Thank you David. Good morning and welcome to Transocean’s second 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 and Contracts. 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, 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 Brad. As we have since the beginning of the pandemic, we are continuing to work safely to do our part to prevent the spread of COVID-19, therefore please forgive any challenges associated with maintaining audio quality from speaker to speaker during this call. As reported in yesterday’s earnings release for the second quarter, Transocean delivered adjusted EBITDA margins of 42.5% by generating $418 million of adjusted EBITDA on $983 million in adjusted revenue. Despite the unprecedented challenges associated with COVID-19, our experienced and committed teams delivered outstanding operating performance, driving a sequential improvement in our revenue efficiency to 97%, resulting in better than forecast revenue and EBITDA. I want to take a moment to express my deepest gratitude to all of the men and women of Transocean who are working through these most difficult times. Our crews have shown tremendous strength and resilience throughout this pandemic, and I would like to acknowledge the personal sacrifices that they continue to make each and every day to keep our company operating safely. Additionally, I would like to recognize and thank our shore-based teammates who have adapted well to working remotely and despite the inconvenience and distractions associated with working from home, they have not missed a beat in supporting our operations and our customers. Moving through the third quarter and the balance of the year, we will continue to take every precaution to keep our crews safe and healthy. Onto our second quarter activity, we also initiated a number of new programs that contribute to our almost $9 billion of backlog. In Canada, the Transocean rig kicked off a program with Equinor we expect to run through the third quarter. In Trinidad, the DD3 commenced her one-year contract with Shell in May. This follows her successful campaign in Equatorial Guinea with Exxon Mobil and, depending on the success of this program, we are hopeful we can keep the DD3 working in-country beyond this current term. We have entered into a 10-month drilling campaign to further rationalize our fleet. Just last quarter, due to the success of the drilling program and the improvement in oil prices, we changed course and exercised an option for an additional well which kept the India drilling into July. Unfortunately, despite the success of the campaign, we see no near-term prospects for the India rig and are therefore in the process of cold stacking the rig. Moving to Asia, the DD1 completed her first full quarter of work on our campaign with Chevron in Australia and we expect this to continue into the fourth quarter. In Malaysia, the Nautilus commenced activity with Petronas that is scheduled to continue into the first quarter of next year. Turning to the contracting front, with the continued uncertainty regarding global energy demand and correspondingly challenged oil prices, contracting activity has been predictably disappointing; however, we are very encouraged to have executed a drilling contract for the industry’s second ultra deepwater 20,000 PSI capable drill ship, the Deepwater Atlas, with Beacon Offshore Energy for the highly anticipated Shenandoah project in the Gulf of Mexico. The Atlas will be the industry’s most capable ultra deepwater drill ship when delivered and will include, among other upgrades, a 3 million pound hoisting system. The Shenandoah project is subject to a final investment decision by Beacon, which we expect by March of next year. Prior to that time, we do not expect to incur any additional material expenditures for equipment purchases associated with the program. Conditioned upon sanction, the program and services would include the drilling and completion of four wells, which would involve commencing drilling operations in the first quarter of 2022 and should keep the rig under contract into the third quarter of 2023, resulting in a total contract value of approximately $250 million. Beyond the Shenandoah project, we are actively engaged in conversations with customers for additional opportunities in the lower tertiary of the Gulf of Mexico that will require a ship with the Atlas’ enhanced capabilities. Importantly, these projects have expected start dates that should closely follow Shenandoah and since Transocean will be the only drilling contractor with the assets and experience to successfully execute in this most challenging of ultra deepwater environments, we will be very well positioned to secure future contracts for the Atlas. Looking now at upcoming market opportunities, the contracting environment has improved marginally from when we last spoke three months ago and oil prices were largely at or even below $20 per barrel. While oil prices are still not where we want or need them to drive demand we saw emerging as we exited 2019, the recent recovery in oil prices to approximately $40 per barrel has encouraged our customers to begin revisiting the projects that we initially expected to start in 2020 but are now likely pushed into 2021. In the U.S. Gulf of Mexico, a 10-well project starting in 2021 was just awarded by an independent producer. In Brazil, Petrobras has recently requested bids for two rigs both with terms of approximately three years for activity kicking off early next year in the Campos and Santos Basins. Additionally, we could see some further movement from IOCs in the country following Exxon Mobil’s recent contracting of a drill ship for initial drilling in the Santos Basin. Furthermore, we believe Equinor is considering awarding a four-year contract in Brazil in the coming months which could begin operations at the end of 2021. Speaking of Equinor, you will note that they recently awarded a multi-year fixture for a high-specifically harsh environment semi in Norway. While the contract day rate was a step down from recently awarded fixtures, given the drop in oil price and continued market uncertainty, we were encouraged to see base day rates remaining near $300,000 a day with fairly significant upside opportunity tied to performance bonuses. Additionally, with the