Transocean Ltd. (RIG) Q1 2022 Earnings Call Transcript

Transocean Ltd  (NYSE: RIG) Q1 2022 earnings call dated May. 03, 2022

Corporate Participants:

Cale Dillingham — Treasury Lead Analyst

Jeremy D. Thigpen — Chief Executive Officer

Mark Mey — Executive Vice President and Chief Financial Officer

Roddie Mackenzie — Executive Vice President and Chief Commercial Officer

Keelan Adamson — President and Chief Operating Officer

Analysts:

Ian Macpherson — Piper Sandler — Analyst

Connor Lynagh — Morgan Stanley — Analyst

Taylor Zurcher — Tudor Pickering — Analyst

Gregory Lewis — BTIG — Analyst

Samantha Hoh — Evercore ISI — Analyst

Karl Blunden — Goldman Sachs — Analyst

Presentation:

Operator

Good day, and welcome to the Q1 2022 Transocean Earnings Conference Call. Today’s call is being recorded. At this time, I would like to turn the conference over to Cale Dillingham. Please go ahead, sir.

Cale Dillingham — Treasury Lead Analyst

Thank you, Kevin. Good morning, and welcome to Transocean’s first 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 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. Thank you very much.

I’ll now turn the call over to Jeremy.

Jeremy D. Thigpen — Chief Executive Officer

Thank you, Cale, and welcome to our employees, customers, investors and analysts participating in today’s call. Before I get into the quarterly update, I would like to provide just a few thoughts on the current global state of affairs. During the first quarter, we observed oil prices which regularly exceeded $100 per barrel. While the Russian invasion of Ukraine and the resulting sanctions certainly contributed to these higher prices and focus the world’s attention on the importance and value of energy security, we believe that the persistent under investment by E&P companies to replace the reserves has resulted in diminished capacity to produce hydrocarbons globally, serving as the primary driver of sustained higher oil prices.

As you know, over the past few years, some of the capital that certain E&P companies may have previously earmarked for investments in reserve replacement and production growth was instead distributed to their shareholders in the form of dividends and buybacks as well as invested in various energy transition initiatives. All else being equal, this is left them with less capital to invest in, planned for and develop offshore projects. While we recognize that taking steps to achieve a lower carbon future is important, we also firmly believe that the diversity of energy sources is critical to ensure adequate and reliable supply. Hydrocarbons will without question continue to play a central role as the energy transition proceeds. In fact, cash flow generated from the sale of oil and natural gas will play a critical role in funding energy transition technologies and initiatives by our customers.

Indeed, the EIA’s International Energy Outlook 2021 indicates that global energy consumption is expected to increase nearly 50% over the next 30 years. While renewable energy resources are expected to experience the most significant growth rates, albeit from a very small base, demand for both petroleum and natural gas sources will continue to increase to meet this demand. Exploration and production companies will continue to engage in the exploration and development work to meet worldwide demand and replenish diminishing reserves. With constructive commodity prices combined with now proven and consistent lower project costs that the industry experienced several years ago, the economics of offshore projects remain robustly favorable. In fact, the consensus of industry observers and experts indicate that approximately 80% of offshore projects are profitable at $60 per barrel with numerous customers claiming that the breakeven price for their respective projects is well below $40 per barrel.

Now to the quarterly results, as discussed in yesterday’s earnings release, for the first quarter, we reported adjusted EBITDA of $163 million on $616 million in adjusted revenue. This strong operating performance was again driven by our team of experienced professionals who delivered fleet uptime of 97.6% for the quarter. Let’s now turn to the fleet and our recent fixtures. During the first quarter, we were able to secure $87.2 million in incremental backlog and return one of our recently idle rigs to work, leaving us with only two warm rigs remaining in our worldwide fleet. And as we mentioned in our press release, we just added an additional $200 million of backlog with fixtures on the Skyros and Invictus.

In the Gulf of Mexico, the Deepwater Inspiration secured a one-well extension with EnVen Energy at an increased day rate of $300,000 per day. The additional well keep the rig busy in the January 2023. Remaining in the Gulf of Mexico, the Deepwater Invictus secured a two-well extension with BHP at an increased day rate of $375,000 per day. The additional wells keep the rig busy through Q1 of 2023, representing eight years of continuous service for BHP. Heading south to Colombia, the Development Driller III return to work, securing an 80-day contract with Petrobras at a rate of $331,000 per day. The rig had been idle since concluding its most recent contract in January. Given the lack of availability of similar assets in the region combined with the well-deserved favorable reputation of the rig, we are actively pursuing opportunities for additional work for commencing later this year.

