Transocean - Q4 2022
February 22, 2023
Transcript
Moderator (participant)
Good day, everyone, and welcome to the Transocean Fourth Quarter 2022 earnings conference call. At this time, all participants are in a listen-only mode. Later, you will have the opportunity to ask questions during the question-and-answer session. You may register to ask a question at any time by pressing the star and one on your touchtone phone. You may withdraw yourself from the queue by pressing star and two. Please note this call will be recorded and I will 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 (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 quick 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 (CEO)
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 adjusted EBITDA margin of approximately 20%, 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 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. 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.
In Brazil, the contracts for the previously disclosed selection of Deepwater Corcovado and Deepwater Orion for the pool tender have been finalized. As a reminder, Deepwater Corcovado was awarded a four-year contract at $399,000 per day and is expected to begin in direct continuation of the rig's current program.
The Deepwater Orion was awarded a three-year contract at $416,000 per day and is expected to commence in the fourth quarter of this year. 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 keeps the rig busy through the third quarter. In Norway, some 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, in the U.K. North Sea, Harbour Energy exercised the third option on its contract with the 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 load, high hook load ultra-deepwater drill ship 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 secure financing on the Deepwater Titan, and we also refiled 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. 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 a number of criteria, including hull size and ease of conversion to a nodule collection vessel.
The contribution of this rig also further rationalizes the global fleet of the benign 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 a role in 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, the Deepwater Atlas commenced its maintenance 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. 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 COO)
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 to thank our customers, Beacon Offshore Energy and Chevron, who have contracted the Atlas and Titan respectively for trusting us to work with them on their industry-leading 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 capabilities, Atlas and Titan are the first and for the foreseeable future, the only drill ships 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 bores 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 drill ships in the world and will ultimately expand the universe of exploration and development opportunities.
With the delivery of the Atlas and Titan, Transocean has now brought a total of nine new build and fully contracted drillships to its fleet in the past decade. These additions have had a marked impact on the capability and operating efficiency of our fleet 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 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 considering that 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 stack 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've 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 Vision and Barrier Vision, a custom application which facilitates our ability to call work, identify and manage risk effectively. 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 growth cycle, drilling contractors must overcome the operational challenges that accompany restarting rigs.
Bringing them back into operation safely, reliably, and efficiently. We've been preparing for this reality through the downturn by investing in our people, assets, and technology, Transocean has the experience and capability to grow our operational fleet with a high level of performance. We look forward to the opportunity to steadily bring our idle fleet back into service in the safest, most cost-effective manner to best ensure the highest returns for our shareholders. With that, I will hand it back to Jeremy.
Jeremy Thigpen (CEO)
Thanks, Keelan. The prospect of a reactivation is very topical as all of our drill ships that are not warm or cold stacked currently contracted. Active drill ship 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 bidding opportunities that we're aware of for work starting in 2024 and 2025 develop as expected, demand cannot be met by the current active supply of drill ships.
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 both harsh and benign 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 8 may be contracted under existing open Petrobras tenders.
Brazil has been an important source of demand for the last two years. We expect this to continue in 2023. Importantly, the incremental demand is driving higher day rates, which have already increased 117% from 2020 to 2022. We anticipate that new fixtures will continue to climb 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 is 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 3 rigs to satisfy its current and upcoming tenders. To fulfill these requirements, rigs from other regions will need to be mobilized, as following our announcement that the KG2 is heading to Brazil, there are currently no ultra-deepwater 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 be contracted elsewhere. In the last 18 months, six semis have departed Norway for work in West Africa, Canada, and U.K. North Sea.
We anticipate at least two additional semis will leave 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 limited.
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. 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 multi-year recovery. I'll now turn the call over to Mark. Mark?
Mark Mey (EVP and CFO)
Thank you, Jeremy. 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. In September, we conducted an exchange of securities that provided the company with an incremental $175 million in liquidity. Last month, we executed more transactions.
