Good day, and welcome to the Quarter Four 2018 Transocean Earnings Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Bradley Alexander. Please go ahead, sir.

Thank you, Molly. Good morning and welcome to Transocean's fourth quarter 2018 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 Web site 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. Please also 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, Brad, and welcome to everyone participating in Transocean’s fourth quarter and full year 2018 earnings call. I’d like to start today’s call with a recap of 2018. As reported in yesterday’s earnings release, for 2018 the company generated adjusted normalized EBITDA of $1.1 billion on $3 billion in adjusted normalized revenue resulting in an industry best adjusted normalized EBITDA margin of 36%. As you well know for the past three plus years, Transocean has been acutely focused on enhancing the quality of our fleet, driving operational excellence through continuous improvements in safety, uptime and drilling efficiency, expanding our position as our customers’ universal first choice and extending our liquidity runway by adding to our industry leading backlog, converting a higher percentage of that backlog to cash and prudently bolstering our balance sheet through timely transactions. In 2018, we took several steps to further each of these objectives. Looking first at our fleet, we added 20 assets with an associated $4.5 billion in backlog through two corporate acquisitions and added another high specification harsh environment floater to the formation of a strategic joint venture. In January, we closed Songa Offshore, the first of our two corporate acquisitions. Through this transaction we acquired seven rigs including four high-specification harsh environment semisubmersibles on long-term contracts with Equinor. These assets were backed by almost $4 billion of high margin contracts extending into 2024. This acquisition was strategically important to us as it enhanced our harsh environment fleet, added scale in the strengthening market of Norway, increased our exposure to a target customer and through its significant backlog provided visibility to strong future cash flows which as you know is critical in the current market. Our second acquisition was Ocean Rig, which we just closed in December. With this acquisition we added 13…

Thank you, Jeremy, and good day to all. During today's call, I will briefly recap our fourth quarter and full year results and then provide guidance regarding the first quarter as well as the full year 2019, which includes the Ocean Rig acquisition for the first time. Lastly, I'll provide an update on our liquidity forecast through 2020. As reported in our detailed press release, for the fourth quarter 2018 we reported a net loss attributable to controlling interest of $242 million or $0.48 per diluted share. After adjusting for unfavorable items primarily associated with discrete tax items and impairment charges related to the previously announced floater retirements, we reported an adjusted net loss of $171 million or $0.34 per diluted share. Further details are included in our press release. Contract drilling revenues decreased $68 million sequentially to $748 million due largely to few operating days as well as unexpected weather-related downtime on two of our harsh environment rigs off the coast of Canada resulting in approximately $21 million in lost revenue. In addition, the quarter was also unfavorably impacted by the completion of the early termination revenue in our program resulting in a $24 million decrease and an unfavorable $21 million impact from the planned-and-extend contract extension on the Petrobras 10000. This was partially offset by the increase in revenue of approximately $15 million from the three working rigs acquired in the Ocean Rig transaction and better revenue efficiency than the previous quarter. In addition to the successful acquisition of Ocean Rig, highlights for the fourth quarter include fleet-wide revenue efficiency of 95.7% and adjusted normalized EBITDA margin of 34% that continues to lead the industry and showcase the strength of both our industry leading backlog and operational performance. And cash flow from operations of $238 billion. For the…

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

Thank you. [Operator Instructions]. We will take our first question from Ian Macpherson of Simmons. Please go ahead. Your line is open.

Thanks. Good morning, everybody.

Good morning, Ian.

Hi, Jeremy. Mark, when you guided full year revenues to 3 billion, could you give us what that figure is on your adjusted normalized basis that strips out the non-cash amortization effect?

Yes. So for 2019 we have $178 million of intangible amortization and $63 million of the step dayrate adjustment which I discussed previously.