In Norway, we added a three-well extension to the Transocean’s Pittsburghan campaign at a rate of $305,000 per day, which will keep the rig working into January 2023. The agreement also contains provisions for additional work at escalating rates through 2023. In Angola, as mentioned in our earnings release, we are pleased to announce that the Deepwater Skyros recently secured 540 days of additional work with a major operator at a base day rate of $310,000 with the opportunity to earn a significant performance based bonus. The rig is now contracted into May of 2024. The award for additional work, while very much appreciated, was not totally surprising as the Deepwater Skyros was previously awarded of totals Rig of the Year, thanks to its superior operational performance.

Heading east to India, three long-term tenders were recently released. Based on our extensive experience in country and our stellar operational performance, we believe we are in a strong position to win some of this work. As we look toward upcoming opportunities for 2022, we are encouraged by the market and industry trends that continue to take shape. Oil prices while somewhat volatile have remained highly supportive and are driving a steady increase in offshore activity, we continue to see a tightening of the offshore market unfolding across multiple regions with committed drillship utilization consistently exceeding 90% with some industry experts suggesting utilization as high as 97%.

As further evidenced that the market has reached an inflection point, according to rig broker Clarksons, for the first time in eight years new contracts are on average being awarded at higher day rates than the contract they’re replacing. Additionally, Rystad Energy analysts yet again increased their short-term expectation for Deepwater investment this time to 14% year-on-year, which is double Rystad’s expectation just six months ago. As we’ve been predicting the current supply shortage of active floating rigs driven by the scrapping of rigs during the historically low demand cycle over the past eight years has contributed to the recent increase in day rates. Since 2014, more than 150 benign environment floating rigs have been scrapped and permanently removed from the global fleet. In addition, we strongly believe that the current real supply of rigs is even more limited than headline data would suggest due to high and increasing reactivation costs combined with long lead times for equipment.

Based upon several third-party estimates and given slight differences in their definitions, there are between 25 and 35 benign floating rigs cold stacked globally. We estimate that the reactivation of the cold stacked rig will take at least 12 months to execute, which has increased due to supply chain constraints and could drive additional cost escalation depending upon demand and availability of the required equipment. Also it is very possible that some of these cold stacked rigs don’t actually have the required specifications to be marketable in the future and will never return to the market.

On the topic of reactivations, I want to reiterate that Transocean will not speculate reactivate a rig. We will only bring incremental capacity to our active fleet with the contract that generate a suitable return on investment. We remain committed to fiscal discipline and we believe that ultimately rig utilization and day rates will continue their upward progression. Preferred lease recent assessment of order books there are 17 new builds currently at shipyards or recently in the hands of investors. We believe the majority of these rigs will likely ease require significant additional capital expenditures in excess of $100 million to $125 million to prepared to go to work, which is in addition to the underlying construction costs. As such, we believe with few exceptions, the aggregate constraints of the balance sheet and liquidity of most industry participants combined with the constraints in the global supply chain will govern the rate of entry of both cold stacked and new build assets into the active fleet.

Taking a closer look around the global market environment. Worldwide committed drillship utilization currently exceeds 90%. Many of these high specification assets are concentrated in the U.S. Gulf of Mexico, where we continue to observe the most significant growth in day rates from the low $200,000 just a few years ago to well over $300,000 per day for recently announced fixtures. It’s very possible that we will see awards made in the near future at day rates above $400,000 per day, which reflects the increasing tightening of this already nearly sold out market. Remaining in the Gulf of Mexico, we eagerly await the delivery of our two new build drillships the Deepwater Atlas and the Deepwater Titan, which will enter the region in the coming months. As you will recall, these floaters have already secured firm contracts for drilling on behalf of Beacon Offshore Energy and Chevron, respectively.

Historically, the Gulf of Mexico has served as a leading market indicator for other deepwater offshore drilling markets. As in the Gulf of Mexico, direct negotiations with customers continue to increase in multiple locations with improving contractual terms, higher day rates and longer durations, reflecting customers’ recognition that there is a looming shortage of rigs and therefore limited time for tendering or lengthy negotiations. In Latin America, we expect strong demand growth going forward. Industry analysts expect a 50% increase in rig demand from March of 2022 through September of 2023. Given our experience, established support infrastructure and operational track record in the region, we believe we are very well positioned to compete for these incremental 15 opportunities.

Just last week Petrobras issued new multi-year tenders for up to eight additional rigs, which would ultimately necessitates up to seven new rigs entering Brazil. In addition to the Petrobras prospects on the horizon, medium to long-term opportunities with IOCs and other NOCs, including Equinor, Shell, Petronas and TotalEnergies are expected to commence in 2023. Current opportunities in Latin America could add more than 14 rig years that will start within the next 18 months. With no high specification idle floaters in the region, rigs from other areas will be required to meet additional demand, which should remain strong over the next several years. In West Africa, we remain very encouraged by floater demand. We see 20 opportunities with program durations of greater than one year commencing within the next 18 months. If this demand materializes, as we expect, a minimum of 15 rig years could be awarded. This additional demand is driven by a return to activity in Angola and Ghana and the recent large discoveries in the [Technical Issues]

