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Edited Transcript of RIG earnings conference call or presentation 30-Jul-19 1:00pm GMT

Q2 2019 Transocean Ltd Earnings Call

ZUG Aug 12, 2019 (Thomson StreetEvents) -- Edited Transcript of Transocean Ltd earnings conference call or presentation Tuesday, July 30, 2019 at 1:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Bradley Alexander

Transocean Ltd. - VP of IR

* Jeremy D. Thigpen

Transocean Ltd. - President, CEO & Executive Director

* Mark-Anthony Lovell Mey

Transocean Ltd. - Executive VP & CFO

* Roddie Mackenzie

Transocean Ltd. - SVP of Marketing, Innovation & Industry Relations

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Conference Call Participants

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* Cale Dillingham

BMO Capital Markets Limited - Senior Associate

* Chase Mulvehill

BofA Merrill Lynch, Research Division - Research Analyst

* Coleman Wayne Sullivan

Wells Fargo Securities, LLC, Research Division - Senior Analyst

* Gregory Robert Lewis

BTIG, LLC, Research Division - MD and Energy & Shipping Analyst

* Ian MacPherson

Simmons & Company International, Research Division - MD & Senior Research Analyst of Oil Service

* John Booth Lowe

Citigroup Inc, Research Division - VP

* Kurt Kevin Hallead

RBC Capital Markets, LLC, Research Division - Co-Head of Global Energy Research and Analyst

* Sasha Sanwal

UBS Investment Bank, Research Division - Director & Equity Research Analyst

* Sean Christopher Meakim

JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst

* Taylor Zurcher

Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Director of Oil Service Research

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Presentation

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Operator [1]

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Good day, everyone, and welcome to the Q2 2019 RIG Earnings Conference Call, Transocean Ltd. Today's conference is being recorded.

At this time, I would like to turn the conference to Brad Alexander, Vice President of Investor Relations. Please go ahead, sir.

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Bradley Alexander, Transocean Ltd. - VP of IR [2]

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Thank you, Augusta. Good morning, and welcome to Transocean's Second Quarter 2019 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. (Operator Instructions) Thank you very much.

I'll now turn the call over to Jeremy.

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Jeremy D. Thigpen, Transocean Ltd. - President, CEO & Executive Director [3]

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Thank you, Brad, and welcome to everyone participating in today's call. As reported in yesterday's earnings release, for the second quarter 2019, Transocean generated adjusted EBITDA of $207 million on $805 million in adjusted revenue. These results were largely driven by a combination of exceptional uptime performance across our global fleet and performance bonuses which we earned on multiple rigs for delivering safe and efficient drilling operations.

For the second quarter and the first half of 2019, this combination of strong uptime performance and customer bonuses has resulted in revenue efficiency of approximately 98%, which is a testament to the superior operating performance from both the legacy Transocean fleet and the assets we've acquired over the past 2 years. While our crews and shore-based support staff deserve a great deal of the credit for the strong and consistent uptime performance, the support that we're receiving from our OEM partners through our care agreements is also a contributing factor. And as I alluded to last quarter, I am pleased to report that we have successfully added the 4 active ultra-deepwater rigs acquired in the Ocean Rig transaction to those care agreements, and we have a template in place to include other assets as we return additional rigs to work. At this point, we have effectively completed the integration of this transaction and expect to fully recognize the anticipated synergies as we move through the balance of the year.

I'd like to take this opportunity to thank the entire Transocean team for delivering another solid quarter. I'd also like to recognize those employees who played integral roles in the timely and seamless integration of Ocean Rig. In addition to strong execution during the period, since our last call, we secured a couple of contracts which we believe to be notable. Two weeks ago, Murphy selected the Deepwater Asgard to drill 2 wells in the Gulf of Mexico at a rate of $185,000 per day, with the opportunity to earn a performance bonus, which could result in total compensation approaching $200,000 per day.

While we certainly need and expect for rates to move higher over the coming months, this fixture demonstrates that we are clearly moving in the right direction for high-specification ultra-deepwater drillships. As another positive data point, just last week, the Transocean Barents secured a 3-well contract working for Equinor in Canada with an estimated duration of approximately 120 days beginning next spring, including mobilization, demobilization, along with ROV and casing services. Over the firm term of the contract, the rig is expected to generate revenues of approximately $54 million with additional opportunities to earn performance bonuses.

It is also important to note that we were able to secure a downtime bank as part of this contract. Needless to say, we are very pleased to have secured this fixture as it represents an improvement to the rig's prior rate and further demonstrates Equinor's trust in our abilities. It is also another tangible indicator that the high-specification harsh environment market is in full recovery.

As evidenced by these 2 contracts, we are actively pushing day rates across our global fleet. We bring tremendous efficiency to our customers' drilling programs. As such, we need to increase dayrates to levels that are more reflective of the value that we create. More importantly, dayrates must improve to levels that enable us to generate meaningful free cash flow.

In fact, to demonstrate our resolve in elevating dayrates, on a go forward basis and consistent with our most recently filed fleet stash report, unless restricted by our customers, we will post all future contracted dayrates.

Furthermore, we will not reactivate an asset without being compensated for the reactivation and startup costs in the form of higher dayrates, longer terms and/or lump-sum reimbursements. We believe that this dayrate visibility, combined with our disciplined approach to reactivations, will help to better demonstrate that our contracting philosophy is aligned with our investors' expectations for appropriate returns.

