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Transocean Ltd
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Ladies and gentlemen, good day and welcome to the Third Quarter Transocean Limited Earnings Conference Call. Today's conference is being recorded.
At this time, I would like to turn the conference over to Mr. Brad Alexander. Please go ahead, sir.
Thank you, David. Good morning and welcome to Transocean's third 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.
During today's call, following those statements made by both Jeremy and Mark, we will conduct a question-and-answer session. During this time, to give more participants an opportunity to speak, please limit yourself to one initial question and one follow-up. Thank you very much. I'll now turn the call over to Jeremy.
Thank you, Brad and welcome to everyone participating in today's call. As reported in yesterday's earnings release, for the third quarter 2019, Transocean generated adjusted EBITDA of $245 million on $832 million in adjusted revenue.
These results were once again driven by a combination of exceptional uptime across our global fleet, which resulted in revenue efficiency of 97% and performance bonuses, which serve as the ultimate acknowledgment that we continue to deliver safe and efficient drilling operations for our customers.
In spite of the challenges we have faced during the downturn, we have continued to focus on improving all aspects of our operations. Our consistently high uptime performance, continuously improving drilling efficiency and our industry best operating margins are a testament to this focus and to the hard work, dedication and professionalism of our valued team members at Transocean.
Looking more closely at our third quarter performance, as a whole our fleet continues to meet and often exceed expectation. I'm especially proud of two of our rigs that began new campaigns during the third quarter. In July, the Transocean Norge began her maiden contract, drilling for Equinor in the Visund field offshore Norway.
The Norge is one of the finest harsh-environment semisubmersibles ever delivered and as has become customary for the new build assets Transocean has placed into the market over the past four years, the Norge has delivered stellar uptime of 97% during her first three months of operation. This is again a great representation of what a customer can expect when they contract one of our newly delivered assets.
The same level of performance can also be expected by our customers from our legacy fleet. The Discoverer India commenced operations in early September for Borealis and has delivered uptime in her first two months of operation that exceeded 97%. This follows a successful campaign with CNRL and Ivory Coast after she was upgraded in 2017.
With this track record of performance Borealis has already exercised its first contract option and we're optimistic that Borealis will continue to exercise their options, which could extend her time in Egypt well into 2020 after aggressively increasing day rates.
Looking at the next two rigs entering our active fleet, I am pleased to report that both the Corcovado and the Mykonos, two of the highest specification drilling rigs we acquired in the Ocean Rig transactions have arrived in Brazil and are going through the final preparations before commencing operations on their respective contracts with Petrobras in the second half of November.
These rigs were among the top-performing asset for Petrobras before they were ultimately stacked after completing their contracts in early 2018. And given our thorough process and proven track record for reactivating and upgrading assets, we fully expect both rigs to quickly ascend to the top of Petrobras' rig ranking again.
While we're certainly pleased to be adding rigs to our active fleet, in early September we announced our intention to remove the Enterprise-class ships from our fleet. These rigs are the Discoverer Enterprise, Discoverer Spirit and Discoverer Deep Seas.
All three of these drillships commenced operations around the turn of the millennium and at the time represented cutting-edge technology as they were the first ultra-deepwater drillships with dual-activity capability.
However, as we turn the clock forward approximately 20 years, the superior capabilities present on the more modern drillships in our fleet combined with the estimated costs associated with reactivating and placing these older assets back into the market have resulted in us now prudently electing to recycle these ships in an environmentally responsible manner.
Also in September, we took the decision to relinquish our interest in the ocean rig Santorini and the ocean rig Crete. These drillships were under construction in South Korea and the rights to these assets were acquired through last year's acquisition of ocean rig.
Although all signs point to an improving market and both assets represent high specification ultra-deepwater floaters that would complement the other assets in our fleet, the approximately $1.1 billion of remaining commitments associated with completing and taking delivery of these assets make them cost prohibitive.
Sticking with the fleet, we continue to explore opportunities to enhance our existing assets to increase their marketability, profitability and sustainability. Earlier this month, we announced the deployment of the offshore drilling industry's first hybrid-energy storage system aboard a floating drilling unit which we installed on the Transocean's Spitsbergen, which is not drilling for Equinor at its North field in Norway.
This patented hybrid power technology better utilizes the rigs powerplant by storing energy in batteries that are strategically placed around the rig. This stored energy is then used to power the thrusters as well as other critical components thus reducing fuel consumption and enhancing the efficiency of our entire power distribution system.
The hybrid energy storage system also improves the reliability of a dynamically positioned rig station keeping enabling operation under either diesel or battery power providing additional redundancy, which is an added and important safety feature.