There are opportunities for MPD drillships in Asia, but there are no available MPD units in the region. We are also seeing increasing demand for Australia, which is most likely to occur in 2023. However, similar to what we are seeing in Asia, there is likely to be a rig shortage in Australia at that time. Transitioning to the harsh environment market, broader expectations are for a stronger Norwegian market beginning the 2023 drilling season. A record level of sanctioning is anticipated by year-end as operators move projects forward to utilize expiring tax incentives. Norway maybe challenged in 2022 and into the summer of 2023 due to program delays based on a shortage of critical sub-sea equipment. We do however anticipate a stronger market by mid-2023 in a sold-out market in Norway in 2024.

Our customers may also need to contend with additional tightening in the market as evidenced by recent 500 day tender in the region starting in late 2023. Total Norwegian active utilization currently stands at 82% with 14 assets working in an active supply of only 17 rigs. This market could further tighten up rigs leave Norway for the U.K. and/or Canada, which is a very real possibility now that the Bay du Nord project in Canada has received environmental approvals offshore Newfoundland. And in the U.K., there is a lack of warm assets. Given the prohibitive cost of reactivating a cold stack rig, we could find ourselves in an environment in which hot rigs from Norway are moved to the U.K. to perform some of the work anticipated over the next year, further tightening the Norwegian market. This would obviously bode well for us as Transocean remains one of the two main providers of sixth generation semi-submersibles in the North Sea.

Additionally, as a result of the recent announcement made by the U.K. government regarding energy security policy to support European energy requirements, we now expect an increase in demand for rigs. We are actively responding to a number of new tenders that have emerged during the past couple of months and are encouraged by the new licensing round for North Sea oil and gas projects in the fall of 2022.

In summary, our outlook is increasingly more positive than at the end of the fourth quarter, reinforced by recent fixture trends, customer conversations, industry analyst reports and market projections for commodity supply-demand balances. The evidence is clear that the market is further tightened since our last earnings call and the day rates contemplated in contracts continued to increase. As a reminder, in the context of a steadily rising market, we will continue to manage our portfolio of rigs to obtain the best combination of rate in term. Transocean currently has significant growth opportunities represented by our 12 6th and 7th-gen stacked or idle rigs. We will evaluate these opportunities on a case-by-case basis, ensuring that the financial return result in value creation for all shareholders.

As you know, Transocean owns and operates the industry’s most technically capable fleet of floating rigs and we are always implementing innovative technology to continuously improve the safety, operating efficiency and value of our assets around the world. The robotic riser system was installed on its first rig in cooperation with our customer in the U.S. Gulf of Mexico and just completed a first pool from 9,500 feet. The robotic riser system automates all activities around the rotary table during riser operations, which improves personnel safety by eliminating the need for work in the red zone area, while simultaneously improving consistency and increasing efficiency of operations. We will deploy a second system to another rig this month in the U.S. Gulf of Mexico. The enhanced kick detection system developed with enhanced drilling was deployed early in the first quarter and has delivered improved well efficiency and operations integrity benefits for our customer through monitoring fluid volumes to help detect flow anomalies.

Our K-BOS shearing technology provides unrivaled shearing capability that will result in a safer well construction process. In the U.S. Gulf of Mexico, following a just over 120-day deployment, we successfully tested our K-BOS technology, sharing a landing string grade drill pipe in milliseconds to demonstrate the benefits of such a system in emergency conditions. Needless to say, we are very pleased with the performance of these new technologies and look forward to continuing to deployment across selected rigs across our global fleet. In conclusion, our industry-leading backlog provides us with the visibility to future cash flows that enable us to continue positioning Transocean for what we anticipate will be a sustained industry recovery.

I’ll now turn the call over to Mark. Mark?

Mark Mey — Executive Vice President and Chief Financial Officer

Thank you, Jeremy, and good day to all. During today’s call, I will briefly recap our first quarter results and then provide guidance for the second quarter as well as an update of our expectations for full year 2022. Lastly, I’ll provide an update on our liquidity forecast through the first half of 2023. As reported in our press release, which includes additional detail on our results for the first quarter of 2022, we reported a net loss attributable to controlling interest of $175 million or $0.26 per diluted share. After certain adjustments as stated in yesterday’s press release, we reported adjusted net loss of $183 million.

Highlights for the first quarter include adjusted EBITDA of $163 million, operating cash flow used during the first quarter was $1 million. We anticipate positive cash flow again in the second quarter and for full year 2022. Looking closer at our results, during the first quarter, we delivered adjusted contract drilling revenues of $615 million at an average day rate of $335,000. This is slightly better than our previous guidance and reflects increased reimbursables and marginally higher operating activity. Operating and maintenance expense for the first quarter was $412 million, which is slightly less than our guidance primarily due to the timing of certain maintenance activities associated with global supply chain challenges.

