Good day, and welcome to the Q3 2021 Transocean Earnings Conference Call. This conference is being recorded. At this time, I would like to turn the conference over to Alison Johnson, Senior Manager, Investor Relations. Please go ahead.

Thank you, Marianne. Good morning, and welcome to Transocean’s third quarter 2021 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, President and Chief Executive Officer; Mark Mey, Executive Vice President and Chief Financial Officer; Keelan Adamson, Executive Vice President and Chief Operations Officer; and Roddie Mackenzie, Senior Vice President of Marketing, Innovation and Industry Relations. 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 and Mark’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 on this call, please limit yourself to one initial question and one follow-up. Thank you very much. I’ll now turn the call over to Jeremy.

Thank you, Alison, and welcome to our employees, customers, investors and analysts participating in today’s call. As reported in yesterday’s earnings release, for the third quarter, Transocean delivered adjusted EBITDA of $245 million, on $683 million in adjusted revenue, resulting in an adjusted EBITDA margin of over 36%. Additionally, our quarterly free cash flow of $104 million represents the sixth straight quarter of positive cash generation. During the quarter, we matched a company best revenue efficiency of 98% for the second consecutive quarter. And we have maintained a revenue efficiency of 97% or higher for six sequential quarters due to our consistently safe, reliable, and efficient operations across our operating fleet. Indeed, it was a true team effort globally. Supported in addition to other transition initiatives by our smart equipment analytics system, which helps us monitor critical pieces of equipment and systems to identify anomalies and signs of degradation such that we can prevent and potentially predict unplanned failures and resulting downtime. The same system allows us to track and trend fuel burn, energy consumption, and emissions in real-time, helping to optimize energy efficiency in our operations, providing us a powerful tool and delivering our 2030 goal of a 40% reduction in our greenhouse gas emission intensity versus 2019. Now turning to our fleet. Starting in the Gulf of Mexico, in August, we announced the $252 million two-phase contract we signed with Beacon Offshore Energy for the Deepwater Atlas. Following the final investment decision of Beacon and the Shenandoah working interest owners to sanction the previously announced project in the U.S. Gulf of Mexico. The Atlas, which is nearing completion at the Jurong Shipyard, will be one of two, eight generation 20,000 psi ultra deepwater drill ships in the transmission fleet. In addition to the 20,000 psi well-controlled equipment, the…

Thank you, Jeremy. And good day to all. During today’s call, I will briefly recap our third quarter results and provide guidance for the fourth quarter and conclude with preliminary expectations for 2022, including our latest liquidity forecast. As is our practice, we provide more specific 2022 guidance. We have our 2021 year end call in February of next year. As disclosed in our press release for the third quarter of 2021, we reported a net loss attributable to controlling interest of $130 million, or $0.20 per diluted share. Highlights with the third quarter include, adjusted EBITDA of $245 million, reflecting robust fleet-wide efficiency. This contributed to another quarter of healthy 36% EBITDA margin. Fleet-wide revenue efficiency exceeded 98%, again, this quarter, reflecting continued operational excellence and the conversion of drilling contract bonus opportunities into revenues. And we generated approximately $141 million in operating cash flow. Additionally, we raised approximately $75 million during the third quarter, another $17 million in early October, the opportunistic sell of our equity using our ATM program. As reflected in our Form 10-Q, this brings our total equity proceeds under the program in 2021 to approximately $158 million, evidencing our continuous efforts to improve liquidity. Looking close at our results, as Jeremy mentioned, during the third quarter, we delivered adjusted contract drilling revenues of $683 million and average day rate of $367,000, reflecting strong conversion of contractual backlog mentioned above. Operating and maintenance expense in the third quarter was $398 million and is favorable relative to our guidance, resulting from lower over time costs due to optimizing our use of labor pools and a decrease in COVID related personnel expenses. We also had lower project costs as a Deepwater Mykonos and Transocean Enabler projects were completed ahead of schedule. We also had postpone some in-service…

Thanks, Mark. Marianne, we’re now ready to take questions. As a reminder to participants, please limit yourself to one initial question and one follow-up question.

Thank you. [Operator Instructions] We will take the first question from Greg Lewis from BTIG. Please go ahead.