As would be expected the reduced use of fuel during normal operations both lowers the cost of operation and reduces nitric oxide and carbon dioxide emissions thereby reducing the carbon footprint of the rig. The implementation of this system is consistent with the aspirational goals that we have outlined in our recently published sustainability report, and furthers our desire to continue introducing efficient and sustainable technologies that deliver higher-value wells to the industry.
Turning to our contracting activities since the second quarter call in addition to the previously mentioned Burullus option exercise for the Discoverer India working in Egypt, we added four additional fixtures. Shell has committed to another well for its current program of Brunei using the Deepwater Nautilus.
As was disclosed in our Fleet Status Report the day rate associated with the rig increased almost 50% from its prior contract and illustrates both the tighter market we are seeing and the bidding discipline we continue to maintain. It is also a testament to our continued strong performance with Shell globally and our confidence in Transocean's ability to consistently deliver safe, reliable and efficient operations.
In Angola, Sonangol contracted the Deepwater Orion for continuation activity that completed near the end of the third quarter. The rig is now available and we see a number of opportunities on the horizon in West Africa with starting dates beginning no later than the middle of 2020.
In the North Sea, Hurricane Energy awarded the Paul B. Loyd Jr., a three-well plus completion program starting in February 2020 with a solid day rate that has significantly improved over her previous contract.
And finally, I'm pleased to report ConocoPhillips just recently signed the Leiv Eriksson for 125 days at a healthy day rate in Norway starting in August of 2020. In total, we added approximately $130 million in new backlog since our second quarter conference call.
While this gross number may seem slightly lower than normal to some it is the direct result of our commitment to remain disciplined in our approach, pushing day rates to levels that improve our cash flow from operations and are more reflective of the value that we bring to our customers' drilling programs.
As a result of the downturn for the past four-plus years we understand the drilling contractors have often been operating ultra-deepwater assets at day rates approximating a cash breakeven cost. In fact at numerous instances, we suspect contractors have entered into contracts that were guaranteed to generate negative cash flow simply to avoid the cost of stacking.
Obviously that approach is not sustainable and for the past several months we have been purposely executing a bidding strategy whereby we only entered in the contracts that we know would generate positive cash flow. This approach especially applied to situations requiring the reactivation, mobilization or upgrade of our rigs.
In those cases as we said on the last call, we will not reactivate an asset without being compensated for the reactivation and startup cost in the form of higher day rates, longer terms and our lump-sum reimbursements.
Our execution of this strategy is yielding some very solid results and although we do not disclose the details of conditional LOIs and LOAs and so they become finalized contracts we are very pleased to see that our first-class operational delivery and disciplined bidding strategy has been rewarded with several LOIs that place near-term ultra-deepwater fixture rates firmly in the mid-$200,000 per day range.
Turning now to the market. Overall, the active floating rig count remained consistent with the prior quarter. Also in line with last quarter the total number of floaters under contract remains near 160 assets keeping overall marketed utilization at a level above 80%.
Of note when we look at the overall number of floating rig opportunities, we identify 90 likely programs spanning approximately 64 rig years. These numbers have continued to grow throughout the year and importantly the average contract durations are lengthening.
We're announcing multiple markets in both the ultra-deepwater and harsh environment where the number of opportunities are either at/or above the number of marketable rigs currently available. As such, we anticipate new contracts to reflect materially increased day rates, which will generate significantly improved cash flow.
This may come as a surprise to many, but even with the dip we've seen in oil prices over the last couple of months, customer interest is now a five-year high. I've discussed this previously but what continued to drive this level of customer interest is both the reduction of breakeven levels that continue to materialize across the offshore space and the confidence in the sustainability of these improved project economics.
There's no question that the current macro uncertainty around energy demand is driving our customers to remain cautious in their investments especially regarding longer cycle projects. However, their confidence in the superior economic they now expect from both of their deepwater and harsh environment portfolios continues to keep their project teams engaged such that they can quickly greenlight projects as the market recovers.
Data indicates that in addition to the improving economics we are experiencing offshore the shale boom that has provided the majority of all incremental supply relative to demand over the past five years is much closer to its peak than was previously anticipated.
Productivity from onshore wells appears to have topped out in 2017 and experienced declines in 2018 followed by further declines in 2019. Recent estimates indicate that oil prices need to average around $60 per barrel to support U.S. onshore supply growth of approximately 0.5 million barrels per day.
As we look at contracting offshore, we are pleased to observe that the recovery is certainly upon us. While we would have preferred a more accelerated uptick by now, we are excited by the continued strengthening in the harsh environment market and we're very encouraged by what we're seeing in the ultra-deepwater markets across multiple basins.
