Categories Earnings Call Transcripts, Energy

Transocean Ltd (RIG) Q4 2022 Earnings Call Transcript

Transocean Ltd Earnings Call - Final Transcript

Transocean Ltd (NYSE:RIG) Q4 2022 Earnings Call dated Feb. 22, 2023.

 

Prepared Remarks:

 

Operator

Good day, everyone, and welcome to the Transocean Fourth Quarter 2022 Earnings Conference Call. [Operator Instructions]. Please note this call will be recorded [Operator Instructions].

It is now my pleasure to turn the conference over to Alison Johnson, Director of Investor Relations. Please go ahead.

Alison Johnson — Director of Investor Relations

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 D. Thigpen — Chief Executive Officer

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 [Phonetic] adjusted revenue, resulting in an adjusted EBITDA margin of approximately 20%, [Phonetic] which when combined with the new fixtures we were awarded in the fourth quarter helped us to close the full year 2022 on a very positive note. Indeed, we think the 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 full 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.

In Suriname, TotalEnergies exercised a one-well option at a rate of $360,000 per day on its contract with Development Driller III. The incremental well is expected to last 90 days and keep the rig busy through the third quarter.

In Norway, certain previously disclosed options under the Transocean Norge 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 U.K. 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 U.K. North Sea, Harbour Energy exercised the third option on its contract with Paul B. Loyd, Jr., for eight P&A wells at $175,000 per day. The additional term is expected to last 275 days and extends 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 drillship to the market. As part of the agreement with our joint venture partners, Transocean maintains the exclusive right to market and manage the operations of this rig. In early January, we raised secured financing on the Deepwater Titan, and we also refined certain series of our secured 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 minerals 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 hole size and ease of conversion to a nodule collection vessel. Contribution of this rig also 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 Limited. Through these transactions, we are excited to play our role [Technical Issues] 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 maiden 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, 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 — President and Chief Operating Officer

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, the Deepwater Atlas and the Deepwater Titan. I would also like thank our customers, Beacon Offshore Energy and Chevron, who have contracted the Atlas and the 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 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 capability, Atlas and Titan are the first and for the foreseeable future, the only drillships outfitted 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 extensive deck space and purpose-built areas to accommodate well completion activities, are the most capable drillships 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 newbuild 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 and also 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 newbuilds will perform at the fleet average revenue efficiency level within the first six months of operation, which would be an extraordinary achievement for any newbuild floater, especially considering that these rigs are equipped with a variety of Serial Number 1 equipment. We look to apply lessons learned from the delivery of our newbuilds 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 and culture. 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. Some of these 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 pool 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 and flawless execution.

As our industry embarks on this long overdue cycle, drilling contractors must overcome the operational challenges that accompany 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 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.

Jeremy D. Thigpen — Chief Executive Officer

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 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, through a combination of mobilization fees, day rate and term, pay for the entire reactivation plus an acceptable return in the initial contract. Rig demand in the 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 years 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.

Brazil currently continues to lead incremental demand for offshore drilling services with a potential for up to 19 floater awards. Of these, up to eight may be contracted under existing open Petrobras tenders. Brazil has been an important source of demand for the last two years, and we expect this to continue in 2023. Importantly, the incremental demand is driving higher day rates, which have already increased 117% [Phonetic] from 2020 to 2022. We anticipate that new fixtures will continue decline as active supply in the region is exhausted, requiring assets from other regions, some of which will need to be reactivated and upgraded to be mobilized to support the demand in Brazil. 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 in 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, rig 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. As such, we anticipate rates on these awards to be higher than the most recent awards in India.

Taking a holistic view of the high specification harsh environment market, multiple harsh environment semi-submersibles have departed Norway for other regions, and even more expected to get to be contracted elsewhere. In the last 18 months, six semis have departed Norway for work in West Africa, Canada, and the U.K. North Sea. We anticipate at least two additional semis will depart Norway in the next 12 months potentially for opportunities in Australia. If this happens, we believe there will be a supply deficit in Norway in 2024.

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 [Technical Issues], and on the backdrop of a strong demand environment, we anticipate our customers will continue to attempt to secure assets for longer term, which in turn should support the prevailing upward trajectory of day rates. With 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 — Executive Vice President and Chief Financial Officer

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 through 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 conducted an exchange of securities that provided the Company with incremental $175 million in liquidity. Last month, we executed two 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 received by the market. In the context of today’s interest rate and or broader capital market environment, these two transactions materially improved our medium term liquidity and further set the stage for us to opportunistically delever, 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 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 two eighth-generation drillships. This was subsequently offset with $525 million raised for 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.