Got it. Thank you. I also wanted to ask about the automated drilling technology upgrades on the Norway rigs. If you could maybe expand a little bit about what – percentage wise, what the efficiency gains have been or the Transocean Enabler that have been measured over the past couple of years? And also if you could talk a little bit more about any economic impacts to you as you apply these technology upgrades to the five additional rigs going forward in terms of is there a daily adjustment, is there a CapEx consideration, et cetera? Thanks.

Hi, Ian. This is Roddie here. So yes, really pleased to announce that and to answer your questions, basically the stuff that Jeremy talked about before our dashboards and those kind of things, those all work on what we call the flat spot parts of the whale curve that essentially shortened the non-drilling. The EDC system is all about optimizing the actual drilling time. So we achieved higher rates penetration and essentially that’s done through measurement of – our highly accurate measurement and application of the drilling system. So things like RPM, weight on bit, circulating pressures, those kind of things. So the investment that we made in this was basically a partial capital investment on equipment across the rigs and what we get in return is a pretty significant bonus opportunity. You asked the question about what improvements we expect to see? Well, we have seen up to 25% to 30% increased rate of penetrations on seven drilling sections and the overall expectation on the impact to the entire well curve is somewhere between 5% to 10% could go up to perhaps 15%. Now if we realize the base case, then our return on the capital investment will be approximately four or fivefold over a five-year period. And if we see the real upside of the potential of the technology fulfilled, that could be almost 10-fold over that five-year period. So it’s a very interesting technology. It’s a very solid economic model from our point of view. But our customers save tremendous amount of time and thereby expense. So again, it’s just one of the steps that we want to take in partnership with Equinor to make sure that we are driving the cost of offshore drilling down and making it as competitive as possible.

Very interesting. Thanks, Roddie. So in effect you are getting an incremental bonus revenue opportunity associated with these upgrades?

Absolutely. And it’s on contract on long-term signed deals with fixed periods. So this is actually a way of making incremental revenue.

And is the technology expandable beyond this customer or is there an IP exclusivity that confines it to Equinor?

No, absolutely expandable. And in fact, we would expect to see that implemented elsewhere around the world.

Good stuff. Thanks as always for all the information on the call.

Thanks, Ian.

Our next question comes from James West of Evercore ISI. Please go ahead.

Hi. Good morning, guys.

Good morning, James.

Jeremy, lots of good details on the deepwater market and how things are changing there. Curious to know though as you talk to customers, as you guys are negotiating these contracts which obviously you’re talking more about low cost, et cetera, is there a sense of urgency building within the customer base about securing rigs for late this year to 2020?

Yes, I think I’ll take that one. Basically what we see is for the higher specification rigs, that’s absolutely the case. So when we think about harsh environment, that’s very obvious. We’re essentially sold out of high spec rigs and the kind of next tier down is now being put to work at extremely healthy dayrates with big bonuses. You asked specifically about ultra-deepwater, so for high liquid assets we’re seeing a very similar thing. So obviously evidenced by the Chevron contract having the very high specification is extremely useful for a long-term view. But we have a couple of very high specified current state-of-the-art rigs that we expect to continue work through 2019 and then into 2020. So we see that market tightening and actually the number of high hook-load rigs available in 2020 should be very small indeed. In fact that may actually encourage some commitments on the other Jurong rig we have that is one of the ultra high rigs?

Okay. That’s great color, Roddie. And then on these assets as dayrates do move up here which it’s pretty clear they’re going to, with the new dayrates and the big bonuses, will you now get to at least cost of capital maybe even above return on the assets?

Yes, I think when we look at the Chevron picture as an example that basically gets us there. It gets us to returning the cost of capital entire asset plus the upgrades and what have you. In the rest of the market where we have more of the lower spec ultra-deepwater ships, we’re not quite there yet but we’re moving in that direction. In fact, we kind of saw a lot of kind of cash breakeven fixtures last year, but now we are already posting a couple of fixtures and extensions that are beginning to return healthier margins. So we’re really encouraged by seeing those commitments.