Turning to the market. Overall, the floating active rig count increased 6% in the first half of the year. Importantly, when including future rigs contracted, the total number of floaters under contract remains near 160 assets, keeping overall marketed utilization at a level above 80%. And while ultra-deepwater dayrates have not yet recovered with the same pace or trajectory as experienced in the high-specification harsh environment markets, they are clearly trending in the right direction, driven by the 14% year-over-year increase in the number of working ultra-deepwater drillships.

While we would've certainly preferred an even sharper recovery to start the year, we are encouraged by the overall direction in both the harsh environment and ultra-deepwater markets, which is being driven by the continued improvement and underlying market fundamentals.

Brent crew, which dipped into the low $50 per barrel range at the end of last year has averaged around $65 per barrel for the most of 2019. As an industry, we continue to streamline operations, contributing to the delivery of most ultra-deepwater projects at or below $40 per barrel.

Reserve replacement ratios for many of our customers continue to decline. And our customers are coming off a year during which they collectively generated record cash flows. So it should come as no surprise that utilization rates and dayrates have moved off of the bottom in every major operating basin around the world.

In the U.S. Gulf of Mexico, we remain engaged with multiple customers around projects that would require incremental rigs in the region. We have also had discussions with multiple operators regarding the need for additional 20,000-psi capable rigs as there are several programs being evaluated in the lower tertiary of the Gulf of Mexico that require high-pressure completions.

Given our experience with Chevron and the Deepwater Titan, our strong technical and operations teams and the fact that we have the Titan's sister rig currently under construction in the Jurong Shipyard, we believe that we are well-positioned should our customers decide to proceed down this path.

In Mexican waters, numerous operators appear poised to initiate further activity as initial results from early exploration programs have been positive. We anticipate beginning our third Mexican campaign, a multiwell program with Shell, later this year with activity running well into 2020.

Additionally, we anticipate drilling a second exploration well in the Trion field for BHP during the third quarter.

In the Caribbean, we are encouraged to see a recent fixture award in Suriname. This, however, is not surprising in the light of the immense success of programs over the past couple of years in neighboring Guyana, and it's hopefully just the first of numerous awards here.

Moving to Brazil. The Ocean Rig Corcovado and the Ocean Rig Mykonos remain on schedule to commence operations in Brazil in the fourth quarter, at which time, we will have 3 ships operating in country. With this installed base, our history of performance in this region, our industry-leading fleet and Petrobras contracting the remaining available local drilling rigs, we feel that we are well-poised to take advantage of the future opportunities that will undoubtedly arise in the coming quarters and years.

In Africa, the opportunities we discussed last quarter emerging in Angola, Nigeria, Ghana, Equatorial Guinea and Senegal are continuing to progress. In Egypt, the Discoverer India will begin her campaign with Borealis in August. This follows a successful campaign with CNRL in the Ivory Coast.

And as stated on past calls, it's important to note that awards in this region would likely represent a significant number of rig years as developments here are typically longer cycle in nature and therefore, can impact the market utilization significantly.

This optimism in West Africa, combined with the increased activity we had noted in Brazil and the Gulf of Mexico, represents an improvement in drilling throughout the Golden Triangle.

In Asia-Pacific, Shell has again contracted the Deepwater Nautilus for its 6-well program in Malaysia. This work commenced in May and will run through the end of the year. We continue to see strengthening in this market, especially in Australia, where recent awards reflect dayrates solidly in the mid- to high $200,000 per day range with additional opportunities on the horizon.

Turning now to the harsh environment market, the Norwegian North Sea remained strong. In fact, our newest addition to the fleet, the Transocean Norge is on scheduled to commence its maiden contract later today. The firm contract concludes in May 2020 that has options that extend into September. This high-specification semisubmersible marks our seventh world-class asset suitable for this market, and we anticipate that she will be in high demand as she approaches the end of her term.

As previously mentioned, we are pleased to be keeping the Barents in Canada. We have good visibility to future work for the Barents in Canada and remain encouraged by her prospects as she is clearly the highest specification asset in the country. However, if we're unable to secure the dayrates and terms that we believe she deserves, we maintain the option of returning her to Norway where we feel very confident we can place her.

And finally, in the U.K., we continue to see fixtures from the independents and majors alike that suggest the market will again be tightened at summer, which bodes well for the likelihood of year-around drilling for our fit-for-purpose assets that performed so well in the U.K.

In summary, we're extremely pleased with the direction of the high-specification harsh environment market, where our top-tier assets are fully utilized, dayrates are approaching and in some cases exceeding $400,000 per day, and customers are, once again, providing downtime banks and reimbursements for mobilization and demobilization.

And while we're somewhat frustrated with the pace and trajectory of the ultra-deepwater market, we remind ourselves that we have moved off the bottom and are clearly in the early stages of what we expect will be a much broader recovery. For this, Transocean is uniquely and exceptionally well prepared. We have spent the last several years positioning ourselves by establishing the offshore drilling industry's largest and most profitable backlog, providing us with unparalleled visibility to future cash flows, the industry's largest and most technically capable fleet of floating rigs and the industry's most talented and experienced crews and shore-based support personnel.

Until our next call, you can count on us to continue to execute on those things within our span of control. Specifically, we will continue to prudently high-grade our fleet just as we did these past few months as we added the Norge to our contracted fleet and we made the decision to recycle the Actinia. Through training, strategic partnerships and engineered solutions, we will continue to explore opportunities to create an incident-free environment, which means no personal injuries, no process safety events and no unplanned downtime for our customers.

We will continue to streamline and automate processes and activities and develop new or leverage existing technologies to outperform our customers' drilling plans and increase the number of economically viable targets within their respective portfolios.

