Ladies and gentlemen, good day and welcome to the third quarter 2020 Transocean earnings conference call. Today’s conference is being recorded. At this time, I would like to turn the conference over to Mr. Lexington May, Manager of Investor Relations. Please go ahead, sir.

Thank you David. Good morning and welcome to Transocean’s third quarter 2020 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, 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 the current expectations and certain assumptions and are therefore subject to certain risks and uncertainties. Many factors could cause actual results to differ materially. Please refer to our SEC filings for more information regarding our forward-looking statements, including the 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. 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 Lex, and welcome to our employees, customers, investors and analysts participating in today’s call. As we have since March, we continue to work remotely to do our part to prevent the spread of COVID-19, therefore please forgive any challenges associated with maintaining audio quality during this call. As reported in yesterday’s earnings release for the third quarter, Transocean delivered adjusted EBITDA margin of almost 41% with $338 million in adjusted EBITDA on $830 million in adjusted revenue. Importantly, this strong operating performance which was driven by our experienced and committed teams enabled us to generate $81 million in operating cash flow. Despite a number of challenges, including a global pandemic and an extremely active storm season in the Gulf of Mexico, we continued to deliver safe, reliable and efficient operations for our customers around the world. During the third quarter, we had 26 active rigs across 10 countries. To put just some of our pandemic related challenges in perspective, I will share with you that before a crew change, 14 of our rigs require crew members to enter a secured quarantine period ranging from five to 14 days, depending on customer protocols and country regulations, and they must also have a negative COVID-19 test before joining the rig. In addition the delays associated with quarantines and testing, to reduce overall exposure we have asked more than 2,500 of our crew members to serve extended hitches, meaning even more time away from home, family and friends. In addition to the quarantine period and extended hitches, while onboard our rigs our crews are subjected to daily temperature checks and are required to wear face coverings and practice certain social distancing protocols when possible. Needless to say, these are suboptimal operating conditions, yet our crews persevere with absolute resolve. Their sacrifice…

Thank you Jeremy, and good day to all. During today’s call, I will briefly recap our third quarter results, provide guidance for the fourth quarter, and provide preliminary estimates on our financial expectations for 2021. Lastly, I will provide an update on our liquidity forecast through 2022. As reported in our press release for the third quarter of 2020, we reported net income attributable to controlling interests of $359 million or $0.51 per diluted share. After adjusting for several items associated with the retirement and restructuring of our debt and discrete tax items and unfavorable items associated with the loss on disposal of assets and liability management costs, we reported an adjusted net loss of $59 million or $0.11 per diluted share. Further details are included in our press release. Highlights for our third quarter include adjusted EBITDA of $338 million, reflecting strong fleet-wide revenue efficiency coupled with robust performance bonuses, fleet-wide revenue efficiency exceeding 96% reflecting our operational excellence and strong backlog conversion, $81 million in operating cash flow. Looking closer at our results during the third quarter, we delivered adjusted contract drilling revenues of $773 million driven primarily by strong revenue efficiency and $10 million performance bonuses across the fleet, as well as a short extension of the Transocean Barents drilling contract. Operating and maintenance expense in the third quarter was $470 million. This is better than our guidance and due to the timing of in-service maintenance and lower than expected costs associated with COVID-19. During the quarter, we recognized approximately $14 million of COVID related expenses, of which approximately half are reimbursable by our customers. Turning to the cash flow and balance sheet, we ended the third quarter with total liquidity of approximately $2.9 billion, including unrestricted cash and cash equivalents of approximately $1.4 billion, approximately $200…

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

[Operator instructions] Our first question comes from Connor Lynagh with Morgan Stanley.

Yes, thanks. I wanted to focus on the back half of ’21 opportunities you were discussing. I appreciate the commentary around that. I guess what we’re trying to figure out is what do you think the customer sensitivity to oil prices is these days, and how would you think about--if oil prices remain broadly where they are today or move up $5 to $10, how would you think about the relative sensitivity of those opportunities?

