Transocean Ltd. (RIG) CEO Jeremy Thigpen on Q1 2022 Results - Earnings Call Transcript
Transocean Ltd. (NYSE:RIG) Q1 2022 Earnings Conference Call May 3, 2022 9:00 AM ET
Company Participants
Cale Dillingham - Investor Relations
Jeremy Thigpen - Chief Executive Officer
Keelan Adamson - President and Chief Operating Officer
Mark Mey - Executive Vice President and Chief Financial Officer
Roddie Mackenzie - Executive Vice President and Chief Commercial Officer
Conference Call Participants
Ian Macpherson - Piper Sandler
Connor Lynagh - Morgan Stanley
Taylor Zurcher - Tudor Pickering Holt
Greg Lewis - BTIG
Samantha Hoh - Evercore ISI
Karl Blunden - Goldman Sachs
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
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 will now turn the call over to Jeremy.
Jeremy Thigpen
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 focused the world’s attention on the importance and value of energy security, we believe that the persistent underinvestment 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 has left them with less capital to invest in, plan for and develop offshore projects. While we recognize that taking steps to achieve a lower carbon future is important, we also firmly believe that a 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 cost than 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 returned one of our recently idled rigs to work, leaving us with only 2 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 1-well extension with EnVen Energy at an increased day rate of $300,000 per day. The additional well keeps the rig busy into January 2023. Remaining in the Gulf of Mexico, the Deepwater Invictus secured a 2-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 8 years of continuous service for BHP. Heading south to Colombia, the Development Driller III returned to work, securing an 80-day contract with Petrobras at a rate of $331,000 per day. The rig had been idled 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 her commencing later this year. In Norway, we added a 3-well extension to the Transocean Spitsbergen 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 Total’s 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 8 years, new contracts are on average being awarded at higher day rates than the contract they are 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 6 months ago. As we have 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 8 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 a 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 speculatively reactivate a rig. We will only bring incremental capacity to our active fleet with a contract that generates a suitable return on investment. We remain committed to fiscal discipline and we believe that ultimately rig utilization and dayrates will continue their upward progression. Per Fernley’s recent assessment of order books, there are 17 newbuilds currently at shipyards or recently in the hands of investors. We believe the majority of these rigs will likely each require significant additional capital expenditures in excess of $100 million to $125 million to prepare 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 sheets 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 newbuild 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 $200,000s just a few years ago to well over $300,000 per day from recently announced fixtures. It is 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 newbuild 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 multiyear tenders for up to 8 additional rigs, which could ultimately necessitate up to 7 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 Total Energies are expected to commence in 2023. Current opportunities in Latin America could add more than 14 rig years that would 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 1 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 Namibia, combined with the reactivation of major developments like Mozambique and Nigeria. In Asia-Pacific, we are seeing pockets of demand for 1 or more years of work with insufficient rig supply to meet those specific needs.
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 in 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 subsea equipment. We do however anticipate a stronger market by mid-2023 and a sold out market in Norway in 2024. Our customers may also need to contend with additional tightening in the market as evidenced by a recent 500-day tender in the region starting in late 2023. Total Norwegian active utilization currently stands at 82% with 14 assets working and an active supply of only 17 rigs. This market could further tighten if rigs leave Norway for the UK and/or Canada, which is a very real possibility now that the Beta Nord project in Canada has received environmental approvals offshore in Newfoundland.
And in the UK, there is a lack of warm assets. Given the prohibitive cost of reactivating a cold-stacked rig, we could find ourselves in an environment in which hot rigs from Norway are moved to the UK 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 UK 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 has further tightened since our last earnings call and the day rates contemplated and 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 and term. Transocean currently has significant growth opportunities represented by our 12th, 6th and 7th gen stacked or idled rigs. We will evaluate these opportunities on a case-by-case basis, ensuring that the financial return on results 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 a customer through monitoring fluid volumes to help detect flow anomalies.
Our KBOS 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 KBOS 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 the deployment across selected rigs across our global fleet.
In conclusion, our industry leading backlog provides us with the visibility to future cash flows that enables us to continue positioning Transocean for what we anticipate will be a sustained industry recovery.
I will now turn the call over to Mark. Mark?
Mark Mey
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 dayrate 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, clearly unrestricted cash and cash equivalents of approximately $110 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’re experiencing upward pressure on salaries and wages and increased pricing from our vendors. Fortunately, although the formulation differs 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 dayrate. In addition, we were notified by several vendors that certain 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 – that 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 of 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 dayrate for a period on the deepwater punters. For the full year 2022, we’re anticipating adjusted contract drilling revenue to be approximately $2.7 billion, also based off 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 the second quarter to be approximately $50 million and range between $180 million and $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 a 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 newbuild 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 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 newbuilds 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 6 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 de-lever 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
Thanks, Mark. Kevin, we’re now ready to take questions. [Operator Instructions]
Question-and-Answer Session
Operator
[Operator Instructions] The first question today comes from Ian Macherson of Piper Sandler.
Ian Macpherson
Thanks. Good morning, everyone.
Jeremy Thigpen
Good morning.
