Transocean Ltd. Q4 FY2022 Earnings Call

Good day, everyone, and welcome to the Transocean Fourth Quarter 2022 Earnings Conference 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. Please note this call will be recorded, and I’ll be standing by if you need any assistance. It is now my pleasure to turn the conference over to Alison Johnson, Director of Investor Relations. Please go ahead.

Thank you, Todd. Good morning, and welcome to Transocean’s fourth quarter 2022 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; Mark Mey, 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 are therefore 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 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, please limit yourself to one initial question and one follow-up question. 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 on today’s call. As reported in yesterday’s earnings release, for the fourth quarter, Transocean delivered adjusted EBITDA of $140 million on $625 million in adjusted revenue, resulting in an adjusted EBITDA margin of approximately 20%, which when combined with the new fixtures we were awarded in the fourth quarter have helped us to close the full year 2022 on a very positive note. Indeed, we think that 2022 will be remembered as a pivotal year in the offshore drilling industry, particularly for Transocean. Offshore contracting activity increased significantly, driving utilization rates and day rates materially higher throughout the year. And as evidenced by our December and January contract announcements, Transocean continues to be a primary beneficiary of this heightened demand. Needless to say, the last several months have been a very busy but rewarding time for the Transocean marketing team as they helped us to secure an incremental $1.5 billion in backlog during the quarter, bringing our full year backlog added to approximately $4 billion. As a reminder of our recent contract awards, in the U.S. Gulf of Mexico, the Deepwater Invictus was awarded a three-well contract with an independent operator at $425,000 per day for an estimated 100 days. The contract is expected to commence in direct continuation of the rig's current program. In Brazil, the KG2 was awarded a 910-day contract at approximately $430,000 per day, including integrated services. The contract is expected to start in the third quarter this year. Also in Brazil, the contracts for the previously disclosed selection of Deepwater Corcovado and Deepwater Orion for the pool tender have been finalized. As a reminder, Deepwater Corcovado was awarded a four-year contract at $399,000 per day and is expected to begin in direct continuation of the rig's current program. The Deepwater Orion was awarded a three-year contract at $416,000 per day and is expected to commence in the fourth quarter of this year. Concern on Energy exercised one well option at a rate of $360,000 per day on its contract with Development Driller III. The incremental wells are expected to last 90 days and keeps the rig busy through the third quarter. In Norway, previously disclosed options under the Transocean Nordic contract with Wintershall Dea and OMV are now firm. The average day rate for this incremental term of 773 days is approximately $428,000 per day. In the UK North Sea, Transocean Barents was awarded a one-well contract with a major operator at a rate of $310,000 per day. The work is anticipated to commence this quarter and last approximately 110 days. Finally, also in the UK North Sea, Harbor Energy exercised the third option on its contract with the Paul B Loyd Jr. for wells at $175,000 per day. The additional terms are expected to last 275 days and extended the contract to the third quarter of 2024. As you’ve no doubt seen, our finance and legal organizations have also been extremely busy supporting a variety of transactions. In November, we announced our minority stake in Liquila Ventures, a joint venture with Lime Rock Partners and Perestroika. We’re excited to partner with these two organizations that have a deep understanding of the offshore drilling market to bring Deepwater Aquila, another high hook load ultra-deepwater drill ship to the market. As part of the agreement with our joint venture partners, Transocean maintained the exclusive right to market and manage the operations of this rig. In early January, we raised secure financing on the Deepwater Titan and refined certain series of our secure notes, improving our liquidity. Mark will discuss these and other efforts to simplify our balance sheet in a few moments. Additionally, earlier this month, we announced our investment in Global Sea Mineral Resources or GSR, a deep-sea mineral exploratory company, which included the contribution of one of our stacked drillships, Ocean Rig Olympia. The Olympia was an optimal candidate for this transaction based on a number of criteria, including size and ease of conversion to a nodule collection vessel. The contribution of this rig further rationalizes the global fleet of nine environment floaters, and we believe will ultimately prove to be a better use of this asset, benefiting our shareholders over time. In exchange for our investment, Transocean received a non-controlling interest in GSR, with GSR responsible for operations of the vessel. This is Transocean’s second investment in the deep-sea minerals exploration industry. As you recall, last year we purchased a minority interest in Ocean Minerals Ltd. Through these transactions, we are excited to contribute to the diversification of global energy supply and a lower carbon economy. Our projects and operations teams also accomplished key objectives throughout 2022. Notably, Deepwater Atlas commenced its contract with Beacon Offshore, and we took delivery of the Deepwater Titan from the shipyard. I’m very pleased to share that in just its first few months of operation, the Atlas has already set a new record for the longest 14-inch casing run at nearly 3.8 miles, likely the first of many records to be set with this new class of drilling asset. In fact, at this time, I’ll hand it over to Keelan to further discuss these two state-of-the-art eighth generation drillships.

