Image source: The Motley Fool.
Transocean Ltd (RIG -2.69%)
Q2Â 2019 Earnings Call
Jul 30, 2019, 9:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Please stand by. Good day, everyone, and welcome to the Q2 2019 RIG earnings conference call, Transocean Ltd. [Operator Instructions]. I would like to turn the conference to Brad Alexander, vice president of Investor Relations. Please go ahead, sir.
Brad Alexander -- Vice president
Thank you, Augusto. Good morning and welcome to Transocean second quarter 2019 earnings conference call. A copy of our press release covering financial results along with supporting statements and schedules, including reconciliation and disclosures regarding non-debt financial measures are posted on our website and deepwater.com.
Joining me on this morning's call are Jeremy Thigpen president-chief executive officer, Mark Mey, executive vice president and chief financial officer, and Rodney Mackenzie, senior vice president of marketing and Contracts. During the course of this call, transition management may make certain forward-looking statements regarding various matters related to our business in 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 FCC 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.
Taylors Archer -- Vice president
Thank you, Brad, and welcome to everyone participating in today's call. As reported in yesterday's earnings release for the second quarter 2019 transaction generated adjusted EBITDA of $207 million, $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 in the first half of 2019, this combination of strong uptime performance and customer bonuses has resulted in revenue efficiency of approximately 98%, which is a testament to the superior operating performance from both the legacy transition fleet and the assets we've acquired over the past two years.
While our crews and Shore Base support staff deserve a great deal of the 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.
Jeremy Lake -- Vice president
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 a template in place to include other assets as we could 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 higher 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 $1085 thousand per day, with the opportunity to earn a performance bonus, which could result in total compensation approaching $200 thousand per day. While we certainly need an expect for rates to move higher over the coming months, this fixture demonstrates that we are clearly moving in the right direction for high specification ultra-deepwater drillships.
As another positive data point, just last week, the Transocean fair secured a three-well contract working for Ecuador in Canada with an estimated duration of approximately 120 days beginning next spring, including mobilization, demobilization, along with ROV and casing services over the first 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 Ecuador'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 to a level that enable us to generate meaningful free cash flow. In fact, to demonstrate our resolve in elevating day rates on a go-forward basis and consistent with our most recently by a police dash report in less restricted by our customers, we will post all future contract day rates. Furthermore, we will not reactivate an asset without being compensated for the reactivation and start-up 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 and 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% euro, Year increase in the number of working ultra-deepwater drilling. Well, 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 in underlying market fundamentals. Brent crude, which dipped into the low $50 per barrel range at the end of last year, has 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 fourty dollars per barrel.
Reserve replacement ratio 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 and every major operating base around the world. In the U.S. Gulf of Mexico. We remain engaged with multiple customers around projects that would require incremental rigs in the region. We've also had discussions with multiple operators regarding the need for additional twenty thousand PFI capable rigs. 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 a Titan sister rig currently under construction in the Jerome shipyard, we believe that we are very well-positioned should our customers decide to proceed down this path. In Mexican waters, numerous operators, if you're poised to initiate further activity as initial results from early exploration programs have been positive. We anticipate beginning our third Mexican campaign, a multi well program with Shell later this year with activity running well into 2020.
Additionally, we anticipate drilling in second exploration well in the trial field for BHP during the third quarter. In the Caribbean, we are encouraged to see a recent fixture award and surname. 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 Corcovado and the ocean rig in Miki Maus, those remain on schedule to commence operations in Brazil in the fourth quarter, at which time we will have three ships operating in the country. With this installed base our history of performance in this region, our industry-leading fleet and Petrobras contracted 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 discover India will begin her campaign with Parolas in August. This follows a successful campaign with CNL in the Ivory Coast and it stated on past calls. It's important to note that awards in this region would likely represent a significant number of rig year developments here 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 is again contracted the deepwater novelists 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 rates 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 Sea remains strong. In fact, our newest addition to the fleet, the transition Norga is scheduled to commence its maiden contract later today. The first contract concluded in May 2020 but has options that extend into September.