And we will continue to take the necessary actions to extend our liquidity runway and ensure that we have the cash that we need to responsibly invest in our assets, our workforce and the community in which we operate. We believe that executing against these initiatives best positions Transocean for the recovery.

I'll now hand the call over to Mark.

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Mark-Anthony Lovell Mey, Transocean Ltd. - Executive VP & CFO [4]

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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 our third quarter 2019. Lastly, I'll provide an update to our 2019 shipyard projects as well as our liquidity forecast through 2021.

As reported in our press release, for the second quarter 2019, we reported a net loss attributable to controlling interest of $183 million or $0.30 per diluted share. After adjusting for favorable items associated with tax and unfavorable items associated with the early retirement of debt and sale of an asset, we reported adjusted net loss of $210 million or $0.34 per diluted share. Further details are included in our press release.

In the second quarter, we delivered adjusted EBITDA of $257 million with an adjusted EBITDA margin of 32% from over $805 million of adjusted revenue. We're very pleased to announce another quarter of efficiency -- of revenue efficiency outperformance, which includes achieving the majority our drilling contract bonus opportunities for the quarter.

We've also settled the long-outstanding customer dispute. We generated cash flow from operations of $153 million, an increase of $204 million of -- quarter-over-quarter, more than reversing the unexpected cash burn experienced in the first quarter.

For the second quarter, rig operating and maintenance expense were $510 million. This was below our guidance due to timing of in-service maintenance and project costs in the second quarter. These forecasted costs, together with the Transocean Spitsbergen's 10-year SPS, will be delayed to the third quarter.

Turning to cash flow and balance sheet. We ended the second quarter with total liquidity of approximately $3.6 billion, including cash and cash equivalents of $2.2 billion and approximately $1.4 billion from our undrawn revolving credit facility. During the second quarter, we amended the terms of our revolving credit facility to increase the capacity to $1.37 billion. We also opportunistically repurchased approximately $130 million of near-dated debt in the open market. Additionally, during the quarter, we successfully accessed debt capital markets issuing $525 million of senior notes due 2023 secured by the Transocean Endurance and Transocean Equinox, 2 of our high-specification harsh environment rigs under long-term contracts with Equinor.

As we have proven over the prior several years, we will continue to take all necessary steps to extend our general liquidity of runway, prudently reduce leverage and proactively manage our new debt and debt maturities.

Let me now provide an update on our third quarter 2019 financial expectations. For the third quarter of 2019, assuming revenue efficiency of 95% on our active fleet, we expect adjusted total contract drilling revenues to be approximately $785 million. Our forecast reflects the Transocean Norge starting its contract this week and the estimated 50 days of other service time with Transocean Spitsbergen.

We expect third quarter O&M expense to be approximately $575 million, including reimbursable expenses of $28 million. This sequential increase in O&M expense is driven by the following: expenses associated with the Ocean Rig Corcovado and Ocean Rig Mykonos reactivations of approximately $38 million related to contractually required customer expenditures that were initially expected to be amortized over the contract term; $16 million due to the shifting the Transocean Spitsbergen 10-year SPS into the third quarter.

In addition to the SPS, our shipyard's scope also includes the installation and commissioning of our automated drilling technology via the self-funding and so achieving enhanced bonuses as a result of improved drilling performance.

Lastly, the KG2 has approximately $6 million of shipyard expenses that will be recognized in the third quarter related to its upcoming campaign with Chevron in Australia. For the full year, we now expect O&M expense to be at the upper end of our previous guidance of approximately $2.1 billion. This updated guidance reflects the previously mentioned expense associated with the Corcovado and Mykonos being expensed in 2019 and the first to be amortized over the term of their respective contracts due 2021.

We expect G&A expense for the third quarter to be approximately $48 million, in line with the second quarter. Net interest expense for the third quarter, we expect it to be $160 million. This forecast includes capitalized interest of approximately $10 million and interest income of $7 million.

Capital expenditures, including capitalized interest for the third quarter anticipated to be approximately $215 million. This includes approximately $120 million for the 4 newbuild drillships under construction with approximately $65 million for the 2 Jurong drillships and up to $55 million for the Samsung rigs. Additionally, we expect maintenance CapEx of $95 million. Our cash taxes are expected to be approximately $10 million for the third quarter.

Turning now to our predicted liquidity at December 31, 2021. Including our $1.37 billion revolving credit facility, which matures in June of 2023, our end of year 2021 liquidity is estimated between $1 billion and $1.2 billion. This liquidity forecast includes an estimated 2020 CapEx of $900 million and 2021 CapEx of $900 million. The CapEx estimates include amounts for our newbuild drillships as well as fleet maintenance. Please note that our CapEx guidance excludes any future rig reactivations.

Being mindful of the importance of maintaining our strong liquidity position, we continue to carefully manage our balance sheet. We're remaining focused on generating cash and reducing leverage. As Jeremy mentioned, and subject to customer consent, we intend to disclose all dayrates going forward, increasing transparency and further demonstrating our commitment to generating positive cash flow. This approach also aligns our interest with those of our shareholders. We continue to witness increased utilization and dayrates in both the harsh environment and ultra-deepwater segments and remain steadfast on our commitment to generate free cash flow through the cycle from our best-in-class rig fleet.

This concludes my prepared comments. I'll now turn the call back over to Brad.

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Bradley Alexander, Transocean Ltd. - VP of IR [5]

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Thank you, Mark. Augusta, we're now ready to take questions. (Operator Instructions)

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question will come from Ian McPherson with Simmons.