In the U.S. Gulf of Mexico, we continue to have constructive discussions with multiple operators regarding the need for a second 20,000-psi capable rig. As you'll undoubtedly know the Deepwater Titan will be the world's first 20,000-psi capable rig that will commence operations for Chevron in 2021. And because of our three million pound hook load the Titan's sister rig, which is currently under construction remains the industry's most obvious solution for the next 20,000-psi commitment.
It should also be noted that Transocean has invested heavily into 20,000-psi capability and has an experienced team that makes Transocean, the low-risk and preferred solution for our customers. And with some customers indicating a desired commencement of activity in late 2020, it's not unreasonable to expect a final investment decision to occur in the coming months.
In addition to the 20,000-psi opportunity, a number of players continue to inquire about ultra-deepwater rig availability in the Gulf, largely for activity commencing in the first half of 2020.
As I stated many times over the last year, well economics in the Gulf continue to improve. This is driven largely by efficiency that reduced project costs through short-cycle times thus derisking projects and making them more attractive options in our customers' respective portfolios.
In Mexican waters positive results from early exploration activity has further heightened our confidence that activity in the market will increase. In addition to the expectation of further exploration work, we're encouraged that a number of development opportunities appear imminent.
In the Caribbean, the continued success at Guyana along with budding opportunities in neighboring Suriname and Trinidad is likely to continue absorbing ultra-deepwater capacity.
Moving to Brazil. In addition to the six rigs that Petrobras recently contracted, we anticipate that they could contract a further three rigs by early next year. We also anticipate another handful of rigs are likely to be contracted through 2020 as a number of international players begin kicking off their pre-salt programs.
In West Africa, I'll start with Angola where we continue to see a growing number of opportunities in addition to the awards made over the last few months. Consistent with this improved forward-looking utilization, the day rate levels are now increasing and appear to be comfortably above $200,000 a day for sixth-generation ultra-deepwater drillships. Additionally, we see a couple IOCs looking to start campaigns in Nigeria along with opportunities in Ghana, Equatorial Guinea, Ivory Coast and Senegal.
In East Africa, we're encouraged by three IOCs looking to kick off their long anticipated projects that would further increase rig utilization. In Asia Pacific, we continued to successfully contract our rigs and anticipate further activity from a number of countries including Brunei, Indonesia, Malaysia, Myanmar and Vietnam. The strongest market in that region remains Australia where awards continue to support day rates solidly in the mid to high $2000,00 per day range and we expect fixtures later in 2020 ready to push closer to the $300,000 per day mark as supply tightens.
Turning now to the harsh environment market. The Norwegian North Sea remained strong and we look -- as we look into 2020, we see a number of programs on the horizon that will keep the market for the high specification assets at full utilization, which would support higher base day rates.
In Canada, the Barents will be completing her current work with Suncor later this year and then kick off her next project with Equinor extending into the middle of 2020 if not longer depending on the success of their program. As the Barents is clearly the highest specification asset in country, we will look to keep her in Canada following her work with Equinor. However, if we are unable to secure the activity in rates we believe are warranted, we will consider the option of returning her to Norway, where we have exceptional confidence in the high-specification harsh environment demand.
In summary, we remain pleased with the direction of the high-specification and harsh environment markets, where our top-tier assets that are fully utilized and day rates for such assets are approaching and in some specialized cases exceeding $400,000 per day. And we're becoming increasingly encouraged by the ultra-deepwater market with the list of opportunities continues to grow rapidly and longer-term campaigns are beginning to surface. The combination of which will inevitably lead to higher day rates for our high-specification assets that are most coveted by our customers.
Strategically, from an asset backlog and balance sheet perspective, Transocean remains uniquely and exceptionally well prepared. We spent the last several years positioning ourselves by establishing the industry's largest and most technically capable fleet of floating rigs with the industry's most talented and experienced crews and shore-based support personnel.
We have the industry's largest and most profitable backlog, providing us with unparalleled visibility to future cash flows and a manageable debt maturity schedule along with an undrawn revolver providing continued financial flexibility. As we've consistently done, we will continue to actively manage our fleet, removing assets we deem no longer marketable, while continuing to monitor high-specification assets available in the market.
We will continue to explore opportunities to create an incident-free environment with the ever-present goal of eliminating personnel injuries, process safety events and unplanned downtime on our rigs. We will continue to streamline and automate processes and activities, while exploring and ultimately integrating new technologies to outperform our customers' drilling plans and increase the number of economically viable targets within their respective portfolios.
And we will accomplish this, while prudently managing our liquidity runway to ensure that we have the cash that we need to responsibly invest in our assets, our workforce and the communities in which we operate. We're confident that these initiatives best position Transocean to capitalize on the recovery, which is now underway.