This high specification semi-submersible marks our seventh world-class assets suitable for this market, and we anticipate that you will be in high demand as she approaches the end of her term. As previously mentioned, we are pleased to be keeping the affairs in Canada. We have good visibility to future work to the bears 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 suggest the market will again be tight next summer, which bodes well for the likelihood of year-round drilling for our fit for purpose athlete that performed so well in the UK. In summary, we are extremely pleased with the direction of the 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, bags, and reimbursements for mobilization and demobilization.
And while we're somewhat frustrated with the pace and trajectory of the ultra deepwater market, we remind ourselves that we have moved off the bottom and are clearly in the early stages of what we expect will be a much broader recovery. For this, 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 is large, 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 almost things within our span of control. Specifically, we will continue to prudently high greater fleet, just as we did these past few months as we added the norga to our contracted fleet and we made the decision to recycle the Ateneo. Their 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 event 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 runway 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 positioned Transocean for the recovery. I'll now turn the call over to Mark.
Mark-Anthony L. Mey -- CFO
Thank you, gentlemen. And good day to all. During today's call, I will briefly recap our second-quarter results, then provide guidance for our third quarter of 2019. Lastly, I'll provide an update to our 2019 shipyard projects as well as our liquidity forecasts to 2021. As reported in our press release for second quarter 2019, we reported a net loss attributable to controlling interest of $183 million or $0.30 per diluted share. After adjusting for favorable items associated with tax, unfavorable items associated with the early retirement of debt and sale of an asset, we reported adjusted net loss of $210 million or $0.34 per diluted share. Further details are included in our press release.
In the second quarter, we delivered adjusted EBITDA of $257 million with an adjusted EBITDA margin of 32% from $805 million of adjusted revenue. We're very pleased to announce another quarter of revenue efficiency outperformance, which includes achieving the majority of our drilling contract plants, opportunities for the quarter. We also settled a long-standing customer dispute. We generated cash flow from operations of $133 million, an increase of $204 million 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 due to the timing of in-service maintenance and project costs in the second quarter. These whole project cost together with the transaction [Indecipherable] 10 years SPS will be delayed to the third quarter.
Turning to cash flow and balance sheet, we ended the second quarter with total liquidity of approximately $3.6 billion, including cash and cash equivalents of $2.2 billion and approximately $1.4 billion from 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 from year-to-year debt in the open market. Additionally, during the quarter, we successfully access the debt capital markets issuing $525 million of senior notes due 2023, secured by the Transocean Endurance and Transocean Equinox, two have a high specification harsh environment rigs under long term contracts with Equinox. As we have proven over the prior several years, we'll continue to take all necessary steps to extend our liquidity runway, prudently reduce leverage and proactively manage our year to year debt maturities.
Let me now provide an update on our third quarter 2019 financial expectations. For the first quarter of 2019, revenue efficiency of 95% on our active fleet, we expect adjusted total contract drilling revenues to be approximately $785 million. Our forecast reflects a. Just enrolled that starting this contract this week and the estimated 50 days about a service time the transactions, Spitsbergen. We expect third quarter O&M expense to be approximately $575 million, including reimbursable expenses of $28 million. The sequential increase in O&M expenses driven by the following. Expenses associated with the Ocean Rig Corcovado and Ocean Rig Miki Maus reactivations approximately $38 million related to contractually required custom expenditures that were initially expected to be amortized over the contract term. $16 million due to shifting the transactions, Spitsbergen continued SPS into the third quarter.
In addition to the SPS, our shipyard scope also include the installation and commissioning of our automated drilling technology that is self-funded through achieving enhanced bonuses as a result of improved drilling performance. Lastly, the cage includes a flexibility of $6 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 for approximately $2.1 billion.
This updated guidance reflects the previously mentioned expenses associated with the Corcovado and Miki Maus expense in 2019 as opposed to the amortized over the term of the respective contracts through 2021. We expect Gina expense for the third quarter we get approximately $48 million in line with the second quarter. Net interest expense for the third quarter expected to be a $160 million. This forecast includes capitalized interest of approximately $10 million and interest income of $7 million. Capital expenditures, including capitalized interest for the third quarter, anticipated to be a hundred -- approximately $215 million. This includes approximately $120 million for the four newbuild drillships under construction with approximately $65 million for the -- to the run drillships and up to $55 million to the Samsung rigs. Traditionally we expect maintenance capex of $95 million.