Norwegian government’s recent enactment of favorable tax incentives for oil and gas operators related to offshore investments, we anticipate this market will stabilize and respond favorably to the investment incentive. In Africa, we soon expect to see the first multi-year ultra deepwater drill ship award in Mozambique. We also think it is very likely we will see an 18-month award in Angola this year. Activity for both of these awards would begin in 2021. In Asia Pacific, we anticipate a five-well contract will be awarded this year for work offshore Australia with activity commencing in 2021. Additionally, we have been pleasantly surprised to see the emergence of a few opportunities for shorter duration work in other countries throughout the region. While we are certainly disappointed that the ultra deepwater recovery has been once again delayed, we take comfort in our almost $9 billion backlog and we are becoming encouraged by various opportunities we see emerging in 2021. Looking at our rigs, we continue to see the benefits of maintaining a young high specification fleet as we continue to operate significantly more floaters than any other contractor. Consistent with our well-defined asset strategy, we have recently taken action to responsibly retire the semi-submersibles Development Driller 2 and the Sedco 712. Beyond the assets’ ages, we continue to employ an objective criteria focused on cash flows when evaluating our fleet composition. When the costs associated with maintaining, reactivating and/or operating an asset outweigh our view of its cash flow potential, we take prudent actions to remove the asset from our fleet. Despite our increased optimism, we remain pragmatic and recognize the challenges the industry, and more specifically Transocean will continue to face in the near to medium term. As we entered the year, we were optimistic that the ultra deepwater offshore recovery was beginning to take shape; however, as a result of the pandemic, the current demand for hydrocarbons has fallen significantly, thus impacting offshore contracting activity. As a result, after thoughtful consideration, we recently took the difficult decision to once again materially reduce our shore-based support costs, which Mark will address in his comments, to more closely reflect what we anticipate being our contracted rig fleet over the coming months. I would like to stress that personnel reductions are without question the most difficult decisions we make as an organization as our team is irrefutably the most qualified and capable group of people within the industry. We embark on this global reduction in force purely as a result of the unprecedented and unforeseen circumstances. We hope that we will be in a position to welcome many of these teammates back to Transocean as the offshore market recovers and we have solid visibility to sustainable growth. I’d now like to provide a few comments regarding the state of the market from our perspective as the leading offshore drilling contractor. As you know, a number of other contractors have either formally started the restructuring process or taken steps that indicate that they are likely to do so in the near term. Given our strong backlog, strong operating performance, and timely balance sheet transactions over the past several years, Transocean is not facing the distractions and challenges associated with a restructuring. As he does every quarter, Mark will provide an update on our liquidity runway and expectations in a few minutes. As we watch the transformation of our industry unfold, we think that there are some very favorable data points in relation to Transocean, which I would like to detail. When the downturn began almost six years ago and many of our competitors went through their first restructuring, our customers, as you might expect, became more focused on the financial stability of drilling contractors and their other service providers. During this time, Transocean was able to further its position as the undisputed leader in ultra deepwater and harsh environment drilling. As the second phase of contractor restructuring is now beginning to occur, we anticipate our position will continue to serve us well on the contracting front with the more active IOCs and NOCs preferring strong counterparties to safely, reliably and efficiently deliver their projects. Different than during the first group of restructurings, activity has fallen to unprecedented levels which will result in extensive rig stackings and recycling throughout the industry as we believe the cost to keep uncontracted rigs crewed and in operating condition is prohibitive. As a result, marketable supply of rigs is likely to fall at a pace similar to the contracted rig count, therefore when oil prices stabilize at more favorable levels, an inflection in rig contracting should have almost immediate and positive impact on day rates due to the shortage of marketable rigs and the significant expense associated with reactivating stacked assets. At Transocean, we have strategically assembled the largest and most competitive floating fleet in the industry with the industry’s most experienced crews. We maintain the most contracted rig fleet with the strongest and most lucrative backlog, providing us with the visibility to future cash flows that we need to continue to invest in the training of our crews and the maintenance of our assets. As such, we are best positioned to survive this latest challenge and benefit from the eventual market recovery. In conclusion, we have accepted that a full-scale recovery in the deepwater offshore market will not begin before 2021; however, as the recent increase in oil prices has brought projects back into the fold, it has given us confidence that our customers will be ready to increase their offshore activity as oil prices continue to stabilize and become more supportive. In the interim, we are committed to our customers to working with them to find the right contractual solution to enable their drilling programs while operating safely at the highest performance levels with the industry’s most capable assets. We are proud to have positioned ourselves as the clear leader in the industry and we expect that our marketed fleet will remain the industry’s most utilized as we successfully navigate this downturn.