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Ian MacPherson, Simmons & Company International, Research Division - MD & Senior Research Analyst of Oil Service [2]

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I certainly love the new look on the fleet status report. Jeremy, you made a couple of comments about additional opportunities under review for high-pressure 20K work in the lower tertiary. And I wanted to just follow up on that and get a sense of how far along those are and how -- what the odds are that you could land additional work in that domain within the next several quarters. Or do you think it's further out in time?

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Jeremy D. Thigpen, Transocean Ltd. - President, CEO & Executive Director [3]

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So there are multiple customers that are exploring this possibility. I'd say that there is one that is very close to a decision. And that decision could come before year-end. And in terms -- the others are probably a little farther out, maybe next year or even the year after for a decision. And in terms of our positioning, as I stated, we've got the only 20K award thus far. We think we're uniquely positioned with the second Jurong rig and that has a 3 million pound hook load. And so I think the combination of our experience, our breadth and depth of expertise and the fact that we've got a rig under construction that could be upgraded to 20K puts us in a very unique position.

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Roddie Mackenzie, Transocean Ltd. - SVP of Marketing, Innovation & Industry Relations [4]

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Yes. Ian, I'll just add into that to say that -- so we did expect one fixture this year, but we also expect another tender to come out this year. So that's pretty good to see that not only fixtures taking place but future work as well. So it could be 1 or 2 tenders. We'll see.

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Ian MacPherson, Simmons & Company International, Research Division - MD & Senior Research Analyst of Oil Service [5]

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Okay. Could I ask you a follow-up just on the fleet status? You've got a couple of rigs rolling later this year that I was curious about, the Henry Goodrich in Canada. Obviously, we're seeing good dayrates there for Tier 1 rigs. Goodrich being Tier 2, what are the prospects there? And then also, I think the Ocean Rig Poseidon is rolling up contracts in Angola pretty soon as well. Any comments on those?

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Roddie Mackenzie, Transocean Ltd. - SVP of Marketing, Innovation & Industry Relations [6]

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Yes. Sure. So the -- as you pointed out, the Tier 1 rigs are really in demand. So we're completely sold out there. For the Goodrich itself, she's going to finish up probably with the Husky program later this year towards the end and then we'll move her to the U.K. So we're looking at couple of things for -- there that we plan to pull the rig over during the wintertime, we'll see what happens. In terms of -- you asked about the Ryan as well. We actually just signed -- yesterday, we signed a contract to extend the rig by 30 to 45 days for another well in Angola, and that's with Sonangol P&P. I don't think I can release any of other information because we don't have permission from the operator yet. But that's a positive data point for us just to keep her busy a bit longer.

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Operator [7]

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Our next question will come from Taylor Zurcher with Tudor, Pickering, Holt.

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Taylor Zurcher, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Director of Oil Service Research [8]

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Maybe I'll start -- a question on the fleet status, I'll echo Ian's comments that the dayrate disclosures is exactly what the market is looking for. But as it relates to Discoverer Clear Leader, I know that rig's been idle for quite some time now, but in the latest fleet status, it looks like you've now stacked that rig. So just curious any more color as it relates to that decision. And then as we think about that rig going back to work in the future, it's a really highly capable rig. How quickly could you return it to active status? And what sort of cost would be required?

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Roddie Mackenzie, Transocean Ltd. - SVP of Marketing, Innovation & Industry Relations [9]

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Yes. So in terms of the market for the rig, so her being a sixth-gen rig, that's basically us prioritizing seventh-gen ahead of her. So in the meantime, we expect to keep her stacked for a little bit of time until -- as Jeremy said, we're looking to see that the dayrates are -- and the contract terms support full payback of the reactivations and not only that but seeing prospects going forward beyond that.

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Jeremy D. Thigpen, Transocean Ltd. - President, CEO & Executive Director [10]

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And just to add to that, Taylor, I mean this was really the result of the acquisition of Ocean Rig and where we've got 4 stacked high-specification, seventh-gen rigs, we feel, are going to be priorities for our customer before the Clear Leader will be.

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Mark-Anthony Lovell Mey, Transocean Ltd. - Executive VP & CFO [11]

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And as to your question as to cost to reactivate, for those type of rigs like the Clear Leader, we've indicated in the past, between $40 million and $50 million should get that rig back up and ready to work.

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Taylor Zurcher, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Director of Oil Service Research [12]

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Okay. Great. That's helpful. And then a question on the some of the newbuilds. You already covered the 20K psi-type opportunities but for the Santorini and the Crete, you still have pretty high back-end payments still due on those rigs. I realize you can push those back-end payments out to the right. But as it relates to kind of the contract you're looking forward to bring those rigs out, clearly, you're looking for a good rate, but is a 1-year term something you're comfortable bringing those rigs out, even if the rate's good enough?

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Mark-Anthony Lovell Mey, Transocean Ltd. - Executive VP & CFO [13]

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Yes. So let me take that. As you know, the final payments on those rigs are between $360 million to $560 million. In addition to that, you have the cost to bring the rig up, which would be anywhere between $75 million, $85 million. So you're looking at a substantial check to arrive. Recognizing of those payments only due at the end of '23 and early '24, we would still need to have a multiyear contract that generates a sufficient return on those assets before we pull it up. Clearly, we have assets that are similar to the Santorini that are currently sitting in prestack, which we could bring out for a lot less. So those will be prioritized over the Santorini as it relates to contract opportunities.

