Transocean Ltd. (RIG) CEO Jeremy Thigpen presents at Barclays CEO Energy-Power Conference (Transcript)

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Transocean Ltd. (NYSE:RIG) Barclays CEO Energy-Power Conference September 4, 2019 2:25 PM ET

Company Participants

Jeremy Thigpen - President and CEO

Conference Call Participants

Dave Anderson - Barclays


Dave Anderson

Jeremy has done a great job over the last three, four, four and half years overhaul in the fleet. In fact they announced yesterday, retired three more assets. So he’s doing his part in this market. Some other guys need to step up now, but anyway before I could go on, for those who don’t know Jeremy was with CFO of NOV for two or three years. Two years there and I don’t know if he was for a long time here, but before I keep paddling on here, I’m going to introduce Jeremy. Jeremy, thank you very much.

Jeremy Thigpen

Thank you for that very formal introduction, Dave. Always good to be here and so thank you for giving us the platform to once again tell the Transocean story and provide you an update on what’s transpired over the course of last year. Hard to believe that this is my first conference here since assuming this role, I know, it seems like just yesterday, great times in the market over those five years by the way as you’ve noticed.

But I am proud of the work that we’ve done during this downturn as we position ourselves of what we view as an imminent recovery. We have totally transformed the organization and really positioned ourselves well as the recovery source to take shape. But before I get into some of the slides around the differentiation at Transocean and where we think the market is going, I'm obliged to show you our legal disclaimer and remind you that most of which you see in here in this presentation are forward-looking statements and are based on assumptions that are subject to change.

So with that, I fulfilled my obligation to our General Counsel and I can move on. You know and the management team, the new management team first came together about four and a half years ago. We got together and we presented ourselves with two challenges. Number one, how do we survive the downturn, and especially if it's prolonged. And that was really around liquidity position. And the other was how do we better position Transocean such as the recovery takes shape, we are in a better position than any of our peer group.

And so, let’s start with the liquidity question. We are in a very unique position in terms of our backlog. We have a massed an industry leading $11.4 billion backlog. A lot of that backlog was secured before the downturn, so it’s at much higher debt rates and very profitable backlogs. We have great visibility to future cash flows, which then gives us the freedom than to go and invest in our people and our assets and in new technologies and we’ll touch on each of those as we move to this presentation.

At the end of the second quarter, we had total liquidity of $3.6 billion, that’s $2.2 billion in cash and short term investments and another $1.4 billion in an undrawn revolving credit facilities. So a very unique position in the offshore drilling space with regard to liquidity both in terms of the backlog and our liquidity position.

In terms of preparing ourselves and better positioning ourselves for the recovery, we have more experience in ultra-deepwater and harsh environments than any of our peers and in fact it’s significantly more. And we think about the ultra-deepwater market and the harsh environment market, these are very challenging environment and very complex applications.

And so that experience and the technical resources that we can bring to bear we really think that’s where we can differentiate ourselves with our customers, that’s where they call on Transocean first whenever they have a technically demanding application and we’ll talk more about that. And in order to really function in that area, you need the best assets in the industry and so we have worked hard to transform our fleet over the next four years and we’ll spend some time talking about that.

Those who have heard our story before will know about four years ago, we took every floater in the industry. There were 328 floaters at the time. We populated them into a database and we captured the age, the year built; all the technical specifications. We then went through and applied a waiting to each of the technical attributes based on what our customer set was most important to them in both the ultra-deepwater space and harsh environment space. And then we post shrinked [ph] all 328 assets. It’s not an exact science, but it gets you pretty close.

And what we found is that gave us a really good representation of how our fleets stacked up against the peer group. And we use that data base to make decisions around retiring assets that we think are going to be less marketable, so lower in that ranking obviously. To upgrade existing assets, to move them higher up in the marketability schedule and to potentially acquire assets that are run by other company. And so let's start with the divestitures. As they pointed out we have been the most active in the space with respect to divestitures.

If you look back at our fleet back in 2014 with a large fleet, it was 91 rigs in total, which included 16 high specification jackups, 34 midwater floaters and 41 ultra-deepwater and harsh environment assets. It's important to note that only 45% of our fleet was focused on the ultra-deepwater harsh environment. Remember at the beginning I said that's where we really want to focus and where we think we can differentiate.

