Good morning, and welcome to Transocean’s third quarter 2021 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, President and Chief Executive Officer; Mark Mey, Executive Vice President and Chief Financial Officer; Keelan Adamson, Executive Vice President and Chief Operations Officer; and Roddie Mackenzie, Senior Vice President of Marketing, Innovation and Industry Relations. 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 on this call, please limit yourself to one initial question and one follow-up. Thank you very much. I’ll now turn the call over to Jeremy.

Thank you, Alison, and welcome to our employees, customers, investors and analysts participating in today’s call. As reported in yesterday’s earnings release, for the third quarter, Transocean delivered adjusted EBITDA of $245 million, on $683 million in adjusted revenue, resulting in an adjusted EBITDA margin of over 36%. Additionally, our quarterly free cash flow of $104 million represents the sixth straight quarter of positive cash generation. During the quarter, we matched a company-best revenue efficiency of 98% for the second consecutive quarter. And we have maintained a revenue efficiency of 97% or higher for six sequential quarters due to our consistently safe, reliable, and efficient operations across our operating fleet. Indeed, it was a true team effort globally. Supported in addition to other transition initiatives by our smart equipment analytics system, which helps us monitor critical pieces of equipment and systems to identify anomalies and signs of degradation such that we can prevent and potentially predict unplanned failures and resulting downtime. The same system allows us to track and trend fuel burn, energy consumption, and emissions in real-time, helping to optimize energy efficiency in our operations, providing us a powerful tool and delivering our 2030 goal of a 40% reduction in our greenhouse gas emission intensity versus 2019. Now turning to our fleet. Starting in the Gulf of Mexico, in August, we announced the $252 million two-phase contract we signed with Beacon Offshore Energy for the Deepwater Atlas. Following the final investment decision of Beacon and the Shenandoah working interest owners to sanction the previously announced project in the U.S. Gulf of Mexico. The Atlas, which is nearing completion at the Jurong Shipyard, will be one of two, eight generation 20,000 psi ultra-deepwater drill ships in the transition fleet. In addition to the 20,000 psi well-controlled equipment, the Atlas and the Deepwater Titan also incorporate other state-of-the-art technology and features, including a growth hoisting capacity of 3.4 million pounds efficient completion setup with dedicated well test and offloading areas and a hybrid power drill floor that flattens peak loads on the engines and reduces fuel consumption. Staying in the Gulf, I’m pleased to share that Chevron has exercised the two $335,000 per day options we announced on our last earnings call for the Deepwater Conqueror, bringing the firm duration to three wells. The additional term will commence in direct continuation of the current contract. And in total, the three wells contribute over $100 million of backlog. These premium rate options reinforce our belief that our customers continue to acknowledge the tightening of the market for readily available high specification ultra-deepwater assets, as well as the recognition of Transocean's ability to consistently deliver safe, reliable, and efficient operations. Also in the Gulf, we signed a one-well extension with BHP on the Deepwater Invictus. The extension is expected to be in direct continuation of the prior well and carries a day rate of $295,000 per day. The rig is now expected to remain on contract through June of 2022. And finally, rounding out the Gulf, based upon our knowledge of the responses to several recent tenders, we expect awards to be made in the near future at day rates of approximately $300,000 per day, reflecting the increasing tightening of this market. Heading down to Trinidad, following a successful find in the Calypso appraisal well Bonga-3 drilled by the DD3, BHP exercised the one-well option at a day rate of $220,000 per day to complete the appraisal. She is now expected to remain on contract through November. We remain encouraged about the future prospects for this ultra-deepwater semi-submersible and are actively bidding the rig for multiple opportunities in various regions across the globe following the conclusion of operations in Trinidad. Jumping over to the Asia-Pacific region, the Deepwater Nautilus had a one-well option exercised by POSCO. The option will keep the rig active through December before she begins mobilization to the commencement of her next campaign in February 2022. And finally, the KG2 has begun contract preparations for her one-well campaign in Brunei with Shell. Looking forward, based upon conversations with our customers and supported by increasing utilization and day rates, we are growing increasingly confident that the recovery is now gradually accelerating for ultra-deepwater and harsh environment markets. Oil prices remain highly supportive as Brent crude has remained in the low to mid $80 per barrel range since the beginning of last month. Moving forward, we expect this trend will continue largely as a result of significant and prolonged underinvestment in traditional sources of energy. Moreover, OPEC+ recently announced its intent to maintain its gradual