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Operator [14]

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Our next question will come from Chase Mulvehill with Bank of America.

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Chase Mulvehill, BofA Merrill Lynch, Research Division - Research Analyst [15]

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I wanted to come back and maybe just talk about the current environment on the ultra-deepwater dayrates. Maybe talk about what kind of momentum you continue to see and expect to see in the back half of this year. And do you expect that momentum to kind of continue into 2020?

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Roddie Mackenzie, Transocean Ltd. - SVP of Marketing, Innovation & Industry Relations [16]

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Yes. Good question. So we're looking at where we are for like the number of contracted rigs and the utilization level, what that's doing to dayrates. So what we've seen, a couple of different parameters. Let's look real quickly at the Gulf of Mexico fixtures because that seems to be a real yardstick in terms of where we see recovery. So since the beginning of the year, we kind of seen a pretty significant increase in terms of the dayrates. In fact, we plot all over these charts. And essentially what we're showing is dayrates have increased anywhere between 30% to 50% based on where they were in the lower part of the downturn, which really the last kind of low-level fixtures seemed to have been made in late 2018. So when we see the Asgard getting booked at rates approaching [$200,000], and then we see several of our competitors are [$170,000] and above in the Gulf of Mexico, that's very encouraging to say that, that has moved up pretty quickly. So if we think about it, we're frustrated that it's not moving even faster, but there is actually a very nice progression in that. And we look at that overall around the world and that's essentially what we're seeing is the dayrates are going up anywhere from 30% to 50% depending on the particular basin.

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Chase Mulvehill, BofA Merrill Lynch, Research Division - Research Analyst [17]

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Okay. And on the ultra-deepwater side, are you seeing a premium for seventh-gen rigs? Or is there just still not that much tightness on the seventh-gen to be able to see the premium there for -- between sixth- and seventh-gen?

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Roddie Mackenzie, Transocean Ltd. - SVP of Marketing, Innovation & Industry Relations [18]

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Yes. Well, I mean the seventh-gen, at the moment, it's effectively sold out. But because of the -- few of the shorter-term contracts associated with that, you're not seeing the big part of pushing towards [$300,000] yet. But certainly, the premium, I think, is more for a hot rig with a great record that's performing well. It doesn't necessarily have to be a seventh-gen, but that typically is the way that works as the higher spec goes to work first.

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Chase Mulvehill, BofA Merrill Lynch, Research Division - Research Analyst [19]

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As things tighten up, what do you think would be an appropriate premium on a seventh-gen versus a sixth-gen rig?

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Roddie Mackenzie, Transocean Ltd. - SVP of Marketing, Innovation & Industry Relations [20]

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It really depends on the targets that you're trying to hit. But I mean, 30%, something like that.

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Chase Mulvehill, BofA Merrill Lynch, Research Division - Research Analyst [21]

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Okay. One quick follow-up for Mark, if I may. Mark, do you have any free cash flow targets that you might -- would like to share maybe over the medium to longer term?

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Mark-Anthony Lovell Mey, Transocean Ltd. - Executive VP & CFO [22]

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Yes. Positive.

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Operator [23]

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Our next question will come from Kurt Hallead with RBC.

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Kurt Kevin Hallead, RBC Capital Markets, LLC, Research Division - Co-Head of Global Energy Research and Analyst [24]

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Jeremy, I think you made an interesting point about the requirements that you will need to kind of activate rigs on a go-forward basis. And I think you mentioned something along the lines of getting some element and commitments from your customer base. And I think clearly, by the way the stocks have been behaving even with the improvement in the underlying fundamentals of the market, it seems like investors would prefer that companies like yours would get the cash up front from the major oil companies and not necessarily have to rely on getting it regrouped over the course of the contract. So, I guess, it's a kind of a long way to set up a question of, do you think it's possible where the companies like yourselves could start to have productive discussions with the major oil companies that are generating this record cash flow and convince them that if they really want the rig, they can afford to prepay to get it out of the yard and kind of accelerate that process? I mean, any thoughts on that'd be appreciated.

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Jeremy D. Thigpen, Transocean Ltd. - President, CEO & Executive Director [25]

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Yes. We look forward to that day. I would say that right now, we're probably there and we've demonstrated that through some of the contracting terms in the harsh environment space. So with high-specification harsh environment assets, I believe, we're there with our customers. I believe you could command an upfront payment or reimbursement payment for reactivating a rig and mobilizing that rig to location. And we've demonstrated that already with the most recent contract. But with the ultra-deepwater fleet, we're not quite there yet. But as we start to see the market continue to tighten, as Roddie said, in the U.S. Gulf, I mean, we're basically at a 100% utilization. And so you could start to see that materialize in the ultra-deepwater space in the not-too-distant future. And that's what we really hope for.

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Roddie Mackenzie, Transocean Ltd. - SVP of Marketing, Innovation & Industry Relations [26]

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Yes. Kurt, I think where you'll see that is it'll show up in mobilization fees. So for example, the mobilization fee that we get with the Titan essentially pays for that moving of the rig over there. That's not something we're recovering over the term. So I think as Jeremy said, we are -- we have already seen it in several instances, the harsh environment being a good example, but I think you're spot on that most folks recognize, including our customers, that it is not entirely reasonable to ask for all things to be amortized over a contract and that cash flows are important and getting paid for mobilizations up front is the way we intend to push it.