Thank you Jeremy, and good day to all. During today’s call, I will briefly recap our second quarter results and then provide guidance for the third quarter. Lastly, I will provide an update to our liquidity forecast through 2021. As reported in our detailed press release for the second quarter of 2020, we reported a net loss attributable to controlling interests of $497 million or $0.81 per diluted share. After adjusting for unfavorable items associated with the impairment charges related to previously announced retirements, we reported an adjusted net loss of $1 million. Further details are included in our press release. Highlights for the second quarter include adjusted EBITDA of $418 million reflecting strong fleet-wide revenue efficiency, cost control actions, and a legal settlement. Also, due to early discussions with customers, agreements were reached regarding responsibility for costs related to COVID-19. As a result of these arrangements, we mitigated what could have been a more negative impact on our quarterly financial performance. Fleet-wide revenue efficiency exceeded 97%, which represents a 3% increase from our first quarter results. We generated $41 million of free cash flow which represents a sequential increase of $196 million. It should be noted that this does not include $46 million related to the legal settlement of a dispute that was paid in the first week of July. Consistent with our guidance, we generated approximately $87 million in cash from operations, an increase of $137 million quarter-over-quarter. During the second quarter, we generated adjusted contracting revenues of $983 million driven primarily by strong revenue efficiency across the fleet and a legal settlement. Also in the quarter, a positive impact of early termination revenue from the Paul B. Loyd was largely offset by the Deepwater Skyros remaining on standby rate for most of the quarter and delayed starts for the Deepwater Nautilus and the DD3 due to COVID-19 travel restrictions. These delayed starts resulted in a lower than forecasted number of operating days during the quarter. Regarding the previously mentioned settlement, we recognized $177 million representing net value of the $185 million settlement, and $46 million on July 1, 2020, June 1, 2021, June 1, 2022, and January 15, 2023. Additionally, we recognized approximately $20 million in legal fees in the second quarter associated with the settlement. Operating and maintenance expense in the second quarter was $525 million, which is below our guidance due to the timing of certain projects and in-service maintenance and lower than expected costs associated with COVID-19. During the quarter, we recognized approximately $30 million of expenses related to COVID-19, of which approximately $10 million of these costs are reimbursable by our customers. Turning to the statements of cash flows and balance sheet, we ended the second quarter with total liquidity of approximately $3 billion, including unrestricted cash and cash equivalents of $1.5 billion and approximately $200 million of restricted cash for debt service and $1.3 billion from our undrawn revolving credit facility. Furthermore, we have forecast positive operating cash flow for the remainder of the year. As Jeremy mentioned, during the quarter we took the difficult decision to reduce our shore-based workforce to better reflect our expected operating activity for ’20 and ’21. As a result of these decisions, we will save approximately $80 million annually. Furthermore, we recognized severance charges of approximately $12 million in the quarter. Let me now provide an update on our third quarter financial expectations. For the third quarter of 2020, we expect our adjusted contract drilling revenues to be approximately $800 million, reflecting revenue efficiency of 95% fleet-wide. This reflects a reduction in activity of six rigs exiting their campaigns, including the KG2 finishing its contract with Chevron ahead of schedule and remaining warm stacked until their next fixture, planned to start in November for Woodside. Furthermore, the Discovery India, Discovery Inspiration, Transocean Barents, Transocean Leader, and Transocean Arctic will be concluding their respective contracts during the quarter. Except for Inspiration which we will warm stack in the U.S. Gulf of Mexico, we will cold stack these rigs. The Inspiration is well positioned for further near-term work in the Gulf of Mexico. This activity reduction is offset by a full quarter of operations on the Deepwater Nautilus, the Leiv Eiriksson, and the DD3 together with the Skyros that has driven operations at full daily rate in July. We expect third quarter O&M expense to be approximately $500 million. The quarter-over-quarter decrease also relates to the lower operating activity discussed above, including our estimate of approximately $14 million related to COVID-19 expenses and $6 million related to severance costs. These COVID-19 costs include but are not limited to overtime pay, charter flights and boats for crew changes, extended quarantine prior to crew rotations, and certain other logistical expenses. We expect G&A expenses for the third quarter to be approximately $45 million. This includes approximately $1 million related to severance payments. Net interest expense for the third quarter is expected to be $150 million. This forecast includes capitalized interest of approximately $13 million and interest income of $1 million. Capital expenditures including capitalized interest for the third quarter are anticipated to be approximately $80 million. This includes approximately $50 million for our new build drill ships under construction and $30 million of maintenance capex. Our cash taxes for the third quarter are expected to be approximately $12 million. Turning now to our projected liquidity at December 31, 2021, including our undrawn revolving credit facility and potential securitization of the Deepwater Titan’s contract with Chevron, our end-of-year 2021 liquidity is estimated to be between $1.2 billion and $1.4 billion. This liquidity forecast includes an estimated remaining 2020 capex of $170 million and a 2021 capex expectation of $1.5 billion. The 2021 capex includes $1.4 billion related to our new builds and $100 million for maintenance capex. Please note our capex guidance excludes any speculative rig reactivations or upgrades. In conclusion, while safety and operational excellence remain our primary areas of focus, we are acutely aware of the extreme dislocation in the energy business and especially oilfield services, including offshore drilling. We recognize that our customers have significantly reduced their 2020 budgets which eliminates the potential for re-contracting rigs completing their contracts this year. However, the potential longer-term hydrocarbon supply constraints implied by our customers’ exploration and development budgets encourages optimism and we remain constructive for 2021 and beyond in anticipation of a gradual increase in demand for energy and oil prices as global conditions improve. Even so, we will continue to proactively manage our balance sheet and capital expenditure requirements while exploring all opportunities to reduce our costs.