A $525 million secured financing of the Deepwater Titan and a $1.175 billion refinancing of our fourth series of our senior notes, both transactions of which were well received by the market. In the context of today's interest rate and broader capital market environment, these two transactions materially improved our medium-term liquidity and further set the stage for us to opportunistically de-lever, simplify, and improve the flexibility of our balance sheet.
Now to the results. As reported in our 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. 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 the $525 million raised in Deepwater Titan, as I mentioned earlier. Looking closer at our results, during the fourth quarter, we delivered adjusted controlling 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 out-of-service maintenance expenses, mostly due to timing and lower personnel 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 billion 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 of 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 this quarter.
For the full year, and as I guided last quarter, we're anticipating adjusted revenues to be between $2.9 billion and $3 billion, also based on 96.5% revenue efficiency. As usual, as the year progresses, we may modify our guidance as necessary. We expect first quarter O&M expense to be approximately $430 million.
This slight quarter-over-quarter increase is primarily attributable to higher costs incurred 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 anticipating O&M expense to be approximately $1.9 billion. We expect GA expense for the first quarter to be approximately $50 million and ranging between $200 million-$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. 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 related to our new builds, as we highlight in our website CapEx schedule, and $100 million for maintenance CapEx. The maintenance CapEx includes approximately $20 million that 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 major spares program.
The newbuild CapEx includes mobilization, capitalized interest, 20K BOP upgrades, and capital spares. In conclusion, our debt and liability actions over the past 12 months have positioned us well for further improving our capital structure. We made significant progress in clearing 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 organically leveraging. We are already seeing this with our other people to fleet, for which estimated average contract day rate is increased approximately $30,000 year-over-year to approximately $340,000 per day as indicated in our fleet support.
As we are in an early stage of a 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 sale 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 delivering 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.
Moderator (participant)
Thank you, Alison. At this time, if you would like to ask a question, please press the star and one on your touchtone phone. You may remove yourself from the queue at any time by pressing star two. Once again, that is star and one to ask a question. Our first question comes from Greg Lewis with BTIG.
Greg Lewis (Managing Director)
Thank you. Good morning and good afternoon, everybody. Jeremy, you know, clearly, you know, congratulations on all the work you guys have done over the last couple of years and on getting the KG2 to work. You know, that was your last idle rig. You know, as we look ahead in this year and in the next year, you know, clearly there are gonna be some of your competitors have reactivated rigs. You have alluded to reactivating rigs as demand come in and customers are willing to pay more.
As we think about, you know, your ability to activate 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 we think are gonna be needed to come into the market to meet demand over the next two years?
Jeremy Thigpen (CEO)
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. By that, you know, 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. 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. We're okay with that.
Roddie Mackenzie (EVP and CMO)
Yeah, I think This is Roddie here. I think I have to add to that a little bit. To kinda demonstrate that discipline, you know, it's often difficult for us to talk about individual tenders and awards and negotiations. However, there's a couple of great examples. One in Brazil, which is, as you know, certain tenders are fully public there, where all the results are published. For example, in the pool tender in the lot two basket, that's one where we won a job with the Deepwater Orion. We were also the next rig to be awarded in that line. 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. We kinda stepped aside from that one and took the disciplined approach of not putting forward the Athena into that tender any further.
You know, since then, the Petrobras moved to the next operator or the next rig contractor, and that's gonna be, according to the results of the public tender, the DS-8, which should see their award at $460,000 a day. That's the publicly disclosed information on that. We'll have to wait and see how that turns out. We just want to reassure you that we take that discipline very, very seriously, and we have walked away from some contracts because they did not provide returns we assess to be adequate.
Greg Lewis (Managing Director)
Yeah, it seems like these multiyear contracts are gonna be, pricing's gonna be heading higher. I did wanna shift gears to the North Sea and to the harsh fleet just because, you know, it's an important EBITDA driver for the company. You know, it seems like we're in this air pocket in Norway, you know, in 2023. As we think about that and maybe some opportunities, let's maybe say, you know, 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, you know, we have the one idle rig, the one of the CAT rigs.