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Kurt Kevin Hallead, RBC Capital Markets, LLC, Research Division - Co-Head of Global Energy Research and Analyst [27]

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Yes. And I appreciate that, and that's definitely helpful and a step in the right direction in the same context if demand is exceeding supply, and these oil companies are asking the industry to kind of pull rigs off the beach and you guys got to foot the up-front bill of the $50 million or whatever at the end of the day, they should be footing that bill, not necessarily the drillers, but that's more of me talking on the soapbox than anything else, but I'd be great to see the industry kind of press for that, which you're...

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Jeremy D. Thigpen, Transocean Ltd. - President, CEO & Executive Director [28]

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Keep preaching, Kurt. Keep preaching.

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Roddie Mackenzie, Transocean Ltd. - SVP of Marketing, Innovation & Industry Relations [29]

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We'll get up on that box with you.

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Kurt Kevin Hallead, RBC Capital Markets, LLC, Research Division - Co-Head of Global Energy Research and Analyst [30]

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Yes. For sure. So second thing, just in the context of liquidity forecast by the end of 2021, maybe following up on Chase's question for Mark, what free cash flow is associated with that liquidity dynamic on a cumulative basis out through 2021?

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Mark-Anthony Lovell Mey, Transocean Ltd. - Executive VP & CFO [31]

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Yes. So Kurt, we have this all in our deck, which you guys have seen many times before. The 2020 and 2021 CapEx numbers are pretty big for us. So clearly, we got a couple -- almost $2 billion of CapEx and we get pretty close to doing that during that time period. Obviously, this is based upon a dayrate deck, which can and will change. But we expect it to be pretty close to free cash flow positive throughout that period.

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Operator [32]

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We'll hear next from Cole Sullivan with Wells Fargo.

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Coleman Wayne Sullivan, Wells Fargo Securities, LLC, Research Division - Senior Analyst [33]

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I'll say thanks again for publishing the rates. I know you've heard that a few times, but I'm sure you'll keep hearing that from us. On just discussions today, how are you seeing the progression of duration and new tenders and private discussions? Are you seeing that begin to stretch out at all versus prior levels?

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Roddie Mackenzie, Transocean Ltd. - SVP of Marketing, Innovation & Industry Relations [34]

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Yes. So in terms of open demand, we were just plotting this week actually. So from the beginning of the year, our numbers on open demand have increased 35% in terms of number of rig years. In terms of number of rig opportunities, it looks like it's up about 15%. So that would suggest that our average duration is increasing, so that's good. But most importantly, that's a pretty big jump in open demand in terms of the number of rigs that has to be picked up. And you asked about what's kind of direct negotiation. So the numbers that we cite are the ones that are not just the public tenders but also the things that we know are happening perhaps on the site. So yes, there's definitely a shift towards direct negotiations when the customer is realizing that they don't have much choice of the specific assets that they want. So if you have a program that's not just bread and butter deepwater drilling, then they are being pretty specific about the rigs that they want. The operational record is very important but so are the unique specifications. So from our point of view, we're certainly seeing a lot more direct negotiations. And I think our competitors are probably seeing the same.

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Coleman Wayne Sullivan, Wells Fargo Securities, LLC, Research Division - Senior Analyst [35]

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All right. That makes sense. And just on the late '19 availability on some of your harsh fleet, like the Barents, has a gap in the contract there before the new fixture. And then you have other ones like the Leader and the Paul B. Loyd. How do you kind of see that over the fourth quarter where you have all the more seasonality coming in? Do see some visibility there behind the current contracts?

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Roddie Mackenzie, Transocean Ltd. - SVP of Marketing, Innovation & Industry Relations [36]

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Yes. So for several of them, we do. For others, it's going to be a little bit more challenged. But what we've seen happen is that we are pretty conservative in how we report durations on our contracts. So typically, the programs run a little bit longer. So with programs running a little bit longer, combined with some gap-filler work that we expect to close in the next month or 2, hopefully, there won't be too many gaps between now and next spring.

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Operator [37]

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We'll go next to J.B. Lowe with Citi.

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John Booth Lowe, Citigroup Inc, Research Division - VP [38]

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I wanted to start with a question on drilling efficiency offshore. We've seen really solid improvements in onshore rig efficiency in terms of wells drilled per rig or footage drilled. I'm just wondering if you guys could put some numbers around how much you've seen your own drilling efficiency improve over the past, let's say, couple of years? And how much more room do you think there is to go, given the higher-spec nature of the rigs that are operating today? How much more can we see that efficiency improve over the next couple of years? And as a quick follow-up to that, does that put a cap or at least a limit on the upside in the floating rig count that you would normally see in a more normalized environment?

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Jeremy D. Thigpen, Transocean Ltd. - President, CEO & Executive Director [39]

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So J.B., let me caveat this by saying that due to the downturn in the industry, it's our best assets and our best crews working and the same is true for our competitors. And so you're getting optimal efficiency performance plus all the time that we've put into it. So we probably see an incremental improvement of about 30% in some cases on some of our high-spec rigs, operating in the Gulf of Mexico and around the world for that matter. So I'd say 30% is probably a good place to start. There's always opportunity for improvement. We're working internally on processes. We're working with our OEMs on improving equipment performance. We're looking at new technologies. And so yes, there will be ways to continue to improve efficiency. What I'd say to that is as the market starts to recover and we start to bring assets at a stack status, we're reactivating crews, bringing new people in. Are we going to lose some of that efficiency as an industry? Absolutely. Obviously, we'll endeavor to get those rigs and crews up to the standard we've established so far. So yes, we've always contended that, that will put a cap on the number of offshore rigs required going forward. And in fact, if you look at the past pace, I think 2014, we had almost 270 floaters under contract and in operation. We've kind of been out there publicly for the last 4 years. And so that -- the new go-forward number may be closer to 200. And so that's why we've really taken the effort to high-grade our fleet and focus only on those high-specification assets because we think those are the ones that are going to work it in the market as it starts to recover.