Importantly, as you look at this slide the average age of our floater fleet back in 2014 was 21 years, so an older, less marketable, less technically capable asset base. Over the course of the last four years, we have decided to divest the jackup business. So we sold our 10 active jackups and the five that were under construction at the Keppel FELS shipyard. What's important about that transaction is we got cash for the transaction which was good from a liquidity standpoint, but we also avoided a billion dollars in CapEx that was tied to the five newbuild. So that was important decision for us both from a fleet composition standpoint, but also from a liquidity standpoint.

You'll see that we have retired 53 floaters over the course of the last four years, 38 deep midwater assets and 15 ultra-deepwater drillships. And as Dave pointed out just yesterday after the market closed, we announced the divestiture of three more of those and these are pretty good rigs actually. These are the last of the 5th gen dual activity rigs, 2 million pound hook-loads. These are much higher spec than some of our peers are still holding on to their rigs.

But as you looked at the cost to reactivate these assets and the length of time we thought they were going be stacked. It just made sense for us to go ahead and remove them from the fleet and so they will be sent to the shipyard and disposed of in an environment -- environmentally friendly way. So, enough about the divestitures, it's more fun to talk about potential acquisitions.

So from the start we have said that we think this piece of the industry needs to consolidate and that we want to lead that consolidation effort. However, we've been very clear. We are only interested in high specification ultra-deepwater floaters and high specification harsh environments and semisubmersibles. That's it. And we don't want to do anything that would materially and negatively compromise our near-term liquidity. So we get a much better view of how the recovery is going to take shape. And so that gives you a pretty narrow focus as an organization.

So the first acquisition we consummated a little over a year ago about 18 months with Songa Offshore. Songa Offshore was Norwegian based. Drilling contractor had five harsh environments semisubmersibles four that were brand new. They were designed in conjunction with Equinor and they had long term contracts that were negotiated before the downturn. So they brought with it almost four billion dollars in high price backlog.

So this was really almost a defensive acquisition. You get visibility to those future cash flows, but you also acquire four really high spec assets on long term contracts. So we enhance our presence in Norway. We enhance our presence and strengthen our relationship with Equinor where we now have -- soon to have seven rigs operating with Ecuador. And so it's just a perfect acquisition for us.

We then followed that up and shortly thereafter and invested a 33% interest in a joint venture with a company called Hayfin. They had acquired the Transocean Norge which is the high specification, harsh environment semisubmersible that had been stranded in the shipyard. So, we have the exclusive marketing and operating rights to that asset. And before we even took delivery of the asset we secured a nice contract with Equinor to operate in Norway. We have since taken delivery and she's been on contract for the better part of a month now I guess and knock on we're performing exceptionally well, Equinor is very happy.

A few months later than we made the decision to acquire Ocean Rig, Ocean Rig had just gone through a restructuring, was actually in a net cash position, which was good, but more importantly they had some outstanding assets. They had 10 of the top rated ultra-deepwater drillships in our database, eight of which were in the market that already taken delivery, two of which are still in the shipyard. They also had a harsh environment stemming on a contract with Lundin Norway. And so again fit within our parameters for strategic acquisitions.

We've also used our database to identify upgrade opportunities within our existing fleet. And so the Discoverer India is a great example of this. In our ranking before she was rated number 75 out of all the ultra-deepwater assets which is a good solid asset. But with a $20 million CapEx investment we added an annular BOP. We added acoustic BOP controls as backup redundancy. We upgraded her dynamic positioning from class two to class three and we made her NPD capable.

And so with that $20 million investment she actually moved up our ranking from 75 to number 50 in the world and so a much more marketable asset. And as a demonstration of that marketability as soon as we finished the upgrade, we secured a contract for her with the CNRL in Ivory Coast. Here the following contract; and now she's just secured a contract with Borealis in Egypt. So she has been contracted ever since we made the investment. We've got three or four other rigs that meet this same kind of -- that are very similar rigs and with a $20 million to $25 million investment we think we can make them far more marketable as well.

So you take all that into consideration; the retirements, the acquisitions, the upgrades, we have gone from a fleet of 91 rigs that was fairly broad and diverse to a fleet of 49 rigs, so a much smaller fleet, but exclusively focused on harsh environment and ultra-deepwater, 94% of the fleet is in at vein. And what's really interesting to look at here is look at the average age of the floater fleet now. We've gone from 21 to 11, that number would actually be lower fleet and have three midwater assets in there because those are older rigs. And if you just look at our ultra-deepwater fleet, the average age is eight.