Thank you, Jeremy, and good morning to all. I would like to start off by thanking our project and operations teams, our key suppliers, and Sembcorp Marine for their remarkable dedication and commitment to complete the construction of our two state-of-the-art eighth generation drillships, Deepwater Atlas and the Deepwater Titan. I would also like to thank our customers Beacon Offshore Energy and Chevron, who have contracted the Atlas and Titan respectively, for trusting us to work with them on their industry-leading deepwater development projects. These rigs represent the newest generation of drillships capable of drilling and completing wells that were previously either technically or commercially infeasible. We often discuss the 20,000 psi capability of these assets. Indeed, Atlas and Titan will be the first two drillships outfitted with complete 20K well control packages, including the blowout preventers. This functionality opens the door for projects such as Anchor and Shenandoah and many other prospects yet to be developed, primarily in the U.S. Gulf of Mexico. In addition to their 20K capabilities, Atlas and Titan are the first and, for the foreseeable future, the only drillships fitted with a net lifting capacity of 3 million pounds. This capability allows our customers to optimize their well designs and run heavier and longer casing strings, which translates immediately to lower well and field development costs. Perhaps more importantly, these improved well designs can ultimately facilitate larger production tubing boards and therefore increase production per well. The rigs, which also feature extended deck space and purpose-built areas to accommodate well completion activities, are the most capable drills in the world and will ultimately expand the universe of exploration and development opportunities. With the delivery of the Atlas and Titan, Transocean has now brought a total of nine new build and fully contracted drillships to its fleet in the past decade. These additions have had a marked impact on the capability and operating efficiency of our fleet, enabling us to refine our expertise, bringing ships out of the yard and into service. Expertise, which we expect will prove invaluable as we put our idle and stacked rigs on contract and return them to the active fleet. Our expectation is that these new builds will perform at the fleet average revenue efficiency level within the first six months of operation, which would be an extraordinary achievement for any new build floater, especially since these rigs are equipped with a variety of serial number one equipment. We look to apply lessons learned from the delivery of our new builds as we reactivate our cold stacked assets. A successful rig reactivation involves not only completing the project work scope in line with cost and time expectations but also starting operations safely, reliably, and efficiently. To achieve this, a drilling contractor must have a robust operational management system. Transocean’s operational culture is data-driven, service-focused, and performance-oriented. Over the last several years, we have developed and implemented a multitude of technologies and processes to support these pillars, resulting in the delivery of operational excellence across our fleet. These tools provide our people with the right information at the right time to make informed decisions. Technologies include smart equipment analytics, which allows us to monitor the health and condition of our equipment in real-time, permit and barrier vision, a custom application which facilitates our ability to call, work, identify, and manage risk effectively, and our operations procedure system, OPS, a digital platform that provides our people with tasks, work designs, and verification checks necessary to deliver procedural discipline and flawless execution. As our industry embarks on this long overdue cycle, drilling contractors must overcome the operational challenges that arise when restarting rigs and bringing them back into operations safely, reliably, and efficiently. Because we’ve been preparing for this reality through the downturn by investing in our people, assets, and technology, Transocean has the experience and capability to grow our operational fleet with a high level of performance. We look forward to the opportunity to steadily bring our idle fleet back into service in the safest, most cost-effective manner to best ensure the highest returns for our shareholders. With that, I will hand it back to Jeremy.

Thanks, Keelan. The prospect of a reactivation is very topical. As all of our drillships that are not warm or cold stacked are currently contracted. Active drillship utilization is expected to remain at or above 97% for the next two years, with active utilization of the highest specification assets at or near 100%. We expect that the demand for our rigs and services will remain elevated for the foreseeable future. In fact, if current tendering and bid opportunities that we’re aware of for work starting in 2024 and 2025 develop as expected, demand cannot be met by the current active supply of drillships. Having said that, we are absolutely firm in our position that we will not reactivate a rig unless our customers pay for it. This includes a combination of mobilization fees, day rate, and term that covers the entire reactivation plus an acceptable return in the initial contract. Rig demand in new harsh environments is robust. Indeed, over the next 18 months, an estimated 82 programs are anticipated to be awarded for a total of 74 rig usage work. Importantly, this demand is globally diversified. Consistent with this outlook, industry analysts predict the number of wells drilled offshore will increase by nearly 15% in 2023.