Hey Connor, this is Jeremy. I’ll let Roddie chime in. From our perspective, there’s still so much uncertainty in the world - you know, when do we find a real solve, if you will, for COVID, and what does that do to global economies and when does that take place, and then how does that impact oil prices certainly. As we saw in 2019, we had a relatively stable oil price that bounced around $60 a barrel for quite a period of time, and that’s really where we started to see these offshore projects pick up with some earnest, so I think right now our customers are growing increasingly encouraged that oil prices have moved up from their bottoms, have stabilized a bit, and that if we can get through the election and determine what the landscape is going to look like there and then start to find, whether it’s a vaccine or whatever solve for COVID, I think that that gives them even more confidence. If you can get oil prices up closer to $50 a barrel, I think we start to see quite a bit more activity. Roddie, I don’t know if you want to add to that?

Yes, just add to the fact that if we do go up another $10 or $15, that will really make a huge difference because I think as you mentioned this before, our customers have spent a tremendous amount of time retooling their wells, simplifying their designs to make them more and more profitable at round about that $50 mark, so I think if we can see something sustained at around the $50 mark, then that’s going to bode very, very well for offshore drilling, where our competitiveness has relatively increased substantially over the past few years.

Yes, makes sense. If you could speak in broad terms - I know you don’t want to give away too much for competitive reasons, but these opportunities that you’re starting to see, how should we think about--and certainly I think you alluded to this on the harsh environment side of things, but on the benign environment rigs, where do you see contract durations, rates trending? It certainly seems like things have been holding up a bit better relative to the prior downturn, but just any broad comments around that would be helpful.

Yes, that’s a really interesting point. We were actually going to make that point, that if you compare to where we were before in the previous blip, day rates, as Jeremy had alluded to, had been down pretty low in the mid 100s, but now we’re seeing that the bottom end of this is clearly not there. I think some of the lowest rates we’re really seeing are the 180 to 190 mark. While we are certainly not there, some folks are, but there seems to be--you know, just the economic reality of delivering the service is kicking in. I think we also expect to see that with the number of tenders that are coming out in place like Brazil, a lot of awards being made in other parts of Latin America, the day rate seem to be less of a spread and everything seems to be moving up a bit. You may see some near term competitive stuff, but we think because a lot of these tenders are now multi-year, in fact there’s probably at least half a dozen multi-year tenders out there just now, we think that is going to have folks bidding above 200 and those are--they’re looking at four and five-year terms of well above 200. They’re going to be closer to 300. So it remains to be seen whether the operators move on those right now, but certainly we’re optimistic about that because we certainly haven’t seen the depth of day rate drop that we did last time around, so clearly economics are better this go round.

Yes, just to sneak one more in here, what do you attribute that change in behavior to? Is it less optimism, less logic of well, I just maintain the customer now and I’ll monetize later? Is it more financial constraints? Basically what I’m trying to figure out here is if your competitors do emerge with cleaner balance sheets, probably not a ton of liquidity but maybe more than they’re working with today, does that derail this discipline or do you think it’s more sustainable than that?

I don’t believe it does. I think it could in the short term if you’re looking at individual rigs that are rolling off contract and they’re just looking for a near term filler opportunity. You might see a little more competitive play to try to just position that rig for a short duration, but as we said in the prepared remarks and we’re starting to see play out, we’re starting to see more rigs cold stacked more quickly, more rigs scrapped, and so the real active marketable fleet is shrinking and so if you want to get into one of these long term arrangements and it’s going to require a rig reactivation, like you said, their liquidity will be improved but you’re looking at a $50 million-plus ticket to reactivate an asset. You can’t do that at today’s day rates - you have to go much higher or you have to get compensated on the front end from the operator. Go ahead, Roddie?

Yes, I was going to add to that, that there’s been a few mistakes made in the past. You’ve seen folks do the reactivation and mobilization speculatively and it just didn’t work out, so I think there’s a lot of hard lessons being learned and I also think there’s going to be a tremendous expectation to create some form of earnings from these contracts. As Jeremy said, reactivation costs are going to curtail that dip in the rates again, but more interesting than that, the relative utilization of high spec assets is only going to get better. As the opportunities have dropped in the latest COVID dip, so has the number of active rigs, so if you look at the chart of the seventh gen drill ships, of those that are stacked, the vast majority are cold stacked, so they aren’t coming out anytime soon. We actually look at the list that I track, there’s six or seven rigs that are listed as being warm stacked and we know that four to five of them already have leading positions in tenders that will take them out of the market. So you really do find yourself in a situation that’s similar to the back end of 2019, when we saw that boost in rates from that 150 level up to the 250 level, and it’s just driven by the fact that there are fewer assets available.