Perfect. Thanks, guys.

Our next question comes from Kurt Hallead of RBC. Please go ahead.

Hi. Good morning.

Good morning.

So, Jeremy, I just want to follow up. You mentioned there could be as many as 91 offshore projects being sanctioned this year versus say the 50 or so last year. I’m just curious, when you mapped that out to potential incremental rig demand, how many rigs does that – you think that will equate to, how many ultra-deepwater rigs does that equate to?

So I don’t know that we’ve gone to that extent. We have put together what we think rig count could look like by the end of the year. And if you factor in all the rigs that have rolled off contract this year and all the new opportunities that we think are available out there, we can see an exit rate for 2019 between 5% and 10% higher than where we exited 2018.

Great, appreciate that. And then the other commentary I think Roddie just talked about of having contract extensions for some of these utra-deepwater ships that previously had been running about cash breakeven. What I’m really trying to get a feel for here is as you look out at potential contracting opportunities whether they be late '20 or into 2021 and it appears to me that the ultra-deepwater rate structure, the discussion should start somewhere between $250,000 and something over $400,000 a day. Can you just kind of dial me back if needed or how do you see things evolving with respect to contracts for that 2021 time period?

I wouldn’t dial you back and what I’d say is that we have two proxies out there, if you will. So if you look at the harsh environment market, we saw over a nine-month period dayrates moved from about $150,000 a day to $300,000 a day plus bonuses for the high-end assets. So what Roddie was saying about the ultra-deepwater market if you look at those really high-end assets with the high hook-load capacity, we think you can see similar movement in dayrate. Maybe it’s not quite that fast. Maybe it is. So what you’re thinking about is not out of the realm of possibility just based on recent data that we have available to us in the harsh environment market. The other data point I would address you to or direct you to is the recent signing of the 20k rig with Chevron. So if you look at that rig and you back out the 20,000 PSI blowout preventers and you kind of back that out of a dayrate, you’re looking at a dayrate somewhere between $350,000, $375,000 a day for a premium seventh gen rig with 15,000 PSI and that’s a start date in 2021. Our customers have the advantage right now, there’s no doubt about that. So in Chevron’s mind, I can’t speak for them, but you would say, listen, a $360,000, $375,000 dayrate on a premium ultra-deepwater rig in 2021, they think they’re getting a discount of 350 to 375 a day. And so I think that bodes well in terms of thinking about dayrate. So I can’t tell you what dayrates are going to be, but we do have some data points out there that would point to somewhere in the neighborhood that you’re talking about.

That’s great color. Thanks so much. I appreciate that, Jeremy.

Our next question comes from Scott Gruber of Citigroup. Please go ahead.

Yes. Good morning.

Good morning.

I want to start with a question on the Norge. Jeremy, how are you thinking about the possibility of buying out the remaining interest in the rig? If you think that’s likely, can you comment on the timing? Is that this year, next year?

I think ultimately that’s the end game, but I think we’re going to need to see another fairly healthy contract or extension behind the current one before we make that decision. But I think both parties and the joint venture agree that ultimately market conditions support it that Transocean will ultimately own that rig outright.

Got it. And just following Kurt’s question on the face of demand recovery, Brazil seems to be a key region in terms of the outlook for demand recovery here with Petrobras now adding some more rigs and the majors picking up a number of new blocks. Can you just comment on the Brazilian floater count, specifically where you think that could end now at the end of '19, end of '20 and to '21 if you want to go out that far? How do you think about Brazil specifically?

Sure. We said on previous calls and I’ll turn it over to Roddie in just a sec. We said on previous calls that we think the more normalized rig count, if you will, if anything’s normalized in this market could be somewhere approaching 40 active rigs with 30-ish probably run by Petrobras and another 10 to 15 by the internationals. And so we think we can get to that point again. Unfortunately as is with all things in Brazil, things kind of pushed to the right never happen according to timetable that we would like. But I think if you get out a couple of years, you can certainly see a rig count of that magnitude. And Roddie, I don’t know if you want to add any more color?