production plan. And the U.S. Department of Energy has decided to leave the strategic petroleum reserve untapped. Both of these decisions support a continued supply deficit outlook heading into the end of the year and possibly beyond. At the same time, we continue to see a tightening of the offshore market unfolding across multiple regions. Market utilization of the global floating rig fleet is nearing 80% to 85%, which has historically been the inflection point at which material increases in day rates are triggered. Notably, active utilization in the Golden Triangle, which consists of the U.S. Gulf of Mexico, South America and Africa, currently sits in the 90% range. In a few moments, I’ll provide more specifics surrounding the outlooks for each of these regions. Globally, offshore rig count contract awards have been on the rise for four consecutive quarters and are beginning to exceed levels seen before the pandemic. Average tender duration increased in the third quarter with a particular uptick in the length of option periods. This reinforces our belief that our customers see the signs of a rising market and are recognizing the importance of securing the highest specification asset for longer periods of time. Project sanctioning has also recovered to near pre-pandemic levels and is projected to reach 129 FIDs in 2022, a significant increase from 2019. Indeed, all the signs point toward a positive outlook for our sector. Taking a closer look around the global market environment, starting in the U.S. Gulf of Mexico, we continue to see high utilization of active floaters with the current active fleet essentially at full utilization. Some of this contracted activity is shorter-term, but we expect that, if the trend continues, the regional fleet will be fully utilized by year-end 2022. In the near term, with the majority of active floaters booked, we have recently encountered several time-sensitive pop-up requirements for operators unable to complete their work due to a shortage of capable and available rigs. While we have yet to see a large volume of long-term requirements in the region, we firmly believe that these are on the horizon. Third-party intelligence organizations also see tightening utilization and increasing demand, with one organization recently predicting a 66% increase in demand growth by 2023. In recent months, multiple IOCs have specified the Gulf as a key region for their businesses and critical to meeting their ESG goals through lower carbon intensity metrics and more attractive economics that help fund their ESG projects. Specifically, one IOC noted the carbon intensity in the Gulf of Mexico at approximately 7 kilograms of CO2 per barrel, as compared to a global average in the high 50s or low 60s. While another IOC indicated break-even prices for its Gulf assets to be as low as $30 per barrel. The combination of these two metrics make the Gulf of Mexico a logical choice for future investment by our customers in exploration and development. Staying in the U.S. Gulf of Mexico, we look forward to the deliveries of our two eighth-generation new build drill ships, the Deepwater Atlas and the Deepwater Titan, both expected to commence their projects with Beacon Offshore Energy and Chevron, respectively. The outlook for these rigs and the 20K market remains very positive. In addition to the potential for follow-on work with Beacon, following the initial firm term on the Atlas, the 20K landscape extends to prospective opportunities with Shell, Equinor, BP and incremental 20K prospects with Chevron as well. We’re encouraged that the commencement of the first 20K projects will serve as a catalyst to green light future prospects, as significant cost barriers have been eliminated with the introduction of the technology required to safely drill and complete these high-pressure wells. Looking to Brazil, we’ve seen 10 rig years awarded by Petrobras in 2021 for commencement in the next 18 months. And we anticipate this trend will continue. With an ambitious national goal to become the fifth largest exporter in the world, Brazil needs to double production by 2030. Accordingly, demand growth for offshore rigs is projected to remain strong. Approvals of 16 FIDs are anticipated between 2021 and 2022 and known requirements support the addition of one to two incremental rigs per year through the end of the decade. While Petrobras continues to dominate near-term commencements, multiple IOCs also have requirements over the next several years. In fact, one IOC has an ongoing tender with an anticipated total duration nearly two years expected to commence in late 2022. We believe we are well positioned to capitalize on these opportunities given our strong, long-term presence and record of performance in the region, as evidenced by the fact that we recently advanced to the number two overall position in Petrobras’ performance based on top of this rankings, a true testament to the teamwork across our three rigs operating in Brazil. Moving over to Norway, we expect a relative bounce in the market through 2022. However, based on customer conversations and third-party reports, projected demand in 2023 could surge to 25 floating assets, which would outstrip the current marketable supply. As we discussed on prior calls, the favorable tax incentives passed in 2020 have helped foster an attractive environment for our customers to progress their operations and are available to project sanctioned by December 2022. It follows