So, a very young, very focused fleet harsh environment and ultra-deepwater only, very high specification. And we are much smaller fleet than we once were. If you look at as compared to our peer group, we're 75% larger than our next nearest competitors which are Borealis and Seadrill. And actually in this market especially as you're talking about ultra-deepwater and harsh environment, you need some shore-base support and technical support on land to actually operating these rigs properly and efficiently and safely. And so the more assets, revenue-generating assets, you can spread that cost across the more efficient you're going to be in the organization. So this is -- size really is important in this respect.

More importantly if you get to the highest specification assets now, we have accumulated the highest concentration of the industry's best assets. The blue bar represents the number of rings we have the Top 100 and the yellow bar is the Top 50. So, basically a third of the Top 100 rigs and over a third of the Top 50 ultra-deep water drillships in the industry far more than the next nearest competitor. One would think that those are going to be the most marketable assets as recovery take shape and that's been our focus.

The same holds true as you look at our harsh environment, semisubmersibles, we have nine of the Top 30 harsh environment assets in the space. So again, well more than when our peer – our next nearest peer and feel like we're in a really good position in that respect too. So you take this high specification assets, newer far more marketable and then you combined that with Transocean's reputation around the world with our customers in each of these geographic markets and we have done fairly well in securing new contract.

We announced that we secured two new contracts with Petrobras in Brazil, importantly those two assets were acquired as part usually Ocean Rig transactions. So it's nice to put those to work so quickly. We got a new contract for the Asgard with Murphy in the Gulf of Mexico and then those that follow our story would have seen late December of last year, we secure the industry's first rig capable of drilling in 20,000 psi, and that's a Deepwater Titan where we secured a five-year contract with Chevron at a very healthy dayrate. First of its kind and we'll talk more about that in the coming slides.

Also pleased to recently secure a contract with Equinor and Canada for the Barents setting a market-leading dayrate in that market and we continue to see harsh environment rates for the really high spec assets moved up into $400,000 a day range plus bonuses, so very healthy market there. Secured a couple new assets and new fixtures in the North Sea and then of course the Transocean Norge which we already referenced in Norway.

Also picked up some work in Egypt with Discoverer India and Equatorial Guinea with ExxonMobil with Development Driller III and then some work in India and Southeast Asia; and so you can see the global player, definitely a quite a bit of success with various customers around the globe in recent months.

As a result, we've accumulated a fairly significant backlog $11.4 billion you'll probably get tired of me saying that. This is my favorite slide by the way. That's our backlog as compared to our peer group. You can see four times larger than next nearest peer and importantly again most of that backlog was secured before the downturn and so its higher dayrates and real good visibility to future cash flows which are competition just doesn't have.

And it really gives us the opportunity to then go invest in differentiating technology. And so let's talk about the 20,000 psi drillship. This is not only a 20,000 psi package, first control package which is a first of its kind. It's also a 3 million pound hook load, 10,000 psi mud system, all bells and whistles and improvements to the deck to allow for more efficient logistics. This is truly one-of-a-kind, I'm very proud of this. Interestingly, when the announcement came out that we had entered into the contract with Chevron we've been approached by a number of customers who also have 20,000 psi opportunities in their portfolios.

And so we were engaged in very healthy conversations for the sister rig to the Titan which is still on the drilling shipyard, which also had [Indiscernible] hook load, which also can be upgraded to a 20,000 psi solution. I'm not telling you that the contract is imminent. I'm telling you that there is a strong interest and we believe in and in fact know that the industry could support another 20,000 psi solution and we represent the best opportunity for that. And so, we're excited about this technology.

Another thing you may have seen or read about us recently as we entered into an agreement with Equinor. Equinor has become by activity standpoint our largest customer. And this is to install what we call ADC or Automated Drilling Control on each of the six rigs that we have drilling for Equinor in the Norwegian Continental Shelf. This is a combination of technologies that includes National Oilwell Varco and Telesur wired type system that transmits data from the bit to the surface of 57,000 bits per second. So it's real time.

It then interfaces with a proprietary software designed by this company called Citgo [ph] at Norway, which then interfaces with the Maritime Hydraulics. Is that right? The Maritime Hydraulics, the image burst [ph] control system that controls the drilling equipment package. And what we found is that by getting real time downhole data shooting that up to surface, processing it through the algorithms through this ecosystem we can then automate the equipment on the drill floor. So specifically mud pump pressure torque weighed on bit and we are seeing much better performance.