I'll now hand the call over to Mark.
Thank you, Jeremy and good day to all. During today's call, I will briefly recap our third quarter results and then provide updated guidance for the fourth quarter 2019. I will also share a first look at 2020. Lastly, I'll provide an update on our liquidity forecast through 2021.
As reported in our press release for the third quarter of 2019, we reported a net loss attributable to controlling interests of $825 million or $1.35 per diluted share. After adjusting for favorable tax items and unfavorable items associated with impairment charges related to the previously announced further retirements, we reported an adjusted net loss of $234 million or $0.38 per diluted share. Further details are included in our press release.
For the third quarter, we are operating a maintenance expense of $547 million. This $28 million favorable variance to our guidance is primarily timing related and is now expected to be incurred in the fourth quarter. I will provide further guidance -- further detail when discussing our fourth quarter O&M expectations.
Looking now at our balance sheet and some strategic actions taken during the quarter. As Jeremy mentioned, during the third quarter, we decided to scrap three of our fifth generation ultra-deepwater floaters: The Discoverer Deep Seas, the Discoverer Spirit and the Discoverer Enterprise. This resulted in a non-cash impairment charge of $580 million.
We will continue to assess the marketability of our fleet and take decisions to recycle rigs when they are deemed to be no longer profitably marketable. Also, during the quarter we opportunistically repurchased approximately $250 million of near-dated debt in the open market serving us approximately $75 million in interest to maturity.
As we have demonstrated over the prior several years, we will continue to take all necessary steps to extend our liquidity runway, prudently reduce leverage and proactively manage our new debt maturities. In this regard, we dissipate using cash on hand to retire our remaining 2020 and 2021 debt at maturity.
Turning to our cash flows. We generated cash flow from operations of $91 million during the third quarter, a slight decrease sequentially due to the timing of receivables and interest payments. We ended the third quarter with total liquidity of approximately $3.2 billion including cash and cash equivalents of $1.9 billion and approximately $1.3 billion from our undrawn revolving credit facility.
Let me now provide an update on our fourth quarter 2019 financial expectations. For the fourth quarter of 2019 assuming revenue efficiency of 95% on our active fleet, we expect our adjusted contract drilling revenues to be approximately $825 million. Our forecast reflects the Deepwater Corcovado and Deepwater Mykonos commencing drilling campaigns in November with Petrobras in Brazil. We also have the KG2 starting her contract in October with Chevron in Australia.
Additionally, several rigs conclude their contracts during the fourth quarter including the Asgard, the Nautilus, the Barents, the Paul B. Loyd, the Transocean Leader, and the Henry Goodrich. Except for the Asgard and the Henry Goodrich all of these rigs begin new contracts in 2020. The Asgard has bid on several U.S. Gulf of Mexico tenders with early 2020 start dates while the Henry Goodrich is expected to go idle in Canada. We expect fourth quarter O&M expense to be approximately $585 million.
As previously mentioned, approximately $28 million forecasted to be expensed in the third quarter will now be recognized in the fourth quarter. This includes $10 million associated with the reactivation and mobilization of the Mykonos Corcovado to Brazil. $5 million of shipyard expense the Spitsbergen, $5 million of SPS preparation cost for the Equinox and $5 million to overall certain capital spares.
Additionally, fourth quarter O&M includes a further approximately $12 million for overhauling various capital affairs, $9 million on the Paul B. Loyd Jr. consisting of 90 days of idle time between contracts and certain maintenance costs. We're also moving through the remaining two cold-stacked rigs in Trinidad the Deepwater Champion and Discoverer Americas to Greece at total cost of about $10 million. This includes customer removal and inventory offloading in Las Palmas.
The inventory removed from these rigs will be made available for use by the rest of our active fleet. These rigs are being moved to Greece to benefit from more favorable environmental conditions resulting in lower stacking costs. Early inspecting costs in Greece are nearly 50% lower than in Trinidad, translating into an annual savings of about $5 million.
We expect G&A expense for the fourth quarter to be approximately $47 million, generally in line with the third quarter. Net interest expense for the fourth quarter is expected to be approximately $160 million. This forecast includes capitalized interest of approximately $10 million and interest income of $6 million.
Capital expenditures, including capitalized interest for the fourth quarter are anticipated to be approximately $153 million. This includes approximately $47 million for the two Jurong drill ships. Additionally, we expect maintenance CapEx of $106 million. Our cash taxes are expected to be approximately $8 billion for the fourth quarter.
Turning now to projected liquidity at December 31, 2021, and including our $1.3 billion revolving credit facility, which matures in June 2023, our end-of-year 2021 liquidity is estimated to be between $900 million and $1.1 billion. This liquidity forecast includes the estimated 2020 CapEx of $900 million and a 2021 CapEx of $900 million. The CapEx estimates include amounts for our two new-build drill ships at Jurong as well as fleet maintenance. Please note that our CapEx guidance excludes any future reactivations.