Our cash taxes are expected to be approximately $10 million the third quarter. Turning now to our projected liquidity, Dec. 31, 2021. Including at $1.37 billion revolving credit facility, which matures in June of 2023. Our end of the year 2021 liquidity estimate between 1 billion and $1.2 billion. This liquidity focus includes an estimated 2020 capex of $100million dollars and 2021capex of $900 million. The capex estimates include amounts for renewable drillships as well as fleet maintenance. Please note that our capex guidance excludes any future regrettable actions. Been mindful of the importance of maintaining our strong liquidity position we continue to carefully manage our balance sheet or remain. In focused on generating cash and reducing leverage. As Jeremy mentioned, and subject to customer consent, we intend to disclose all day rates going forward. Increasing transparency for the demonstrating our commitment to generating positive cash flow. This approach also brought an alliance of interests with those of our shareholders.
We continue to witness increasing utilization and database in both the harsh environment ( inaudible) to segments. And in mind fitness and a commitment to generate free cash flow through the cycle from our best interest rig fleet. This concludes my prepared comments. I now turn the call back over to Brad.
Brad Alexander -- Vice president
Thank you, Mark. Or does that we're now ready to take questions. And as a reminder to all our participants, please let me yourself. The one initial question and one follow up question.
Operator -- Vice president
Thank you, Mr. Alexander.
(operators instructions) Our first question will come from Ian MacPherson with Simmons. Please go ahead.
Ian MacPherson -- Analyst
Thanks. Good morning, everybody. I certainly love the new look at the fleet status report. Thanks for that. Jeremy, you made a couple of comments about additional opportunities under review for high pressure 20K work in the lower tertiary and I wanted to just follow up on that and get a sense of how far along those are and what the odds are that you could land additional work in that domain. You know, within the next several quarters, you think it's further out in time.
Jeremy Lake -- Analyst
So there are multiple customers there 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. In terms of the others are probably a little further out, maybe next year or even the year after for a decision and in terms of our positioning stated. You know, we've got the only 20 K award thus far, we think we're uniquely positioned with the second to run rig that has the 3 million pounds of load. So I think the combination of our experience are 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.
Brad Alexander -- Vice president
Just adding into that to see that. So we do expect one picture that here. But we also expect another tender to come out this year. So that's pretty good to see, not only fixtures taking place, but, you know, future work as well. So could be one or two tenders we'll see.
Ian MacPherson -- Analyst
Ok. Thanks, Robert. Can I ask you a follow up just on the fleet that you've got a couple of rigs rolling later this year. But I was curious about the Henry Goodrich in Canada. Obviously, we're seeing good day rates there for Tier 1 rigs, Goodrich being Tier 2. What are the prospects there? And then also, I think the ocean rig Poseidon is.
Questions and Answers:
Ian MacPherson -- Simmons & Company -- Analyst
Contract in Angola pretty soon as well. Any comments on those?
Jeremy Lake
Yes, you're still the as you as you pointed out, the Tier 1 rigs are really in demand. So we're completely sold over there for the good rigs itself. And she's going to finish up probably with a husky program later this year toward the end, and then we'll move to the UK. So we're looking at a couple of things for the year that we plan to pull the rig over during the wintertime we'll see what happens.
In terms of the rain as well we actually just signed yesterday, we signed a contract to extend the rig by 30 to 45 days for another well in Angola and that's with a Senegal PMP. 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 why there'd be a point for us just to keep her busy a bit longer.
Ian MacPherson -- Simmons & Company -- Analyst
Okay. Thanks, I'll pass it over.
Jeremy Lake
Thank you.
Operator
Our next question will come from Taylors Archer with Tudor, Pickering, Holt.
Taylors Archer -- rig
Hey, good morning, thanks. Turns out. But maybe I'll start a question on the fleet status and I'll echo Ian's comments that the dairy disclosures is exactly what the market's looking for. But as relates to discover a clear leader, I know that rig's been an idol for quite some time now, but in the latest fleet, it looks like you've now stacked that rig. So just curious. Any more color as relates to that decision and then as we think about that rig going back to work in the future. It's a really highly capable rig. How quickly could you return it to active status and what sort of costs would be required?