We've operated system on one of the Cat D rigs for a little over a year now and in certain sections of certain offset wells we're seeing 30% improvements in rates of penetration. So a really interesting combination of technologies that's delivering a great solution for Equinor and we've agreed to jointly invest in the application of this technology on the other five rigs that are currently drilling for Equinor in Norway, certainly something over time as we can demonstrate more value and communicate that value to our other customers, you could see the system deployed on more of our assets around the world.

One of the things that we're doing is just purely safety focus. What we've found is no matter how much training we provide, no matter how crisp and clearer our policies and procedures are, we're dealing with humans who lose focus at times and inadvertently put themselves and harms way. So, we've got the system that we're calling Halo Guard and it's a combination of sensor technology and cameras so that our machines can actually understand where our people are as opposed to our people trying to figure out where our machines are.

And so what you'll see here and you saw in the animation is you've got proximity sensors built into the vest of anybody working on the drill floor. As they start to approach a moving piece of equipment and they enter that yellow zone, they will be alerted through vibrations, through sound and by light, you were getting close to a danger zone. If they continue on and enter the red zone the equipment will automatically stop. This is really interesting technology and certainly something that could improve safety on the drill floor.

We are piloting this toward the end of the year. If it works as intended then there's no reason to believe it won't. This is something that we can quickly deploy on the other assets that are active around the world. All right perhaps the most interesting technology. This is called aShear. And you can see it ticks the boxes of efficiency and costs. This is a partnership with a company called Kinetic Pressure Control [Indiscernible]. The Shear in itself is retrofitted to any existing BOP whether it would be NOV, Baker Hughes, Schlumberger-Cameron.

It is driven by our proprietary control system which is a subsea pump package. We recently, recently I mean two weeks ago ran a test in 5000 feet of water. Betsy was present, multiple customers were present. We shared a sixteen and a quarter inch piece of casing with six and five, eight drill pipe inside, never before done. And it was like butter. I mean it was unbelievable. This is this is the ultimate insurance policy. As you can imagine the regulatory bodies are very interested in this. The customers are very interested in this. This could be a step change in BOP technology, and again retrofittable to any existing BOP.

The last piece of technology I'll talk about is the hybrid power package. Here is an interesting approach. We've taken battery storage unit connected him to our thrusters and the idea is that we can more efficiently and more reliably manage our power management power distribution system. If you look at the benefits of this reduced fuel consumption, which means reduced cost, reduced emissions, reduced footprint, all of those very good things. It also builds in some additional safety factors for us and that we're storing energy, storing power in these batteries such that if we do have a blackout at any point in time we'll have enough power to maintain station and control the critical components on the rig and so that just ticks the box on every single front.

So, a very exciting technology. We're in the process of finalizing the installation on the Transocean Spitsbergen which we'll then begin drilling again for Equinor. And again, with the focus on ESG opportunities to reduce costs, improvements to safety, this could be an interesting piece of technology that again could be spread to multiple assets in our fleet. And again we're able to make those investments because of the visibility of future cash flows. So again I'll talk about our $11.4 billion backlog if I hadn't already. But the interesting view over the backlog here is it shows how that backlog supposed to convert to revenue over the course of the next several years.

And so what you can see here, if we were not to secure another order which won't happen. Don't worry; we're going to secure more orders. You still have visibility to future revenue and then cash flow over the next several years, that's more than enough to sustain the organization. We always get asked about the sanctity of the backlog. 94% of our backlog is with investment grade customers and specifically at Shell, it's Equinor, its Chevron. Great relationships with these -- they honor their contracts, they pay their bills and so a very solid backlog, and again most of which was negotiated before the downturn.

So securing the backlog is one thing. Converting that backlog to cash is equally important, and so really focusing on up time performance which then is a proxy for revenue efficiency. If you look over the last four years, the uptime performance across our fleet has been outstanding leading to revenue efficiency in excess of 96% for the past four years. And in fact for the first half of this year I think we're above 97%. So $0.96, $0.97 of every dollar of backlog is actually being converted to revenue, which is a good sign.

Then you look at the chart on the right and you can see with all of the cost reduction and efficiency improvements we've driven into the organization we're actually converting a lot of that revenue to EBITDA, maintain EBITDA margins in excess of 35% despite the fact revenues have declined 60%, you normally won't expect to see that. So the organization has done a great job in that regard. Because we've done such a great job on the operational side converting backlog to cash and Mark Mey our CFO and his team have done such an exceptional job with various financing transactions over the course the last four years. We're actually a fairly unique liquidity position amongst our peer group.

