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Transocean Ltd
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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 Bradley Alexander, Vice President of Investor Relations. Please go ahead, sir.
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. During this time, to give more participants an opportunity to speak on this call, please limit yourself to one initial question and one follow-up. Thank you very much.
I’ll now turn the call over to Jeremy.
Thank you, Brad, and welcome to everyone participating in today’s call. As reported in yesterday’s earnings release for the second quarter of 2019, Transocean generated adjusted EBITDA of $207 million and $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 for both the legacy Transocean fleet and the assets we've acquired over the past two years. While our crews and short based support staff deserve a great deal of credit for their strong and consistent uptime performance, the support that we are 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 four active ultra-deepwater rigs acquired in the Ocean Rig transaction to those care agreements. And we have the template in place to include other assets as we turn 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 two 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 a day. What we certainly need and expect for rates to empire over the coming months. This fixture demonstrates that we are clearly moving in the right direction and for high specification ultra-deepwater drill ships.
As another positive data point, just last week, the Transocean Barents secured a three well contract working for Barents Equinor in Canada, with an estimated duration of approximately 120 days beginning next spring, including mobilization, demobilization along with RV 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 secure this fixture as it represents an improvement to the rigs 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 two contracts, we are actively pushing day rates across our global fleet. We bring tremendous efficiency to our customer drilling programs. As such, we need to increase day rates to levels that are more reflective of the value that we create. More importantly, day rates must improve for levels that enabled us to generate meaningful free cash flow. In fact to demonstrate our result in elevating day rates on a go forward basis and consistent with our most recently filed fleet status report, unless restricted by our customers we'll post all future contracted day rates.
Furthermore, we will not reactivate an asset without being compensated for the reactivation and startup costs in the form of higher day rates, longer terms and/or lump sum reimbursements. We believe that this day rate visibility combined with our disciplined approach to reactivation 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 market at utilization at a level above 80%. And while ultra-deepwater day rates 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 40% year-over-year increase in the number of working ultra-deepwater drill ship.
While we would have 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 crude which dipped into the low $50 per barrel range at the end of last year had averaged around $65 per barrel for 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 day rates have moved off of the bottom in every major operating basin and around the world. In the US Gulf of Mexico, we remain engaged with multiple customers around projects that would require incremental rigs in the region. We've 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 sister rig currently under construction in the Jurong shipyard, we believe that we are very well positioned should our customers decided 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 and multi well program which Shell later this year, with activity running well into 2020.
Additionally, we anticipate drilling in 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 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 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 three shifts 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 arrive 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 Burullus 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 development here are typically longer cycle in nature, and therefore can impact the market and utilization significantly. This optimism in West Africa combined with the increased activity we have 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 six-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 day rigs 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 remains strong. In fact our newest addition to the fleet the Transocean Norge is scheduled to commence its maiden contract later today. The pro contract includes in May 2020, but has options that extend into September. This high specification semi-submersible 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 to 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 day rates and terms 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 UK, we continue to seek fixtures from the Independent and majors alike that suggests the market will again be tight next summer, which bodes well for the likelihood of year around drilling for our fit for purpose assets that performs so well in the UK.
In summary, we're extremely pleased with the direction of a high specification harsh environment market where our top tier assets are fully utilized. Day rates 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. 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 transition 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, the 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 hydrate 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 customer 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 run rate and 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 believe that executing against these initiatives best position transition for the recovery.
I'll now hand the call over to Mark.
Thank you, Jeremy and good day to all. During today's call I'll 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 of 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 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 on margin of 32% from over to $805 million of adjusted revenue. We're very pleased to notch another quarter of revenue efficiency out performance which includes achieving the majority of our drilling contract furnace opportunities for the quarter. We 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 we had operating and maintenance expense of $510 million. This was below our guidance to the timing of in service maintenance and project costs in the second quarter. These forecasted costs together with the Transocean's Spitsbergen's 10 year SPS will be delayed to the third quarter.
Turning to cash flow and balance sheet, we entered the second quarter of a total liquidity of approximately $3.6 billion, including cash and cash equivalents of $2.2 billion and approximately $1.4 billion from the 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 [ph] debt in the open market.