that we will see an uptick in requirements during this time period. Moreover, similar to the U.S. Gulf of Mexico, Norway has also been cited by our customers as having relatively low carbon intensity reservoirs. Therefore, making it a more attractive area for investment in their respective portfolios. Recently contracted day rates continue to hover around $300,000 per day before performance bonuses and are projected to climb as we begin to approach the rebalancing of the market. As much of the Norwegian fleet is booked well into 2022, we are growing increasingly confident that projections will continue to track as expected. Nearby in the UK, the outlook remains positive, and we are actively engaged in a number of discussions for opportunities commencing in 2022, both through tenders and through direct negotiations. A dozen programs are expected to commence in the region over the next 18 months. If this happens, the available active fleet in the UK is insufficient to meet the expected demand. And it’s likely the market will remain undersupplied as the cost of reactivating cold-stacked rigs is still prohibitive in the current price environment. Consequently, we may see one or more rigs, potentially rigs within the Transocean fleet, depart the Norwegian continental shelf for work in the UK. In West Africa, we’re seeing a number of opportunities emerge for both short and long-term work from various IOCs. Previous prohibitive fiscal policy in certain African countries has improved and there is a large push for government investment. At the beginning of the pandemic, several locations such as Angola experienced significant challenges from the effects of COVID. In Q2 2020, the offshore rig count in the country went to zero as contracts were either suspended or terminated. Looking forward to 2022, we anticipate the Angolan rig count to be north of seven rigs, while Ghana and Nigeria have similar outlooks. Ongoing tenders, including the long-term Exxon and TotalEnergies prospects in Angola are set to add over four rig years for firm work commencing in 2022. More broadly, regional utilization has doubled from this time last year and is projected to increase again by year-end. Indeed, the region is expected to experience some of the highest growth globally over the next three years, and we believe we are well placed to benefit from incremental demand given our longstanding presence in the region. In the Asia-Pacific region, which includes Australia, we see numerous short- and long-term tenders for work set to commence over the next 18 months. The steady flow of opportunities in the region is encouraging, and we are actively responding to several inquiries. To summarize, we believe that the industry recovery is solidly underway. We are encouraged by the sustained improvement in the macro environment as it affects our industry, specifically offshore drilling. Our view is supported by ongoing conversations with our customers and backed by third-party market outlooks. Many of our competitors have emerged from restructuring in the past year, with another anticipated to emerge from its second filing around the end of the year. Additionally, the first major transaction between two of these parties, Noble and Pacific Drilling, closed earlier this year, driving much-needed consolidation in our space. We believe that further consolidation is required. And we also believe that these actions will assist in encouraging disciplined bidding behavior that helps drive the day rates needed to support our industry and its investors. This includes incremental retirement of cold-stacked assets, contracting practices that support value creation and financial justification to reactivate idle rigs. Recent behavior suggests the obligation to return value to shareholders is a growing importance across our peer group, and we’re encouraged by the developing trend. Transocean has remained committed to all its stakeholders throughout this challenging cycle, including from a financial perspective. On numerous occasions, we have seized opportunities to reduce our debt and extend our liquidity runway. Since 2016, we have completed $9.8 billion of liability management transactions, including the repurchase of $1.7 billion of debt. We will continue to look for and take advantage of opportunistic situations to further improve our capital structure as they arise. In conclusion, Transocean has taken deliberate action throughout the downturn to position ourselves as the industry leader in offshore drilling. We have assembled the highest specification floating fleet in the industry while simultaneously preserving shareholder value. Our 27 ultra-deepwater floaters, soon to be 29, and 10 harsh environment floaters comprise the most technically capable fleet in the industry, positioning us well to capitalize as the market improves. Our industry-leading high-quality $7.1 billion backlog provides us with visibility to future cash flows, enabling us to continue to invest in the training of our employees, the proper maintenance of our assets, and new and differentiating technologies and initiatives that will enable us to deliver even safer, more reliable, and more efficient services to our customers, while simultaneously helping us to deliver our 2030 emissions goals. Needless to say, we are very encouraged by what we are observing in the market and we’ll continue to prioritize delivering the results required to drive value for the company and shareholders.