Yes, absolutely. So when we think about just 2019 the near term, we’re expecting that Petrobras is going to make somewhat in the region of five to seven fixtures in 2019 which is great because that brings them up bottom and starts building the rig count a little bit. But in addition to that, you get another five to seven fixtures from the IOCs in Brazil. So that’s a pretty healthy outlook. The real interest is probably as you stated towards the end of '20 and '21 when things really start to push on. So yes, we’re just looking at the tenders out there just now and we think that that rig count in Brazil is going to increase over the next 12 to 18 months and I think after that it could increase quite sharply.

And if I could squeeze one more. Can you just comment on the types of rigs that are being demanded in the contracts, particularly with the majors but also with Petrobras just in terms of the quality step up? There seems to be one. So just wondering from your perspective what you’re seeing.

Yes, absolutely. So specifically to Brazil that is what we’re seeing is there’s a variety of tenders. So Petrobras in particular are very good at parsing out kind of categories of tenders. So in the deepwater tenders, they are demanding much higher specification rigs, lowering the average age and raising the average spec of the rig in Brazil. But then you also have some of the new tenders that are for obviously a little bit older rigs, but less capable. So there seems to be a pretty good spectrum of demand across the different specs in Brazil, but certainly a push for higher spec rigs or primarily more efficient rigs is where we see it going.

Okay. Thank you.

Our next question comes from Sasha Sanwal of UBS. Please go ahead.

Thank you and good morning.

Good morning, Sasha.

Jeremy, maybe the first question for you just to kind of follow up on some of your market commentary. I was intrigued by just some of the comments you were making about the ship tendering to direct negotiation, we’ve seen on past cycles as well and then some of your commentary just about potentially negotiating some of the shipyard potentially surveys for some of these reactivations. Can you kind of comment or maybe give us more color on just how broad based this is across region? And then maybe in some of these discussions, is the contract term that’s under discussion also?

Yes, I’ll let Roddie deal with that one.

Yes, sure. So as we think about direct negotiations, so what we’ve seen is there are more direct negotiations particularly around extensions of existing rigs, but what we’re also seeing is when a tender goes out here in the beginning, I think the replies now are that there are far less assets available that are highly desirable. So typically you’ll see an operator just selecting one or two that are available and going direct with those contractors which is obviously very positive for us. You asked about durations, so that’s actually one of the key themes that we do a snapshot year-on-year. So in January 2018 versus January 2019 and we’re actually seeing the length of the projects has more than doubled. So if you take the average length of a project, it’s doubled. So basically it demonstrates that things are looking much better for the long term. And then I think just in general as we go around the world, you see the direct negotiations clearly in Norway and the North Sea are prevalent now where everything was tender previously. I think that’s basically more often than not the case. And certainly for the high specification units in the ultra-deepwater side of things, there’s a lot of direct negotiations because again the supply of the best spec units is pretty tight.

Great. Thank you. That’s helpful. And maybe just as a follow up just wanted to see if we can get an update on just potential reactivation costs for the Ocean Rig asset, any change there? Thank you.

Sasha, no change to that yet. We’re still working through that. You’ve obviously seen our comments on the Ocean Rig Santorini and Crete. But at this stage we haven’t completed our analysis in updating our previous guidance of about $35 million for those rigs.

Thank you. I’ll turn it over.

Our next question comes from Greg Lewis of BTIG. Please go ahead.

Greg? Sorry, we missed the question.

Sure. So I guess my question is around the Chevron 20k stacked rig contract and really how we should be thinking about that on the dayrate curve, because if I think about that rig that seems like a one-off kind of biggest, best rig in the world?