Now turning our attention to 2020 for the full year, we expect to have adjusted revenue at or above 2019 adjusted revenue. Additionally, we expect operations and maintenance expense of around $2.1 billion, excluding any speculative reactivations. Furthermore, we anticipate G&A expense to be between $175 million and $185 million. We will update full year 2020 guidance on our next earnings call in February. This concludes my prepared comments.
I will now turn the call back over to Brad.
Thank you, Mark. David, we're now ready to take questions. And as a reminder to all our participants, please limit yourself to one initial question and one follow-up question.
Thank you, sir. [Operator Instructions] And our first question will come from Greg Lewis with BTIG.
Yes. Thank you. Good morning, good afternoon, everybody.
Hey, Greg.
Jeremy, thank you for the – you kind of went through each basin and talked about what you're seeing in the opportunities. I guess more of a direct question. Clearly, you guys have been in the market trying to push pricing higher. You've had some successes. You -- probably wish you had some more successes. As you're tracking the overall fleet and your competitors, how many like capable seventh gen, seventh gen plus rigs are out there that are hot that kind of - maybe we need to be chewed through before we can start to see pricing momentum maybe accelerate a bit? Is there any way to kind of quantify that?
I'll let Roddie take that one. He's smiling. He's ready for this question.
Yes. When we look at the active sixth and seventh gen high-spec stuff that you're talking about, utilization looks like it's going to peak 95% by Q2 next year. So, there really isn't very much to burn through as you say. So I mean that's basically it, and that's kind of why we're seeing this little push on day rates, projecting day rates sitting at kind of anywhere between 170 to 260. We're obviously really on the high end of that. But yeah, that's basically exactly what's going to happen. That supply is going to dry up pretty quickly.
It's really the first time since the start of the downturn we have multiple customers fighting over the same asset. And so that's a very good sign for us, and it's the reason we are really doing our best to push day rates upward.
Okay, great. And then just another one, I guess last month you -- the company was able to get out of two drill ship new builds. Just kind of as -- I guess a couple of questions in there. As one, I mean I want to say six to 12 months ago, there were active people -- active drillers bidding for some of these new builds in these shipyards. I'm just kind of -- anything that you're hearing or seeing in terms of, is there appetite to take out any of these new builds at these shipyards?
And the second question on that is how many rigs at shipyards or drill ships do we kind of think are stranded at this point?
I don't think there's any appetite from anyone to go and take one of these new builds out of the yard at this point in the cycle. I mean if you think about just the cost to bring one of these out, you think that when these were ordered and it was back in the peak of the new build cycles so 2012, 2013 and even into 2014 and shipyards were offering 5% down, 15% along the construction process and then 80% upon delivery, so there's still a big ticket to write at the end of all of this. Plus, to help it with critical spares and commissioning and move, it's another $100 million on top of that. And so, in the current environment and with the balance sheets of all the offshore drillers stretched pretty thin, I just can't see a scenario whereby you'll see any of these rigs come out anytime soon.
Okay. Perfect. Thank you for the time everybody.
Thank you. Our next question comes from Ian MacPherson with Simmons.
Thanks. Good morning. Jeremy, on the hybrid power system on the Spitsbergen is that a -- I mean you described all of the positive attributes of it. Is that an upgrade that nets positive economically to you that rig and it's something that you would like to scale up across the fleet or...
Well, in this particular case, we received some reimbursement from the Norwegian government for lowering emissions. We have to demonstrate that we are lowering those omissions over the course of the next six to 12 months. And then they will actually help fund reimburse some of the funding for that. But then also as you look at the fuel savings that we will realize depending on the relationship, the contractual relationships with the customers that either accrues to them or to us. And so in the case with Equinor, the saving is accrued to us because we're responsible for fuel consumption.
So it's going to be very interesting to see the value that we can create through the system over the course of the next six months. And our belief is that we'll be material enough and attractive enough where customers will be willing to pay for its installation on other assets across the fleet.
Yes. I think I'll also just add to that the system was originally designed for benign environments, because that's basically where you can make the greatest fuel savings. So, it's actually a very good situation where we're able to kind of perfect the system in Norway where we receive a significant reimbursement, and then take those lessons learned and push it into the benign environments maybe the U.S. Gulf of Mexico or Africa. So yeah, watch this space. There's going to be more movement on that.