Additionally, during the quarter was successfully exited the debt capital markets issuing $525 million of senior notes due 2023 secured by the Transocean Endurance and Transocean Equinox. Two of our high specification harsh environment rigs under the long-term contracts with Equinor. As we have proven over the prior several years, we'll continue to take all necessary steps to extend our liquidity run rate, prudently reduce leverage and proactively manage on near dated debt maturities.
Let me now provide an update on our third quarter 2019 financial expectations. For the third quarter of 2019 should the 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 about other service time with Transocean Spitsbergen.
We expect third quarter O&M expense to be approximately $575 million, including reimbursable expenses of $28 billion. This sequential increase in O&M expense is driven by the following; expenses associated with Ocean Rig Corcovado and Ocean Rig Mykonos of approximately $38 million related to contractually required custom expenses that were initially expected to be amortized over the contract term, $16 million due to shifting the Transocean Spitsbergen into the third quarter.
In addition to the SPS our shipyard scope also includes installation and commissioning of our automated billing technology that is self-funding to achieving enhanced bonuses as a result of improved early performance. Lastly, the KG2's 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 expenses associated with the Corcovado and Mykonos been experienced in 2019 as the first to be amortized over the term of the respective contracts through 2021.
We expect G&A expense for the first quarter to be approximately $48 billion in line with the second quarter. Net interest expense for the third quarter is expected to be $160 million. This forecast increases capitalized interest of approximately $10 million and interest income of $7 million.
Capital expenditures including capitalized interest for the third quarter is anticipated to be approximately $215 million. This includes approximately $120 million for four new build drill ships under construction with approximately $65 million for the Jurong drill ships and up to $55 million with 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 projected liquidity December 31, 2021, including our $1.37 billion revolving credit facility which matures in June of 2023, our end of the 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 new build drill ships 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'll continue to carefully manage our balance sheet, while remaining focused on generating cash and reducing leverage. As Jeremy mentioned and subject customer consent, we intend to disclose all day rates going forward, increasing transparency and further demonstrating our commitment of generating positive cash flow. This approach also better aligns our interests with our shareholders. We continue to work those increased utilization and day rates in both the harsh environment and all reported [ph] segments and we remain stick faced in our commitment to generate free cash flow through the cycle from our best in class rig fleets.
This concludes my prepared comments. And I'll turn the call back over to Brad.
Thank you, Mark. Augusta, 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, Mr. Alexander. The question-and-answer session will be conducted electronically. [Operator Instructions] Our first question will come from Ian Macpherson with Simmons. Please go ahead.
Thanks. Good morning, everybody. I certainly love the new look in the fleet status report. Thanks for that. Jeremy, you made a couple of comments about additional opportunities under review for high pressure 20 K 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 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.
So there are multiple customers that are exploring this possibility, I'd say that there is one that is very close to a decision, a decision. And that decision could come before year end. And in terms of the others are probably a little farther out maybe next year, even the year after for a decision. In terms of our positioning as I stated, we've got the only 20 K award thus far. We think we're uniquely positioned with the second Jurong rig and that has a 3 million tons of 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 20 K puts us in a very unique position.
Yeah, I'd just add into that to say that, so we do expect one fixture this year, but we also expect another tender to come out this year. So that's pretty good to see. Not only fixtures taking place, but future work as well. So could be one or two that we'll see.
Okay, thanks Roddie. Could I ask you a follow up just in the fleet status? You've got a couple of rigs rolling later this year, but I was curious about the Henry Goodrich in Canada, obviously we're saying good day rates there for Tier 1 rigs. The 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?
Yeah sure, as you as you pointed out, the Tier 1 rig is really in demand, so we're completely sold out there for the Goodrich itself and she's going to finish up probably with the Husky program later this year towards the end, then we'll move her to the UK. So we're looking at a couple of things, but earlier that we plan to pull the rig over during the wintertime, we'll see what happens. And in terms of – you asked about the Orion as well, we actually just signed a yesterday we signed a contract to extend the rig by 30 to 45 days for another well in Angola and that's what's there in Senegal PUB. I don't think I can release any of the other information because we don't have permission from the operator yet. But that's – probably be a point for us just to keep her busy a bit longer.
Okay. Hey, thanks. I'll pass it over.