Makes sense. Thanks for the color.

Thank you. Our next question comes from Taylor Zurcher with Tudor Pickering Holt.

Hey, good morning, and thank you. Appreciate all the color, or the initial color on 2021, and if I’m doing my math correctly, the implied EBITDA number for 2021 is much better than what consensus is thinking right now. Mark, I think I heard you say that at the revenue line, about 80% of your forecast is contracted today, and so a two-part question. For the other 20%, could you help us understand which rigs that are currently idled today are going to help move the needle the most or that you see the best opportunity for work in 2021 embedded in that forecast? Then secondarily, it seems like the biggest delta would be, at least versus our thinking, would be on the cost side, so good to see that. If I just take the midpoint of the cost guidance for 2021, I think it’s about $1.5 billion - divide that by four, that’s $375 million type quarterly run rate for 2021 relative to $455 million you’re guiding to in Q4 this year. Just hoping you could help us understand how you get to that structurally lower cost run rate moving forward absent a number of rigs rolling off contract in the coming quarters. Thank you.

Thank you, good morning. Let me respond to your first question regarding the 20% of spec revenue that’s brought into our forecast. It’s really down to four or five rigs, one being the Asgard, the Inspiration, the DD3, and the Norge, and those are almost equally split between those, and then we’ve also got two other rigs, the Petrobras 10,000 and the Nautilus that come in at much lower numbers for next year. So like I said, four rigs would drive the vast majority of that 20% of spec revenue. As you look at the cost for next year, it’s not--I think your calculation of dividing the 1.5 by four is a way of doing it, but as you know, rigs are going to be coming off throughout the year. As they come off, costs would be reducing on a quarter by quarter basis. Next year, we also see the full benefit of our cost cutting efforts which we implemented this year throughout the second half of the year. [Indiscernible] contract, we’ve had to reduce costs. We’ve cold stacked several rigs, so all of that has happened incrementally in 2020. In 2021, we’ll get the full benefit on day one.

Got it, that’s helpful. Second question is on liability management from here. Clearly you’ve been extremely busy over the past few months, which has been really good to see. Moving forward, you still have quite a bit of capex slated for 2021 on the two new builds that you have remaining. Can you talk about the timing of those back end payments and whether there’s any potential to potentially push those out a little bit to the right? We’ve seen a lot of your competitors do that over the years, and I know you’ve got contracts in place for these two rigs and there’s some time constraints there, but do you see any potential as part of your liability management playbook to figure out a way to push those back end payments to the right a little bit?

I would look at that in a different light. That really isn’t liability management. We have a commitment to the shipyard for those two rigs and obviously the final payments have been delayed several times in the past, but those rigs are now slated to be delivered next year. We would need to take delivery of those rigs and pay the payments at the time. That being said, we’re always in conversation with our vendors, including the shipyards, and there’s a potential that something could happen there, but at this stage we are not pointing to anything specific.

Understood. Thanks for the answers.

Thank you. Our next question comes from Kurt Hallead with RBC.

Hey, good morning. Thanks for that color. I wanted to come back around, make sure that I understood some of the dynamics around the market outlook correctly. You guys talked about how currently ultra deepwater rates are in the 180 to 190 range effectively. It looks like they’re unchanged over the last few months. Then you mentioned at least half a dozen tenders on multiple years, and then I thought I heard something that with day rates approaching $300,000 a day for those multi-year tenders. Can you go back and just clarify that a bit?

Yes, sure. I said the low end is that 180 to 190. We’re seeing responses to tenders all the way up to $300K a day. That’s really because of the length of term. I would say that the near term market is somewhere between 180 to 230, and then that long term market looks to be substantially higher. It really depends on how many rigs will be taken by these long term prospects, and what you see there is essentially the low bidders being taken first, so as those rigs come off the market - in other words, they’re committed, then the balance of rigs available combined with the relative few number of warm assets, we think that’s going to really help push the dynamic. Hopefully that makes sense. As we see an uptick in bidding activity now, that should translate into an uptick in awards six, nine, 12 months from now.