Good. Thank you, both. Mark on your guidance for next year, just sort of falling behind a little bit with my pencil. I think I essentially netted out to a revenue guide for next year you said up slightly. And then it were $2.1 billion for O&M expense that will be flat to down versus this year. So is that the directional message excluding reactivations?
Yes, that's correct. That's correct, yes.
Got it.
Okay. Thank you.
Thank you. Our next question comes from Connor Lynagh with Morgan Stanley.
Thanks. Good morning.
Good morning.
You made a comment about the pipeline of opportunities. I think it was somewhere around 64 rig year. So I was just wondering if you could give some color to how that's trended over the past, I don't know 12 to 18 months? Just trying to get a feel for it how much that's building up versus where we were at this time a year ago?
Yes. When we look at that compared to a year ago, we're basically seeing about a 45% increase in the number of rig years that are out there. Couple of things, I'd probably point out about that is fixture numbers are remaining slightly positive quarter-on-quarter. But most importantly, the duration is going up.
So when I look at what happened kind of across 2018, the average duration only been about kind of six months or so. We're now pushing up at an average beyond nine months. And in fact the last quarter shows the average is about 11 months. So we kind of see a pretty sharp increase there, at least a 50% increase in the duration of the fixture. So again, a really positive sign on that recovery.
Yes. And you sort of segue to this so maybe I'll ask you, there's been some concern from some of your competitors and some market observers that we're in sort of a structurally lower contract duration environment than we have been in the past. Would you agree with that? Do you view it is a cyclical dynamic? Just your thinking around how that's going to trend over the next couple of years?
So we have the benefit of seeing all the tenders and things that are -- direct negotiations that are happening behind the scenes and we can definitely say that durations are increasing, there's no doubt about that.
Yes definitely, longer than they've been in the last four years, where we've been kind of going well-to-well type of opportunities. We are starting to see multiyear campaigns with options behind those. Now, are we going to get back to the 10-year terms? Probably not anytime soon. But we are seeing multiyear opportunities right now.
And I think actually as you look at the number of big FIDs that are going to be awarded in the next kind of six to 12 months, those are typically around developments, which attract, typically a lot longer durations. We have been focused a lot on short-term production work and a few exploration things in downturn, but there's no questions, especially in basins like Mexico and the U.S., there's a big shift towards development drilling in the next 12 months.
Got it. Thanks for the color.
Thank you. Our next question comes from Taylor Zurcher with Tudor Pickering Holt.
Hey, good morning. I wanted to touch on the 20000-psi opportunity set. It sounds like discussion there continue to move in the right direction. Just curious if you could frame the potential magnitude opportunity set for that type of rig moving forward. And then for the one that -- the contract that seems to be -- or a contract announcement that seems to be nearing, would you expect to get assuming it's you that wins contract or whoever wins the contract, would you expect to get similar economic as to what you got for the Deepwater Titan?
Yes. So Taylor I think the number of operators that are into this there's probably three or four very serious and we think there's -- two of them are getting closer and closer to making an award. And as Jeremy alluded to, there one could actually be this year for the precursor award to that.
So, certainly activity moving in the direction there. In terms of day rates, I imagine that there should be at least if not better than what were -- we thought and decide. We can't speak to what our competitors are doing, but certainly we are ensuring that our reasonable economics follow that particular fixture.
Okay. Got it. And maybe a question on Gulf of Mexico. For a while, we've heard a lot of positive commentary coming out of Brazil and even West Africa, but the Gulf of Mexico on the U.S. side seems to have been lagging a bit. The outlook commentary and prepared remarks is pretty encouraging there. When you talk about the incremental conversations you're having today, are these primarily extensions with some of the big IOCs that are already there, big independents that are contracting incremental rigs? Or any more color there would be helpful.
Actually, so it's a mixture of everything. And in fact, there's kind of less of the extensions and more of the kind of new works. So there are several players that have been relatively quiet over the downturn.
There's also a couple of new players. But the U.S. side of the Gulf of Mexico is very interesting, more active than it's been probably four, five years. And on the Mexico side of things, I mean, stuff is really picking up. People are making discoveries. And that -- the focus is now shifting from a lot of exploration work and everyone's now thinking about what they're going to do develop and monetize these discoveries. So certainly, a lot of good stuff following there and that's really helping up -- soak up that additional supply that we have seen kind of this year. So it's going to be supertight 2020 I believe.
Great. Thanks guys.
Thank you. Our next question comes from Justin Howe with Citigroup.
Hey, good morning guys. Justin here on behalf of J.B. Thanks for taking my question. So I know you guys mentioned the Barents possibly moving that over to Norway back to Norway. But I'm just wondering with the Goodrich set to roll off next month looks like it's going to be idle why wouldn't that be considered an opportunity to send over?