Our next question will come from Taylor Zurcher with Tudor, Pickering and Holt.
Hey, good morning. Thanks.
Good morning Taylor.
Maybe I'll start a question on the fleet status. All echo Ian's comments that that the day rate disclosure is exactly what the market is looking for. But as it relates to discover a 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 to active status and what sort of cost would be required?
Yeah, 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 day rates are and the contract terms support the full payback of the reactivation and not only that, but seeing prospects going forward beyond that.
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 four stacked high specification seventh gen rigs, we feel are going to be priorities for our customer before they're cleared it will be.
And the answer to your question as to cost to reactivate, for those types of rigs like the clear leader, we've indicated in the past between $40 million and $50 million should get the rig back up and ready to work.
Okay, great, that's helpful. And then a question on some of the new builds. You already covered the 20 K PSI type opportunities, but for the Santorini and the Crete, you still have pretty high back end payments still due on those rigs there. 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 rings out clearly, you're looking for a good rate, but is a one year term something you're comfortable bringing those rigs out even if the rate is good enough?
Yeah, 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 out, which could be anywhere between $75 million, $85 million. So you're looking at a substantial check to write, recognizing of those payments are 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 put it out. Clearly, we have assets that are similar to the Santorini that are currently sitting in Greece back which we could bring on for a lot less. So those will be prioritized over the Santorini as it relates to contract opportunities.
Okay, understood thanks. I'll turn it back.
Our next question will come from Chase Mulvehill with Bank of America.
Hey, good morning. I wanted to come back and maybe just talk about the current environment on the ultra-deepwater day rates. Maybe talk about what kind of momentum you continue to see in the – you expect to see in the back half of this year and do you expect that momentum to kind of continue into 2020?
Yeah, good question. So we're looking at where we are from like the number of contracted rigs and the utilization level what that's doing to day rates. 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're seeing recovery. So since the beginning of the year, we've kind of seen a pretty significant increase in terms of the day rates. But we put all these charts and essentially, what we're showing is day rates have increased anywhere between 30% to 50%, based on where they were and the lower part of the downturn, which really the last kind of low level fixtures seem to have been made in late 2018. So when we see the ads are getting booted, breaks approaching 200. And then we see several of our competitor's are170 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. We look at that overall, around the world. And that's essentially what we're seeing that the day rates are going up anywhere from 30% to 50% depending on the particular basin.
Okay and on the ultra-deepwater side, are you seeing a premium for seventh gen rigs or they're just still not that much tightness on the seventh gen to be able to see the premium there for between six and seventh gen?
Yeah, well, I mean, seventh gen at the moment is effectively sold out. But because of few the shorter term contracts associated with that, you're not seeing the big pot pushing towards the hundred 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 is the highest bet goes to work first.
As things tighten up, but what do you think would be an appropriate premium seventh gen versus a sixth gen rig?
It really depends on the targets that you're trying to hit. But I mean, 30%, something like that.
Okay, one quick follow up for Mark, if I may. Mark, do you have any free cash flow targets that you would like to share maybe over the medium to longer term?
Yeah, positive.
Already, I will – I guess I'll turn it over and look forward to the positive free cash flow.
Our next question will come from Kurt Hallead with RBC.
Hey, good morning.
Hey, Kurt.
Hey, 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 of 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 in 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 recouped over the course of the contract. So I guess it's kind of a long way to set up the question of, do you think it's possible where the companies like yourselves can 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 to rig they can afford to prepay to get it out of the yard and kind of accelerate that process? Any thoughts on that we appreciate it.
Yeah, we look forward to that day. I would say that right now. They're probably there. And we've demonstrated that there's some of the contract in terms of the harsh environment space, some of the 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 I already said many years ago, and we were basically at 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 really hope for.
Yeah, Kurt I think where you'll see that is it will show up in mobilization fees. So for example, the mobilization fee that we get with the Titan essentially pays for that movement of the rig over there. That's not something that we're recovering over the term. So I think Jeremy says we are we have already seen it several instances and 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 the contract and that cash flows are important and they're getting paid for mobilizations up front is that we intend to push it.