Right. I’ll just kind of go back to what I say previously. If you backup the upgrade cost from the dayrate, you get to a 15,000 PSI kind of gen-seven rig with high hook-load capacity, there’s no doubt in the $350,000 to $375,000 day range. I think that’s the only market that we have out there today and so I’m thinking somewhere in that range as we get into 2021 for that type of asset, maybe a little north of that, maybe a little south, but I think something in that range is fairly reasonable.

Okay, great. And then I guess when the two rigs, the Ocean Rig, the Paros was I guess decided to be retired, how much equipment was able to be taken from that rig and sort of put back into inventory or sort of thought about? Just in thinking about the BOPs, the pipe, was there sort of any number we could throw on that?

No. It’s zero probably. That rig had gone through some pretty tough times with an owner that had gone bankrupt and had not invested in the asset at all. There were no records of any maintenance or original equipment documents. It had been cannibalized for parts and it was in pretty bad shape.

Okay, all right, guys. Thank you very much for the time.

Thanks.

Our next question comes from Taylor Zurcher of Tudor, Pickering & Holt. Please go ahead.

Hi. Good morning. Thank you. Jeremy, I think – in the past I think you’ve talked about potentially reactivating one to potentially two of the Ocean Rig floaters per year moving forward. And so my question is, is that still the assumption or fair assumption to make today? And I assume in the 3 billion revenue guidance for 2019, there’s effectively nothing embedded in there for rigs – on the Ocean Rig side that aren’t currently contracted today?

Well, the pace of reactivation is going to depend on the contracts. And so to the extent that we can secure contracts that are deserving in reactivating the asset, then we’ll make that decision at that point in time. But given what we’re seeing in the marketplace, it’s probably not unreasonable to think that. What was the second part of the question?

Yes, let me just add to that. So we’ve included no reactivations into our guidance be it revenue or be it OpEx or CapEx. Just to remind you, Ocean Rig does have two warm stacked rigs sitting in Las Palma. So those will be the first two assets more likely than not to get reactivated to contract.

I’d also add that we’re at the point in the market now for the right assets that I don’t believe we any longer have to fund the mobilizations or the reactivations ourselves. So I think a lot of this stuff that our customers will see has been in the market and basically inclusive of them paying those costs. Essentially, as Jeremy had indicated, the operators deliver record level cash flows which doesn’t make sense really for us to be funding those reactivations at this stage. Certainly maybe a few fixtures that were made in the past will include that, but I think going forward much less of it.

Okay. Thanks for that. And if I heard you correctly in prepared remarks, you talked about a third drillship likely being mobilized to Mexico for one of our ISC customers. If I heard that correctly, is that a rig that’s currently contracted or is that a rig that would be idle today?

That’s a rig that’s currently contracted and operating the U.S. Gulf of Mexico.

Okay, got it. Thanks. That’s it for me.

Our next question comes from Eirik Rohmesmo of Clarksons. Please go ahead. Your line is open.

Thanks. Can you just discuss a bit more around the second newbuild at Jurong in terms of you mentioned potential opportunities? Is it fair to assume that that rig will be the one chosen for other high spec opportunities in the U.S. Gulf of Mexico? And in terms of additional CapEx, will that be in the same kind of range?

There’s certainly interest for that asset across multiple customers. And so we’re obviously in conversations on that rig right now. But in terms of further upgrades to that rig, we don’t have anything planned at this juncture. We did upgrade it to the 3 million pound hook-load, which certainly differentiates it in the class of rigs. And so it is going to be we think a rig that will be in high demand once it’s delivered.

Yes, certainly the high hook-load and a few other key features that are on that rig make a very interesting for the really difficult deep wells in the Gulf of Mexico. And also as Jeremy said, this time we’re not planning to do proactively but definitely with a contract she will be just an ideal candidate for the second 20k rig.

All right, thanks. And just quickly on the Ocean Rig transaction, is there any update on the estimate of synergy effects on that or is the number still $70 million or so?

Eirik, we’re going to start behind our $70 million. And as I’ve mentioned previously, we expect to get that all in 2019.