Here's it. You remember this one. I knew five years ago. I got a lot of attention. But if you look at kind of this liquidity windfall here, so what we're showing is from the end of 2000 -- from the end of the second quarter of 2019 till the end of 2021, these are just the puts and takes around liquidity. So $2.2 billion in cash, $1.4 billion in an undrawn revolver, we expect conservatively to generate operating cash flows from now until 2021 of around $1 billion. I say conservatively because we've baked in 95% revenue efficiency into that number. And I just told you we're consistently in 96 and maybe even at 97 now.

We also do not include any speculative reactivation is in that number. So to the extent that we get an opportunity to reactivate an asset, the cost of the reactivation and the cash flow that that reactivation would generate by the contract are not included in there. So it's a fairly straightforward and conservative view we believe to cash flow -- operating cash flows. We have quite a bit CapEx do over the course of the next year and a half, two-year period. Most of that is tied to the four newbuilds that we have one of the Titans, so we have a contract for that which is good. The other three do not currently have contracts. I'll come back to that in just a minute.

And then we have $1.4 billion of maturities do over the same time right. And so you get to the end of 2021 and you're looking at between a $1 billion and a $1.2 billion in liquidity which obviously means that we're tapping into our revolver at that point in time, but we've got some levers we can pull. So once we take delivery of the Deepwater Titan we can get on contract, we can secure what we believe is probably up to $400 million and secured financing against that asset and that contract. And if we're successful in securing a similar type of contract for the sister rig over that time horizon obviously we could do something similar with that.

So we've got a little bit of flexibility there with some of the timing of that CapEx and potentially securing some financing against it. And we've demonstrated over the years that we can work well with the shipyards and defer deliveries and push payments out if we absolutely need to, so, and a very good liquidity position through the end of 2021 and beyond.

All right. So hopefully I've demonstrated. We've got a great fleet. We operate it very well. We've got great customer relationships. We've got solid liquidity position. So we're definitely going to survive the downturn and continue to invest in our business through new technology, better maintenance, training of our people. So the next question is all right. So when does the ultra-deepwater market recovery take place. I would argue, its already taking shape in harsh environment and we'll talk a little bit more about that. But the high specification utilization, harsh environment asset is 100% and dayrates reflect that.

Dayrates have moved from a low of about $150,000 a day to north of $400,000 a day in about an 18 month span. So recovery in harsh environment is clearly taking shape and we're starting to see the recovery in the ultra-deepwater space as well and why are we starting to see that. You guys don't get to have the customer conversations that we do. And so I can tell you that the customer conversations are really encouraging and that there are a lot of projects out there but you can't see it. So let me give you some public data that would hopefully help you get comfortable with the fact that the ultra-deepwater market is starting to recover and let's start with costs.

Offshore project costs have decreased significantly over the course of this downturn whereas the average offshore break even now for most projects is around $43 a barrel. For those who don't know that's very competitive with U.S. shale. So from a cost standpoint offshore has become very competitive with U.S. shale. Part of the reason to become competitive is because we have dramatically improved drilling and completion times. If you look here on the left hand side this is just for Brazil. You can see the days per deepwater well being cut almost in half from 121 days to 67 days and the entire supply chain is responsible for that.

Better planning from our customers, better coordination between our customers and us and the other service providers, and we are delivering well faster. We're drilling wells faster based on the technology that we have today. So that is leading to downtime to first oil being cut by 25. So now not only are the cost starting to be more competitive with shale but the time to first oil and if with the time that you take to get your return on investment is actually being compressed. And so these offshore projects now are becoming far more attractive as our customers look at their total portfolio and the total opportunity that they have to invest capital. Offshore is looking far more competitive.

So you got lower cost. You've got shorter cycle time to first oil. The fact that we as an industry have not invested offshore and have not invested much in the way of exploration is evident as you start to look at reserve replacement ratios. I mean this is a very telling chart. From a peak of almost 200% reserve replacement back in 2006 to 7% last year, 7% And it's -- I mean it's obvious we're not investing in exploration and so at some point in time that's going to come home to roost. I mean if you look specifically at the offshore market, we're only replacing one in every three offshore barrels produced.