Turning to the cash flow and balance sheet, we ended the first quarter with total liquidity of approximately $2.6 billion, including unrestricted cash and cash equivalents of approximately $910 million, approximately $280 million of restricted cash for debt service and $1.3 billion from our undrawn revolving credit facility.

Before I move on to updated guidance, let me address the impact of inflation and supply chain delays on Transocean’s operations. As of both companies we are experiencing upward pressure on salaries and wages and increased pricing from our vendors. Fortunately, although the formulation for each our long-term contracts provide cost escalation protection with a time lag. As we negotiate new contracts we reflect these cost increases in a day rate. In addition and we will notified by several vendors, some parts and equipment may take longer to procure, and as such, we have adjusted our inventory strategy to address these potential delays. At this point, we do not anticipate shortages of critical equipment or spares, which may — could impact our operations.

Let me now provide an update on expectations for the second quarter and for full year financial performance. For the second quarter 2022, we expect adjusted contract drilling revenue of approximately $705 million based upon an average fleet wide revenue efficiency of 96.5%. The expected higher revenue efficiency than our first quarter is largely due to circumstances experienced in the first quarter, including waiting on weather in Norway and a reduced day rate for a period on the Deepwater Pontus. For the full year 2022, we are anticipating adjusted contract drilling revenue to be approximately $2.7 billion, also based upon 96.5% revenue efficiency for the three remaining quarters.

We expect second quarter O&M expense to be approximately $460 million. The slight quarter-over-quarter increase is primarily attributable to timing of maintenance projects across the fleet. For the full year 2022, we expect O&M expense to be approximately $1.7 billion. We expect G&A expense for second quarter to be approximately $50 million and range between $180 million, $185 million for the full year. Net interest expense for the second quarter is forecasted to be approximately $98 million. This includes capitalized interest of approximately $17 million. For the full year, we estimate to incur net interest expense of approximately $395 million, including capitalized interest of approximately $73 million.

Capital expenditures and capital additions, including capitalized interest, but excluding imputed interest on favorable shipyard financing of the Deepwater Atlas are forecasted to be approximately $511 million for the quarter. This represents approximately $490 million for our new build drillships, predominantly the Deepwater Atlas, of which $370 million will be financed and $21 million of maintenance capex. Cash taxes are expected to be approximately $10 million for the second quarter and approximately $28 million for the year. Our expected liquidity in June of 2023 prior to the — to our current $1.3 billion revolving — revolver maturing is expected to be between $1.4 billion and $1.6 billion, including restricted cash for debt service of approximately $275 million and anticipated secured financing of our second 8th generation drillship Deepwater Titan.

This liquidity forecast includes an estimated 2022 capital expenditures and capital additions of $1.3 billion and a 2023 capex expectation of $140 million. The 2022 capex includes $1.2 billion related to our new builds and $80 million for maintenance capex. As always, our guidance excludes speculative rig reactivations or upgrades. In conclusion, in addition to the safe, reliable and efficient operation of our rigs, we will maintain our focus on optimizing revenue and cash flow generation by enhancing our revenues in this improved offshore drilling environment and effectively optimizing our operational costs.

As we have demonstrated through our prudent management of our capital, opportunistically executing liability management transactions comprising more than $10 billion over the last six years and judiciously assessing capital — equity capital markets, strengthening our balance sheet and improving our liquidity remain our priority. We will continue to actively monitor and pursue opportunities to delever and extend our liquidity runway through a variety of actions using all appropriate tools available in the market.

This concludes my prepared comments. I’ll now turn it back over to Cale.

Cale Dillingham — Treasury Lead Analyst

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

Questions and Answers:

Operator

[Operator Instructions] The first question today comes from Ian Macpherson of Piper Sandler.

Ian Macpherson — Piper Sandler — Analyst

Thanks. Good morning, everyone.

Jeremy D. Thigpen — Chief Executive Officer

Good morning.

Ian Macpherson — Piper Sandler — Analyst

Jeremy, curious about the state of play in Norway. You described how there is going to be a potential deficit of rigs in the harsh environment theater, but possibly some project delays between end of the year and some of the summer of ’23 that could push some of these starts out. So curious how that influences your nearer term contract exposure there, rigs like the Equinox, which I think Equinor might be finishing their drill work early this year. How does that play into your thinking for bidding shorter term, longer term and where you think rates are going for that class of rigs into that type of market?

Jeremy D. Thigpen — Chief Executive Officer

Thanks, Ian. I will turn that whenever to Roddie as he has been net deep in this conversation right now.