Yeah, then I appreciate that. And that's definitely helpful. And then a step in the right direction in the same context is demands exceeding supply and these oil companies are asking the industry to kind of pull rigs off the beach and you guys got a foot the upfront bill of the $50 million, or whatever, at the end of the day they should be footing that bill, not necessarily the drillers, but it's more of a talking on a soapbox and anything else, but be great to see the industry kind of kind of press for that with their tax –
Keep reaching Kurt.
Keep reaching. We'll get up on that box to let you.
Yeah, for sure, so second thing just in the context of the 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? It's on a cumulative basis after 2021.
Yeah, so Kurt, we have this hole 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 very close to doing that during that time period. Obviously, this is based upon a David Deck, which can and will change. But we expect to be pretty close to free cash flow positive throughout that period.
Okay. Mark thanks for that additional color. Appreciate it. That's it for me.
Well, here next from Cole Sullivan with Wells Fargo.
Hi, good morning. And 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?
Yeah. So in terms of the open demand, we would flooding 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 and in terms of the number of rig opportunities, it looks like it's up by 15%. So that would suggest that our average duration is increasing. So that's good. That was importantly, that's a pretty big jump in open demand in terms of the number of rigs that have to be picked up and you activate what kind of direct negotiation. So the numbers that we site are the ones that are not just the public tenders, but also the things that we know are happening, perhaps on the side. So yeah, there's definitely a shift towards direct negotiations, when a 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 the bread and butter deepwater drilling, then they are being pretty specific about the rigs that they want that the operational records 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.
All right, that makes sense. And just on the late '19 availability on some of your harsh fleet, like the Barents as a gap in the contract there before the new the new fixture and then you have other ones like the Leader in the Paul B. Lloyd [ph], how do you kind of see that over the fourth quarter where you have a little more seasonality coming in? Do you see some visibility there behind the current contracts?
Yeah, 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 and 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 two and hopefully there won't be too many gaps between now and the next spring.
Alright, thank you. I'll turn it back.
We'll go next to J.B. Lowe with Citi.
Hey, good morning guys
Hi, J.B.
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 a couple 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 improved over the next couple 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? Thanks.
The J.B. let me caveat this by saying that due to the downturn in the industry I thought best assets and our best crews working and the same is true for our competitors. And so you're getting an optimal efficiency performance plus all the time that we put into it. So we've probably seen 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. But 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 to that. We'll put a cap on the number of offshore rigs required going forward. And in fact, if you look at the best of past peak, I think, 2014, we had almost 270 floaters under contract and in operation. We've kind of been up there publicly for the last four years and so that's the new go forward number maybe closer to 200. And so that's what we've really taken the effort to hydrate our fleet and focus only on those high specification assets because we think those are the ones, they're going to work it in the market as a first recover.
Okay, great. Thanks for that. Quick follow up just on the contract on the Barents, can you guys put some numbers on what the demob and mob costs are going to be, so we can kind of get a cleaner rate for that rig?
Well, also we can't, we discussed this with that customer and they would prefer that the actual day rate not be doing precisely so. Although it indicates – that would indicate to you that it's a pretty good day rate. So no, I have respect for – definitely we certainly we can't devote [indiscernible].
Alright, thanks very much guys.
We'll go next to Sasha Sanwal with UBS.
Thank you, and good morning.
Good morning Sasha.
Yeah, look and so a lot of my questions have been answered. But just kind of wanted to touch on – just to maybe kind of think about potential reactivation through 2020 here. And so you say you were pretty forceful comments, I think about kind of the requirements kind of get a full payback on reactivation and what the cost might be. Just kind of wanted to get a sense of is there 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 guideposts to kind of help us to get a sense of that?
Well, 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 day rate in terms acquire 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 a 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 have a very, very – we've established a very high bar for reactivating an asset at this point in time.
Great, okay, a tough one and maybe just kind of touch on just essentially the – I think you mentioned this, the Spitsbergen just the installation of the automatic joint 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 day rate uplift?
Yeah, again – so, on the day rate uplift I'm not sure we can really share the details of that because it's in a confidential contract. But yeah, in terms of customers interested in it – yeah, customers are very interested in that because if you 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 cost. So that's why these kinds 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.
But 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 automated drilling controls, if we perform as we think we will, these will pay for themselves inside of a year.