Thank you Mark. David, we’re now ready to take questions. As a reminder to all of our participants, please limit yourself to one initial question and one follow-up question.

Hey, thanks. Good morning everybody. Jeremy, I wanted to see if I could dig in with a little more detail on the Atlas opportunity. You said the initial four-well program would be, I think you said Q2 of ’22 through the middle of ’23. Is it the $250 million award to be finalized over an 18-month specific term, or is that not the correct interpretation?

I’ll start, but Roddie, why don’t you correct me? It is well driven and we anticipate that to take about 17 months.

Okay, well driven. Are you contemplating any price options?

No, that is correct - well driven, and the details of options and expected durations are you know, we’re not really going to talk about that until the FID is made, but yes, certainly a very positive data point for us at the moment.

Absolutely, so congrats and good luck getting that over the finish line. Then also wanted to see if you can speak to the remaining capex as the rig will be stacked, and how much, if any, of that is included in the ’21 capex that Mark just described, the $1.4 billion new build capex that will fall next year?

I’ll defer to Mark on that one. Mark, you might be muted?

Yes, could you ask that question again, please?

Yes, I wanted to see how much remaining capex for the final build out of the Atlas in total, and then how much of that might be included in the $1.4 billion new build spending that you outlined for next year?

The 1.4 is almost equally spread between the two rigs, and except for some well control equipment, all of it is included in the 1.4.

So the rig will be effectively fully built out, or budgeted for within next year’s spending?

Correct, yes.

Got it. Okay, thanks guys. Look forward to getting the update on that one.

Thanks Ian.

Yes, thanks. Good morning guys. There’s a lot of questions out there as to what the impact of these bankruptcies across the industry are going to be. Two sides of the question for you. Are you concerned about your competitive position as competitors re-emerge with clean balance sheets? On one hand, it would argue for them having a lower cost structure; on the other hand, bids at sub-$200,000 a day suggest interest expense and return on capital weren’t really major factors in bidding behavior, so where do you think that shakes out?

It’s interesting, and all I can do is look back at what we’ve seen recently and walk through that and assume that that will replicate itself as we go through this second wave. If you think back to the first wave, we had companies like Pacific and Seadrill and Ocean Rig and Vantage go through restructuring. Out of all four of those, only Ocean Rig came out with a clean balance sheet, the rest came out with still pretty considerable debt. That’d be one piece of it. I don’t expect these companies to come out completely clean. I think they’re still going to have quite a bit of debt. It’ll be pushed to the right and certainly be reduced from what it is today, and I doubt that they’re going to come out with a lot of cash. As you well know, it takes a lot of cash to operate and maintain these assets, and certainly a lot of cash to reactivate them, so I’m not sure that they’re going to be in a much better position than we are, first of all, so I’d just attack that one now. The other thing we saw was when these companies were going through the restructuring process, we increased our market share, and I can’t tell you it was because our customers were definitely choosing the more financially stable, less distracted organization, but it sure showed up in the way that we won contracts because we were not the low bidder during that time. So I think at least in the interim period, I think we have a decided advantage because we’re not facing that uncertainty and those distractions, and then we’ll just see how these companies come out of the restructuring process.

Got it, thank you. You alluded to the second part of my question, which is everyone is in cash preservation mode right now. It seems like cold stacking is the obvious preferred option for most rigs that are going idle. How should we think through the costs of reactivating rigs that maybe really never came back this cycle or were cold stacked early in the cycle, and how do you think about how the cost curve of those idled assets is changing over time?