Roddie Mackenzie — Executive Vice President and Chief Commercial Officer

So looking at this as we had mentioned before, there is no been 36 development plans submitted or expected to be submitted this year for that period of ’23, ’24, ’25. So that’s where the significant optimism about just how tight that market is going to be come from. And in the near-term, we’ve yet to see any reaction in Norway to the Russian crisis, Russian Ukrainian issues with gas. So the energy crisis that you have in Europe has not yet played out in terms of rig activity in Norway. It has played out a little bit in the U.K.

So what you’ve seen recently in the U.K. is a really strong move by the government to basically reduce the red tape to open up as much as they can in terms of permitting and actually enact the new licensing round. So with the cad do you, specifically the Equinox, she is very well placed to go in and do these increased oil recovery projects that allow her to use that lighter BOP and go on existing wells to essentially increased production of gas in the near-term, and that’s what we think is going to play out here quite strongly between the U.K. and eventually I’ll come to Norway.

Norway, being a bit more regulated bit more red tape involved in moving projects forward. So you could see that although the rig is done well and finishing the project kind of ahead of time, we think there’s pretty good prospects on the back end of that just might be a small gap in between. The really interesting thing about that market is the U.K. already has a couple of tenders that are out — there just know that are kind of in the process of being negotiated and we would expect to see within the next couple of months that a couple of rigs, premium rigs from Norway are going to get pulled out. So as you see those rigs leave Norway, the remaining fleet in Norway is going to be in high demand particularly when folks are waking up to what’s going on in the longer term. And you have actually seen one or two of the operators proactively booking longer term programs in Norway despite the fact they don’t actually have those wells filled on their on the chart. So, really optimistic about Norway, even more optimistic about the changes just happened in the U.K., but there will be a little bit softer market just in the near-term so kind of like through the end of ’22.

Ian Macpherson — Piper Sandler — Analyst

Understood. Thanks, Roddie. And then I wanted to ask separately, just how we’re looking with the final construction and commissioning for the Deepwater Atlas ahead of the Beacon start up and if you could refine the estimated start date there as well as how that plays into your full year guidance, if you don’t mind. Thanks.

Roddie Mackenzie — Executive Vice President and Chief Commercial Officer

Yeah. So I’ll turn that one over to Keelan, who is just personally back from the Singapore.

Ian Macpherson — Piper Sandler — Analyst

Okay.

Keelan Adamson — President and Chief Operating Officer

Good morning. Just return from Singapore where we conducted the naming ceremony for the Deepwater Atlas. So she is on schedule for delivery in Q2 and we expect her to be in the Gulf of Mexico on working by the end of the year, so no change there.

Ian Macpherson — Piper Sandler — Analyst

Okay. And then just lastly, I was curious of the full year guidance contemplate some material contribution or if it’s more of a late Q4 start.

Mark Mey — Executive Vice President and Chief Financial Officer

Yes, Ian, it’s Mark. It’s unlike Q4 starts, so there’s nothing material contributed from the Atlas at this stage.

Ian Macpherson — Piper Sandler — Analyst

Got it. Thanks, everyone.

Operator

Our next question comes from Connor Lynagh of Morgan Stanley.

Connor Lynagh — Morgan Stanley — Analyst

Yeah, thanks. So, obviously, things are looking very strong in the industry right now. I appreciate this is sort of an overly simplistic way of looking at it, because the calculation is complex. But how are you thinking about potential uses and sources of capital? Mark, you alluded to this somewhat in the prepared remarks. But obviously there will likely be some reactivation opportunities. Would you push customers to pay some of the reactivation cost upfront and how are you thinking about potentially tapping the market further for equity?

Mark Mey — Executive Vice President and Chief Financial Officer

Yes. So, thank you,Connor. I proud of this year is to first of all get our RCF renegotiated, extended to provide us the cushion we need for the next several years. In addition to that, we’re very focused on adding to our fleet, either through our cold stacked assets or in other ways. And if we do that, as Jeremy mentioned in his prepared comments, that the reactivation costs will be coming from the initial contract in addition to a day rate that’s sufficient to be able to return a fair amount of capital to our investors. We’re also focused on other liability management opportunities and I won’t get to that at this stage, but clearly there’s a lot that we can do in a market that — market backdrop that we currently have as opposed to what we’ve been dealing with the last seven years. So I’ll pause there and hand it back to you.

Connor Lynagh — Morgan Stanley — Analyst

Got it. That’s helpful context. Maybe just moving to the broader market here, I think it’s very apparent that supply has been a major source of the tightness better discipline from some competitors out there and obviously a lot of attrition in the fleet. I guess, where we get some questions from investors is the demand outlook here, and you’ve outlined some big areas. But I guess just broadly speaking, have you seen a change in customer conversations over the past few months here in light of what’s been going on in Russia and Ukraine? And how are you thinking about the broader exploration opportunity globally over the next couple of years here?