Turning to cash flow and 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 [Phonetic] from our undrawn revolving credit facility.

Let me now provide an update on our 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, in 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 wide 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 the quarter.

For the full year and as I’ve 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 approximate $430 million. This slight quarter-over-quarter increase is primarily due — attributable to higher costs included in relation to the contract preparation for 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 expense to be approximately $1.9 billion. [Phonetic] 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 bifurcated exchange feature embedded in our exchangeable bonds issued in the third quarter of 2022. Net interest expense for the first quarter is forecasted 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 are forecasted to be approximately $115 million [Phonetic]. This includes approximately $85 million for newbuild 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 is related to our newbuilds as we highlight in our website capex schedule and a $100 million for maintenance capex. The maintenance capex includes approximately $20 million, which is contractually required for the two long-term contracts for the Deepwater Orion and the KG2 in Brazil and $30 million for our fleet-wide major spares program. The newbuild capex includes mobilization, capital interest, 20k BOP upgrades and capital spends. In conclusion, our debt and liability [Phonetic] actions over the past 12 months have positioned us well for further improving our capital structure. We made significant progress in carrying our liquidity runway. We will now focus on simplifying and right sizing our balance sheet.

As more of our rigs transition to higher contract day rates, cash flows from operations will accelerate organic deleveraging. We are already seeing this with [Technical Issues] for which estimated average contract day rate has increased 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 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 strength of 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 delevering 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.

Alison Johnson — Director of Investor Relations

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.

Questions and Answers:

 

Operator

Thank you, Alison. [Operator Instructions]. Our first question comes from Greg Lewis with BTIG.

Gregory Lewis — BTIG — Analyst

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 vital 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 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 be maybe on the early side or the later side of the wave of rig reactivations that we think are going to be needed to come into the market to meet demand over the next two years?

Jeremy D. Thigpen — Chief Executive Officer

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 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 — Executive Vice President and Chief Commercial Officer

Yeah, I think — this is Roddie here, I think I’ve got 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 examples, one in Brazil, which is, as you know, certain tenders are fully public there where all the results are published. So for example in the pool tender in the Lot 2 basket, that’s one where we won a job with the Orion, we were also [Technical Issues] 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 Athena into that tender any further. And since then, the Petrobras moved to the next operator or the next rig contractor, and that’s going to be according to the results of the public tender of 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 we assess to be adequate.

Gregory Lewis — BTIG — Analyst

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. Yeah, we’re — it seems like we’re in this air pocket in Norway in ’23. 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, [Indecipherable] 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 more of a — just manage and wait for that market to rebound in ’24?

Roddie Mackenzie — Executive Vice President and Chief Commercial Officer

Yeah. 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 ’23, in a period of two years, that number has dropped from in excess of 20 — about 22 rigs down to 13 rigs available in ’23. 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 U.K., 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 merged 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 in 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 had 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 fleet 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 stacked Cat-D, we’re in active negotiations for placing all of those, so I think and over the period of this year, you’re going to see pretty much all of 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.

Gregory Lewis — BTIG — Analyst

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 — Barclays — Analyst

Hi, good morning. So we’ve obviously seen a lot of floater 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 multiyear 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 — Executive Vice President and Chief Commercial Officer

Yeah. So really that is what’s happening. And I would not 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 multiyear contracts for the majors. But 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. But I would argue very smart move because they’re going to get the bulk of the available rigs 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 [Technical Issues]. 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’s typically where the inflection point on the next tier of rates comes. So we’re really optimistic about that and 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 multiyear 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 — Barclays — Analyst

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 and onshore support. Another one of your peers talked about kind of rig level opex moving up in the high-single digits rig type of 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 — President and Chief Operating Officer

Yes. Thanks, Eddie. Yeah, 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 — Barclays — Analyst

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 — Clarksons Platou Securities — Analyst

Hey, can you guys hear me now?

Jeremy D. Thigpen — Chief Executive Officer

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

Fredrik Stene — Clarksons Platou Securities — Analyst

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 definitely have some leeway now, but in terms of rightsizing 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 — Executive Vice President and Chief Financial Officer

Yeah, 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, you can never delever 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 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 simplifying — 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. Those are also on the table for us to address over the next year or so.