Yes, so there's an opportunity to send the rig over to U.K. in that environment. But to be honest, the stacking costs of the rig in Canada are very cost effective. So until we see a significant opportunity, we'd probably keep the rig there for now and see through the winter and then think about moving her over there.
Okay. Great. And then regardless of which one of those ships if you guys were to send it over, would that be a -- would you be looking for a paid move? Or would you guys be willing to take that investment to send that over?
Yes. I think we'd be looking for a paid move or perhaps a paid demo. But certainly, any movement of the assets as Jeremy alluded to before, we're looking for payback on those. I mean there's -- we're not moving rigs speculatively, we're not trying to out guess ourselves or not. It's really time for those economics to pay forward.
Okay. And then just last one for me. You guys mentioned that you guys saw increased revenue beyond guidance from performance bonuses. Just wondering if that's something you guys have been more successful in your ability to negotiate in your contracts?
Yes. I think -- so we've always said that actually throughout the downturn that we are very interested in performance bonuses kind of putting your money where your mouth is. And I must say our operations teams have executed extremely well. So we continue to see that as being a good lever to demonstrate our willingness to perform. And that's worked out for us so far. So there's no reason we wouldn't turn -- we would continue to do it.
It's very much customer-specific. Some customers just prefer the flat day rates. Others are willing to enter into performance contracts. And so it's totally dependent on the contract. We remain flexible on that front.
Okay, great. I'll turn it over. Thanks.
Thank you. Our next question comes from Mike Sabella with Bank of America.
Hey, good morning guys.
Good morning.
So one of your biggest customers has recently floated a pretty long-duration tender down in Brazil. You guys work for them in other parts of the world, but not down there. Can you talk us through kind of on whether your relationship you have developed up north is helpful in that bidding process or the market is just kind of too different?
No. I think the relationship speaks for itself. I mean if you look back five years ago, we had no work with them and now we're the largest drilling contractor and we operate globally for them. And so I think this has been a very effective partnership. Good relationships on the commercial side and then excellent operational performance across the active fleet. So no we would certainly like our chances to expand that relationship into other markets.
Great. And if you could just kind of circle back to 20K BOP I know you all sound like there's potentially the market for a couple of more of these rigs. Can you talk about your willingness to go out and maybe get in contact with one of those shipyards on the stranded assets, if it came to that. And then talk about the difference between a new-build versus upgrading an existing rig with 20K BOP?
Yes. To be clear, we think the market needs another 20,000-psi. We're not sure about multiple more after that. And so I think it's an awfully big upgrade and a very big check to write for a drilling contractor and operator. And so we do believe that there is a market for at least one more 20,000-psi and if there's a market for more and the customer is willing to pay for it then okay, sure, we look at a stranded asset or one of our existing assets to see if the upgrade makes sense.
Great. Thanks.
Thank you. Our next question comes from Kurt Hallead with RBC.
Hey, good morning.
Hey, Kurt.
Hey, thanks for all that color. It seems like things are heading in the right direction. The question I had was just on the follow-up. Jeremy in your initial comment -- answer to one of the earlier questions was ultra-deepwater utilization hit 95% by second quarter 2020. Then you talked about the kind of day rate range somewhere between 170 and 260.
So on the day rate range just kind of curious was that 170 to 260 about rates that have already been signed or was that your kind of indication of what some future signings maybe as you get out into second half of 2020. Can you give us some color on that?
Yes. Sure. So I mean, we've seen a few signatures in that 170 range unfortunately. We mentioned the LOI that we're sitting on are firmly in the mid-200s, so that gives you an indication of where we see those things coming out in the very, very near future. The 170 to 260 range is actually not our number that's a number from like Burnleys and Arctic and some of the industry commentators.
And if we actually look at that range in a VRU, one or two of our competitors from that, in fact -- actually one specifically then that range will -- the bottom end of that range immediately jumps up 20%. So I mean even though there's unfortunately one or two fixtures still in the 100s, we're seeing everything going forward. It's going to be minimum 200 and pushing up to mid-200s.
Okay. Appreciate that additional color. Then Mark on the outlook into kind of 2020 you mentioned paying down the 2020 and 2021 debt numbers. How does this all translate into -- or does it translate into any need to kind of tap in that revolver into 2020 or into 2021? Can you provide some perspective on that?
Sure Kurt. We don't see us using a revolver at all until late 2021, if at all. There are a few things that we have to do in the interim including putting on secured financing on the Deepwater Titan. So once we've accomplished that there's no need to tap into the revolver at all. But as you know, we can't do that until the rig has delivered which won't be until late 2021.
Okay. Great. And then just one last follow-up just on a housekeeping, Mark any sense on how we should think about the quarterly depreciation going into fourth quarter and then into next year?