Thank you, Jeremy. And good day to all. During today’s call, I will briefly recap our third quarter results and provide guidance for the fourth quarter and conclude with preliminary expectations for 2022, including our latest liquidity forecast. As is our practice, we provide more specific 2022 guidance during our 2021 year-end call in February. As disclosed in our press release for the third quarter of 2021, we reported a net loss attributable to controlling interest of $130 million, or $0.20 per diluted share. Highlights for the third quarter include adjusted EBITDA of $245 million, reflecting robust fleet-wide efficiency contributing to another quarter of healthy 36% EBITDA margin. Fleet-wide revenue efficiency exceeded 98% again this quarter, reflecting continued operational excellence and the conversion of drilling contract bonus opportunities into revenues. And we generated approximately $141 million in operating cash flow. Additionally, we raised approximately $75 million during the third quarter, with another $17 million in early October from the opportunistic sale of our equity using our ATM program. As reflected in our Form 10-Q, this brings our total equity proceeds under the program in 2021 to approximately $158 million, evidencing our continuous efforts to improve liquidity. Looking closely at our results, as Jeremy mentioned, during the third quarter, we delivered adjusted contract drilling revenues of $683 million and an average day rate of $367,000, reflecting strong conversion of contractual backlog mentioned above. Operating and maintenance expense in the third quarter was $398 million and is favorable relative to our guidance, resulting from lower overtime costs due to optimizing our use of labor pools and a decrease in COVID-related personnel expenses. We also had lower project costs as the Deepwater Mykonos and Transocean Enabler projects were completed ahead of schedule. We also postponed some in-service maintenance expenses into the fourth quarter due to the timing of activities we performed on the rigs. We ended the third quarter with total liquidity of approximately $2.7 billion, including unrestricted cash and cash equivalents of approximately $900 million, approximately $365 million of restricted cash for debt service, and $1.3 billion from our undrawn revolving credit facility. I will now provide an update on our expectations for the fourth quarter. We currently expect to generate adjusted contract drilling revenue of approximately $670 million. Based upon an average fleet-wide revenue efficiency of 96.5%, a slight quarter-over-quarter decrease in revenue is attributable to a lower day rate on the Deepwater Skyros, which is starting a new option, and low activity on the Transocean Barents. We expect O&M expense to be approximately $403 million. The sequential increase is attributable to the timing of anticipated maintenance spend across the fleet and KG2’s return to operation in the quarter. We expect G&A expense for the fourth quarter to be approximately $46 million, slightly above our third quarter due to incremental consulting fees and IT expenditures. Net interest expense for the fourth quarter is forecast to be approximately $104 million. This includes capitalized interest of approximately $15 million. Capital expenditures for the fourth quarter, including capitalized interest are forecast to be approximately $96 million. This includes approximately $78 million for our new build drill ships under construction and $18 million of maintenance CapEx. Cash taxes are expected to be approximately $10 million for the fourth quarter. Now, I’d like to provide a preliminary overview of our financial expectations for 2022. We currently forecast adjusted contract drilling revenue to be between $2.6 billion and $2.8 billion. Furthermore, we believe our full-year 2022 operations and maintenance expense will be between $1.6 billion and $1.8 billion. Finally, we expect G&A costs to be between $175 million and $185 million. Our liquidity as of December 31, 2022, is forecast to be between $1.8 billion and $2 billion, including restricted cash for debt service of approximately $300 million and the potential securitization of the Deepwater Titan. This liquidity forecast includes an estimated remaining 2021 CapEx of $96 million and 2022 cap expectations of $1.3 billion. As always, our guidance excludes any speculative cold-stacked rig reactivations or upgrades. In conclusion, as Jeremy mentioned, we are observing incremental improvement in demand for high specification, ultra-deepwater and harsh environment floaters. We believe this trend will continue supported by the strength in oil prices. While we are encouraged by the progression of utilization and day rates, we will remain highly disciplined in our criteria for expenditures. We will assess cold-stacked assets on a case-by-case basis and will not reactivate a rig unless another contract provides an adequate return. We will also remain diligently managing costs associated with preparing a warm-stacked rig for its contract. As we have demonstrated, we will continue to focus on enhancing our liquidity and proactively managing our balance sheet, taking advantage of capital markets to improve liquidity and reduce our debt. Accordingly, we will work closely to examine our capital expenditure requirements and avenues to reduce our costs while maintaining a high level of operational integrity and a focus on safety. This concludes my prepared comments. I’ll now turn it back to Alison.