You know, relying that its water depth is, you know, is, you know, what, like 1,700 ft 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, you know, those Cat D rigs potentially find work? Or is it more of a, you know, just manage and wait for that market to rebound in 2024?
Roddie Mackenzie (EVP and CMO)
Yeah. Okay, great question. I'll take that one. As Jeremy had explained, you know, 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, you know, in excess of 20, about 22 rigs down to 13 rigs available in 2023. As you think about the effect that that's gonna have, that's the stuff that you're talking about where rigs are moving out of the region. They're going to, you know, West Africa, some are going to Canada.
There's a lot of speculation about, you know, some rigs maybe even more than one going to Australia, but also the U.K.. The stuff in West Africa seems to be growing even further. The really interesting thing was, in discussions that we've had with certain large operators in South America, the next tender that we expect from them is going to be specifically targeting moored units with high efficiency drilling packages. That would be ideal for the likes of the Cat D or any of the other high spec harsh environment rigs in Norway. Just to touch on that a little, you mentioned margins earlier. You know, with the cost base as being a little bit higher in Norway than it is elsewhere, that's going to be a key driver.
So you've seen these kinda 6 rigs move out, fully expect to see three or four more pretty soon. When those rigs move out, once you've got over the hurdle of the movement, and as Jeremy pointed out, you know, the customers are paying for those mobilizations now, you make better margins outside. For those rigs to come back to Norway, it's going to be an increased hurdle for them to come back. You know, with that said, we have line of sight to jobs on pretty much all of our harsh environment fleet, including the stacked Cat D.
You know, 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 some all of those. I think, over the period of this year, you're gonna see pretty much all of those rigs get fixtures put on them, and you'll see that the day rates associated with those and the locations should raise a few eyebrows in terms of the trajectory of rates for harsh environment rigs.
Greg Lewis (Managing Director)
Okay, great. Hey, Roddie, thank you for the time. Thanks everybody. Have a great day.
Moderator (participant)
Thank you. Our next question comes from Eddie Kim with Barclays.
Eddie Kim (VP of Equity Research)
Hi, good morning. We've obviously seen a lot of loaded events, the past nine months, which has mostly been driven by Petrobras. You guys have clearly been the biggest beneficiary of that. Just shifting to the majors, you know, we haven't quite seen as many large multiyear contracts from that group yet, likely because most of them are beholden to their investors. Are we getting to a point where Petrobras is just absorbing so many rigs that this is almost gonna force the majors hand in locking up rigs for multiple years?
Roddie Mackenzie (EVP and CMO)
Yeah. Really that is what's happening. You know, I would not say that the majors have been quiet. In fact, you know, 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 that are multi-year for the majors. By contrast, it would appear like they are moving slower. The context here is they're moving faster than they've ever moved in the past seven years, but Petrobras is really on a different level. Petrobras is progressing their tenders at a clip that, you know, impresses everybody.
I would argue a 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 fix in the mid-$400s. To your point, there will not be much supply left for the other prospects.
As Jeremy has 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. We're really optimistic about that, not only because we can push a lot of volume in Brazil, but mainly because they're long-term contracts.
We are beginning to see the majors around the world, particularly West Africa, are really beginning to focus on longer term. You're gonna see in the West African region, several fixtures will be made over the next few months that will be multi-year in nature. 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 (VP of Equity Research)
Got it. That sounds very positive for day rates moving forward. Just shifting to costs. One of your competitors yesterday highlighted higher costs this year for offshore crews and onshore support. Another one of your peers talked about kind of rig level OpEx moving up in the high single digits rig type of range. Is that something you're seeing or expecting as well? Is that kind of uptick in costs currently embedded in your full year O&M guide?
Mark Mey (EVP and CFO)
Yes. Thanks, Eddie. Yeah, clearly, with the inflation currently ongoing and the tight labor market, we're seeing similar cost increases. I would say somewhere in that 5%-8% area, if you blend both the labor plus the O&M costs. Yes.