While we currently don’t see the same volume of long-term activity in Brazil, the U.S. Gulf of Mexico is expected to remain relatively tight with local supply and demand maintaining relative balance. This region typically demands the highest specification rigs with the highest hook loads, which currently are all under contract. Additionally, based on our direct negotiations, we believe that there could be sufficient future demand to bring one or two more rigs into the region on long-term programs. West Africa and the Mediterranean are also experiencing a return of demand. While many opportunities are relatively short in duration, there are multiple multi-year tenders including one in Angola with Azule Energy, a joint venture between Eni and BP, and one in Romania with OMV. We are encouraged by the uptick in requirements in this region, as drilling is predicted to increase nearly 14% this year. In India, ONGC will require up to three rigs to satisfy its current and upcoming tenders. To fulfill these requirements, rigs from other regions will need to be mobilized and following our announcement that the KG2 is heading to Brazil, there are currently no ultra-deep water rigs available in the region. Consequently, we anticipate rates on these awards to be higher than the most recent awards in India. As mentioned in previous calls, the tax incentives in Norway encouraged record sanctioning over the past two and half years, with 35 projects totaling approximately 190 wells sanctioned. As this translates to heightened demand, we believe Norway’s floater market will see a strong comeback in activity from 2024 that will require rigs to return to meet the expected demand. In summary, our outlook for high-specification floating fleet is starkly positive; the available active supply of high-specification floaters remains tight, and against the backdrop of a strong demand environment, we anticipate our customers will continue to secure assets for longer term, which in turn should support the prevailing upward trajectory of day rates. An acute focus on delivering safe, reliable, and efficient operations, as well as reducing our debt, positions Transocean well to prosper and deliver shareholder value as we continue through what we expect to be a sustained multiyear recovery. I’ll now turn the call over to Mark.

