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Presentation

Operator: 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 a 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 should need any assistance. It is now my pleasure to turn the conference over to Alison Johnson, Director of Investor Relations. Please go ahead.

Alison Johnson: 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 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 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.

Jeremy 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 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 a 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 and direct continuation of the rigs 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 per day and is expected to begin in direct continuation of the rigs 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 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 and also in the UK North Sea Harbor Energy exercised the third option on its contract with the Paul B Loyd Jr. wells at $175,000 per day. The additional terms expected to last 275 days and extended the contract of the third quarter of 2024. As you’ve no doubt see in 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 load €“ 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 we also 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 the number of criteria, including whole size and ease of conversion to a nodule collection vessel.

Contribution of this rig, although further rationalizes €“ also further rationalizes the global fleet of a 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, transition 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 play €“ contributing 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 commences its made €“ contract with the 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 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. Keelan?

Keelan Adamson: 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 Atlasand the Deepwater Titan. I would also like 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 28 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 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 capable Atlas and Titan are the first and for the foreseeable future, the only drillship 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 translate 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 extends of 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 contract drillships to its fleet in the past decade. These additions have had a marked impact on the capability and operating efficiency of our fleet to enabled 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 is 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 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 the right 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 which provides our people with the tasks, work designs and verification checks that are necessary to deliver procedural discipline flawless execution. As our industry embarks on this long overdue cycle, drilling contractors must overcome the operational challenges that a company restarting rigs and bringing them back into operations safely, reliably, and efficiently. Because they’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 the high level of performance.

We look forward to the opportunity to steadily bring our idle fleet back into service in the safest, most of cost effective manner to best ensure the highest returns for our shareholders. With that, I will hand it back to Jeremy.

Jeremy Thigpen: Thanks, Keelan. The prospect of a reactivation is very topical. As all of our drillships that are not warm or cold stacked 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 the work starting in 2024 and 2025 to develop as expected, demand cannot be met by the current active supply of drillships. Having said that, we were absolutely firm in our position that we will not reactivate a rig unless our customers, there a combination of mobilization fees, day rate and term pay for the entire reactivation plus an acceptable return in the initial contract.

Rig demand and new harsh environment is robust. Indeed, over the next 18 months, an estimated 82 programs are anticipated to be awarded for a total of 74 rig use of 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 we see in Brazil, the U.S. Gulf of Mexico is expected to remain relatively tight with local supply and demand keeping and 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 sufficient future demand to bring one or two more rigs into the region on long-term programs. West Africa and the Mediterranean are also experienced 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 and 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, rig from other regions will need to be mobilized and as following our announcement that the KG2 is heading to Brazil, there are currently no ultra-deep water rigs available in the region. As such, 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, available active supply of high specification floaters remains bid, and on the backdrop of the other strong demand environment, we anticipate our customers will continue to exempt 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 Transocean is well positioned to prosper and deliver shareholder value as we continue through what we expect should be a sustained multiyear recovery. I’ll now turn the call over to Mark.

Mark Mey: 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 of our expectations for full year 2023. Lastly, I will provide an update on our liquidity forecast to 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 of which were well oversee by the market.

In the context of today’s interest rate and or broader get capital market environment these two transactions materially improved our medium term liquidity and further set the stage for us opportunistically delever, simplify and improve the flexibility of our balance sheet. Now to the results. As reported in the press release, which include 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 are stated in yesterday’s press release, we reported 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 .

And 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 both lower than expected in-service and other service maintenance expenses, mostly due to timing and lower P&L costs.

2022 cash flow in the balance sheet, we ended the fourth quarter of a 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. We’re now 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. 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 quired 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 to quarter. For the full year and as I’ve guided last quarter, we’re anticipating interested 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 an necessary. We expect first quarter O&M expense to be approximate $430 million. This slight quarter-over-quarter increase is primarily due attributable to higher costs included in relation 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 earn and expense to be approximately $1.9 billion.

We expect G&A expense for this quarter to be approximately $50 million and ranging 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’re anticipating net interest expense of approximately $470 million, including capitalized interest of approximately $30 million. Capital expenditures including capitalized interest for the first quarter of forecast will be approximately within $15 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 particular 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 that service. This liquidity forecast includes 2023 CapEx expectations of $275 million of which $175 million related to our new bills as we highlight in our website CapEx schedule and a $100 million for maintenance CapEx. The maintenance CapEx includes approximately $20 million is contractually required for the two long-term contracts of the Deepwater Orion and the KG2 in Brazil and $30 million for our fleet-wide program. The new board CapEx includes mobilization, capital interest 20K BOP upgrades 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 may significant progress on clearing our liquidity one way. We will now focus on simplify and right sizing our balance sheet. As more of our rigs transition to higher contract day rates, cash flows model accelerate organically leveraging. We already seeing this with other people with free feed for which estimated average contract day rate is increase 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 stage of the cyclical recovery, we expect this train 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 plan for the offshore drilling market supports our ability to organically reduce our data overtime without the use of incremental equity. We will, however, continue to pursue delivering actions as and when that makes sense. Operationally we remain focused, 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.