You know, we’ve been on record saying this for quite some time - no asset is the same and no preservation techniques are the same. We’ve looked at different rigs ranging from $20 million to $25 million on the low end to in excess of $100 million on the high end, so if you just wanted to take the midpoint of that, it’s a really significant investment to bring one of these assets back online. If you look at the kind of contracts that have been awarded recently with respect to day rate and term, there aren’t many that would justify it. As we said in the prepared comments, as we see rigs roll off contract, and I think over the course of this year and next we expect 89 to 90 rigs to roll off contract, those rigs go to cold stack because people can’t afford to keep them active and crewed. It’s a pretty big check that one has to write in order to reactivate those assets, and the day rates today and the terms today won’t support it, so we think supply and real marketable supply and demand could come together pretty quickly.

I was just going to add to that that I think we saw in the bidding behavior that for rigs that were rolling off contract, some of our competitors bidding extremely low rates but certainly in the public tenders, where you can see what the rates were, any of the rigs that did require reactivation or were being mobilized from a significant distance, the numbers were quite different. Of course with there being very little cash on hand amongst those that have low active rig counts, we think that’s going to be a key theme going forward, that as soon as that hot supply is taken by the next uptick, the rates just simply have to move to cover the expenses that Jeremy was talking about - reactivations and equipment upgrades and what have you. So yes, there may still be a little bit of softness in some of the rates in the near term, but certainly there’s no other place for them to go but up.

Got it. I was just going to sneak in one more. If you guys could look in your crystal ball, how many rigs would you guess leave the marketed floater supply over the next year or two here?

You know, if you look at the 89 or so floaters that are rolling off contract over this year and next, there are, let me see here, 21 rigs that are over 30 years old. You would think and hope that at least those 21 never see the light of day again. I think there are another 20 or so that are between the ages of 11 and 22, 23. Those are probably at risk too, so there could be a good 30, 40 rigs that don’t ever see a contract again.

Yes, we’ve been in the downturn long enough that I think everybody has very solid experience of what it looks like to stack a rig and the condition that the rig is in to bring it back up, so I just think there’s going to be far fewer of these speculative reactivations where we see some folks lose a ton of money on that. Yes, I think it actually bodes pretty well going forward that, as Jeremy says, of those re-contracting necessities, the older ones are just not going to survive.

Appreciate it. I’ll turn it back.

Hey, good morning, and thank you. Jeremy, I wanted to touch on some of your comments on the marketing outlook. You ticked through a number of long-term contract opportunities in Brazil, Africa and Australia. In this sort of market, all those opportunities are going to be fairly lucrative for not only you but for the rest of your peer group. Roddie, you touched on some of the pricing behavior right now, I’m curious if you can frame where you think maybe qualitatively pricing shakes out for that sort of work, just given it’s real long-term work, and if you think any of the terms and conditions in some of these contracts as it relates to payments and things like that, might change a bit relative to where they were entering 2020, given the downturn that we’ve entered over the past few months.

Yes, I think you asked specifically about Brazil, you mentioned that, so Brazil is a great example. It’s actually the one region that is showing an uptick in expected awards this year compared to where it was before, but of course they were dealing with different issues prior. But Petrobras alone looks like they are going to contract four to five rigs out of the three tenders that they have open at the moment, and we actually expect that for starts in ’21, there could be as many as 12 rig years awarding fairly soon, and that includes not just Petrobras but other operators. That looks pretty interesting because you know there’s a big push on things like the Buzios Field, there’s significant increase in order of FSPOs, so that’s going to drive rig demand for sure. How that relates to the pricing as you point out, mobilizations and upgrades are very important considerations, and I think what you’ll see is that those that have assets in the region very close, perhaps already up to the requirements in Brazil or have been outfitted specifically for the Petrobras specification, I think you may see some of them still being quite competitive, but after that it actually is driven by the necessity of spending money on the rigs and having to recover that. The interesting thing about those prospects is that they’re all reasonably long term, so to us it’s a little counterintuitive to take your asset and book it for two or three years without any return on investment, so certainly we would expect that not only are the activation costs and the mobilization costs covered in those contracts but in addition to that, there should be a little bit of upside in it too. So in summary, really I think you’ll see the rigs that are hot and ready on the spot may still go a little bit cheap, but after that supply is taken that we expect to be soaked up in ’21, then it should be much more interesting towards the end of ’21 and into ’22.

Okay, that’s helpful. Then one market I didn’t hear much about is the North Sea. Can you just give us a flavor of where you see that market trending over the next 12 to 24 months, and maybe just parse the market between the higher end sixth generation assets and some of the non-sixth generation assets? I know you have a couple of those rigs rolling off in the next few months, so just curious what your take on that market is over the next one to two years.