Ian Macpherson
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 year and the summer of ‘23 that could push some of these starts out. So curious how that influences your near-term contract exposure there, rigs like the Equinox, which I think Equinor might be finishing their troll 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 Thigpen
Thanks, Ian. I will turn that one over to Roddie as he has been neck deep in this conversation right now.
Roddie Mackenzie
Yes. Ian, thanks for the question. So looking at this, as we had mentioned before, there is now 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 comes from. 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 UK. So what you’ve seen recently in the UK 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 a new licensing round. So with the CAD [ph] 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 to existing wells to essentially increase production of gas in the near-term, and that’s what we think is going to play out here quite strongly between the UK.
And eventually, it will come to Norway. Norway being a bit more regulated, a bit more red tape involved in moving projects forward. So you could see that – although the rig has done well in finishing the project kind of ahead of time, we think there is pretty good prospects on the back end of that. There just might be a small gap in between. The really interesting thing about that market is the UK already has a couple of tenders that are out there just now 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 hot 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 chart. So really optimistic about Norway, even more optimistic about the changes that have just happened in the UK, but there will be a little bit soft market just in the near-term, so kind of like through the end of ‘22.
Ian Macpherson
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 startup 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
Yes. So I’ll turn that one over to Keelan, who is just freshly back from Singapore.
Keelan Adamson
Good morning. Ian, just returned from Singapore where we conducted the naming ceremony for the Deepwater Atlas. So she’s on schedule for delivery in Q2. And we expect her to be in the Gulf of Mexico and working by the end of the year. So no change there.
Ian Macpherson
Okay. And then just lastly, I was curious if the full year guidance contemplates some material contribution or if it’s more of a late Q4 start?
Mark Mey
Yes, yes, it’s Mark. It’s a late Q4 start. So there is nothing material contributed from the Atlas at this stage.
Ian Macpherson
Got it. Thanks everyone.
Operator
Our next question comes from Connor Lynagh of Morgan Stanley.
Connor Lynagh
Yes, 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. Like, 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 costs upfront? And how are you thinking about you potentially tapping the market further for equity?
Mark Mey
Yes. So thank you, Connor. Our priority 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 our – through our fleet either through our cold stacked assets or in other ways. And if we do that, as Jeremy mentioned in his prepared comments, the reactivation costs will be coming from the initial contract, in addition to a dayrate that’s sufficient to be able to return a fair amount of capital to our investors. We are also focused on other liability management opportunities. I won’t get into that at this stage. But clearly, there is a lot that we can do in a market that – a market backdrop that we currently have as a first of what we’ve been dealing with the last 7 years. So I’ll pause there and hand it back to you.
Connor Lynagh
Got it. That’s helpful context. Maybe just moving to the broader market, I think it’s very apparent that supply has been a major source of the tightness, better discipline from competitors out there and obviously, a lot of attrition in the fleet. I guess where – we got 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?
Roddie Mackenzie
Yes, I think I’ll take that one. Yes. So look, in the context of Russian 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 7 years are what drove the commodity prices up towards that $90, $100-barrel mark prior to all 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’ve got 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 is less tendering going on. There is 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 are out, they are expected to award an additional 16 potentially in the remainder ‘22.
So, if you think about it in that context, it seems like an unprecedented move. It seems like that is now going to be a huge pull on the active supply. And in fact, it’s 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, look, 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 3.5 years firm, but with 3 years, 4 years of options. So, that is going to be a tremendous draw on the global availability of ships.
Connor Lynagh
Interesting. Thank you for that. I will turn it back.
Operator
The next question comes from Taylor Zurcher of Tudor Pickering Holt.
Taylor Zurcher
Yes. Thanks Jeremy, Mark and Roddie. Roddie, I actually wanted to follow-up on some of the comments you just made there. So, you are talking about 16 more rigs or rig years maybe going down to Latin America, such Brazil. Jeremy, in the prepared remarks, you said at 20 opportunities with over 1 year of potential term in West Africa, so call it 15-rig years there. And 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 is all this incremental work truly incremental and going to need to be serviced by rigs that aren’t contracted today?
Roddie Mackenzie
Yes. Good question. So, the tenders that are out in Brazil prior to the ones that just came out this week, those were for rollover contracts. So, those are BS had [ph] 11, Libra, those kind 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’s – rigs that 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 have already seen, I think 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 have got several shorter term contracts, but there are a few that are long-term. Specifically, in India, you have 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 in 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. And that’s why we see a fully sold-out market on the near-term horizon.
Taylor Zurcher
Yes. Very encouraging. And good segue into my next question, which is rig reactivation. So, I mean you have got a number of cold-stacked rigs today. And actually, the higher spec rigs have been stacked for, call it, 5 years or 6 years now. So Jeremy, you talked in the prepared remarks about reactivation costs continuing to tick higher as industry wide, I think was your reference, as time continues to pass by. So, curious if you could refresh us as to what sort of cost it’s going to take Transocean to bring some of these rigs out of stack? Thank you.
Jeremy Thigpen
The cost?