Yes. Hey, thank you, and good morning, everybody. Jeremy, just kind of trying to parcel through some of your prepared comments, it seems, like, you laid out the details, the market is definitely getting – going in the right direction. As we – as you think about 2022, I’m trying to kind of understand, do we kind of view that more as a little bit more of another transition year or it almost sounds like we’re going to start to see incremental day rate growth and pricing get going here, maybe as rig start to get fixed in the back half of 2022. Is that kind of the right way to think about it and just in piggyback…

Did you want to finish up there? Sorry. I thought you were done with the question.

Yes. No, I was going to say, and then just in thinking about that, tying that in the Mark’s comments about not reactivating a rig without some term work. There have been – we have started to see some multi-year contracts being fixed. Hey, maybe the rates aren’t – those leading edge spot rates you’re referring to, but nevertheless, some attractive EBITDA being generated. Is that kind of – is that – how we should be thinking about how 2022 unfolds where we’re going to have some opportunities to fix some multi-year rigs on contracts?

Yes, I think that is the right way to think about it. And I’ll turn it over to Roddie here in just a second, but I will say, I think the roadmap that you’ve laid out feels about right. Contracting activity to continue to pick up as we exit this year and enter next for work that will commence kind of in the back half of 2022 and then in 2023. And as long as – we all recognize the high utilization for high spec assets in these various markets and we’ll then go up. I think we’ll start to see longer terms and we’re starting to have those conversations with customers now. Just a little anecdote before I hand it over to Roddie, it’s been interesting that many of our customers have approached us with direct negotiations as opposed to putting things out for tender and they’ve also approached us – to revisit our business model and look at something that’s more of a partnering approach that can survive upturns and downturns. And so I think it’s a good sign that everybody sees the market recovering in the space and that the availability of really high spec assets that are currently marketable is limited. And so with that, I’ll hand it over to Roddie for some more comments.

Yes. Greg, I think I would attack this kind of on a regional basis. So as how you should think about 2022, so it depends on where you are. You will see this – as you say, this kind of transition year that we start to plug a few gaps on the white space lines and get a closer and closer to that 100% utilization of the marketed assets. Certainly, in places like Norway harsh environment, you have a few gaps in 2022 – exiting 2022 and going into 2023 starts to look a bit better, 2023 summer is really, really strong 2024 and beyond as many high spec assets as they’ve ever had in projected utilization. So I think you will see this kind of transition where term starts to increase. We’ve seen that in the numbers so far that this quarter is yet another uptake, not only in the number of awards, but the duration of the awards, the number of programs available and the number of rig years that are out to tender at the moment. So all of those metrics are pointing in the right direction. And as Jeremy had mentioned in his comments, we’re seeing that translate directly into increased day rate. So, especially in the U.S. Gulf of Mexico, which seems to be the hottest segment at the moment, we’ve seen those rates push up to the 300 mark. If a one customer told us the other day that it’s going to be a case of musical chairs and somebody is going to find themselves with that rig. So I think when you view that kind of sentiment, then there’s certainly a lot of optimism about the value of the rigs in terms of getting what you need. And I think the other really big one just now we’d have to describe as Brazil. As we mentioned, there’s about 27 years of work have already been awarded this year for the floater market in Brazil. As we look at the project approvals that are to be sanctioned in 2022, 2023 and 2024, those combined three years will sanction somewhere in the region of 28 to 30 projects, so the follow-on effect on the rig count is going to be substantial. So I think that’s just increase utilization and then not locking in for long-term at the low rates, but really trying to split that strategy between a bit of backlog and an ability to earn some really solid EBITDA numbers. Yes. And just to kind touch on the reactivation piece, our customers know that they’re going to have to pay for that either through large one-time mobilization fees and/or through higher day rates and longer terms that would justify the significant investment is going to take for all drilling contractors to reactivate these assets have been sacked for quite some time.

Okay, great. And then just wanted to follow-up a little bit on Brazil. I mean, clearly, Petrobras has been active, but as we kind of try to parcel out the multiple projects that are going on in Brazil. Without getting into specifics, is there any kind of way to think about, how much of that is Petrobras and how much of that is also IOCs, because – and correct me if I’m wrong, but I kind of get the sense that it’s going to be the IOCs driving price in Brazil, maybe not Petrobras, who tends to always be able to get a discounted rate?