Eddie Kim (VP of Equity Research)
Okay. Understood. Thanks for all that color. I'll turn it back.
Moderator (participant)
Thank you. Our next question will come from Fredrik Stene with Clarksons Securities. 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 (Deputy Head of Research)
Hey. Can you guys hear me now?
Moderator (participant)
Yes, sir. Please. We can hear you.
Fredrik Stene (Deputy Head of Research)
Okay, perfect. I'm not sure what happened there, but hi 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.
You also said that, you know, there might be more work to do. You definitely have some leeway now. 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, you know, the sensible next steps and also timing wise on that?
Mark Mey (EVP and CFO)
Yeah. Thanks, 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 de-lever a down cycle. Now we're in a cyclical recovery, and as a result of that, as I mentioned in my prepared comments, we have higher day rates, generating significant cash flow.
We're prepared to take our time and grow into our balance sheet by using these organic flows to de-lever the balance sheet. By simplifying, you know, we've got four different types of debt on our balance sheet. Clearly, simplifying means taking those four and moving them down to one eventually, but over time.
As you know, there's unsecured, there's secured, there's PGNs and SPGNs. Clearly the first focus is gonna be PGNs. From there, we'll look at the other types of debt on the balance sheet. Thirdly, we have exchangeable bonds. We have three tranches of that. Those are also on the table for us to address over the next year or so.
Fredrik Stene (Deputy Head of Research)
This is super helpful. Two other quick ones from me. First one, the Aquila, which you have the marketing rights to. How will you go about, you know, managing your investment there and also the other owners versus how you market your own stacked assets, for example? How is that governed?
Mark Mey (EVP and CFO)
Fredrik, I didn't hear you very clear, but I think you're referring to the Aquila. If that's the case, we have experience in doing this. As you're well aware, we own a third interest in the Norge, and we have a similar process whereby we maintain a clean marketing team to avoid any kind of antitrust concerns. We'll use the same approach with the Aquila and perhaps if we get the Libra, that rig as well.
Fredrik Stene (Deputy Head of Research)
Perfect. Thanks. Thanks. Super quick. For reactivations, do you guys have any idea of how many global reactivations, the supply chains will handle per year? Do you think there's a limit to that, how many you and your peers can do at the same time?
Mark Mey (EVP and CFO)
I'm gonna take a stab at this, and obviously Jeremy or Roddie can jump in as well. I think what we're seeing right now is the first in line are not the cold stacked rigs. It's the rigs that have been 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 2022, given the fact that I think there's a consensus around at least 12 months to reactivate a rig from a shipyard or from cold and to prepare the rig for its contract, because as you know, each operator has their own contracts, specific requirements, and equipment for that opportunity.
I think it's gonna be measured mainly because of this constraint, but also because of the fact that there is significant amount of cash required to do this. If you look at the balance sheets of the drillers, especially those that have just come through restructuring, I'm not sure it supports a wholesale reactivation program unless it's paid upfront by the customers.
Fredrik Stene (Deputy Head of Research)
Right. Thank you so much. That's all from me. Thanks.
Moderator (participant)
Thank you. Our next question will come from Thomas Johnson with Morgan Stanley.
Thomas Johnson (Financial Advisor and Managing Director of Wealth Management)
Hi. Thanks. Question on the Deepwater Atlas. Clearly, you know, if you sign that contract or more work today, you know, we would assume that 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, you know, kind of the mid-2024 expiration? In addition to that, maybe just, you know, 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 (EVP and CMO)
Yeah. Okay, I'll take that one. Yes, we're in discussions for follow-on work after her main contract. You know, that's still a while before she gets through that maiden contract. There are several bites, some of them which are in the 20K space. As Keelan had pointed out, one of the most interesting features of the rig is the super high hook load. We know that, you know, we set the record on the longest and heaviest casing run in the Gulf of Mexico. I have to say, the record was set about few days before on the Deepwater Conqueror. That was really stressing her to her maximum capacity.
