if those rigs are sold and particularly if they’re sold for auto drilling work, I think that would be great prices, etcetera. So, are you able to give us some updates on the process around those two rigs? And also if you believe they will still continue to drill or if they will be used for other purposes?

Jeremy D. Thigpen: So, the assets, were sold without restriction on use once they were sold. However, the specification, the uniqueness of assets gives us a good deal of probability of us competing against them in the future is relatively low. With respect to the timing of the transaction, we’re just working with the prospective buyer right now. We’ve given we indicated in our filing that we expect the transaction to close by the end of the year, had to do with the financing elements and things of that nature, but that’s all we have as far as updates right now.

Fredrik Stene: Okay. Thank you very much. And thank you guys for taking my questions. Have a good day.

Jeremy D. Thigpen: Thanks, Fredrik. You too.

Operator: Thank you. And we will take our next question from Greg Lewis with BTIG. Please go ahead.

Greg Lewis: Hey, thank you and good morning and thanks for squeezing me in. A lot’s been covered, so I’ll try to keep it brief. I did want to talk a little bit about Brazil. You did mention the for spec, the high spec tender that’s I guess going to be announced shortly and the and Sépia. You kind of alluded to a third one, less familiar with that one in terms of maybe when that starts up. And then just as I think about that, Jeremy, I think you did talk about direct negotiations. As we look and we don’t need to talk specifically about the Mykonos, but as we look at rigs in Brazil rolling off contract in ‘25, the numbers don’t match. And it looks like there’s going to be a couple of rigs that are idle. I guess, two questions there.

One is, in the past, I believe Petrobras has done direct negotiations with rigs that were already on contract and just extending those. Is that something that is still happening? And then I guess if an international contracting rig was idle in Brazil, it doesn’t seem like idle rigs stick around Brazil too long. Realistically, how much white space could an international contractor rig be in Brazil before it would move out?

Roddie Mackenzie: Yes. Hey, this is Roddie. I’ll take that one. Yes, so you’ve got the Roncador tenders already been decided, and then you’ve got like the Sépia and the pool three tender. Yes, there is quite a lot of anticipation about there being additional tenders to come. So, I think that was the first comment that you had. The second piece is direct negotiations is open to Petrobras, particularly on developed they have a different ownership pattern or like a wider partner base, if you would. So, there’s a couple of those that could result in direct negotiations for extensions. And again, the concept being, it’s far more efficient from the operator’s point of view to extend a rig rather than to bring in a new one.

So, even to stop a contract, have a pause and then start up again, there’s a lot of frictional losses there, not only for the contractor potential, but also for the operator. So, like picking up services, laying down services, going through inspections, all that kind of stuff. So, we do expect that there’s going to be a little bit of that going on in terms of direct negotiations. We also think there’s going to be some additional tendered work coming out. So, I think the incumbent fleet in Brazil is going to look pretty good for the most part. And then your last piece about how long would you hang around in Brazil, typically, there used to be a rule that you had to remove the rig from Brazil if you were not on the contract. That is no longer a rule.

So, you can actually hang out in Brazil for a while. So, I think that probably depends a lot on the rigs that have some white space, it’s not until six, nine months from now, maybe longer. So, they’re probably going to wait and see what these additional tenders look like before making a decision on that. And I would imagine they would wait as long as they possibly could. But I think you’ll see over the next few months the anticipation for the other tenders, the possibility of some direct negotiations, and you’ll probably see that play out kind of by the end of the year or first quarter next year.

Greg Lewis: Super helpful. Thank you very much.

Operator: Thank you. And it appears that we have reached our allotted time for questions. I will now turn the program back to Alison Johnson.

Alison Johnson: Thank you, Madison, and thank you everyone for your participation on this call. We look forward to speaking with you again when we report our fourth quarter 2024 results. Have a good day.

Operator: This does conclude today’s presentation. Thank you for your participation. You may disconnect at any time.