Thank you, Jeremy, and good day to all. Through today’s call, I will briefly recap fourth quarter results and then provide guidance for the first quarter as well as an update on our expectations for full year 2023. Lastly, I will provide an update on our liquidity forecast for 2023. I’d like to take a few minutes to review the numerous liability management actions we have taken over the last year. First in July 2022, we extended our revolving credit facility through June 2025. Then in September, we contracted an exchange of securities that provided the company with incremental $175 million in liquidity. Last month, we executed more transactions, a $525 million secured financing on the Deepwater Titan and a $1.175 billion refinancing of our four series of senior notes, both transactions, which were overseen by the market. In the context of today’s interest rate and broader capital market environment, these two transactions materially improved our medium-term liquidity and further set the stage for us to opportunistically deleverage, simplify, and improve the flexibility of our balance sheet. Now to the results. As reported in the press release, which includes additional detail on our results for the fourth quarter of 2022, we reported net loss attributable to controlling interest of $350 million or $0.48 per diluted share. After certain adjustments as stated in yesterday’s press release, we reported an adjusted net loss of $356 million. During the quarter, we generated adjusted EBITDA of $140 million, which translated into cash flow from operations of approximately $178 million. Our negative free cash flow of $231 million in the fourth quarter reflected the CapEx associated with shipyard payments for our 2H innovation drillships. This was subsequently offset with the $525 million raise in Deepwater Titan, as I mentioned earlier. Looking closer at our results, during the fourth quarter, we delivered adjusted contract drilling revenues of approximately $625 million at an average day rate of $349,000. This is above our guidance and reflects more than anticipated operating days, higher than expected recharge revenue, and strong bonus revenue. Operating and maintenance expense for the fourth quarter was $423 million. This is below our guidance, mainly due to lower than expected in-service and other service maintenance expenses, mostly due to timing and lower P&L costs. In 2022, cash flow in the balance sheet, we ended the fourth quarter with total liquidity of approximately $1.8 billion, including unrestricted cash and cash equivalents of approximately $683 million, approximately $275 million of restricted cash for debt service, and $774 million from our undrawn revolving credit facility. Now we’re providing updates on expectations for the first quarter and full year financial performance. Revenue guidance is based primarily on firm contracts as listed in our Fleet Status Report, but also includes a speculative component, which we have a high level degree of confidence in. Any potential bonus revenue is excluded from guidance. For the first quarter 2023, we expect adjusted contract drilling revenue of $635 million based upon an average fleet required revenue efficiency of 96.5%. This is slightly higher than the fourth quarter of 2022, largely due to increased activity on certain rigs, partially offset by fewer operating days in the quarter. For the full year, as I guided last quarter, we’re anticipating adjusted revenues to be between $2.9 billion and $3 billion, also based on 96.5% revenue efficiency. As usual, as the year progresses, we may modify our guidance as necessary. We expect first quarter O&M expense to be approximately $430 million. This slight quarter-over-quarter increase is primarily due to higher costs related to the contract preparation of the Deepwater Orion and the KG2 for contracts in Brazil, partially offset by lower in-service maintenance activities. For the full year, we’re participating O&M expenses to be approximately $1.9 billion. We expect G&A expense for this quarter to be approximately $50 million and range between $200 million and $210 million for the year. Excluding further non-cash charges associated with a fair value adjustment of the basic exchange feature embedded in our exchangeable bonds issued in the third quarter of 2022, net interest expense for the first quarter is forecast to be approximately $120 million. This includes capitalized interest of approximately $18 million. For the full year, we anticipate net interest expense of approximately $470 million, including capitalized interest of approximately $30 million. Capital expenditures, including capitalized interest for the first quarter, are forecast to be approximately $105 million. This includes approximately $85 million for new build CapEx and approximately $30 million of maintenance CapEx. Cash taxes are expected to be approximately $10 million for the first quarter and approximately $40 million for the year. Our expected liquidity in December of 2023 is projected to be between $1.3 billion and $1.4 billion, reflecting our revenue and cost guidance and including the $600 million capacity of our revolving credit facility and restricted cash of approximately $210 million, which is mainly reserved for debt service. This liquidity forecast includes 2023 CapEx expectations of $275 million, of which $175 million relates to our new builds as highlighted in our website CapEx schedule and $100 million for maintenance CapEx. The maintenance CapEx includes approximately $20 million contractually required for the two long-term contracts of the Deepwater Orion and the KG2 in Brazil and $30 million for our fleet-wide maintenance program. The new build CapEx includes mobilization, capital improvements, and capital spend. In conclusion, our debt reliability actions over the past 12 months have positioned us well for further improving our capital structure. We have made significant progress on clearing our liquidity. We will now focus on simplifying and right-sizing our balance sheet. As more of our rigs transition to higher contract day rates, our cash flow will accelerate organically leveraging. We are already seeing this with our fleet, with the estimated average contract day rate increasing approximately $30,000 year-over-year to approximately $340,000 per day, as indicated in our Fleet Status Report. As we are in the early stages of the cyclical recovery, we expect this trend to continue. As I stated in the last quarter, we do not have plans to utilize our ATM equity sales program. We believe that the current outlook for the offshore drilling market supports our ability to organically reduce our debt over time without the use of incremental equity. We will, however, continue to pursue deleveraging actions as and when that makes sense. Operationally, we remain focused on delivering safe, reliable, and efficient operations, which ultimately supports our deleveraging goals and creates value for our shareholders. This concludes my prepared comments. I’ll now turn it back over to Alison.

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

Thank you, Alison. Our first question comes from Greg Lewis with BTIG.

Thank you, and good morning and good afternoon everybody. Jeremy, congratulations on all the work you guys have done over the last couple of years and on getting the KG2 to work, that rig was your last title rig. As we look ahead this year and in the next year, clearly there are going to be some of your competitors who have reactivated rigs. You’ve alluded to reactivating rigs as demand comes in and customers are willing to pay more. As we think about your ability to reactivate rigs and what’s going on in the current market, does it make sense for Transocean to maybe be on the early side or the later side of the wave of rig reactivations we think are going to be needed to come into the market to meet demand over the next two years?

Thanks for the quick question, Greg. I don’t think we’ve alluded to anything. I think we’ve been very clear in our position on reactivations, that the customer has to pay for it in the first contract. And by that, I mean some form or mixture of upfront payment, mobilization fees, plus day rate and term that more than pays for the reactivation itself and actually generates a suitable return for Transocean. So that may mean that we’re later to the reactivation party than some of our peers if they’re willing to reactivate on speculation or for lesser returns. And we’re okay with that.