You start to continue on that trend and you get into 2020, 2021 and you can look at a real supply deficit which would create a massive correction. Somebody is calling me on my phone. So, the other thing I point to, so you've got lower costs. You've got shorter cycle times. You've got real reserve replacement challenges. And all of the pressure that has been applied by some of the people in this room to the EMP companies are large customers has delivered the intended results.

Record free cash flow for the publicly traded E&P companies over the last year and expected to be very healthy again in 2019. So our customers gotten to the point where they have -- started to deliver the balance sheet and now they're generating enough cash to continue to deliver if they need to return cash to shareholders in the forms of dividends and share buybacks and to invest in both short term land projects and longer cycle offshore projects. So they can really take an all the above strategy and that's what we're seeing in our conversations with them.

I know that their CapEx budgets haven't changed meaningfully, but I'd offer two things One they're directing more that CapEx to offshore than they did historically prior to maybe the last year everything had been directed towards -- most everything had been directed toward land. So they're directing more offshore and they can do more with less, now that the project costs have come down so much. And so we are seeing activity-- opportunities for activity to pick up across the board.

And here's just another graph showing offshore spending continuing to increase. You can see the low point there in 2018, we're expecting a bit of an increase in 2019. And they're really ramping up in 2020 and 2021. I mean ignore the outer years. This is who knows what's going to happen in 2024 in 2025. But this is right. That's projection of offshore spending over the next several years. And what I would say is it's consistent with the conversations that we're having with our customers that spending and activity is poised to pick up offshore over the course, the next couple of years.

So then the question is all right let's give that to you, Jeremy we're going to see an increase in offshore spending which will create more demand for your assets and services. There's still way too many floating assets out in the marketplace way too much supply. I would argue that that's not the case. You know people plug into a spreadsheet. The total number of floaters out there and what of that 235 to 234 floaters out there. But only a 155 are contracted or soon to be contracted. The others you've got 35 that are idle or warm and 44 that are cold stacked.

If you look at the cold stacked assets out there today, it could cost anywhere between $50 million and $100 million to reactivate the asset. You'd have to have a pretty healthy dayrate, let's call it $325,000 a day for at least one year term just to pay back the initial investment that doesn't get your return. And so you start to look are those really marketable right now, not in this environment. We've publicly said we're not going to reactivate an asset what the customer pay for either in a monthly as well kind of a one-time lump sum reimbursement or in the form of a term and higher dayrates.

So there are many of those assets that we don't think are really considered part of marketable supply. You look at the idle and one stacked rigs you're looking anywhere from $25 million to $50 million. We'll take a look at all of the offshore drillers and tell me who can write a check like that without being reimbursed by the customer. But let's go in and say they're all in there. They're all in there and we're looking at a complete fleet of somewhere in the 234 2035 range.

As we look at our database and we look at the age, the technical specification and the estimated cost to reactivate. There are 50 assets that we don't have another contract. Now our peers may not actually recycle them like we do. They may not announce they're being retired, but they're never going to get another contract. So let's just say that there are 184 and again there's some of that one 84 that are going to require $50 to 4100 million to be paid. So I don't know how marketable they really are, but we'll give you the full number.

And then we're at 28 that are currently under construction in the shipyards. Most of them are primarily done, but they've been abandoned by the drilling contractor that initially ordered them. For those that remember back in the 2012, 2013, 2014 timeframe shipyard got very aggressive with financing. 5% down, 15% over the construction period, and 80% upon delivery. Well, we got to the 80% upon delivery and all the drilling contractors said, no, thank you, I don't want them. And so you've got assets that are just sitting in the shipyards. And if you look at what the original cost to construct these assets you're looking over $500 million per asset that is still owed in order to bring these out of the shipyard.

So take what I said about reactivation and magnified by ten -- five to 10, and so when are those going to actually hit the market. There's only one in those 28 that actually have the contract and that's the Deepwater Titan, the 28 rig that we talked about earlier. So honestly we don't really consider those part of the marketable supply. Today you're going to need a much better environment in order to bring any of those rigs out. At that point in time we're all going to be happy to bring those rigs out. Looking at $400,000, $500,000 a day in five year terms, but if you take them all together and you count on a newbuild you're looking at about 212 floaters in the global fleet.

And if you start to look at then what we expect utilization to be over the course of the next several years, you can see here that we're showing. Here's an interesting one. And now let's see if you can see it very well up here. On the left hand side this shows high spec sixth and seventh gen availability and utilization, so April 2018, so sixth and seventh gen, so the high specification of ultra-deepwater eight assets.