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John Booth Lowe, Citigroup Inc, Research Division - VP [40]

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Okay. Great. Quick follow-up just on the contract on the Barents. Can you guys put some numbers on what the demob and the mob costs are going to be so we can kind of get a cleaner rate for that rig?

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Roddie Mackenzie, Transocean Ltd. - SVP of Marketing, Innovation & Industry Relations [41]

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Well, so we can. We discussed this with our customer and they would prefer that the actual dayrate not be known precisely. So all of it indicate -- that would indicate to you that it's a pretty good dayrate. So I have respect for our customers. We certainly can't divulge that if they ask us not to.

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Operator [42]

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We'll go next to Sasha Sanwal with UBS.

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Sasha Sanwal, UBS Investment Bank, Research Division - Director & Equity Research Analyst [43]

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Look -- and so a lot of my questions have been answered but just kind of wanted to touch on just the way to kind of think about potential reactivations for 2020 here. And so you had pretty forceful comments I think about kind of the requirements. You're going to get a full payback on reactivations and what that cost might be. Just -- right, just kind of wanted to get a sense of if there are any kind of benchmarks you can put out there in terms of how much of that reactivation you would kind of like to be essentially paid back within the first contract term and just essentially any guidepost to kind of help us get a sense of that.

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Jeremy D. Thigpen, Transocean Ltd. - President, CEO & Executive Director [44]

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Well, yes, Sasha, it's a good question and one we talk about internally. And if you look at the cost of reactivation, we've been public about this. Let's say, it's a $50 million ticket, you can back into the dayrate and term required just to pay back that initial investment of $50 million. And then you'd have to have confidence that either you have enough term to generate return on that investment or you have a follow-on contract that you feel really good about because otherwise, why go through the effort, and then you just have to stack it again. And so we're -- we have a very, very -- we have established a very high bar for reactivating an asset at this point in time.

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Sasha Sanwal, UBS Investment Bank, Research Division - Director & Equity Research Analyst [45]

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All right. Okay. That's helpful. And then maybe just kind of touch on the -- just essentially the -- I think you mentioned this, the Spitsbergen, just the installation of the automatic drilling technology, right? So maybe the question is to what extent are essentially customers requesting this? And would you be willing to share even a rough range of how we should think about the dayrate uplift?

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Roddie Mackenzie, Transocean Ltd. - SVP of Marketing, Innovation & Industry Relations [46]

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Yes. Again, so on the dayrate uplift, I'm not sure we can really share the details of that because it's in the confidential contract. But yes, in terms of customers interested in it, yes, customers are very interested in that because if you're able to drill the well, as Jeremy said, we've improved 30% in some of our assets. But I mean even if you're picking up 10% or 15%, it makes a material difference to the well costs. So that's why these kind of self-funding bonuses really work well for both sides. So I mean, we've been collecting very nice bonuses over the last couple of quarters. So we expect that to continue. But in terms of an absolute number, I don't think I can really divulge that.

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Jeremy D. Thigpen, Transocean Ltd. - President, CEO & Executive Director [47]

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But we have -- we did say on the last call, I mean as we look at the specific relationship that we have with Equinor in the installation of the automatic drilling controls, if we perform as we think we will, these will pay for themselves inside of a year.

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Sasha Sanwal, UBS Investment Bank, Research Division - Director & Equity Research Analyst [48]

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Okay. Great. And maybe if I could sneak in one more quick one. Just maybe in terms of some of the recent contract fixtures that were announced, can you maybe give us a sense of how competitive those were? And maybe just general thoughts on how you kind of see essentially the discipline from the other contractors playing out?

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Roddie Mackenzie, Transocean Ltd. - SVP of Marketing, Innovation & Industry Relations [49]

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Yes. So we would love to see lots more discipline from our competition. But yes, really, it's about -- you haven't seen anybody book any long-term fixtures at low dayrates. So that kind of tells you where everybody's head is in terms of the future. So that's good. The short term is a bit more competitive. And it depends on which basin you are, which region you are. But I would just say that if you look at the average fixtures and you see where things are going, it's not just us that are increasing the bidding rates, but it looks like almost all of our competitors are, 1 or 2 might be a little bit behind the curve, but hopefully, they'll catch up.

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Jeremy D. Thigpen, Transocean Ltd. - President, CEO & Executive Director [50]

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I think the important thing to note there is -- what Roddie led with, which was that no real long-term contracts have been awarded at low dayrates. And it's really just people are scrambling in some cases to try to fill gaps so that they don't have to take a rig idle or even stack it.

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Operator [51]

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We'll go next to Gregg Lewis with BTIG.

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Gregory Robert Lewis, BTIG, LLC, Research Division - MD and Energy & Shipping Analyst [52]

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I guess, Roddie, just following up on that sort of train of thought. If we were to look at like today versus a year ago, do you have a sense for how much the bid/asks between somebody like Transocean, which is more focused on price and overutilization versus maybe some of the competitors, how much that sort of bid/ask has, at the high end versus the low end, has kind of converged?