Yes, I think this is Roddie here. I get to add to that a little bit, so to demonstrate that discipline, it’s often difficult for us to talk about individual tenders and awards and negotiations. However, there are a couple of great examples, one in Brazil, which is, as you know, on certain tenders are fully public there where all the results are published. For example, in the pool tender in the lot two basket, that’s one where we won a job with the Orion. We were also the next rig to be awarded in that line, and the day rate on the rig was $474,000 a day. However, when we went through the details of this and we went through the timeline that Petrobras was going to execute upon, we decided the cash flows just didn’t meet our return requirements. So we kind of stepped aside from that one and took the disciplined approach of not putting forward the bid into that tender any further. Since then Petrobras moved to the next operator or contractor, and that’s going to be, according to the results of the public tender, the DS-8, which should see their award at $460,000 a day. That’s the publicly disclosed information on that. We’ll have to wait and see how that turns out, but we just wanted to reassure you that we take that discipline very seriously and we have walked away from some contracts because they did not provide returns that were adequate.

Yes, it seems like these multi-year contracts are going to be pricing heading higher. I did want to shift gears to the North Sea and to the harsh fleet, just because it’s an important EBITDA driver for the company. Yes, we’re – it seems like we’re in this air pocket in Norway in 2023. As we think about that and maybe some opportunities, let's maybe say, I know you mentioned Australia on the call, but as we think about some of these rigs and how the market's developing in West Africa, we have the one idle rig, one of the CAT rigs, realizing that it’s water depth is what like 1,700 feet or something along those lines where outside of a place like Norway, and I guess the Southern North Sea, could we see rigs, some of those CAT rigs potentially find work? Or is it more of a, just manage and wait for that market to rebound in 2024?

Yes. Okay. Great question. I’ll take that one. So as Jeremy had explained, we see that there’s basically about six rigs moving out of the Norwegian market. What’s interesting in that is, if you look at the supply of rigs available to the Norwegian market and you look at the numbers from 2021 and compare them to where we are in 2023, in a period of two years, that number has dropped from in excess of 20, about 22 rigs down to 13 rigs available in 2023. So, as you think about the effect that that’s going to have, that’s the stuff that you’re talking about where rigs are moving out of the region, they’re going to West Africa, some are going to Canada. There’s a lot of speculation about some rigs maybe even more than one going to Australia, but also the UK and the stuff in West Africa seems to be growing even further. What’s really interesting was in discussions that we’ve had with certain larger operators in South America, the next tender that we expect from them is going to be specifically targeting merge units with high efficiency drilling packages. That would be ideal for the likes of the CAT-Ds or any of the other high spec harsh environment rigs in Norway. So just to touch on that a little, you mentioned margin earlier, so with the cost basis being a little bit higher in Norway than it is elsewhere that’s going to be a key driver. You’ve seen these six rigs move out; we fully expect to see three or four more pretty soon. Once you’ve got over the hurdle of the movement and as Jeremy pointed out, the customers are paying for those mobilizations now, you make better margins outside. For those rigs to come back to Norway, it’s going to be an increased hurdle for them to come back. With that said, we have line of sight jobs on pretty much all of our harsh environment including the stacked CAT-D. I can’t really disclose the details about that, but essentially, it’s safe to say that for all of our harsh environment fleet, including the stacked CAT-D, we’re in active negotiations for placements for all of those. I think throughout this year, you’re going to see pretty much all those rigs get fixtures on them. You’ll see that the day rates associated with those and the locations should raise a few eyebrows in terms of the trajectory of rates for harsh environment rigs.

Okay. Great. Hey, Roddie, thank you for the time. Thanks everybody and have a great day.

Thank you. Our next question comes from Eddie Kim with Barclays.

Hi, good morning. So we’ve obviously seen a lot of demand over the past nine months, which has mostly been driven by Petrobras and you guys have clearly been the biggest beneficiary of that. But just shifting to the majors, we haven’t quite seen as many large multi-year contracts from that group yet, likely because most of them are beholden to their investors. But are we getting to a point where Petrobras is just absorbing so many rigs, that this is almost going to force the majors’ hands in locking up rigs for multiple years?