Brad Alexander -- Vice president
Yes. So it goes to the market for the rig. And so having a sec gen Rick, that basically is prioritizing the 7th gen ahead of ourselves. In the meantime, we expect to keep our stock for a little bit time until, as Jeremy said, know, we're looking to see that the day rates are contract terms, support the full payback and the reactivations. And not only that, but seeing your prospects going forward beyond that.
Jeremy Lake
And just to add to that, Taylor, I mean, this was really the result of the acquisition of Ocean Rig and where we'd get four stacked high specification seventh-gen rigs would be are going to be priorities for our customer. Before that, clearly, it will be. By next year, Christmas through cost to reactivate for those type of rigs like the [Indecipherable] relitigating the past between $40 and $50 million should get that rig back up and ready to work.
Analyst
Okay, great. That's helpful. And then a question on some of the new builds already cover the 20 KPFA type opportunities. But for the Santorini and the Creed, you still have a pretty high back end payments still do on those rigs. I realize you can push those back end payments out to the right. But as it relates to kind of the contract you're looking forward to bring those.
Taylors Archer -- rig
To exophoria, you're looking for a good rate, but it is a one year term, something you're comfortable bringing those rigs out even if the rate is good enough?
Brad Alexander -- Vice president
So let me take that. As you know, the final payments on those rings are between 360 plus million to $560 million. In addition to that, you have the cost of the regard, which could be anywhere between 75, $85 million. So you're looking at a substantial check to write, recognizing that those payments are only due at the end of 23 and early 24. We would still need to have a multi-year contract that generates sufficient return on those assets before we put it up. Clearly, we have assets that are similar to the Santorini that are currently sitting in Greece stack which we could bring up for a lot less. So those will be prioritized over the Santorini as it relates to contract opportunities.
Taylors Archer
Okay, understood. Thanks for feedback.
Operator
Our next question will come from Chase Melville with Bank of America.
Chase Melville -- 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. You know, maybe talk about what kind of momentum you continue to see and expect to see in the back half of this year. And do you expect that momentum to kind of continue into 2020?
Jeremy Lake
Yes. 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 rate. So what we've seen a couple of different parameters. Let's look real quickly at the Gulf of Mexico, Texas, because that seems to be a real yardstick in terms of when we're seeing recovery.
So since the beginning of the year, we've seen a pretty significant increase in terms of the day rates. So if we plot all these charts and essentially what we're showing is if day rates have increased anywhere between 30 to 50% based on where they were and the lower part of that downturn, which really the last kind of low-level fixtures seem to be made in late 2018. So, you know, when we see the ad start getting boots at brace approaching 200 and then we see several of our competitors are 170 and above in the Gulf of Mexico.
That's very encouraging to say that, that has moved up pretty quickly. So if if we think about it we're frustrated that it's not moving even faster, but there is actually a very nice progression in that. And we look at that overall around the world. And that's essentially what we're seeing, is that the day rates are going up anywhere from 30 to 50% depending on the particular base in.
Unidentified Participant
Okay. And on the ultra-deepwater side, are you seeing a premium for seventh-gen rigs or that they're just
Chase Melville -- Bank of America
Still not not that much tightness on the seventh you to be able to see the premium, therefore, between 6 or 7th gen?
Jeremy Lake
The 7th gen at the moment it's effectively sold out. But because there's a few the shorter-term contracts associated with that, you're not seeing the big pop pushing toward 300 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 7th gen but that typically is the way that works is the higher-spec goes to work.
Chase Melville -- Bank of America
As things tighten, what do you think would be an appropriate premium for a 7 gen versus a 6 gen, Lake?
Jeremy Lake
It really depends on the targets that you're trying to hit. But I mean, 30% , something like that.
Unidentified Participant
Okay. One quick follow up for Mark, if I may. Mark, do you have any free cash flow targets that you might would like to share, maybe over the medium to longer term?
Mark-Anthony L. Mey -- CFO
Yes. Positive.