Fredrik Stene — Clarksons Platou Securities — Analyst

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

Mark Mey — Executive Vice President and Chief Financial Officer

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 Norge, 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 we could deliver [Phonetic] that rig as well.

Fredrik Stene — Clarksons Platou Securities — Analyst

Perfect. Thanks. Thanks. And super quick for reactivations. Do you guys have any idea of how many reactivate — global reactivations the supply chains 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 — Executive Vice President and Chief Financial Officer

I’m going to take a stab at this, and obviously Jeremy or Roddie can jump 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 reactivate a rig from the shipyard or from cold and to prepare the rig for its contract, because as you know, each operator has their own contract specific requirements and equipment for their 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 sheets of the drillers especially, those [Indecipherable] restructuring. I’m not sure it supports a wholesale reactivation program unless it’s paid upfront by the customers.

Fredrik Stene — Clarksons Platou Securities — Analyst

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 — Morgan Stanley — Analyst

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.

Roddie Mackenzie — Executive Vice President and Chief Commercial Officer

Yeah. Okay. I’ll take that one. Yes, so we’re in discussions for follow-on work after her new contract. So that’s still a while before she gets through that main contract. But there’re 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. And we know that, we set the record on the longest net casing run 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 think there’s real demand for these ultra-heavy casing strings, and of course you can only do that with that kind of asset, 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 — Morgan Stanley — Analyst

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 — Executive Vice President and Chief Financial Officer

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

Thomas Johnson — Morgan Stanley — Analyst

Got it. Thanks. I’ll turn it back.

Operator

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

David Smith — Pickering Energy Partners — Analyst

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 marketed floater fleet and the mix of rigs coming up on their second or third SPS is growing. So the industry needs reactivations, maybe some [Technical Issues] 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, I just wanted to see if — do you see [Indecipherable] for shipyard and OEM capacity to be a constraint on growing the supply of active floaters in the next couple years?

Mark Mey — Executive Vice President and Chief Financial Officer

Yeah, we do. Clearly, as you’ve indicated, the reason that it takes at least 12 months to reactive a rig is because of the challenges that our OEMs are having because they reduce capacity significantly during [Indecipherable]. 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 — President and Chief Operating Officer

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 to understand their restrictions and plan around not only their capability, but also our capital for equipment that we have on hand to handle those projects and reactive divisions. So it is a restriction. But I would say that we’re working collaboratively to find ways to remove it.

Jeremy D. Thigpen — Chief Executive Officer

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 in 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 the growth will come through day rates as opposed to adding a bunch of rigs to the fleet.

David Smith — Pickering Energy Partners — Analyst

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?

Roddie Mackenzie — Executive Vice President and Chief Commercial Officer

Yeah. 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 going 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-plus rigs.

David Smith — Pickering Energy Partners — Analyst

Thanks so much.

Operator

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

Samantha Hoh — Evercore ISI — Analyst

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?

Roddie Mackenzie — Executive Vice President and Chief Commercial Officer

Yeah, 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 sixth-generation 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 multiyear 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.

Jeremy D. Thigpen — Chief Executive Officer

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 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 — Evercore ISI — Analyst

Excellent. And I guess in a 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?

Roddie Mackenzie — Executive Vice President and Chief Commercial Officer

Yeah, 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 Galp Energia [Phonetic] is out for an additional tender in the mid Namibia. 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 operators are interested [Phonetic], 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 — Evercore ISI — Analyst

Okay, thank you. And if I could just squeeze one more in, it’s kind of interesting how 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 toe 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 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 [Phonetic] similar in like one-third interest that you have in the north?

Jeremy D. Thigpen — Chief Executive Officer

Hey, Samantha, sorry, you really pulled on this in, but I think, [Technical Issues] about the return profile on the deep-sea mining opportunities?

Samantha Hoh — Evercore ISI — Analyst

Yes.

Jeremy D. Thigpen — Chief Executive Officer

[Technical Issues] or was it on the Aquila?

Samantha Hoh — Evercore ISI — Analyst

And Aquila.

Jeremy D. Thigpen — Chief Executive Officer

Oh, could it — we just defer that to a call afterwards with the investor teams [Technical Issues] because it really has been difficult to understand you. Sorry.

Samantha Hoh — Evercore ISI — Analyst

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

Jeremy D. Thigpen — Chief Executive Officer

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 — Director of Investor Relations

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

[Operator Closing Remarks].

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