Yes, so let me deal with the U.K. side first. A little bit lower specification on the assets, but really the U.K is dominated by the independents, and of course the uncertainty brought by COVID and the oil price war makes getting funding for them tough, right, so certainly when they do have funding they are going to be very cautious about how they spend that. Really, what’s happened in the U.K. side of things is that a lot of the stuff has been pushed out, so you’re basically sitting on a significant number of prospects that are drill ready but are struggling for lack of funding. In the meantime, what’s happened on that side of the North Sea is that a lot of rigs have been scrapped. We’ve seen some extensive cold stacking of rigs, so the active supply has basically been cut in half. You’re going from about 15 rigs down to about 7 or 8 rigs. Again, going through the reactivation costs and expectations of making some margin going forward, as COVID does subside and we hope that happens sooner rather than later, you will see these guys being able to get some funding and when that does happen, the number of available rigs for the North Sea is not going to be that many. Then when we think about Norway, which is the higher spec that you alluded to there, as Jeremy mentioned, it was good to see fixtures being made. Equinor are pretty active. But you know, Norway has really moved beyond COVID now. They’re really back up and running - schools are all back in, people are back in offices, and Equinor is very active, and not just Equinor but we’re hearing the likes of Lundin, once they get through the IPO, Neptune, etc., they have the better part of perhaps a dozen prospects that expect to move forward, and a lot of that has been driven by the tax breaks. So again, great to see the Norwegian government essentially stimulating investment by putting together a tax relief package that has really cut breakevens by as much as 40%. Even mature fields like Troll, breakevens are now in the 20s instead of the 40s where they were before, so that’s all just really positive. We really think on the high spec side, the Norway side of things, that that demand just picks up steadily through the rest of this year as everybody comes to grips with the tax relief package, and it could be a very tight market in ’21.

All right, super helpful response. Thank you.

Yes, thank you, and good morning everybody. I guess my first question is a follow-up to, I think, Connor’s question around some of the stress from some of your competitors in the market. Roddie, as you are out there realizing that there’s not a lot of activity out there, but has it started to come up in conversations, given the fact that relationships matter, that we traditionally use Company A and we use you guys as well, but just given the fact that we don’t know what Company A is going to look like, whether it’s going to be acquired, whether it’s going to be unwound, is there any sort of hey, we need to keep some viable companies up there and maybe that’s going to drive a little bit more work through Transocean’s doors?

Yes, for sure. I mean, if we look back at the second half of 2019, we were actually very successful in breaking into several new customers, and we’re very happy to report that our operations team have absolutely nailed it. The customers that are getting a taste of Transocean for the first time are seeing that we really are delivering value, that the well times are tumbling, and of course the return on investment for the operators is looking better and better. I’m not saying that’s unique to us, but certainly we’re able to demonstrate that we are right up there. I think where you may have seen customers that hadn’t used us before, those that are using us just now are extremely pleased, so again hats off to the ops team. They’ve done a fantastic job. Then of course with our long-term customers, we’re executing extremely well as can be seen in the revenue efficiency numbers, but not only that, the way that the teams have dealt with COVID - you know, almost uninterrupted operations, only a few instances where rigs went on standby for short periods of time. But being able to keep operations running worldwide during the pandemic is just outstanding, and it comes just through tremendous on planning and being proactive and doing that kind of stuff. So look, we really believe that there’s a lot of value in that. We have some of our customers telling us we know that you guys are a bit more expensive, you perhaps deserve that premium. They’re always cautioning us not to be too expensive, but we’re proud to say that we are able to get a premium, but I think we deliver tremendous value for that premium, and actually I wouldn’t describe it as a premium, I would describe it as a saving for the operators.

Okay, great. Thanks Roddie. Then just for Jeremy or Mark, a little bit bigger picture question more around capital allocation. As we look across the capital structure and obviously there’s bonds in the back end that are trading at huge discounts, but there’s also some in the near term that are trading at discounts, and cash is key. But is there any arbitrage opportunity as you look at your equity versus your debt, where you could kind of take advantage to solidify Transocean liquidity position, balance sheet position a little bit more? It looks like there should be.

I’ll defer to Mark on that one.

Yes Greg, as you know, we’ve been very proactive over the last several years in managing our balance sheet. We’ve raised over $3.5 billion, we’ve refinanced over $2 billion of debt, we’ve done tenders on a regular basis, we’ve done open market repurchases virtually every quarter, so we look at every opportunity to lengthen our runway, to look at our near-term maturities, make sure we’ve got liquidity available to address that, and nothing’s going to change now. We’re going to continue to do that, and you’re right - our bonds are trading at deep discounts, but our equity is trading at pretty low price as well, so it’s pretty difficult to go out there and say we’re going to issue several hundred million dollars of equity to buy debt when both sides of the equation are deeply discounted at the moment. With that being said, we will continue to look at interesting ways in which we can extend our runway and keep the company operating at a very high level of excellence.