Jeremy D. Thigpen — Chief Executive Officer

Yeah, I think I’ll take that one. Yes, so look in the context of Russia and Ukraine, we’re not focused on that as a driver for the commodity price. The underlying fundamentals and the lack of investment in oil and gas developments over the past seven years are what drove the commodity price is up towards that $90, $100 barrel mark prior to all of that. So if you take that out of the equation and you don’t think that that upset is going to happen on a long-term view, so you’re going to be a bit more conservative if you do that. We look to the demand that’s being created around the world. So everyone has had the discussions directly with the customers that there’s less tendering going on, there’s more direct negotiations as customers seek out to get just the right asset for them.

But it’s interesting the move by Petrobras to issue tenders for up to eight rigs just at this moment in time in addition to the tenders they already have out there, Brazil, for example, has already awarded five rigs this year and with these new tenders that out they’re expected to award and additional 16 potentially in the remainder of ’22. So if you think about it in that context, it seems like an unprecedented move, it seems like that is a now going to be a huge pool on the active supply and in fact is going to necessitate some reactivation of rigs, because there simply aren’t enough rigs to meet that demand. But I have to tell you, I don’t think it is unprecedented. I think this is Petrobras’ contracting philosophy. I think this is the ultimate barometer of how strong this market is going to be and for an extended period of time.

In previous downturns, as you come into the upswing whenever you see Petrobras go along that tells you that they are locking in capacity, because they see the writing on the wall in terms of availability. So it appears unprecedented, but it’s not. I mean, I think this is truly the barometer that says drillships are going to be in very strong demand for many, many years. In fact, those tenders in Brazil are — I think the average is about three, three and a half years firm but with three, four years of options. So that is going to be a tremendous draw on the global availability of ships.

Connor Lynagh — Morgan Stanley — Analyst

Interesting. Thank you for that. I’ll turn it back.

Operator

The next question comes from Taylor Zurcher of Tudor Pickering Holt.

Taylor Zurcher — Tudor Pickering — Analyst

Yeah. Thanks, Jeremy, Mark and Roddie. Roddie, I actually wanted to follow up on some of the comments you just made there. So, I mean, you’re talking about 16 more rigs or rig years maybe going down to Latin America/Brazil. Jeremy, in the prepared remarks, you said 20 opportunities with over one year of potential term in West Africa, so call it 15 rig years there. I mean, I guess, my question is, are these sorts of opportunities or rigs that are currently working today that the types of rigs that are bidding into these opportunities or resolve this incremental work truly incremental and going to need to be serviced by rigs that aren’t contracted today.

Jeremy D. Thigpen — Chief Executive Officer

Yeah, good question. So, the tenders that are out in Brazil prior to the ones that just came out this week those were for rollover contract. So those BS11, Libra those kinds of projects are for rigs that are already on contract and expected to renew them or roll them over. This potential for up to an additional eight, we think seven of those are incremental demand. So that rigs are either not currently in Brazil or certainly would have to come from elsewhere to meet that demand. In terms of the Africa numbers, we’ve already seen six, seven awards this year expected to get another 12 to 14 by the end of the year and about half of those new ones are again incremental demand. Not only that, but in Asia, as an example, we’ve got several shorter term contracts, but there are a few that are long-term. Specifically in India, you’ve got three longer term programs that are all incremental demand that will require rigs from either currently not utilized or coming from outside to satisfy that demand. So as we think about that coming across the world the incremental demand is each one of the major regions. So the short answer to that is a very substantial portion of these contracts is going to be all incremental. That’s why we see a fully sold out market on the near-term horizon.

Taylor Zurcher — Tudor Pickering — Analyst

Yeah, very encouraging and good segue into my next question which is rig reactivations. So, I mean, you’ve got a number of cold stacked rigs today and actually the higher stack rigs have been stacked for, call it, five or six years now. So, Jeremy, you talked in the prepared remarks about reactivation costs continuing to tick higher as industry wide I think was you reference as time continues to pass by, so curious if you could refresh us what — as to what sort of cost is going to take Transocean to bring some of these rigs out of stack. Thank you.

Mark Mey — Executive Vice President and Chief Financial Officer

Yeah. So this is a moving target Taylor as you can imagine. Yeah, as an industry we have never reactivated a cold stacked rig 7th gen, 6th gen cold stack rig with all the electronics that has. So we’ve been estimating this based upon a in-depth study by our engineering team and our estimates for our rigs are in that $50 million to $75 million. We do believe that that number could grow higher because this is based upon a 2021 estimate. Clearly we are going to see that seen that there has been inflation of somewhere around 8% to 9%. So you can probably add that inflation impact to it as well. But as Jeremy said and this is the other issue, with the supply chain delays, it will take at least 12 months to get these rigs back into the operating fleet and that’s excluding the impact you may have coming into certain markets like the U.S. Gulf of Mexico we have to have specific configurations on your BOPs.

Taylor Zurcher — Tudor Pickering — Analyst

Understood. Thanks, Mark.