Yes. So really that is what’s happening. I would now say that the majors have been quiet. In fact, we signed two-year contracts with some of the majors in the Gulf of Mexico. We know that there are several others to be signed, our multi-year contracts for the majors. By contrast, it would appear like they are moving slower. The context here is they’re moving faster than they’ve ever moved in the past seven years. But Petrobras is really on a different level. Petrobras is progressing their tenders at a clip that impresses everybody. It’s a very smart move because they’re going to get the bulk of the available rigs at what we would consider solid day rates. I think, in time, they will prove to be an absolute bargain from Petrobras' point of view because they’ll affect mid-400s. To your point, there will not be much supply left for the other prospects. As Jeremy had said, once we get into those kind of 90% utilization rates, that’s typically where the inflection point on the next tier of rates comes. So look, we’re really optimistic about that. Not only because we can push a lot of volume in Brazil, but mainly because they’re the long-term contracts, and we are beginning to see the majors around the world, particularly West Africa, are really beginning to focus on longer-term. We are going to see in the West African region, several fixtures to be made over the next few months that will be multi-year in nature. You’ll see that across the board. It’s that Petrobras is moving so quickly, it makes it look like the others are not.

Got it. Got it. That sounds very positive for day rates moving forward. Just shifting to costs, so one of your competitors yesterday highlighted higher costs this year for offshore crews and onshore support. Another one of your peers talked about kind of rig level OpEx moving up in the high-single digits rig per range. Is that something you’re seeing or expecting as well? And is that kind of uptick in costs currently embedded in your full-year O&M guide?

Yes. Thanks, Eddie. Clearly with your inflation ongoing and the tight labor market, we’re seeing similar cost increases, I’d say somewhere in that 5% to 8% area if you blend both labor plus the O&M costs. So yes.

Got it. Okay. Understood. Thanks for all that color. I’ll turn it back.

Thank you. Our next question will come from Fredrik Stene with Clarksons Securities. And, sir, please go ahead. Your line is live. Okay, we’ll try our next question. Looks like we have another line from Fredrik Stene with Clarksons Securities. Please go ahead.

Hey, can you guys hear me now?

Yes, sir, please. We can hear you here.

Okay. Perfect. Sorry for – I’m not sure what happened there, but hey, Jeremy and team, and thank you for the good update today. I think some of my questions have been covered. Mark, maybe you could help me out there. You’ve done some proper work on the balance sheet over the last year, as you mentioned in the prepared remarks. But you also said that there might be more work to do. You definitely have some runway now, but in terms of right-sizing and simplifying your balance sheets, are you able to share any more color at high-level thinking around how we would go about that and what would be sensible next steps and also timing wise on that?

Yes. So Fredrik, great question. Look, the goal of the actions we’ve taken over the last 12 months was to buy ourselves some time. I’ve been saying this since I joined Transocean in 2015. We can never deleverage in a down cycle. Well, now we’re in a cyclical recovery, and as a result of that, as I mentioned in my prepared comments, we have higher day rates generating significant cash flow. So we are prepared to take our time and grow into our balance sheet by using these organic flows to deleverage the balance sheet. In terms of simplification, we’ve got four different types of debt on our balance sheet. Clearly, simplifying means taking those four and moving them down to one eventually, but over time, so as you know, there’s unsecured debt, secured debt, PGNs, and SPGNs, so clearly the first focus is going to be PGNs. From there, we’ll look at the other types of debt on the balance sheet. Thirdly, we have exchangeable bonds. We have three tranches of that also on the table for us to address over the next year or so.

Super helpful. Two other quick ones for me, first one, the Aquila, which you’ll have the marketing rights to. How will you go about managing your investment there and also the older owners versus how you market your own stacked assets, for example, how that covered?

Perfect. Fredrik, I didn’t hear you very clearly, but I think you’re referring to the Aquila. If that’s the case, we have experience in doing this. As you’re well aware, we own a third interest in the Norga, and we have a similar process whereby we maintain a clean marketing team to avoid any kind of antitrust concerns. We’ll use the same approach with the Aquila and perhaps if we get the Libra that rig as well.

Perfect. Thanks. And super quick for reactivations. Do you guys have any idea of how many reactivations the global supply chain will handle per year? Do you think there’s a limit to that, how many you and your peers can do at the same time?