Okay guys, thank you very much. Have a great day.

Hey, good morning everyone. I was just thinking maybe we could talk for a little bit more about the upgrade of the Atlas and just walking us through that decision. Really maybe what are the options for you or really any of your peers to upgrade an existing rig instead of taking a new build, and then maybe on the flipside, what you could have reasonably expected from the shipyard if you had decided to just delay or cancel delivery of that rig.

Let me start with the last piece first. There really was no opportunity to cancel the rig, contractually we were committed. We’ve obviously thought about every possibility over the course of the last five years and recognizing that this was significant capex for us as we roll into 2020, 2021, so that was kind of off the table for us. With respect to the upgrade itself, there’s more than just buying the 20K pressure control equipment to upgrade one of these assets to be able to drill and complete effectively in the Gulf of Mexico. The higher hook load, which we mentioned on the call and we mentioned several times before, is of paramount importance. The larger deck that both of these rigs, the Titan and the Atlas, have are ideal for large completion work. There are several other features, attributes that have been added to these rigs to make them really optimal for these 20K projects in the lower tertiary. Are there other assets that are out there for us or our competitors that could be upgraded? Yes, but significant cash - bringing one of these assets into a shipyard, upgrading the hook load capacity, upgrading the mud system, buying the 20K pressure control equipment and associated plumbing and everything else that goes with it, so it’s really - as we look at our competitive landscape, there is not really a viable option out there because everybody is so desperate right now with respect to their cash position, so we feel like we’re in a very unique situation having the only two 20K capable assets in the industry. We feel good about it. We’re excited to have the drilling contract, although conditional, with Beacon and their partners, and we see other opportunities. We’ve been in active conversations with other customers about follow-on work after the Shenandoah project, so still a few things left to be done but excited about the opportunity.

Mike, this is Mark. As Jeremy indicated, all the other upgrades that have to occur to the rig, we think this decision 12 to 18 months ago to go ahead and prepare the rig for a 20,000 PSI upgrade, so those costs have all been included in the numbers I mentioned earlier. Ian asked the question earlier, does it include everything? I said that except for some well control equipment, and the reason I’m not specific on that is because the contract that we’ve signed is conditional and has some items that yet need to be agreed upon, including some of the well control equipment, so once we get a better handle as to what that is, we’ll be able to give you a better estimate as to what that costs. But the vast majority of the other costs associated with this, in fact all of it is included in the $1.4 billion.

That’s great, guys. That was very helpful. Then just a follow-up, so we recently saw a contract disclosed by a peer in the Gulf of Mexico, 450 days at $180K per day going out to 2022. I was wondering just as we all try to figure out what the day rate curve looks like, assuming you all were a part of the bidding process on that rig, was it really the front end that you didn’t like the rate or the back end as well, and then what does that indicate for where you guys think rates could go out into 2022?

We’ve been very vocal, especially over the last couple of quarters with respect to the fact that we need to enter into contracts that generate positive cash flow from operations, and that means not only covering our rig-specific costs but covering our corporate overhead. We have to generate cash, as do all of our competitors, and so that’s how we are approaching our response to tenders. Roddie, I don’t know--

Yes, sure. I’d also add, you asked about the front end of the back end. The truth of the matter is on that one, there’s a fairly significant period to elapse before that campaign starts, so in our view trying to beat that kind of a rate if you also have an asset that’s not going to do anything for six to nine months ahead of it and, as Jeremy said, if you’re honest about what your overhead is, then clearly that doesn’t really work for us. I guess it may work for others, but there’s just not going to be any cash generated from it, and it’s been our stated policy for quite some time that we will not enter into contracts that are just treading water or still reducing our liquidity. So yes, we were involved in that, a great operator, we’ve worked for them very well in the past, but that was not the rate level we were willing to look at.

That’s great. Thanks a lot, everyone.

Hey, good morning. Just an initial follow-up here for Mark. When you provided the liquidity guidance out going forward, that $1.2 billion to $1.4 billion range, I was just curious as to whether or not you anticipate having to tap into your revolver to maintain that liquidity level.

Kurt, our revolver is $1.3 billion, so it’s right in the middle of the range, so if we hit the middle of the range, the answer is no. But there’s a potential that we dip into it by as much as $100 million.

Okay, that’s fair enough, I appreciate that. Just to follow up on the cash flow dynamic here, you kind of provided your capex numbers for the back half of the year and you indicated you’d be positive from cash from operations. Given the overall level of capex in the back half, would you anticipate you could potentially be free cash flow positive in the back half of the year?