Okay, great and maybe if I could just sneak in one more quick one. Just maybe in terms of some of the recent contract pictures that were announced, can you maybe give us a sense of how competitive those were and maybe just your general thoughts on how you kind of see essentially, the discipline from the other contractors playing out? Thank you.
Yeah, so we would love to see lots more discipline from not competition. But yeah, really, it's about, you haven't seen anybody book any long term fixtures at low day rates. 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 what basin you're, which region you're. 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 most all of our competitors are, one or two might be a little bit behind the curve. But hopefully we'll catch up.
I think the important thing to note there what Roddie led with, which was that no real long-term contracts have been awarded at low day rates. And its 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.
Thank you. I'll turn it over.
We'll go next to Greg Lewis with BTIG.
Yes, thank you and good morning, everybody. 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 pricing, over utilization versus maybe some of the competitors, how much that sort of bid ask at the high end versus the low end is kind of converged?
So yeah, they are converging, there's no doubt, right. I mean, as you see the fixtures are much more closely grouped as a basket. If you look at like the Gulf of Mexico, the last series of fixtures basically sets this year apart from kind of one outlier with the N-28503, Pacific and ourselves are all looking stuff 165, 170, 180, 185 that kind of range. So there may be one or two outliers, but for the most part of that discipline seems to be there.
Okay, great and then just totally shifting gears. I mean, I guess free cash flow is in a little bit of a theme on this on this call. I guess right now out in the market there's a tender and the North Sea potentially for a rig of the future. Now realizing that this is each still years away. Is this something that we think Transocean is actually looking at pursuing?
Yes and we are, I just –
Okay. And just sort of you could give a little bit of color around how we should be thinking about when that startup could be and sort of like when – how we should be thinking about that?
Let me stress it would not be on a speculative basis. Yes, so that prospect is several years in the future. But really its – if you look at – in Norway what you have is like – so a rig like the Cat-Ds are fir for purpose designed exactly to do what they need them to do in the most efficient manner possible. And so it's one of those exercises again, it's 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 probably four or five years away, so there's a lot of things 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 for the future on a continual basis. It's just at that moment in time, you would have to see a very significant investment from the operator up front to see any of those take off.
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 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 this thing to the finish line.
Okay, perfect. Perfect. Okay, guys, thank you very much.
We'll go next to Sean Meakim with JP Morgan.
Thanks. Good morning.
Good morning.
So, just a couple things, I want to kind of get your thoughts around how contract negotiations are evolving? Y noted some more direct negotiations some of the operators are trying to get specific rig specs that they're looking for. Maybe can we talk about how what non day rate compensation arrangements are being prioritized from your side or from the customer side? Are both costs becoming more commonplace or is this only still on select tenders? Just can you get a little more of a feel for how that's going on as you're negotiating these new contracts.
Yeah, so a lot of the direct negotiation stuff you're going to see is either because the operator already has the rig or the rig is – how to say, in the region immediately available. So in that case, mobilization costs are pretty low practically zero. But we're definitely seeing is that negotiation stuff is around the best performing asset or unique specifications that really helped them. So you would have seen that much available in Africa, in Canada and the US and a few others that are typically not tended opportunities. In terms of the mobilization fees, we are seeing that across the board now. So where there is a mobilization costs, 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 in the new dynamics that these contracts become cash flow positive.
Got it, that's helpful. Thank you for that. 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?
Yeah, I think you always got a balance depending on how competitive things are. But I mean, you saw that in the baskets of rigs, you saw that Petrobras picking up seven 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 the same contract for more than one rig with the same operator. But I don't think there's a volume cash discount certainly out there. I think it really is a case of [indiscernible].
Got it, okay. Great, thank you.
Our final question will come from Daniel Boyd with BMO capital markets.
Good morning, this Cale Dillingham on for Dan. Could you just clarify if your revenue guidance of 785 million includes amortization revenue?
Yes.
Thank you. That's it for me.
Thanks.
I'd like to now turn the conference back to Mr. Alexander for any additional or closing remarks.
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 record our third quarter 2019 results. Have a good day.
That does conclude our call for today. Thank you all for your participation. You may now disconnect.