Mark Mey
Yes. So, this is a moving target tail, as you can imagine. As an industry, we have never reactivated a cold-stacked rig 7th gen 6th gen cold-stacked rig with all the electronics that it has. So, we have been estimating this based upon an in-depth study by our engineering team. And our estimates for our rigs are in at $50 million to $75 million. We do believe that, that number could grow higher because this is based upon a 2021 estimate. Clearly, we see 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 in coming into certain markets like the U.S. Gulf of Mexico, where you have to have specific configurations on your BRPs.
Taylor Zurcher
Understood. Thanks Mark.
Jeremy Thigpen
Yes. The one thing I would 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, it’s been short-term projects and ever-increasing dayrates, it seems which is great. But ultimately, they are going to have to move to longer terms to secure the existing assets or they are going to wind up paying a pretty penny for reactivation of one of these assets, and they are going to have to wait potentially 12 months or more.
Taylor Zurcher
Right. It makes sense. Thanks.
Operator
Our next question comes from Greg Lewis of BTIG.
Greg Lewis
Hi. 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 things that’s happening right there is kind of – you might argue the lack of long-term work where you are seeing short-term spot work, which is enabling dayrates to 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 months, 12 months, 18 months, the majority of the work is spot, which is going to enable you to continue to push pricing higher?
Roddie Mackenzie
Yes. 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 are 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 have seen is that in each one of these discussions, which are typically not out to tender, they are 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 underinvestment 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 is 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 was ask for even more options. So, that’s happened on a couple of rigs for us. There is also a couple of things that we are looking at that we are asked for multiyear work, and it really is going to just pan out on a 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 are going to see further growth in terms of day rates, but we also think you are going to see a few fixtures that are multiyear in nature as the operators basically have a much better looking runway now with a sustained commodity price up at $100-plus.
Greg Lewis
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 could actually benefit from an improving market in Australia?
Roddie Mackenzie
Yes. Australia – I will take that one. I mean always been a kind of an 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 is 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 a moored rig and a DP rig. And also high-performing moored assets like our Deepwater Nautilus, rigs like that. In the past, we have also had several of the drillships in there. So, like our KG rigs as well. So, I think it’s – there is potential for a number of different classes of vessels to move into Australia. But Australia has 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 dayrates in Australia have become real solid. And in fact, I think you probably saw that in the last fixture that was up towards the 400 mark. I think you will see them well beyond that going forward.
Greg Lewis
Okay. Great. Thank you very much.
Operator
Our next question comes from Samantha Hoh of Evercore ISI.
Samantha Hoh
Hi guys. Thanks for taking my question. I know this might be unusual. But I have a question about your recent announcement about the investment that you made in Ocean Mineral. I have to submit that you guys – definitely on my radar before The Cook Islands. I just wonder if you could elaborate on the type 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 would be really appreciated?
Jeremy Thigpen
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, 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 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 to a potential business. But at this point, it’s very early days. So, don’t expect too much coming in the months or quarters.
Samantha Hoh
Okay, got it. Well, actually, then the other question, my follow-up was really with the CCS topic. You guys have sort of announced that you are drilling one of the wells in the side track toward the Northern Lights project. Could you – is that happening this year?
Roddie Mackenzie
Yes, that’s already underway. So, yes, I think you will see a few more of those there. But again, those are, as Jeremy alluded to, being part of the broader solution for energy that’s kind of one more facet of the business that we are very interested in because you use – our existing assets were largely unchanged to go do the CCS work.
Samantha Hoh
Okay. Excellent. Congrats guys.
Operator
And our next question comes from Karl Blunden of Goldman Sachs.
Karl Blunden
Hi, good morning. Thanks for the time. Really good to see the two new fixtures announced in the press release with – one with strong term, another with a really good dayrate and question was, is that the kind of backdrop that you are looking for 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?
Jeremy Thigpen
Sorry. Karl, could you ask the question again? I am sorry.
Karl Blunden
No problem. Two new fixtures announced positive backdrop and I think the comment last quarter was that with a stronger backdrop going to 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 positive market that you have described?
Mark Mey
Yes. So, thanks Karl. Our RCF is secured by the assets, the still value of the assets. Obviously, having contracts on those rigs improves 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 assets 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 are looking at an extension somewhere in that 2-year, maybe 2.5 year range. I think that’s good for us. It’s good for the banks because we do believe we are coming into a multiyear up cycle, which gives us a little more leverage down the road to be able to redo this and maybe at a larger amount or better terms.
Karl Blunden
That’s very helpful. One other theme that’s been coming through earnings season is just the inflationary pressures that many companies are seeing. Interested in what you are 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
Yes. 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 potentially against that dollar-by-dollar. So, over time, that does benefit us. And then obviously, with the new contracts, as Roddie and his team are negotiating with them, we know what the cost structure is and we can incorporate those increases into the dayrate. And because this is an increasing dayrate environment, you can make the argument that margins are expanding and therefore, softening any impact from inflation that we are seeing. I don’t think it’s peaking. I do think we are in for a bit of a ride and maybe another 12 months of increasing inflation, but we are well positioned to take care of that.
Karl Blunden
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
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
Ladies and gentlemen, that now concludes today’s conference call. We thank you for your participation. You may now disconnect.
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