I’m going to take a stab at this and obviously Jeremy may want to chime in as well. But I think what we’ve seen right now is that the first in line are not the cold stacked rigs; it’s the rigs that are being completed and are sitting at the yards in South Korea. Several of these are projected to be contracted in Brazil, West Africa, and elsewhere throughout this year. We don’t believe that any of those rigs can really start on their contracts in 2023, given the fact that there’s a consensus around at least 12 months to activate a rig from a shipyard or from cold storage to prepare the rig for the contract. Each operator has their own contracts, requirements, and equipment for that opportunity. It’s going to be measured mainly because of these constraints, but also because there’s a significant amount of cash required to do this. If you look at the balance sheets of the drillers, especially those that come through restructuring, I’m not sure it supports a wholesale reactivation program unless it’s paid upfront by the customers.

Right. Thank you so much. That’s all from me. Thanks.

Thank you. Our final question will come from Thomas Johnson with Morgan Stanley.

Hi, thanks. Question on the Deepwater Atlas. Clearly, if you sign that contract or similar work today, we would assume that the rates would be much higher. But could you maybe give us an update on how conversations are going on the outlook for work for that rig following the mid-2024 expiration? And in addition to that, maybe just give us a quick update on potential to do any secured issuance against that and how we should think about capacity there relative to the Titan? Thanks.

Yes, okay. I’ll take that one. Yes, so we’re in discussions for follow-on work after the Atlantis contract. So that’s still a while before we get through that main contract. But there are several bites, some of which are in the 20K space; but as Keelan had pointed out, one of the most interesting features of the rig is this super high hook load. We know that, we set the record on the longest casing run in the Gulf of Mexico. I have to say, the record was set about a few days before on the Deepwater Conqueror. That was really pushing her to her maximum capacity. Now we have the Atlas available in the market for those even higher hook loads. We’re really optimistic about that. We think there’s real demand for these ultra heavy casing strings, and of course she can only do that with that asset, and she happens to be the 20K rig. The concept is we basically have the most capable rig on all fronts, and we’ve kept her available in a relatively near-term situation. So we’re very optimistic about what’s going to come next for her.

Great, thanks. And then just maybe any commentary on potential plans or capacity for a secured issuance if you were to receive a multi-year contract on the Atlas, maybe just relative to what has been recently announced on the Titan?

Yes, I think Thomas, we’ll crack that bit when we get to it, but clearly at the moment, we don’t see a need for that.

Got it. Thanks. I’ll turn it back.

Thank you. Our next question comes from David Smith with Pickering Energy Partners.

Hey, good morning and thank you. So looking at the marketed floater fleet, I think we see a little increase in special surveys this year, close to twice as many next year for the entire floater fleet and the mix of rigs coming up on their second or third SPS is growing. So the industry needs reactivations, maybe some stranded new delivery to accommodate growing demand. At the same time, it feels like shipyards are busy and OEMs have rationalized a lot of capacity in the last four years. So taking a slightly different angle on a prior question, I think you mentioned constraints among contractors as maybe a governing factor for reactivation. But I wanted to ask if that reactivation cash were there. Just wanted to see if you see potential for shipyard and OEM capacity to be a constraint on growing the supply of active floaters in the next couple of years?

Yes, we do. Clearly, as you’ve indicated, the reason that it takes at least 12 months to reactivate the rigs is because of the challenges that our OEMs are having; they reduced capacity significantly during the downturn. Now as they’re ramping up, we’re starting to see these challenges because demand from the drilling contractors has improved substantially. I’ll pause there and see if Keelan has something to add.

No, I think you’ve covered it well, Mark. I would add that we are continually engaged with our major key suppliers to look at the demand forecast that we have through our collaboration agreements and care agreements that we have with those very important suppliers to us. We are able to take a very confident look at the supply chain from their side, understand their restrictions, and plan around not only their capability but also our capital equipment that we have on hand to handle those projects and reactivations. It is a restriction, but I would say we’re working collaboratively to find ways to mitigate it.

Sorry, I just want to add to that. In some ways, the capital constraints of the drilling contractors and the supply chain challenges that we’re facing with the shipyards and OEMs is actually healthy for the industry. We can’t do what we’ve done in the past and overbuild, so that’s why we think it’s going to be a prolonged recovery because we can’t overbuild as an industry at this point in time. So while the growth will be slow, it’ll be steep and should last longer. Really growth will come through day rates as opposed to adding a bunch of rigs to the fleet.

Appreciate all the color. And sorry if I missed it, but do you have a view on how many floaters might be working off Brazil in 2025?