In 2018, April 2018 utilization with 69%, April 2019 that jumped to 84%. So, keep that in mind and then look at the chart on the right. This shows the dayrates by utilization rate historically and what you'll see there is when you jump from 80 to 85 percent utilization you see a dramatic increase in markets and just getting over 200 in the U.S. Gulf of Mexico. And so as you look at approaching 85% utilization for these best assets you could start to see a meaningful movement in dayrates as we move through the next several quarters and years.

We've already seen it in the harsh environment market and we talked about this before. But if you just look over the last year in Q1, sixth gen harsh environment assets were being priced at around $300,000 a day. And now in Q3 they're up over $400,000 a day. So dayrate can move very quickly for these high spec assets as utilization increases, as long as everyone remains disciplined, which we hope the entire sector will do. As you look then at ultra deepwater rates we are starting to see some movement, it's not as steep as we would like to see but it is moving. And so these are just utilization and geo in spot rates over the course of the last year and I'd kind of pull your attention to those in pink. So we signed the deepwater has to a contract last year at $125,000 a day.

We just signed that same rig with the same company in the same area for $185,000 a day, plus the bonus, that gets it up to $200,000 per day. So rates are moving in the right direction for ultra-deepwater as well as harsh environment. So we think based on what we have done with our floater fleet certainly because of our experience in the ultra-deepwater and harsh environment challenging markets because of our backlog and our liquidity position and we think we are very well-positioned as this market recovery takes shape. We are well into the recovery and harsh environment. And so glad that we have such a large participation in that market and we are just in the early stages of that recovery in ultra-deepwater.

We're seeing activity pick up in every market around the world and with every customer and dayrates are starting to reflect that just not as steeply as we would like. So we hope and believe that over the course the next couple of quarters we will see market improvement in dayrates, in ultra-deepwater and longer terms. And at that point time this business can generate a heck of a lot of cash at which point in time we start the delivering process. So with that.

Dave Anderson

So Jeremy, we just had a couple minutes here before, Jeremy who were going to break out in Riverside, just ask you one question here. So you talked about the automation on those soon to be six rigs up in Norway. You talked about the human machine engineering which is a really creepy term, but fine and then the hybrid power. Are those three things -- give me a sense of what's that CapEx like for you to add all three of those to a rig? How much incremental CapEx would that be?

And two; would you need a customer to pay for that before you were to do that or would you go out there and put it on a couple of rigs and have customers see how it works, hoping that although they'll jump on it?

Jeremy Thigpen

So let's start with ADC, the Automated Drilling Control. We are actually de minimis CapEx investment. I mean low single digit millions of dollars, $2 million to $3 million I think are piece of the investment with Equinor picking up the other piece of the investment. So that's not a very large investment. And the relationship we've struggled with Equinor which is very open, very transparent, very fair is they've actually given us more upside potential on performance bonus if we make this capital investment. So it didn't change our dayrate. But as we looked at the benchmark data and what we thought we could achieve with the ADC, the bonus potential is far greater than what we would have anticipated in terms of the fixed dayrate. So again, Equinor is very fair and we've got a great and trusting relationship.

We would anticipate being able to demonstrate otherwise six rigs, the performance improvements that we get from ADC and then marketing that to our customers and get them to pay for it in the form of capital investment or hard area performance bonus. The hybrid power, difficult to said at this point. Hybrid power is actually going to be and looking at my Chief Operating Officer over here, hybrid power we think is going to actually be more valuable in the ultra-deepwater drillships where we can actually demonstrate more improvement.

It just happened to be that Equinor is very conscious about its carbon footprint and so wanted to invest in this jointly. And so we'll have to see after we get it to market. Like I said, we're finalizing implementation. Now we'll see the benefits particular around fuel consumption emissions. And if we can demonstrate that there's real value there than something also that we would sell to the customers, its not something that we would go respectively.

Dave Anderson

And the last form of the human machine engineering is that – where is that in terms development or…?

Jeremy Thigpen

Very low CapEx, its existing technology we're just merging those technologies on the drill floor. So low capital investment and quite frankly that's one just from a social standpoint we got do it. You can find a way to keep people out of harm's way on the drill floor. You do it. And so that's one that we're going to pursue regardless.

Dave Anderson

That makes sense. Please thank me -- please join me in thanking Jeremy, CEO of Transocean.

Question-and-Answer Session

End of Q&A