Alison Johnson: 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.

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

Greg Lewis: Thank you, and good morning and good afternoon everybody. Jeremy, clearly congratulations on all the work you guys have done over the last couple years and on getting the KG2 to work, that rig was your last title rig. As we look ahead in this year and in the next year, clearly there are going to be, some of your competitors have reactivated rigs. You’ve alluded to reactivating rigs as demand come in and customers are willingly 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 on the early side or the later side of that 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?

Jeremy Thigpen: Hey, 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, some form or mixture of upfront payment mobilization fees plus day rate and term that more than pays for the reactivation itself, it actually generates a suitable return for Transocean, and so that may mean that we’re later to, to the reactivation party than some of our peers if they’re willing to reactivate on spec or for lesser returns. And we’re okay with that.

Roddie Mackenzie: Yes, I think, this is Roddie here, I get to add to that a little bit, so to kind of demonstrate that discipline, it’s often difficult for us to talk about individual tenders and awards and negotiations. However, there’s a couple great example, one in Brazil, which is, as you know on certain tenders are fully public there where all the results are published. So 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 that 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 into that that tender any further.

And since then the Petrobas moved to the next operator or the next rig contractor, and that’s going to be the 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, very seriously and we have walked away from some contracts because they did not provide return lease as to be adequate.

Greg Lewis: Yes, it seems like these multiyear contracts are going to be pricing’s going to be 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, the one of the CAT rigs, relying 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 these, those CAT rigs potentially find work? Or is it kind €“ more of a, just manage and wait for that market to rebound in 2024?

Roddie Mackenzie: 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 in like 2021 and you 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.

And the really interesting thing 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. So 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 and Norway than it is elsewhere that’s going to be a key driver. So you’ve seen these kind of six rigs move out, fully expect to see three or four more pretty soon. And when those rigs move out, 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.

So 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 and 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 stack CAT-D we’re in active negotiations for placing in all of those. I think and over the period of this year, you’re going to see pretty much all those rigs get fixtures on them. And you’ll see that the day rates associated those and the locations should raise a few eyebrows in terms of the trajectory of rates for harsh environment rigs.

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

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

Eddie Kim: Hi, good morning. So we’ve obviously seen a lot loader demand 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, this is almost going to force the majors hand in locking up a rigs for multiple years?

Roddie Mackenzie: Yes. So really that is what’s happening. And I would now see 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. But by contrast and 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. But I would argue very smart move because they’re going to get the bulk of the available rigs and at what we would consider solid day rates, but I think in time they will prove to be an absolute bargain from Petrobras point of view because they’ll affected mid-400s .

And to your point, there will not be much supply left for the other prospects. And of course as Jeremy had said, once we get into those kind of our 90% utilization rates, that, that, 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. So you’re going to see in the West African region, several fixtures will be made over the next few months that will be multi-year in nature. So I think you’ll see that across the Board. It’s just that Petrobras is moving so quickly, it makes it look like the others are not.

Eddie Kim: 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 cost this year for offshore crews in 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?

Keelan Adamson: Yes. Thanks, Eddie. Yes, yes, clearly with your inflation currently 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 the labor plus the O&M costs. So yes.

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

Operator: 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.

Fredrik Stene: Hey, can you guys hear me now?

Jeremy Thigpen: Yes, sir, please. We can hear you here.

Fredrik Stene: Okay. Perfect. Sorry for €“ I’m not sure what happened there, but hey, Jeremy and team, and thank you for good update today. I think some of my questions have been covered, but 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, you €“ there might be more work to do. You have def €“ you definitely have some rewind 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?

Mark Mey: 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 delever a down cycle. Well, now we’re in a cyclical €“ and as a result of that, as I mentioned in my prepared comments, we have higher day rates generating a significant cash flow. So we are prepared to take our time and grow into our balance sheet, but by using these organic flows to delever the balance sheet. By simplify, we 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, there is secured, there’s PGNs and SPGNs, so clearly the first focus is going to be PGNs. And then from there we’ll look at the other types of debt on the balance sheet.

And then 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.

Fredrik Stene: 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 ?

Mark Mey: Perfect. Fredrik, I didn’t hear you very clear, but I think you’re referring to the Aquila, if that’s the case, we have experienced 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. So, we’ll use the same approach with the Aquila and perhaps if we get the Libra that rig as well.

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

Mark Mey: I’m going to take a stab at this and obviously Jeremy are already conjunct in as well. But I think what we’ve seen right now is the first in line are not the cold stacked rigs, it’s the rigs that are being completed that are sitting at the yards in South Korea. And 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 I think there’s a consensus around at least 12 months to activate a rig from a shipyard or from cold and to prepare the rig foots contract, because as you know, each operator has their own contracts perfect requirements and equipment for that opportunity.

So I think it’s going to be measured mainly because of this constraint, but also because of the fact that there is significant amount of cash required to do this. And if you look at the balance sheet of the drillers especially, those are risk come through restructuring. I’m not sure it supports a wholesale reactivation program unless it’s paid upfront by the customers.