Got it. All right, that’s helpful. Then Jeremy, I wonder if you could help us put into context, you’ve been among the leaders of taking assets out of the market and rationalizing your fleet. I was wondering if you could give us some general sense as to maybe how many rigs you could expect to rationalize in 2021 and maybe put that into broader context of how many industry-wide assets could be rationalized next year.

Well, I take offense to among the leaders - I mean, we’ve been the clear leader, unfortunately. With respect to our own fleet, I think you can continue to watch us follow past practice. We’ve been pretty consistent - as rigs roll off contract and we see limited prospects for them, and we don’t see them as overly marketable or profitable going forward, we won’t waste any time in removing those assets from our fleet. But I’d tell you, given what we’ve done so far, we’ve pulled the vast majority of those assets out of the fleet, as you well know, but certainly there could be a couple more going forward but we’ll address those as they come. Regarding the rest of the industry, it will be interesting to see how these competitors emerge from restructuring and whether as part of that restructuring they are forced to retire or recycle some of the older, less capable assets. Our expectation is they will because they’re just too costly to keep around and not overly viable going forward. That will certainly help with the supply side on the spread sheet, but candidly, we’ve said for a long time now we’re not as worried about the total number in the Excel spreadsheet because we know a lot of these rigs will never find another contract, but optically it will certainly improve things.

Okay, great.

Yes, we just see several of our competitors, as they’re transitioning management teams, are making a lot of overtures around just simply taking that supply out because, A, it’s just not viable, and B, it does not help market dynamics, so we encourage that.

Got it. Maybe one for Mark - what do you anticipate the securitization of the Titan being?

Kurt, as you know, that’s a five-year contract with Chevron at a pretty healthy rate, so I think we could get somewhere between $350 million and $400 million of secured financing against that rig.

Okay, that’s awesome. Thanks for the color, everybody. Appreciate it.

Thank you. Our next question comes from Fredrik Stene with Clarksons Platou Securities.

Hey guys, thank you for your optimistic comments today. It’s nice to hear that it’s more activity out there now than it was three months ago. What I’m wondering about today has to do with rig efficiency and how your customers have approached that. I’m thinking Equinor, with their recent [indiscernible] award, was very vocal that they’re now looking even more at cost per well versus just day rate, so have you--I think it’s been in place for some time, but have you felt that even more now when you’re hearing about the high grading of fleet, cold stacking, scrapping, etc., leaving the best assets on water? Is that something that you feel will be important both from a competitive standpoint going forward, but also from a utilization standpoint? As a follow-up to that, I think I mentioned Equinor - you’re taking the Barents to Norway. How do you view the re-contracting chance for the four rigs you have with Equinor already? Thanks.

Let me take the efficiency question first. Look - that’s been the push over the past several years, and really I think why we’re seeing offshore, particularly deepwater and harsh environment, doing well in terms of collecting bonuses and that kind of stuff, it’s all about that well cost, and the push for the well cost, it’s not only obvious that it’s better to drill a well for less the cost, but it typically brings the well on earlier, so then you have less spread rate that runs for a longer time, then you get earlier production and you get to drill more wells in the same period of time, so it really is the catalyst to more and more activity. So yes, we are fully behind that push. We have our customers equally participating in upgrades to rigs and allowing us to make substantial compensation on that, so it’s a very healthy environment from that point of view in terms of performance and high specification assets. You’ll have heard us say many times that that is our philosophy, is to be at that cutting edge of performance, but not because it’s just not only fun to be there but because it drives the economics of more activity and puts you in a better spot reputation-wise with the customers, that they know if they pick up a Transocean rig, then they’re going to be drilling the fastest wells out there. That’s really important for us and obviously makes a big difference in terms of how much we can collect on a contract and how much profitability is in it for the operators as well. The second part of your question was around bringing the Barents to Norway. Look - that’s her natural home, she was in Norway for a long…

Super, thanks. Just to follow up there, the four rigs that you have with Equinor in Norway already, how do you view the outlook of those rigs? I’ve spent a lot of time discussing with investors around those rigs, so I think anything that you can give - do you think that they will be extended, that there’s work for that kind of rigs, the midwater rigs, completion drilling, etc. in the same way that you will find work for the Barents, that you believe that these will continue to be Equinor’s workhorses also when the firm terms expire?