Chase Melville -- Bank of America
Already I will. I guess I'll turn it over and look forward to the positive free cash flow.
Operator
Our next question will come from Kurt Fleet with RBC.
Kurt Fleet -- RBC. -- Analyst
Hey, good morning?
Jeremy Lake
Hey, Kurt.
Kurt Fleet -- RBC. -- Analyst
Hey, Jeremy. You made an interesting point about the requirements that you will need to activate rigs on a go-forward basis. And I think you mentioned something along the lines of getting some element 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 upfront 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 long way to set up a question of, do you think it's possible where the companies like yourselves could start to have productive discussions with the major oil companies that are generating this record cash flow and convince them that if they really want to rig, they can afford to prepay to get it out of the art and in kind of accelerate that process? Any thoughts on that will be appreciated.
Mark Mey
Yeah, we look forward to that day. I would say that right now is probably there. And we've demonstrated that there's some of the contract in terms of a harsh environment base, some of the high specification, harsh environment assets, I believe were there with our customers. I believe you could command an upfront payment or reimbursement payment for reactivating a rig and.
Mark-Anthony L. Mey -- CFO
Authorizing that rig to location, 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 and ready sediment in the Gulf, I mean, we're basically at a 100% utilization. So you could start to see that materialize in the ultra-deepwater space in the not too distant future and that's that's what I really hope for.
Brad Alexander -- Vice president
Yes. 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 said we are we have already seen it in several instances, the harsh environment being a good example. But I think you're spot on that most folks recognize, including our customers, that it is not entirely reasonable to ask for all things to be amortized over the contract and that customers are important and they're getting paid for mobilizations upfront is the way we intend to push it.
Kurt Fleet -- RBC. -- Analyst
Then I appreciate that, you know, and that's definitely helpful. And then a step in the right direction in the same context, if demands exceeding supply and its oil companies are asking the industry to kind of pull rigs off the beach and you guys got 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 patrollers, but that's more of me talking on a soapbox than anything else. But be great to see the industry kind of press for that. [Speaker Overlap]
Jeremy Lake
Keep preaching Kurt. Keep preaching.
We'll get on that box with you.
Kurt Fleet -- RBC. -- Analyst
For sure, so second thing, just in the context of liquidity forecast by the end of 2021, maybe following up on Chase's question for Mark. What free cash flow is associated with that liquidity dynamic. It's, you know, on a cumulative basis out through 2021?
Mark Mey
That's correct. We have this all in our deck, which you guys have seen many times before. The 2020 and 2021 capex numbers are pretty big for us. So clearly we're going to cover almost $2 billion of capex and we get very close to doing that during that time period. Obviously, this is based upon my direct deck, which can and will change, but we expect to be pretty close to being cash flow positive throughout that period.
Kurt Fleet -- RBC. -- Analyst
All right, thanks for that positional color. Appreciate it. That's it for me.
Operator
We'll hear next from Cole Sullivan with Wells Fargo.
Cole Sullivan -- 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?
Jeremy Lake
Yes. So in terms of the open demand, we were just floating this week, actually. So from the beginning of the year, our numbers on open demand have increased 35%. In terms of a number of regulars and downs 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. But most importantly, that's a pretty big jump in open demand. Down to the number of rigs that have to be picked up. You asked about, you know, one was kind of that act 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 site so when. Yes, there's definitely a shift toward direct negotiations when the customer is realizing that they don't have much choice of the specific assets that they want.
So if you have a program that's not just, you know, bread and butter, deepwater drilling, then they are being pretty specific about the rigs that they want. The operational record is very important, but so are the unique specifications. So from our point of view, we're certainly seeing a lot more direct negotiations. And I think our competitors are probably seeing the same.
Cole Sullivan -- Wells Fargo
All right. That makes sense. In just on the late 19 availability on some your harsh fleet like the Barents as a gap in the contract there before the new fixture. And then you have other ones like the leader in the Paul V Lloyd, how do you kind of see that over the fourth quarter where you have all the more seasonality coming in, do you see some visibility there behind the current contracts.