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

Thank you. We will take the first question from Greg Lewis from BTIG. Please go ahead.

Yes. Hey, thank you, and good morning, everybody. Jeremy, just kind of trying to parcel through some of your prepared comments, it seems like you laid out the details, the market is definitely getting – going in the right direction. As you think about 2022, I’m trying to understand, do we kind of view that more as a little bit more of another transition year or it almost sounds like we’re going to start to see incremental day rate growth and pricing get going here, maybe as rigs start to get fixed in the back half of 2022. Is that kind of the right way to think about it and just in piggyback…

Did you want to finish up there? Sorry. I thought you were done with the question.

Yes. No, I was going to say, and then just in thinking about that, tying that in Mark’s comments about not reactivating a rig without some term work. There have been – we have started to see some multi-year contracts being fixed. Hey, maybe the rates aren’t – those leading edge spot rates you’re referring to, but nevertheless, some attractive EBITDA being generated. Is that kind of – is that how we should be thinking about how 2022 unfolds where we’re going to have some opportunities to fix some multi-year rigs on contracts?

Yes, I think that is the right way to think about it. And I’ll turn it over to Roddie here in just a second, but I will say that I think the roadmap that you’ve laid out feels about right. Contracting activity will continue to pick up as we exit this year and enter next for work that will commence around the back half of 2022 and then into 2023. And as long as we all recognize the high utilization for high spec assets in these various markets and that will then go up. I think we’ll start to see longer terms, and we’re starting to have those conversations with customers now. Just a little anecdote before I hand it over to Roddie, it’s been interesting that many of our customers have approached us with direct negotiations as opposed to putting things out for tender and they’ve also approached us to revisit our business model and look at something that’s more of a partnering approach that can survive upturns and downturns. And so I think it’s a good sign that everybody sees the market recovering in the space and that the availability of really high spec assets that are currently marketable is limited. And so with that, I’ll hand it over to Roddie for some more comments.

Yes. Greg, I think I would attack this kind of on a regional basis. So as to how you should think about 2022, it depends on where you are. You will see this – as you say, this kind of transition year that we start to plug a few gaps on the white space lines and get closer and closer to that 100% utilization of the marketed assets. Certainly, in places like Norway harsh environment, you have a few gaps in 2022 – exiting 2022 and going into 2023 starts to look a bit better, 2023 summer is really, really strong 2024 and beyond as many high spec assets as they’ve ever had in projected utilization. So I think you will see this kind of transition where term starts to increase. We’ve seen that in the numbers so far that this quarter is yet another uptake, not only in the number of awards, but the duration of the awards, the number of programs available and the number of rig years that are out to tender at the moment. So all of those metrics are pointing in the right direction. And as Jeremy had mentioned in his comments, we’re seeing that translate directly into increased day rates. So especially in the U.S. Gulf of Mexico, which seems to be the hottest segment at the moment, we’ve seen those rates push up to the 300 mark. If a one customer told us the other day that it’s going to be a case of musical chairs and somebody is going to find themselves with that rig. So I think when you view that kind of sentiment, then there’s certainly a lot of optimism about the value of the rigs in terms of getting what you need. And I think the other really big one just now we’d have to describe as Brazil. As we mentioned, there’s about 27 years of work have already been awarded this year for the floater market in Brazil. As we look at the project approvals that are to be sanctioned in 2022, 2023 and 2024, those combined three years will sanction somewhere in the region of 28 to 30 projects, so the follow-on effect on the rig count is going to be substantial. So I think that’s just increase utilization and then not locking in for long-term at the low rates, but really trying to split that strategy between a bit of backlog and the ability to earn some really solid EBITDA numbers. Yes. And just to kind touch on the reactivation piece, our customers know that they’re going to have to pay for that either through large one-time mobilization fees and/or through higher day rates and longer terms that would justify the significant investment it’s going to take for all drilling contractors to reactivate these assets that have been stacked for quite some time.