Yes, so when we look at those, the CATDs and the kind of work that they deliver, they are absolutely fit for purpose, and not only are they fit for purpose for when they were built but we’ve done some upgrades to them. We’ve brought them more and more into the digital realm, so with Equinor we’ve worked to enhance the performance of those rigs and they’re extremely pleased with the results that that has borne, and actually again for us, results in collection of bonuses and those kind of things. But we continue on that push of keeping those rigs right up there in terms of performance and the latest digital technologies, and as we see it and as the feedback we get is that Equinor are very keen to see them continue in that vein beyond their firm contracts, the contracts do have options on them, so we think there’s plenty of scope for those to be extended in the not-too-distant future.

As a final follow-up to that, do you think if there’s an extension that it’s fair to assume that they have options, but maybe a rate that’s more in line with the current market [indiscernible] type of discussion?

I think it’s a little early to say, but that’s always a possibility. But you know, without engaging in significant and earnest negotiation on those, I think I’ll not be drawn in that for now. We’ll just wait to see how that pans out when we do enter full time negotiations.

Okay, thank you so much. That’s all for me.

Thank you. Our next question comes from Greg Lewis with BTIG.

Hey, thank you, and good morning everybody. Mark, I guess I just wanted to ask a question around the ongoing tender, realizing that it’s ongoing. I know when it initially came out, it was a $200 million number, and then you kind of reserved the right to increase it or decrease it. Assuming that it’s successful, how should we think about the capacity or scope to increase it beyond that $200 million number, if there is any?

Thanks Greg. I think at this stage, we are disinclined to increase that cap beyond $200 million. Clearly once we finish this, it will be, I think, the fourth liability management initiative we’ve completed this year, so we’re going to take a step back, take a look at our five-year plan, look at our liquidity and reassess the next steps in our efforts to improve our capital structure and increase our liquidity run rate. But for this tender, I think we’re going to keep it at 200.

Okay, great. Then whether this is for Roddie or Mark, I know on the question around revenue, the Asgard was mentioned as a rig that’s going to--or has the potential to generate revenue in 2021. That rig is scheduled to roll off at some point this quarter. Just kind of curious how we think about that, and should we be thinking about maybe--you know, heading into winter, should we be thinking about maybe some idle time around that rig before it starts working maybe in the spring or summer, or do we think that there could be an opportunity really to just keep that rig really working post its rollout later this year?

I think you do have that opportunity to keep on going, but if there are some gaps in the schedule, we expect it will be relatively short - you know, a month or two here or there. But yes, she’s performing well in general, she’s really a high specification unit, so we’ve got a few irons in the fire on her. I would expect to see her working, but certainly it’s possible there are a few idle spots on her schedule.

Okay, and then just in thinking about that, knowing that--I mean, things look to have bottomed and turning the corner, but as we think about--and clearly once you guys don’t see--Roddie, once you don’t see much of an opportunity to keep the rig working, you probably start lowering daily opex. What is the window that would make--I realize the [indiscernible] is probably different, is it kind of, hey, if we have line of sight for 90 to 100 days, we’ll keep everything staffed up. Just trying to understand if that’s change relative to what it was a couple of years ago.

I’m not sure it’s really changed tremendously. I mean, as we go into these short idle periods, we have some levers to pull that reduce costs quite significantly if there is an idle spot on a campaign, but then you’ve got work on the back end of that. But it really depends on that future marketability of the rig, which of course the Asgard is right up there at the very top of the list, and also the prospects in that region. Look - the Asgard’s been down to some parts of Latin America several times. She’s a very mobile unit, so with Latin America in general doing extremely well just now, we would expect that the idle time on her would be limited, but we would be able to reduce expenditures during that time. But again, I think because this rig is in good demand, or this class of rig is, that the day rates are going to be pretty reasonable, so you can offset a little bit of idle time with that.