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

Operator: Thank you. Our next question will come from Thomas Johnson with Morgan Stanley.

Thomas Johnson: 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 kind of 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.

Jeremy Thigpen: Yes. Okay. I’ll take that one. Yes, so we’re in discussions for follow-on work after contract. So that’s still €“ a while before gets through that main contract. But there’s several bites €“ some of them 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. And we know that, we set the record on the longest in in the Gulf of Mexico. And I have to say the record was set about a few days before on the Deepwater Conqueror. So that was really stressing her to her maximum capacity. And now we have the Atlas in the market available for those even higher hook loads. So we’re really optimistic about that. We thinkthere’s real demand for these ultra heavy casing strings, and of course she can only do that with that assay, and she happens to be the 20k rig.

So 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.

Thomas Johnson: 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?

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

Thomas Johnson: Got it. Thanks. I’ll turn it back.

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

David Smith: 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 market 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 actually 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 €“ do you see petrol for shipyard and OEM capacity to be a constraint on growing the supply of active floaters in the next couple years?

Mark Mey: Yes we do. Clearly, as you’ve indicated, the reason that it takes at least 12 months to reactive the rigs, because of the challenges that our OEMs are having because they reduce capacity significantly during the . So now as they’re ramping up, we’re starting to see these challenges because demand from the drilling contractors has improved substantially. And I’ll pause there. And see Keelan has something to add.

Keelan Adamson: 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 reactivation. So it is a restriction. But I would say that we’re working collaboratively to find ways to remove it.

Jeremy Thigpen: Sorry, I just add to that, in some ways, in some ways the capital constraints of the drilling contractors and the supply chain challenges that we’re facing and the shipyards and with 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. And so while the growth will be slow, it’ll be steep and should last longer. And really growth will come through day rates as opposed to adding a bunch of breaks to the fleet.

David Smith: 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?

Jeremy Thigpen: Yes. By the time we get to 2025 that counts going to increase the range of 40 or maybe even more. Because not only you’re looking at Petrobras adding significant capacity, but there’s six other programs from the likes of Shell, Total, Equinor and others that are got to be satisfied as well. So, we dip down to kind of 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.

David Smith: Thanks so much.

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

Samantha Hoh: 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 be have operating a fleet of about five, I think vessels there, five drillships there in that country, and just a lot of concentration really around the U.S., Gulf of Mexico and Brazil. I was wondering if you could maybe provide some sort of commentary around, what that does for your profitability in that region, when you have so many rigs concentrated in one market?

Jeremy Thigpen: Yes, 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. And 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. And the good thing about that from our point of view is, it opens up a world of possibilities for our assets. So we don’t necessarily have to deploy the seventh generation, which are potentially the highest earners to Brazil to be able to be successful. So 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.

And we’ve had a presence for over 50 years. And of course we’re now looking at five rigs being contracted there, I would be very optimistic that we’d 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 apologize, but I think you were asking a little bit up a question around economies of scale. And there certainly are economies of scale there with a larger €“ with a larger installed base working fleet there. It requires a tremendous amount of effort and time and energy and experience to run one ultra-deepwater safely, reliably, and efficiently. But then as you add rigs, you don’t have to add much in the way of incremental support onshore.

So there’s definitely some economy of scale to be had the more rigs we can add to a certain jurisdiction.

Samantha Hoh: 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 I guess exploration versus development type of work, and just wanting that, that longer duration visibility of like a development project in Brazil versus the high profile exploration type work in Namibia?

Jeremy Thigpen: Yes, I’ll take that one. So look, the exploration stuff in Namibia, you’ve now got several operators, who are kind of dipped their toe on that and they’ve had good success. So with success in exploration, they move into the development phase a little bit further down the track. So, you’ve basically got you 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. So, I think that’s going to be a really solid jurisdiction for the foreseeable future. I think you’re going to see multiple rigs. I think you’re going to switch from the kind of 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.

So the difference here is that you just have even more auditors aren’t 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 a lot more discoveries in the last year than you had in some previous years. You will see 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 of those wells in that given timeframe.

Samantha Hoh: 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, that sort of exciting new venture. I was just wondering, obviously the thinking around that, 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 like a one year type contract initially, but is there like a return type profile? Anything that we can use in terms of the modeling, be on that similar in like one-third interest that you have in the north?

Jeremy Thigpen: Hey, Samantha, sorry, you really pulled on this in, but I think, return about the return profile on the deep-sea mining opportunities.

Samantha Hoh: Yes.

Jeremy Thigpen: Oh on the €“ or was it on the Aquila?

Samantha Hoh: In Aquila.

Jeremy Thigpen: Oh, could it, we just defer that to a call afterwards with the investor teams that and now the, because, it really has been difficult to understand you. Sorry.

Samantha Hoh: Sorry about that. But thanks guys for all your time.

Jeremy Thigpen: All right. Thanks, Samantha.

Operator: Thank you. That does conclude our Q&A Session. I’ll turn it back to management for any additional or closing remarks.

Alison Johnson: 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.

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