I think I'll take it offline. Thanks.
Thank you. Our next question comes from Sean Meakim with JPMorgan.
Thanks. Jeremy I was hoping you could maybe just characterize those rigs years that you're looking at in terms of 2020 versus 2021, versus 2022 or beyond? And are you willing to maybe just share the types of floors you've considered from a day-rate perspective when bidding for term work across those years?
I'll take that one. The first one about the duration. So as an illustration if you look at the 6th, 7th-Gen drillships in 2018 we had about 15 rig years awarded. In 2019 year-to-date we're already 28. So we're seeing a doubling of that. Our projections on 2020 and 2021 and 2022 are really based upon project sanctioning. So project sanctioning as we look at those movements are basically increased at least 50%, 60% between 2018 and 2019 and we think that increases another 20% into 2020 and then onto 2021.
So that's kind of the range that you'll see things continue to grow. In terms of day rate floors, first I mean obviously I can't give that away. Certainly, we see rates increasing from where they are today. I think you'll see some interesting fixtures in the next 1 month or 2, certainly before the end of this year that will support that. And then we would expect that things would continue to improve from there.
Fair enough. I appreciate that. Could you maybe just -- thinking about Brazil could you maybe give us a bit of a contrast in terms of timing, magnitude and maybe type of rig demand as you look at Petrobras against the other IOCs that are acquiring acreage maybe thinking about activity post-salt versus pre-salt?
Yes fair enough. I think coming up is the next pre-salt bidding round number 6 and I had understood there are 17 different oil companies that have been qualified for that which is the largest number ever cleared to participate in a Brazilian bidding round. You mentioned Petrobras, so Petrobras have been super aggressive. Originally they came out for a tender, actually it were a tender that was expected to contract two units. They went ahead and contracted six. We also see that Petrobras has just launched another tender for multiple rigs and that's in the Santos Basin, so that's pretty interesting. And then as somebody had mentioned before you've got some of the IOCs they're already out to tender and expect to make awards. So…
As you can see, just to add to that, if you think back, I mean Petrobras has already awarded six contracts to some of the local players and so absorb some of that capacity. And so as you look at the future, they have at least a few more contracts that they are going to award here over the next several months. And then you've got the IOCs that are coming in and tendering. And my guess is a lot of the local capacity is going to be consumed and the international players are going to want higher spec assets in the market anyway. And so I think that opens up the door for us to grow our presence there.
Yes. And Sean actually the stuff that we know that's under negotiation at the moment would basically place all of the rigs that are in country under contract. So there's no more local supply available you'd have to bring rigs from outside.
Got it. It’s very helpful. Thank you.
Thank you. Our final question will come from Vebs Vaishnav with Howard Weil.
Hey, good morning and thank you for taking my questions. I guess, just thinking about the floater count it has -- we started off with a working count of about 100, 105. We went to about 120 and now we are back below 115. I just wanted to see if there's some seasonality that you guys think is going on and this has got -- this could be like a transition number and then from here on we go -- keep going upwards? Any color would be helpful.
Yeah. I think if you look on any given moment that might fluctuate by a little bit. But we're seeing that progression pushed up to 130 rigs working almost 160 under contract. And actually the -- we're not going to see a whole lot more than that just simply from the point of view that they cost a lot of money to bring a rig to reactivate it or to bring it from shipyard. So what we think happens now is that this active fleet that you have at the moment is basically going to increase in its utilization level, it's going to support solid day rates. And once those day rates are high enough perhaps in the 300 and beyond range then you're going to see that move up again, but that's going to be because of reactivated units, which as we've kind of stated from our point of view that would have to be paid forwards.
And Vebs if you look at just -- contracted rigs that's been up over the last three years. So I think you're seeing rigs contracted much sooner now for work starting further into the future.
Okay. And unrelated follow-up maybe for Mark. So when you guys guide about $825 million of drilling revenues that excludes the, call it $45 million of amortized revenues or contract intangibles. So when you actually report it would be -- we should think about $825 million plus that $45 million. Is that fair?
No. Our contract grew revenue it would be $778 million and our adjusted contract revenue is $825 million.
That’s very helpful. That’s all for me.
Thank you. Ladies and gentlemen, that concludes our allotted time for questions-and-answers. I would now like to turn it back to Mr. Alexander for closing comments.
Yes. Thank you very much David. And thank you to all of our participants on today's call. If you have further questions, please feel free to contact me either today or later in the week. We look forward to talking with you again when we report our fourth quarter and full year 2019 results. Have a nice day.
Ladies and gentlemen, that concludes the third quarter Transocean Limited earnings conference call. You may now disconnect. And thank you for joining us this morning.