Now we have the Atlas in the market available for those even higher hook loads. We're really optimistic about that. We think there's real demand for these ultra heavy casing strings. Of course, you can only do that with that class of asset. She happens to be the 20K rig. The concept is we basically have the most capable rig on all fronts, and we've kept her available in a relatively near-term situation. We're very optimistic about what's gonna come next for her.
Thomas Johnson (Financial Advisor and Managing Director of Wealth Management)
Great. Thanks. Then just maybe, any commentary on, you know, potential plans or capacity for a secured issuance if you were to receive, you know, a multiyear contract on the Atlas, maybe just, you know, relative to what has been recently announced on the Titan.
Mark Mey (EVP and CFO)
I think Thomas will craft our build when we get to it, but clearly, at the moment, we don't see a need for that.
Thomas Johnson (Financial Advisor and Managing Director of Wealth Management)
Got it. Thanks. I'll turn it back now.
Moderator (participant)
Thank you. Our next question comes from David Smith with Pickering Energy Partners.
David Smith (Director of Research Team)
Hey, good morning, and thank you. Looking at the marketed floater fleet, you know, I think we see a little increase in special surveys this year, close to twice as many next year for the, you know, entire marketed floater fleet. The mix of rigs coming up on their second or third SPS is growing.
You know, the industry needs reservations, maybe some stranded newbuild 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. You know, taking a slightly different angle on a prior question, I think you mentioned balance sheet constraints, you know, among contractors as maybe a governing factor for reactivation. I wanted to ask if that reactivation cash were there, I just wanted to see, you know, do you see potential for shipyard and OEM capacity to be a constraint on growing the supply of active floaters in the next couple of years?
Mark Mey (EVP and CFO)
Yes, we do. Clearly, as you've indicated, the reason that it takes at least 12 months to reactivate a rig is because of the challenges that our OEMs are having because they've reduced capacity significantly during the seven-year downturn. Now as they're ramping up, we're starting to see these challenges because demand from the drilling contractors has improved substantially. I'll pause there and see if Keelan has anything to add.
Keelan Adamson (President and COO)
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 reactivate them. It is a restriction, I would say that we're working collaboratively to find ways to remove it.
Jeremy Thigpen (CEO)
Sorry, I'd just add to that.
Mark Mey (EVP and CFO)
Please do.
Jeremy Thigpen (CEO)
In some ways, the capital constraints of the drilling contractors and the supply chain challenges that we're facing in the shipyard then with OEMs is actually healthy for the industry. We can't do what we've done in the past and overbuild. 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. While the growth will be slow, it'll be steady and should last longer. Really the growth will come through day rates as opposed to adding a bunch of rigs to the fleet.
David Smith (Director of Research Team)
Appreciate all that color. Sorry if I missed it, but do you have a view on how many floaters might be working off Brazil in 2025?
Roddie Mackenzie (EVP and CMO)
By the time we get to 2025, that count's gonna increase to the range of 40 or maybe even more. 'Cause not only are you looking at Petrobras adding significant capacity, but there's, you know, six other programs from the likes of Shell, Total, Equinor and others that are gonna be satisfied as well. You know, 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. I think you're looking at 40-plus rigs.
David Smith (Director of Research Team)
Thanks so much.
Moderator (participant)
Thank you. Our final question will come from Samantha Hoh with Evercore ISI.
Samantha Hoh (Equity Research Analyst)
Hey, guys. thanks for taking my questions. Congrats on a really productive quarter. I wanted to maybe stay a little bit on the topic of Brazil. It looks like you're gonna be operating a fleet of about five, I think, vessels there, five drill ships there in that country. 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, you know, what that does for your profitability in that region when you have just so many rigs concentrated in one market.
Roddie Mackenzie (EVP and CMO)
Yeah, okay, around the concentration of rigs in that market. 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 tender, there's basically a minimum specification, and you either qualify or you don't. 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. We don't necessarily have to deploy the seventh-generation, which are potentially the highest earners, to Brazil to be able to be successful. That's why it's been of significant interest for us.