Yes. By the time we get to 2025 that count is going to increase in the range of 40 or maybe even more. Because not only are you looking at Petrobras adding significant capacity, but there are six other programs from the likes of Shell, Total, Equinor, and others that need to be satisfied as well. We dipped down to the teens in terms of rig count in Brazil, but it’s going to double over the next little while. So, I think you’re looking at 40, 40 plus rigs.

Thanks so much.

Thank you. Our final question will come from Samantha Hoh with Evercore ISI.

Hi. Thanks and thanks for taking my questions, and congrats on a really productive quarter. I wanted to maybe just stay a little bit on the topic of Brazil. It looks like you’re going to have an operating fleet of about five vessels there, five drillships in the country, and just a lot of concentration really around the U.S. Gulf of Mexico and Brazil. I was wondering if you could provide some commentary around what that does for your profitability in that region when you have so many rigs concentrated in one market?

Okay. Around the concentration of rigs in that market. So what’s interesting about it is most of the work in Brazil comes out in the form of a tender. As you go to the tender, there’s basically a minimum specification and you either qualify or you don’t. So the specification is set realistically for what’s required in Brazil. The good thing about that from our point of view is it opens up a world of possibilities for our lower spec assets. We don’t necessarily have to deploy the seventh generation, which are potentially the highest earners, to Brazil to be able to be successful. That’s why it’s been of significant interest for us. We’re basically taking our lower spec rigs and booking them on multi-year high day rate contracts in a region that we’re very familiar with. We’ve had a presence for over 50 years. Of course, we’re now looking at five rigs being contracted there; I would be very optimistic that we’ll be able to add one, two, or three more to that over the next year or so. And Samantha, just to add to that, your question was a little muffled on this end, so I apologize. I think you were asking about economies of scale. There are economies of scale with a larger working fleet in a certain jurisdiction. It requires a tremendous amount of effort, time, energy, and experience to run one ultra-deepwater rig safely, reliably, and efficiently. But then, as you add rigs, you don’t have to add much in the way of incremental support onshore. There’s definitely some economy of scale to be had the more rigs we can add to a certain jurisdiction.

Excellent. And I guess similar vein, I mean taking that rig out of Namibia, which has gotten so much press and excitement lately. What are your thoughts in terms of like that market? And what its potential looks like longer term? Is that, I mean, is that just a view in terms of the exploration versus development type of work, and just wanting that longer duration visibility of like a development project in Brazil versus the high-profile exploration type work in Namibia?

Yes, I’ll take that one. So look, the exploration stuff in Namibia, you’ve got several operators who are kind of dipped their toe on that and they’ve had good success. With success in exploration, they move into the development phase a little bit further down the track. You’ve got kind of two rigs working in Namibia now. There’s demand for more; in fact, Gulf Energies is out for an additional tender in the mid. I think that’s going to be a really solid jurisdiction for the foreseeable future. I think you’re going to see multiple rigs. You’re going to switch from the exploration phase into appraisal and then development over the next few years. So, I would expect to see a story there very similar to what you saw in Guyana with ExxonMobil. The difference here is that you just have more operators interested, so I think that’s a really positive sign, particularly because they use harsh environment rigs rather than just benign rigs. But again, around the world, I think you’ve seen more discoveries in the last year than you had in previous years. As we shift towards more development of these fields rather than just exploration, you're going to see a lot more long-term contracts because that’s typically how this cycle works in terms of delivering all those wells in that given timeframe.

Okay, thank you. And if I could just squeeze one more in, it’s kind of interesting that you used that phrase, dipping your toes because I think earlier this year or last year when you guys first announced your JV into the deep-sea mining, Jeremy used that same phrase about dipping your toes in that sort of exciting new venture. I was just wondering, obviously the thinking around that potential opportunity has shifted a little bit, and it was really nice to see that you guys are swapping out essentially the Olympia with the Aquila. What type of economics should we be thinking about for the Aquila? I mean, you guys mentioned that you’re looking for a one-year type contract initially, but is there like a return type profile? Anything that we can use in terms of modeling, be on that similar in like the one-third interest that you have in the north?

Hey, Samantha, sorry, you really pulled on this in, but I think, can we just defer that to a call afterwards with the investor teams because it really has been difficult to understand you. Sorry.

Sorry about that. But thanks guys for all your time.

All right. Thanks, Samantha.

Thank you, Todd. And thank you everyone for your participation on today’s call. We look forward to talking with you again when we report our first quarter 2023 results. Have a good day.

This concludes today’s call. Thank you for your participation. You may disconnect at any time.