Yes. So that’s really interesting. So Petrobras has obviously seen what’s coming. They move very quickly. They – despite, the relative bureaucracy in Petrobras for awarding contracts, they’ve been prolific and the contracts that they’ve awarded this year. They have taken the lion’s share for sure. And what’s really interesting in the charts that we show in terms of those project approvals, the past couple of years has all been Petrobras, but moving forward, it’s kind of an even split between the IOCs and Petrobras. In fact, next year, I think, eight or nine of the expected project approvals for sanctioning are non-Petrobras. So Petrobras still very active. And as we’ve described before, they’re kind of turning over the rig fleet renewing them as they come available. And that incremental demand is really being pushed by the IOCs, which is over and above what Petrobras is doing. So yes, and somebody is kind of like a 50-50 split going forwards on IOCs versus Petrobras awards.

Okay, perfect. Thank you all for the time.

[Operator Instructions] We’ll now take the next question from Connor Lynagh from Morgan Stanley.

Yes. Thanks. Wanted to ask about the topic of the day, which is inflation. Just curious what you guys are seeing in terms of labor availability, any needs to raise your wages either on the rig or more shore-based costs. Just broadly speaking, how are you thinking about that?

It’s actually a timely question and also a good question. I mean, the market is improving. So that’s good. Yes, we are seeing a bit of wage inflation. We’re bringing two new builds onto the market next year. And so finding crews after seven years of a pretty desperate market where we’ve lost a lot of people in the industry to other industries of the carriers finding the right talent and getting them back and getting trained to the standard that transition is accustomed to is one of our chief concerns. There’s no doubt about it. I would like to ask Keelan, since he’s sitting here and he’s living this each and every day to talk a little bit about what we’re seeing out there.

Yes. Thanks, Jeremy. And Connor, I would say similar to the last answer from Roddie in the market, it is regional based at the moment. The cost structure, the way the pressure on labor we’re seeing in the Gulf of Mexico, in certain positions offshore, there are other opportunities for those people to work outside of our sector even. And so with the increase in reactivations and new bills coming in, and the general increase in activity in the Gulf of Mexico, we’re definitely seeing some wage pressure there. I think also on the supply chain side for running our rigs, we’re starting to see some cost inflation from our suppliers in that area as well.

Got it. And it – I mean, from the sound of it is and sounds like you think you have the ability to pass on most of this cost increase, yes.

Yes, yes. We will do that, Connor.

Okay.

Yes, Connor.

Just one last one, sorry.

I was just going to say, yes, several of our contracts have adjustments and them for lag kind of a change in the environment to do with labor, but also the cost of equipment general oil field service costs. So we have several of the major contracts that we have potentially the longer-term ones have those adjustments built into them. So it’s a means for us to protect that EBITDA margin.

Got it, got it. Just sort of an unrelated follow-up here, just thinking through, you’ve seen more cold stacked reactivations have been also interested to see some of the bareboat charter arrangements that, that some of your competitors have been executing with yards. I mean how do you think about that altering the balance in the market and does a bareboat charter rig compete favorably with the cold stack rig? Just how do you think about that influencing market dynamics here?

Yes. I think so what we see now is with a lot of the restructured drillers not having a tremendous amount of cash on hand. The true cost of reactivating the rigs has to be taken into account. So certainly in terms of what it costs to bring the rigs out and it’s not cheap. I mean there’s substantial equipment costs to do with overhauls, but there’s also the OPEX associated with rig crews and ramping up and going through your data procedures to bring the rig to market and mobilize it. So look at me, we’ve seen them the operators paying for a lot of those things in terms of being competitive. So no reason why a cold stacked asset can’t perform well, but it’s been the industry’s experience that the hot assets perform far better. Now the call that pulls that assets can eventually get up to that level of performance, but there’s always some teething issues bringing in the out. So there’s a very strong preference at the moment for securing rigs that are hot and active. We expect that’s going to continue, but certainly as we get to that sold-out realization on the active fleet, there’s going to be no other choice, but to bring out more coal stacked assays. But of course, we believe the economics of the jobs are going to support that decision. So we cautiously look forward to getting to that point of being a 100% utilization for the hot rigs.