Jeremy D. Thigpen — Chief Executive Officer

Yeah. The one thing I’d add to that Taylor is our customers are finally starting to recognize the cost required to reactivate these assets and the duration, the time it’s going to take to reactivate these assets. And so up until now in short-term projects and ever increasing day rates it seems, which is great, but ultimately, they’re going to have to move to longer terms to secure the existing assets or they’re going to wind up paying a pretty penny for a reactivation of one of these assets and they’re going have to wait potentially 12 months or more.

Taylor Zurcher — Tudor Pickering — Analyst

Right, right. Yeah, makes sense to me. Thanks.

Operator

Our next question comes from Greg Lewis of BTIG.

Gregory Lewis — BTIG — Analyst

Hey, thank you and good morning, everybody. I was hoping you guys did a good job of laying out the improving market case in Brazil and West Africa and the term work around that. It’s interesting in the Gulf of Mexico one of the best thing that’s happening right there is kind of you might argue the lack of long-term work where you’re seeing short-term spot work which is enabling day rates they just continually push higher and higher. As we think about the Gulf of Mexico and kind of the appetite for rig demand, is there anything that’s going to change, that’s going to make customers think about taking rigs for longer or are we in this kind of this nice pocket where as you look out over the next 6, 12, 18 months the majority of the work is spot, which is going to enable you to continue to push pricing higher?

Roddie Mackenzie — Executive Vice President and Chief Commercial Officer

Yeah. So if you think about the situation that we’re in, we actually have four long-term contracts in the Gulf of Mexico. So if you think about our fleet and our strategy, it’s about split 50-50 between rigs that are available for short-term work and rigs that are available — are unavailable because they’re on the longer term stuff. The discussions that we have are kind of mix of both, right. So there are some customers that are looking to add year plus programs. And what we’ve seen is in each one of these discussions which are typically not out to tender, they’re almost all direct negotiations now in the Gulf of Mexico.

Each one of those customer conversations is indicating longer and longer periods. And I think that comes back to the overarching under investment in oil and gas and the U.S. Gulf of Mexico representing a very quick uptick in terms of being able to exploit those opportunities. So what you see is the operators being able to move quickly in the Gulf of Mexico. And as they go through their budget cycles there is more and more term getting added to these. So what we typically see as we start out with two, three wells firm and then they want some options and then before we actually get to the start of the contract those options are now becoming firmed up and there’s ask for even more options. So that’s happened in a couple of rigs for us.

There is also a couple of things that we’re looking at that we are asked for multi-year work and it really is going to just pan out on kind of a case-by-case basis. We are trying to keep our powder dry for our very highest spec assets so as to take advantage of the improving market and the complete lack of availability in ’23. So, watch this space. We think you’re going to see further growth in terms of day rates, but we also think you’re going to see a few fixtures that are multi-year in nature as the operators basically have a much better looking runway now with the sustained commodity price up at $100 plus.

Gregory Lewis — BTIG — Analyst

Okay, great. Thank you for that, Roddie. And then just, Jeremy, you mentioned in the prepared remarks, Australia. I know Transocean has been in Australia previously. I don’t think we — I don’t think you are working in Australia right now. As I look across your assets and realize in Australia is not the North Sea, but Australia is a challenging environment nevertheless, what type of rigs could this transition have that can actually benefit from an improving market in Australia?

Roddie Mackenzie — Executive Vice President and Chief Commercial Officer

Yeah, Australia, I’ll take that one, I mean, always been kind of interesting market for us over the years. Today there is only a couple of rigs working. But as I look down the list of opportunities here, we have at least five rig lines required in Australia, and there’s only a couple of rigs there. So I mean of course there is — that requires rigs to come in and be reactivated. The kind of the ideal push for rigs there are rigs like our development driller class. So these are the rigs that are kind of a hybrid between emerge rig and a DP rig and also high performing moored assets like our Deepwater Nautilus rigs like that. In the past, you’ve also had several of the drillships in there. So like our KG rigs as well. So I think it’s there potential for a number of different classes of vessel to move into Australia, but Australia has a reasonable amount of red tape and requirements to get in. So there is going to be some expense associated with that. So I would expect to see the day rates in Australia become real solid and in fact I think you probably saw that in the last fixtures that was up towards the 400 mark. I think you’ll see them well beyond that going forward.

Gregory Lewis — BTIG — Analyst

Okay, great to hear. Thank you very much.

Operator

Our next question comes from Samantha Hoh of Evercore ISI.

Samantha Hoh — Evercore ISI — Analyst

Hey, guys. Thanks for taking my question. And this might be unusual, but I have a question about your recent announcement about the investment that you made in Ocean Minerals. I have to submit that deep seabed minerals was it really on my radar for the Cook Islands. I just wonder if you could elaborate on the types of technology that you would be developing. What this means for your rigs? Do you just — so anything you can provide in terms of what this investment entails for would be appreciated.