Okay, great. And then just wanted to follow up a little bit on Brazil. I mean, clearly, Petrobras has been active, but as we try to parcel out the multiple projects that are going on in Brazil. Without getting into specifics, is there any kind of way to think about how much of that is Petrobras and how much of that is also IOCs, because – and correct me if I’m wrong, but I kind of get the sense that it’s going to be the IOCs driving price in Brazil, maybe not Petrobras, who tends to always be able to get a discounted rate?

Yes. So that’s really interesting. So Petrobras has obviously seen what’s coming. They move very quickly. They – despite the relative bureaucracy in Petrobras for awarding contracts, they’ve been prolific in the contracts that they’ve awarded this year. They have taken the lion’s share for sure. And what’s really interesting in the charts that we show in terms of those project approvals, the past couple of years have all been Petrobras, but moving forward, it’s kind of an even split between the IOCs and Petrobras. In fact, next year, I think, eight or nine of the expected project approvals for sanctioning are non-Petrobras. So Petrobras is still very active. And as we’ve described before, they’re kind of turning over the rig fleet renewing them as they come available. That incremental demand is really being pushed by the IOCs, which is over and above what Petrobras is doing. So yes, I’d say it’s kind of like a 50-50 split going forwards on IOCs versus Petrobras awards.

Okay, perfect. Thank you all for the time.

We’ll now take the next question from Connor Lynagh from Morgan Stanley.

Yes. Thanks. Wanted to ask about the topic of the day, which is inflation. Just curious what you guys are seeing in terms of labor availability, any needs to raise your wages either on the rig or more shore-based costs. Just broadly speaking, how are you thinking about that?

It’s actually a timely question and also a good question. I mean, the market is improving. So that’s good. Yes, we are seeing a bit of wage inflation. We’re bringing two new builds onto the market next year. And so finding crews after seven years of a pretty desperate market where we’ve lost a lot of people in the industry to other industries has made finding the right talent and getting them back and trained to the standard that Transocean is accustomed to one of our chief concerns. There’s no doubt about it. I would like to ask Keelan, since he’s sitting here and he’s living this each and every day, to talk a little bit about what we’re seeing out there.

Yes. Thanks, Jeremy. And Connor, I would say similar to the last answer from Roddie in the market, it is regionally based at the moment. The cost structure, the way the pressure on labor we’re seeing in the Gulf of Mexico, in certain positions offshore, there are other opportunities for those people to work outside of our sector even. And so with the increase in reactivations and new builds coming in, and the general increase in activity in the Gulf of Mexico, we’re definitely seeing some wage pressure there. I think also on the supply chain side for running our rigs, we’re starting to see some cost inflation from our suppliers in that area as well.

Got it. And it – I mean, from the sound of it is, and sounds like you think you have the ability to pass on most of this cost increase, yes?

Yes, yes. We will do that, Connor.

Okay.

Yes, Connor. I was just going to say, several of our contracts have adjustments in them for lagging changes in the environment to do with labor, but also the cost of equipment general oil field service costs. So we have several of the major contracts that we have potentially the longer-term ones have those adjustments built into them. So it’s a means for us to protect that EBITDA margin.

Got it, got it. Just sort of an unrelated follow-up here. Just thinking through you’ve seen more cold-stacked reactivations. I’ve also been interested to see some of the bareboat charter arrangements that some of your competitors have been executing with yards. I mean, how do you think about that altering the balance in the market and does a bareboat charter rig compete favorably with the cold stack rig? Just how do you think about that influencing market dynamics here?

Yes. I think so what we see now is with a lot of the restructured drillers not having a tremendous amount of cash on hand, the true cost of reactivating the rigs has to be taken into account. So certainly in terms of what it costs to bring the rigs out, it’s not cheap. I mean, there are substantial equipment costs associated with overhauls, but there’s also the OPEX associated with rig crews and ramping up and going through your data procedures to bring the rig to market and mobilize it. So look at me, we’ve seen the operators paying for a lot of those things in terms of being competitive. So there’s no reason why a cold-stacked asset can’t perform well, but it’s been the industry’s experience that the hot assets perform far better. Now the call that pulls those assets can eventually get up to that level of performance, but there are always some teething issues bringing them out. So there’s a very strong preference at the moment for securing rigs that are hot and active. We expect that’s going to continue, but certainly as we get to that sold-out realization on the active fleet, there’s going to be no other choice but to bring out more cold-stacked assets. But of course, we believe the economics of the jobs are going to support that decision. So we cautiously look forward to getting to that point of being at 100% utilization for the hot rigs.