Jeremy Lake
Yeah. So for several of them we do. And for others, it's maybe a little bit more challenged. But what we've seen happen is that we are pretty conservative in how we report durations on our contract. So typically that the programs run a little bit longer. So with programs running a little bit longer, combined with some gaap filler work that we expect to close in the next month or two, and hopefully there won't be too many gaaps between now and the next spring.
Cole Sullivan -- Wells Fargo
All right. Thank you. I'll turn it back.
Operator
We'll go next to J.B. Lowe with Citi.
JB Lowe -- Citi
Hey, good morning, guys. I want to start with a question on drilling efficiency offshore. You know, we've seen really solid improvements in onshore rig efficiency in terms of wells drill prager or footage drilled. I'm just wondering if you guys could could put some numbers around how much you've seen your own drilling efficiency improve over the past, let's say a couple of years, and how much more room do you think there is to go, given the higher spec nature of the things that are operating today? How much more can we see that efficiency improve over the next couple of years? And that's 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.
Brad Alexander -- Vice president
Jeremy, let me caveat this by saying that due to the downturn in the industry, our best assets and our best crews working in the same is true for our competitors. And so you're getting 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 I'd say 30% is probably a good place to start.
There's always opportunity for improvement. You know, we're working internally on processes. We're working with our OEM is on improving equipment performance and 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 stacked status, we're reactivating crews, bringing new people in.
Are we going to lose some of that efficiency of an industry? Absolutely. Obviously, we'll endeavor to get those rigs and crews up to the standard we've established so far. So, yes, we've always contended that that will put a cap on the number of offshore rigs required going forward. And in fact, if you look at the back, the past, Pete, I think, you know, 2014, we had almost 270 floaters under contract in operation.
We've kind of been out there publicly for the last four years and said that the new go forward number may be closer to 200. And so that's what we've really taken the effort to high grade our fleet and focus only on those high specification assets because we think they're the ones they're going to work at in the market starts to recover.
JB Lowe -- Citi
Okay, great. Thanks for that. Quick follow up just on the contract on the Barents. Can you guys put the numbers on what the demo and mope costs are going to be so we can kind of get a cleaner rig for that rig?
Brad Alexander -- Vice president
Well, or so we can we discuss this with our customer and they would prefer that they're the actual dairy not be doing precisely so. All it would indicate would indicate to you that it's a pretty good day rate. So I thought. No, I have respect for our customer. We certainly can't divulge, they ask us not to.
JB Lowe -- Citi
All right, thanks very much, guys.
Operator
We'll go next to Sasha Stone Wall with UBS.
Sasha Stone Wall -- UBS
Thank you, and good morning. [Indecipherable] Yeah. Look, and so a lot of my questions have been answered, but just kind of wanted to touch on. Just maybe you can think about potential reactivation of 2020 here and so you. You were pretty forceful comments, I think, about kind of the requirements going to get a full payback on reactivation and what that cost might be just right. Just kind of wanted to get a sense of, you know, if there any kind of benchmarks you can put out there in terms of how much of that reactivation you're going to like to be essentially paid back within the first contract term and just essentially any guideposts to kind of help us get a sense of that.
Jeremy Lake
Well, I should say it's a good question, and when we talk about internally and you know, if you look at the cost of reactivation, we've been public about this, let's say the $50 million ticket. You know, you can back into the day rate and term required just to pay back that initial investment of $50 million. And then you'd have to have confidence that either you have enough term to generate a return on that investment or forward. 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, you know, we're really very, very -- we've established a very high bar for reactivating an asset at this point.
Unidentified Speaker
Right. Tough one, maybe just kind of touch on. The just especially the thing you mentioned is the Smith Burger and just the installation of the automatic drilling technology. Right. Maybe the question is to what extent are essentially customers requesting this and would you be willing to share even of rough range of how we should think about daily rate uplift?
Brad Alexander -- Vice president
Yeah again, so on the dairy 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. Customers are very interested in that because if you are able to drill the well, you know, as Jeremy said, was improved 30% in some of our assets.But I mean, even if you're picking up 10 or 15%, it makes a material difference to the well costs. So that's why these kind of self-funded bonuses really work well for both sides. So, I mean, we've been collecting, you know, 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 [Speech Overlap]
Jeremy Lake
But we have we did say in the last call, I mean, as we look at these specific relationships that we have with that Gumayan installation of the automated drilling controls, if we perform as we think we will, these these will pay for themselves inside of a year.