We're basically taking our lower spec rigs and booking them on multiyear high day rate contracts in a region that we're very familiar with, and we've had a presence for over 50 years. Of course, we're now looking at five rigs being contracted there. I would be very optimistic that we'd be able to add, you know, one, two or three more to that over the next year or so.
Jeremy Thigpen (CEO)
Samantha, just to add to that.
Samantha Hoh (Equity Research Analyst)
Yes.
Jeremy Thigpen (CEO)
Your question was a little muffled on this end, so apologize, but I think you were asking a little bit of a question around economies of scale.
Samantha Hoh (Equity Research Analyst)
Yes.
Jeremy Thigpen (CEO)
There certainly are economies of scale with a larger installed base working fleet there. You know, it requires a tremendous amount of effort and time and energy and experience to run one ultra-deepwater rig safely, reliably and efficiently. As you add rigs, you don't have to add much in the way of incremental support on shore. There's definitely some economy of scale to be had, the more rigs we can add to a certain jurisdiction.
Samantha Hoh (Equity Research Analyst)
Excellent. I guess similar vein, I mean, taking that rig out of Namibia, which you know, has gotten so much press and excitement lately. You know, what are your thoughts in terms of like that market and what its potential looks like longer term? You know, is that, I mean, is that just a view in terms of the, you know, I guess exploration versus development type of work and just wanting that longer duration, visibility of like a development project in Brazil versus, you know, the high profile exploration type work in Namibia?
Roddie Mackenzie (EVP and CMO)
Yeah, I'll take that one. look, the exploration stuff in Namibia, you've now got several operators, who are kinda dipped their toe in that, and they've had good success. With success in exploration, they move into the development phase a little bit further down the track. You've basically got your kind of two rigs working in Namibia now.
There's demand for more. In fact, Galp Energia is out for an additional tender in Namibia. I think that's gonna be a really solid jurisdiction for the foreseeable future. I think you're gonna see multiple rigs. I think you're gonna switch from the kind of exploration phase into appraisal and then development over the next few years. I would expect to see a story there very similar to what you saw in Guyana with ExxonMobil.
The difference here is you just have, you know, even more operators that are interested. I think that's a really positive sign, you know, particularly because they use harsh environment rigs rather than just benign rigs. Again, you know, 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 gonna see a lot more long-term contracts because that's typically how the cycle works in terms of delivering all of those wells in that given time frame.
Samantha Hoh (Equity Research Analyst)
Okay. Thanks. If I could just squeeze one more in. You know, it's kind of interesting that you use that phrase, dipping your toes, 'cause 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, you know, dipping your toe into that sort of exciting new venture. I was just wondering, you know, obviously the thinking around that potential opportunity has shifted a little bit. It was really nice to see that you guys are, you know, swapping out essentially the Olympia with the Aquila. You know, 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, you know, is there like a return type profile? You know, anything that we can use in terms of the modeling based on that, you know, similar in like 1/3 interest that you have in the North?
Jeremy Thigpen (CEO)
Hey, Samantha. Sorry, you're really muffled on this end.
Samantha Hoh (Equity Research Analyst)
Oh, geez.
Jeremy Thigpen (CEO)
Return, whatever, about the return profile on the deep-sea mining opportunities?
Samantha Hoh (Equity Research Analyst)
Yes.
Jeremy Thigpen (CEO)
Oh, oh, on the. Was it on the Aquila?
Samantha Hoh (Equity Research Analyst)
In Aquila.
Jeremy Thigpen (CEO)
Oh, could we just defer that to a call afterwards with the investor team to add notes after you? The, 'cause it really has been difficult to understand you. Sorry.
Samantha Hoh (Equity Research Analyst)
Sorry about that, but thanks, guys, for all your time.
Jeremy Thigpen (CEO)
All right. Thanks, Samantha.
Moderator (participant)
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.