Sounds good, good to hear. All right everybody, thank you very much for the time.

Thank you. Our next question comes from Mike Sabella with Bank of America.

Hey, good morning everyone. I was kind of hoping we could maybe go back to the cost discussions and really try to unpack the guide for next year. When we think of bottom of the cycle type activities and layering in some of the advancements we’ve seen globally in remote monitoring, AI, understand lower activity means lower costs here. How should we be thinking about lower costs on the rigs that are working just as we see advancements here in AI and remote monitoring, and then kind of the same question on where you think you could take the shore base.

Mike, let me take a shot at this first. With regard to shore-based firstly, obviously as rigs come off, we need fewer people on the shore base to manage and support those rigs, so that happens as the rig count varies over time. As it relates to digitization or AI or any other current initiative, there’s going to be an investment into that, that initially offsets any cost savings we’re going to see in that quarter or that year. We’ve done a lot of this over the last several years, so we’re starting to see the benefit of that right now and we’ll continue to see this into the future as we continue to invest in our rigs to make them more efficient and more able to support the customers and their initiatives around digitalization.

Yes, I think I’d just add to that to say the equipment analytics programs and systems that we’ve put on the rigs that are remotely monitored from shore have already proven to be extremely useful, and primarily around being much more accurate in your maintenance and your assessment of the condition of the equipment, thereby not spending unnecessary maintenance dollars with time and effort. We’re already well down that track and our steady implementation of digitization projects like that, whilst they may not be grabbing headlines, they are certainly helping us manage costs through these difficult times.

Just one more thing to add to that, we have been working extremely hard over the last several years now to optimize the size of our crew and the activities on board, to optimize fuel consumption not only from a cost standpoint but from a carbon footprint standpoint, and so continuing to work down those areas and then just delivering these wells faster drives cost out of these projects and out of the organization, while also improving our carbon footprint as well.

Perfect, appreciate all that. Then just switching gears, maybe on the working capital front, it looks like it was a bit of a drag there in 3Q. As revenues kind of come lower, are there targets for working capital that you could share with us just as we head into next year, how we should be thinking about the working capital from here?

If you’re looking at working capital for this year, we’ve had--for the year to date, you’ve had two things that have happened that you’re not going to see on an ongoing basis. One, we had the Macondo [indiscernible] settlement of $125 million earlier this year, and also the E&I settlement which we only received one installment of that settlement, with the rest of it being expected to be collected over the next two or three years. If you’re looking at the quarter specifically, we had an increase in our interest payments for the quarter given the liability management actions we took, in addition to the fact that we accelerated some A/P payments that were a little slower in Q2, so between the two of those, you got to about $80 million to $90 million that also is not a trend and shouldn’t recur in the ordinary course.

Great, thanks a lot everyone.

Thank you. Our final question will come from Sean Meakim with JP Morgan.

Thanks, good morning. Most of my questions have been covered here, so just one on the back end. Maybe Mark, can we just talk about what type of liquidity levels are needed to run the business at current activity, and if you take possession of the new build next year, how does your liquidity position look relative to your needs exiting ’21? Anything else that needs to be done besides securing the secure financing on the Titan?

Sean, I gave you our estimate for liquidity end of 2022. I haven’t broken out the 2021 right now, but we can certainly get that to you. But we’ve built in the payments to JSPL for those rigs, the Atlas and the Titan. We’ve also built in the potential financing using the cash flow from the Chevron contract on the Titan, so all of that has been built in. In addition to that, as I mentioned earlier, we took a significant action this year with regard to reducing our shore base overhead, our G&A, and any other costs associated with running the business, which has been implemented as our rig count came down during the second half of this year. You just heard me talk about five rigs that came off contract this quarter, so as those rigs come off, obviously correspondingly we reduce the folks involved in managing those rigs. That is what I would point to with regard to costs.

Okay, fair enough. I appreciate it.

Thank you. I’ll now turn it back to Mr. Lexington May for closing comments.

Thank you David, 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 2020 results. Have a good day.

Ladies and gentlemen, that concludes the third quarter 2020 Transocean earnings conference call. You may disconnect your phone lines and thank you for joining us this morning.