It would be close, Kurt. We do have $170 million in capex for the second half of the year. It should be close.

Okay, and then just one follow-up for Jeremy. You guys talked about the difficult decision to have to reduce costs and reduce some personnel. On a broader dynamic around cost reductions, given the dynamics that have occurred over the course of the year, has there been any opportunity potentially to reduce, number one, your daily rate operating costs, and secondly, have you been able to negotiate better terms with vendors to be able to reduce your overall costs, let’s say on the new build Atlas, for example?

So constantly looking for opportunities to drive cost out of the system, out of our operations, out of our shore-based support, Kurt, as you know, but we’ve been at this now pretty diligently since the start of the downturn, let’s call it late ’14, early ’15, and so we’ve captured all of the low hanging fruit and then some. We certainly work with customers to optimize the crews that we have on each of our assets and we’ve done that on several assets where we’ve been able to pretty substantially reduce crew size without negatively impacting performance. In fact, we’ve seen safety performance and reliability improve in most of those cases, and so constantly looking for opportunities. With respect to our supplier base, our supply partners, we’ve entered into, and this is probably two years plus now, entered into the long term care agreement with all of our major suppliers and equipment providers on every major piece of equipment on our assets, and so those are long term relationships, long term contracts where we negotiated fairly significant discounts a couple of years ago. Obviously, we continue to go back to our vendors for support given these challenging times, but I think the incremental savings are going to be pretty de minimis, not overly material.

Great, thanks for that.

Thanks, good morning. Maybe just to follow on the Atlas discussion and the Beacon contract, the numbers look pretty good, but it seems like there’s pretty limited visibility on follow-on opportunities. North Plat seems like the other big piece of the puzzle. It’s unclear maybe the likelihood or timing of that one. Are we missing some others out there from a 20K perspective, and how do you think about follow-on opportunities as you try to secure cash payback on that rig without a big anchor-type contract?

There are other opportunities that are out there. Basically as we talk to the customers that are engaged in these kind of fields, in fact you can probably go Google some of the really interesting stuff about how many of these high pressure fields there are in the Gulf of Mexico, the operators that are engaged in that are wide ranging, so everyone from Chevron and Beacon or the Shenandoah group, but on top of that there’s Total, there are also more requirements for some of the bigger guys as well, so even Chevron, Shell, these folks are all talking about the possibility of incremental demand in that area. Now of course, right at this minute in the midst of COVID, there’s some uncertainty about timing of those kinds of things, but needless to say there are additional opportunities, and without going into details of the Beacon arrangement, we’ve put that in such a way that allows us to move forward with minimal risk to not recovering the investment that we’ll make in the well control equipment, but on top of that being able to capitalize on the upside on the other side of it, having as Jeremy said the most capable rig in the world and being 20K outfitted and ready when that happens. So our re-contracting risk, we think is pretty low because the re-contracting wouldn’t take place for at least another three or more years. Certainly there are plenty of fields that require this equipment in the Gulf of Mexico, and we think three to four years is plenty of time for the efficiencies of deepwater to come through. We’re already seeing how well we’re performing versus shale and other places, but as time moves on and we continue this fantastic drive on efficiency, I think there are lots of opportunities there for it and we feel that we should be able to take advantage of that first mover position.

Got it, thanks Roddie. I think you framed that really well. Jeremy, you certainly have an advantage in bidding right now as your peers restructure, but unfortunately this might limit opportunity to push that advantage given the lack of tenders. The goal since the early days of the last downturn was for you to be the last man standing. Seven years post-peak, you’re about there, and you made all the right moves in the interim to position yourself there, so you called it right. But even with restructuring, there’s a huge capital hole in the sector, so does your view on being the last man standing change? Is there a shift in strategy on capital structure if deepwater activity stays pretty anemic for the next 12 to 18 months?

No, it doesn’t change. I think -- I mean ultimately, as you well know, we’re going to need some help in the market at some point in time, but we maintain a five-year forecast and continue to look at our liquidity position under various different scenarios in terms of utilization and day rate, and feel comfortable with our near to midterm. Obviously if we get three years out plus and the market hasn’t started to recover and day rates haven’t started to recover where we can generate some significant cash flow from operations, then obviously we’re going to be like everybody else that’s going through the process right now. We are the last man standing. We have done, I think, made all the right moves both from a fleet operations and balance sheet perspective, and we’ll continue to pull every lever we can to extend that liquidity runway and keep moving on.

Fair enough. Thanks for the thoughts, Jeremy. I appreciate it.

Thank you David, and thank you to all participants 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 third quarter 2020 results. Have a good day.

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