Jeremy D. Thigpen — Chief Executive Officer

Hey, Samantha, thanks for the question. First of all, let me say, it’s a very small investment, basically dipping our toe in the water. We sit around and we talk about different opportunities for the direction of our business and things that we might be able to contribute to and grow into. And as you think about the nature of our business in terms of our assets and our expertise and our global presence and what we can bring to bear in that regard I kind of look for opportunities outside of our current space that may or may not make sense. And so obviously something like Ocean deep seabed mining potentially we could utilize existing assets, potentially we could utilize our expertise that I’ve just described in terms of delivering safe, reliable and efficient operations to create value in that space. As of now, again, it’s just — it’s a little more exploratory at this point. We are hopeful that it could develop into a potential business. But at this point, it’s very early days. So don’t expect too much coming in months or quarters.

Samantha Hoh — Evercore ISI — Analyst

Okay, got it. Well, actually, then the other question my follow-up was really with the CCS topic. You guys just announced that you’re drilling one of the wells and the sidetrack for the Northern Lights project. Could you — is that happening this year?

Roddie Mackenzie — Executive Vice President and Chief Commercial Officer

Yeah, that’s already underway. So, yeah, I think you’ll see a few more of those there, but again those are, as Jeremy alluded to, being part of the broader solution for the energy. That’s kind of one more facet of the business that we’re very interested in, because we use our existing assets were largely unchanged to go do the CCS work.

Samantha Hoh — Evercore ISI — Analyst

Okay, excellent. Congrats, guys.

Operator

And our next question comes from Karl Blunden of Goldman Sachs.

Karl Blunden — Goldman Sachs — Analyst

Hi, good morning. Thanks for the time. Really good to see those, the two new fixtures announced in the press release with one with strong term, another with really good day rate. And question was, is that the kind of backdrop that you’re looking forward to look to extend the bank facility. I know that I think last quarter Mark made a comment about wanting to have an improving backdrop and expecting that. And then what do you think is a reasonable term to look at when you think about an extension there to give you time to grow into this up cycle?

Roddie Mackenzie — Executive Vice President and Chief Commercial Officer

Sorry, Karl, could you ask the question again. I’m sorry.

Karl Blunden — Goldman Sachs — Analyst

No problem. Two new fixtures announced, positive backdrop and I think the comment last quarter was that with a stronger backdrop going to be put you in a better position to extend the bank facility. So just kind of wondering are you now there at that position where you can do that and what kind of term do you think is reasonable to target on the bank facility to give you time to grow into this the positive market that you’ve described?

Mark Mey — Executive Vice President and Chief Financial Officer

Yeah. So thanks, Karl. Our RCF is secured by the the assets, the still value of the assets. Obviously, having contracts on those rigs improve that, but that’s not a big driver. I think the fact that we are in an up cycle now. We have numerous higher value asset secured in the facility. I don’t foresee an issue with us getting that done. This will not be a new facility. We are looking at extending it. So you’re looking at an extension somewhere in that two, maybe two and a half year range. I think that’s good for us, it’s good for the banks, because we do believe we’re coming into a multi-year up cycle, which gives us a little more leverage down the road to be able to redo this and maybe a larger amount toward better terms.

Karl Blunden — Goldman Sachs — Analyst

That’s very helpful. One other theme that’s been coming through earning season is just inflationary pressures that many companies are seeing, interested in what you’re seeing from your major drivers of cost, labor being one of them, but also maintenance capex expenses, how are those trending? Do you feel like some of those headwinds have peaked at this point in time, any commentary there would be helpful.

Mark Mey — Executive Vice President and Chief Financial Officer

Yeah, so in my prepared comments, Karl, I mentioned the fact that we do have — we do see the inflation in both salaries, wages and in some — from some of our vendors. All of our long-term contracts have protection. Now, there is a time lag. But we are protected against the dollar for dollar. So, over time that does benefit us. And then obviously with the new contracts as Roddie and his team are negotiating them, we know what the cost structure is and we can incorporate those increases into the day rate. And because this is an increase in day rate environment, you could make the argument that margins are expanding, and therefore, softening any impact from inflation that we’re seeing. I don’t think it’s speaking. I do think we rainfall a bit of a region, maybe another 12 months of increasing inflation, but we are well positioned to take care of that.

Karl Blunden — Goldman Sachs — Analyst

That’s helpful. Thank you.

Operator

[Operator Instructions] And as there are no further questions, I would like to hand the call back to Cale Dillingham for any additional or closing remarks.

Cale Dillingham — Treasury Lead Analyst

Thank you, Kevin. And thank you everyone for your participation on today’s call. We look forward to talking with you again when we report our second quarter 2022 results. Have a good day.

Operator

[Operator Closing Remarks]