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Roddie Mackenzie, Transocean Ltd. - SVP of Marketing, Innovation & Industry Relations [53]

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Yes. So yes, they are converging, there's no doubts, right? I mean, the -- as you see the fixtures are much more closely grouped as a basket. If you look at it, like the Gulf of Mexico, in the last series of fixtures, basically, since this year, apart from kind of one outlier with the escalating 503, Pacific and ourselves and Seadrill are all booking stuff, [$165,000, $170,000, $180,000, $185,000] that kind of range. So -- there may be 1 or 2 outliers, but for the most part, the discipline seems to be there.

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Gregory Robert Lewis, BTIG, LLC, Research Division - MD and Energy & Shipping Analyst [54]

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Okay. Great. And then just totally shifting gears. I guess, I guess free cash flow is -- has been a little bit of a theme on this call. I guess that right now, out in the market, there's a tender in the North Sea potentially for a rig of the future. Now realizing that this is still years away. Is this something that we think Transocean is actively looking at pursuing?

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Roddie Mackenzie, Transocean Ltd. - SVP of Marketing, Innovation & Industry Relations [55]

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Yes, we are. I just (inaudible).

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Gregory Robert Lewis, BTIG, LLC, Research Division - MD and Energy & Shipping Analyst [56]

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Okay. And just sort of if you could give a little bit of color around how we should be thinking about when that startup could be and sort of like what, when -- or how we should be thinking about that?

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Roddie Mackenzie, Transocean Ltd. - SVP of Marketing, Innovation & Industry Relations [57]

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Let me stress, it would not be on a speculative basis. It isn't, it isn't. Yes, so that prospect is several years in the future. But really, it's -- if you look at -- in Norway, what you have is like a -- so I realize that CAT-Ds are fit for purpose, designed exactly to do what -- even to do in the most efficient manner possible. And so it's one of those exercises again, it is like, so what does the new CAT-D look like. And in terms of actually delivering that rig and starting that program, we think that's probably 4, 5 years away. So there is a lot of time to think about it. But on any given Sunday, we're always looking at what is the latest technology, what does the future look like. So I mean, our teams are looking at rigs of the future on a continual basis. It's just, at this moment in time, you would have to see a very significant investment from the operator upfront to see any of those take off.

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Jeremy D. Thigpen, Transocean Ltd. - President, CEO & Executive Director [58]

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And the specific opportunity you're referencing is driven by one customer who was trying to take a look at this. And so it would be -- have to be something that the customer -- we look at technology internally all the time, but it would have to be driven by and funded by the customer in order to get the thing to the finish line.

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Operator [59]

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We'll go next to Sean Meakim with JP Morgan.

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Sean Christopher Meakim, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [60]

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So just a couple of things. Wanted to kind of get your thoughts around how contract negotiations are evolving. You noted some more direct negotiations. Some of the operators are trying to get specific rig specs that they're looking for. Maybe could we talk about how -- what non-dayrate composition arrangements are being prioritized from your side or from the customer side? Are mob costs becoming more commonplace? Or is this only still in select tenders? Just would like to get more of a feel for how that's going on as you're negotiating these new contracts.

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Roddie Mackenzie, Transocean Ltd. - SVP of Marketing, Innovation & Industry Relations [61]

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Yes. So a lot of the direct negotiation stuff you're going to see is either because the operator already had the rig or the rig is, how would you say it, in the region immediately available. So in that case, mobilization costs are pretty low, I mean, practically zero. But what we're definitely seeing is that direct negotiations stuff is around the best-performing asset or unique specifications that really help them. So you would've seen the (inaudible) in South Africa, our sales in Canada and in the U.S. and a few others that are typically not tendered opportunities. In terms of the mobilization fees, we are seeing that across the Board now. So where there is a mobilization cost, then we are seeing mobilization fees getting paid. So I mean, I can't speak for my competitors, obviously, but from our point of view, that's very important and a new dynamic that these contracts become cash flow positive.

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Sean Christopher Meakim, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [62]

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Got it. That's helpful. And then just thinking about those few opportunities for larger projects where several rigs will be required. Are there enhancements you would consider to entice an operator to contract several rigs together? Or is that not as favorable as a strategy of trying to get the best terms you can for each rig at this point in the cycle?

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Roddie Mackenzie, Transocean Ltd. - SVP of Marketing, Innovation & Industry Relations [63]

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Yes. I think you've always got to balance that depending on how competitive things are. But I mean, you saw that. You're talking about baskets of rigs, you saw that Petrobras picked up 7 rigs. I mean, that's fantastic to see that kind of activity from Brazil. In terms of other operators looking at multiple rigs, there are a couple of multiple rig opportunities out there. And there's always a kind of a synergy when you pick up that -- the same contract for more than one rig with the same operator. But I don't think there's a volume/cash discount, certainly. I think it really is a case of each earning asset is earning the best she can.

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Operator [64]

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Our final question will come from Daniel Boyd with BMO Capital Markets.

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Cale Dillingham, BMO Capital Markets Limited - Senior Associate [65]

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This is Cale Dillingham on for Dan. Could you just clarify if your revenue guidance of $785 million includes amortization revenue?

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Mark-Anthony Lovell Mey, Transocean Ltd. - Executive VP & CFO [66]

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Yes.

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Operator [67]

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I'd like to now turn the conference back to Mr. Alexander for any additional or closing remarks.

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Bradley Alexander, Transocean Ltd. - VP of IR [68]

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Thank you, Augusta, and thank you to all of our participants on today's call. If you have any further questions, please feel free to contact me. We look forward to talking with you again when we report our third quarter 2019 results. Have a good day.

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Operator [69]

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That does conclude our call for today. Thank you all for your participation. You may now disconnect.