Perfect. Thanks.

Thank you.

Our next question comes from Colin Davies of Bernstein. Please go ahead.

Hi. Good morning. I wonder if we could get a little bit more color on the Master Service Agreements you mentioned in the prepared remarks, a sense of how rig-specific is it, pricing, term, just a little bit more color would be helpful? Thank you.

Yes, I’ll take that one. So the Master Service Agreements that we enter are actually a vehicle for which to contract very expeditiously. So standard terms and conditions like liabilities, indemnities and such are then kind of memorialized in that Master Service Agreement. And the piece that does get negotiated each time is often a service agreement that’s attached to it that deals with the rig specific. So which particular asset is, how long the program is, when it starts, those kind of things.

That makes sense. That’s helpful. Thank you. And then just on further scrappage obviously, the Paros was an interesting one as you say fairly degraded sixth gen. Do you think that’s kind of a one-off special situation or do you think the industry and perhaps transactions specifically is now taking a harsher view on perhaps some of those earlier sixth-gens that are still sitting down?

Yes, the Paros was definitely a special circumstance. As I said, the owner went through bankruptcy and became virtually not existent. He didn’t invest anything in the asset and so it was just – it was basically just a hole that remained. And so that was a very special circumstance. With respect to our played strategy, I think we’ve been pretty clear and consistent over the course of the last four years. We are focusing on that high specification ultra-deepwater drillship and harsh environment semisubmersibles. But I don’t think you’re going to see a big push to eliminate sixth-gens from the global fleet; still a very marketable asset, it’s a very capable asset.

That was helpful. Thank you.

We will take our last question today from Sean Meakim of JPMorgan. Please go ahead.

Thank you. Hi. Good morning.

Good morning, Sean.

I was hoping we could maybe just talk a little on contract strategy today. How are you thinking about managing fixed price options? Are you factoring in escalators, variable indexing? Just thinking about new contracts, is it different than maybe how you thought about that a year ago? And to some extent, if drilling efficiencies lead to contract impairments, how does that sit near term if it’s – ultimately those results are helping to drive incremental opportunities with customers?

I’ll handle that one. I think in terms of impairments for high performance, we definitely don’t see that. What we see is a great performing rig gets re-contracted and actually helps the operators justify picking up additional rigs because their cost per well goes down. So that’s really the direction to push into.

And with respect to the larger contracts, we definitely had a different view today than we had 12 to 18 months ago as it relates to the ultra-deepwater market and are unwilling to lock up our best assets and longer-term contracts at today’s dayrates. And so anything beyond the next 6 to 12 months, we’re going to have escalations built in for any term beyond that or we’re just not going to accept --

Absolutely. And I think you see that really keeping validities much shorter and obviously honoring offers that we’ve made in the past, and I’m sure many of our competitors will that going forward there’s much less willingness to offer options because they create some uncertainty as to availability and be pricing now. We’re obviously placing that much higher level for future work.

Got it, that’s very helpful. I appreciate that feedback. And then with respect to the rig automation updates, Equinor has been a trailblazer in a number of these areas for a long time. Are there other operators as focused on efficiencies, are there specifics that make these rigs more amenable, just thinking about what the addressable market is for you, for ADC upgrades?

No, absolutely. ADC is actually several components pulled together and those components are of great interest to others around the world. So it just so happens that we cannot jump first in Norway. But in the Gulf of Mexico here we’ve got several of our major customers are very interested in technology and efficiency upgrades. So I think you can see it translate very quickly to Gulf of Mexico side, but then to be honest any rig that would benefit from it is a candidate.

Okay, fair enough. Thank you.

This concludes today’s question-and-answer session. Mr. Alexander, I will now turn the conference back to you for any additional or closing remarks.

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 first quarter 2019 results. Have a good day.

This concludes today’s conference call. Thank you for your participation. You may now disconnect.