All right, thanks. I’ll turn it back.

We’ll now take the next question from Taylor Zurcher from Tudor, Pickering, Holt.

Hey, thanks, and good morning, guys. Jeremy, I just wanted to follow-up on one of your earlier responses in Q&A. You talked about more customer direct negotiations, but also more customers looking to revisit a partnership approach with you. And I just – I’m curious what you mean by a partnership approach to me maybe some longer-term contracts, which helps smooth out the cycles for you, at least at the rig level, but just curious what you’re seeing in here and when it comes to different business models that your customers are open to.

Yes. I think it varies by customer. I think that the primary message is they see value in keeping continuity. It definitely improves operations from a safety, reliability and efficiency standpoint and so. I think some of them are recognizing that. And so instead of going out to tender to every drilling contractor and service provider on the planet, it’s look – let’s narrow it down to a couple that are qualified and work closely with them to more safely, reliably and efficiently deliver wells. I think there’s also an element of it around let’s make sure dayrates don’t get too high and let’s come up with a model where we’re both drilling provider, service provider and an operator can all benefit and the ups and the downs of the cycle and continue to thrive. But it’s interesting. We didn’t really have these conversations on the way down. Yes, yes. I think it – really is about efficiency, right. So clearly if we are able to deliver a superior service, then with the commodity prices where they are, and many of the big guys having a very solid returns at the moment increasing dividends kind of stands to reason that there’s enough in the system for all of us to do well. So it’s our focusing on making sure we get those win-wins. And I said that kind of tongue in cheek, but it is encouraging to see a different approach where it is more of a partnering relationship where they recognize that that continuity is important. And so that’s an encouraging for us, and it’s also a sign. We think that they see the market improving and want to make sure that they’re well-positioned for it in terms of not only having the highest spec assets, but working with the best providers.

Yes. Understood. Good to hear. And my follow-ups on the UK, this is the second straight quarter. You’ve talked pretty positively about the outlook in the UK 2022 and beyond, and potentially pulling some rigs from Norway to satisfy that demand. When I look at your fleet, I mean most of your rigs in Norway are pretty well contract, and particularly the stronger rigs. And I’m just curious the way you see it right now, which rigs in your fleet are most likely to service that demand that you do have a couple that, that have some holes in 2022, which probably be well-suited for that work, but when it comes to shifts and rigs from Norway to the UK, I was hoping you could just provide a little bit more color on which rigs we should be thinking about there.

Yes, I’ll take that one. So when we’ve got – if you look at the UK, the struggle in the UK is actually equipment. So long leads on wellheads and casings and various other bits and pieces are kind of stalling them at the moment. The demand or the optimism about going ahead with projects is certainly there. It’s just – that’s why it’s not here right now. They basically can’t pull the trigger on it at the moment, because they don’t have the site to the equipment that they need to complete the wells. So that’s kind of what’s driving this uptake and it happens to be coincidental with the uptake this predicted to Norway. And a lot of the uptake in Norway is off the back of the tax incentive schemes that were put in place last year and are now reaching the point of fruition where those include putting rigs to work and developing these assets. So from that point of view, we expect that there’s going to be pretty high demand for the rigs in Norway, especially the higher specification, which is the choice certainly for Equinor and some of the other bigger operators. But in the meantime, as you point out, there’s a few gaps here and there. So I think you could see us look at some of the rigs that have gaps as potential candidates for going to the UK. We did this in the past with the likes of the Spitsbergen and a couple of other older assays. But it’ll be interesting to see, which segment moves the quickest, because they’re going to be the ones that pick up the best rigs.

Got it. Thanks for the answers.

[Operator Instructions] As there are no further questions, I would like to hand the call back over to Alison for closing remarks.

Thank you, Marianne, and thank you, everyone for your participation on today’s call. If you have further questions, please feel free to contact me. We look forward to talking with you again when we report our fourth quarter 2021 results. Have a good day.

Thank you. That will conclude this conference call. Thank you for your participation, ladies and gentlemen. You may now disconnect.