All right, thanks. I’ll turn it back.

We’ll now take the next question from Taylor Zurcher from Tudor, Pickering, Holt.

Hey, thanks, and good morning, guys. Jeremy, I just wanted to follow up on one of your earlier responses in Q&A. You talked about more customer direct negotiations but also more customers looking to revisit a partnership approach with you. And I just – I’m curious what you mean by a partnership approach to me maybe some longer-term contracts, which helps smooth out the cycles for you, at least at the rig level, but just curious what you’re seeing in here when it comes to different business models that your customers are open to.

Yes. I think it varies by customer. I think the primary message is they see value in keeping continuity. It definitely improves operations from a safety, reliability and efficiency standpoint. I think some of them are recognizing that. And so instead of going out to tender to every drilling contractor and service provider on the planet, they’re looking to narrow it down to a couple that are qualified and work closely with them to more safely, reliably and efficiently deliver wells. I think there’s also an element of it around making sure day rates don’t get too high and coming up with a model where we’re both the drilling provider and service provider and an operator can all benefit in the ups and downs of the cycle and continue to thrive. But it’s interesting. We didn’t really have these conversations on the way down. Yes, yes. I think it really is about efficiency, right. So clearly, if we are able to deliver a superior service, then with the commodity prices where they are, and many of the big guys having very solid returns at the moment increasing dividends, kind of stands to reason that there’s enough in the system for all of us to do well. So it’s our focusing on making sure we get those win-wins. And I said that kind of tongue-in-cheek, but it is encouraging to see a different approach where it is more of a partnering relationship where they recognize that continuity is important. And so that’s encouraging for us, and it’s also a sign that we think they see the market improving and want to make sure that they’re well-positioned for it in terms of not only having the highest spec assets but also working with the best providers.

Yes. Understood. Good to hear. And my follow-up on the UK, this is the second straight quarter. You’ve talked pretty positively about the outlook in the UK 2022 and beyond, and potentially pulling some rigs from Norway to satisfy that demand. When I look at your fleet, I mean most of your rigs in Norway are pretty well contracted, and particularly the stronger rigs. And I’m just curious the way you see it right now, which rigs in your fleet are most likely to service that demand that you do have a couple that have some holes in 2022, which probably be well-suited for that work. But when it comes to shifts and rigs from Norway to the UK, I was hoping you could just provide a little bit more color on which rigs we should be thinking about there.

Yes, I’ll take that one. So when we’ve got – if you look at the UK, the struggle in the UK is actually equipment. So long leads on wellheads and casings and various other bits and pieces are stalling them at the moment. The demand or the optimism about going ahead with projects is certainly there. It’s just that’s why it’s not here right now. They basically can’t pull the trigger on it at the moment, because they don’t have the site to the equipment that they need to complete the wells. So that’s kind of what’s driving this uptake and it happens to be coincidental with the uptake this predicted to Norway. And a lot of the uptake in Norway is off the back of the tax incentive schemes that were put in place last year and are now reaching the point of fruition where those include putting rigs to work and developing these assets. So from that point of view, we expect that there’s going to be pretty high demand for the rigs in Norway, especially the higher specification, which is the choice certainly for Equinor and some of the other bigger operators. But in the meantime, as you point out, there are a few gaps here and there. So I think you could see us look at some of the rigs that have gaps as potential candidates for going to the UK. We did this in the past with the likes of the Spitsbergen and a couple of other older assets. But it’ll be interesting to see which segment moves the quickest, because they’re going to be the ones that pick up the best rigs.

Got it. Thanks for the answers.

As there are no further questions, I would like to hand the call back over to Alison for closing remarks.

Thank you, Marianne, and thank you, everyone for your participation on today’s call. If you have further questions, please feel free to contact me. We look forward to talking with you again when we report our fourth quarter 2021 results. Have a good day.

Thank you. That will conclude this conference call. Thank you for your participation, ladies and gentlemen. You may now disconnect.