JB Lowe -- Citi
Okay grerat, maybe if I could sneak in one more quick one, just maybe in terms of some of the recent contract fixtures that were announced. Could you maybe give us a sense of how competitive those were and maybe just general thoughts on how you kind of see essentially the discipline from the other contractors buying out? Thank you.
Brad Alexander -- Vice president
Yes, so we would love to see a lot more discipline from our competition, but yeah, really it's about, you know, you haven't seen anybody book any long term fixtures at Lode. So that kind of tells you where everybody's head is in towns with the future. So that's good. The short term is a bit more competitive. It depends on which space you are which region are. But I would just say that if you look at the average picture, you see where things are going. It's not just those 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.
Jeremy Lake
I think the important thing to note there is what Brad led with which was that no real long term contracts have been awarded at low day rates. And it's really just people are scrambling in some cases to try to fill gaps so that they don't have to have to take a rig idle or even staggered.
Sasha Stone Wall -- UBS
Thank you, I'll turn it over.
Operator
We'll go next to Craig Bliss with ETIG.
Craig Bliss -- ETG
Yes. Thank you. Good morning, everybody. I guess, Brad just following up on that sort of train of thought. You know, if we were to look at Mike today versus a year ago, do you have a sense for how much the bid asks between, you know, somebody like Transocean, which is more focused on price and over utilization versus maybe some of the competitors, how much that sort of bid-ask has come at the high end versus the low? It's kind of converged?
Brad Alexander -- Vice president
And so, yes, they are converging, there's no doubt it's 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, since this year, far from kind of one a wire with the escalating 503, the Pacific and ourselves seized a lot of looking stuff. You know, 165, 175, 180, 185, that kind of range. So there may maybe one or two outliers, but for the most part of the discipline seems to be there.
Craig Biss -- ETIG
Okay, great. And then just totally shifting gears, I mean I guess free cash flows. You know, it's been a little bit of a theme on this call. I guess right now out in the market, there's a tender in the North Sea potentially for a rig of the future, not now realizing that this is still years away. Is this something that we think Transocean is actively looking at pursuing?
Brad Alexander -- Vice president
Yes, we are. I just met.
Craig Biss -- ETIG
And just sort of you could give a little bit of color around, you know, how we should be thinking about, you know, when that start up could be and sort of like what went with how he had been thinking about that.
Jeremy Lake
Let me stress, it would not be on a speculative basis. [Speech Overlaps] it isn't.
Brad Alexander -- Vice president
Yes. So that prospect is several years in the future and it really is. If you look at Nari what you have is like a So a rig like the cat D are fit for purpose. Designed exactly to do what you need them to do. The most efficient manner possible. And so it's one of those exercises, again, is like. So what does the new cat D look like? And in terms of actually delivering that rig is starting that program, we think that probably, you know, 4 or 5 years early. So there's a lot of things to think about it. But, you know, 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 rest of the future on a continual basis. It's just at this moment in time, you would have to see a very significant investment from the operator upfront to see any of those takeoffs.
Jeremy Lake
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 would. 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.
Craig Biss -- ETIG
Perfect. Okay, guys, thank you very much.
Operator
We'll go next to question Sean Makeum with JP Morgan.
Sean Makeum -- JP Morgan
Thanks, good morning.
Jeremy Lake
Good morning, sir.
Sean Makeum -- JP Morgan
So just a couple of things. One, if I get your thoughts on around how contract negotiations are evolving, you know, to some more direct negotiations, some of the operators are trying to get specific rigs back that they're looking for. Maybe could we talk about how they would non-dairy compensation arrangements are being prioritized from your side or from the customer side. Our mob costs becoming more commonplace or is this only still in select tenders? Just regular more of a feel for how that's going on as you're negotiating these new contracts.
Brad Alexander -- Vice president
Yes, a lot of direct negotiations, stuff you're going to see is either because the operator already has the rank, are the riggers, has to see the region immediately available. So in that case, mobilization costs are pretty low, or practically zero. But what we're definitely seeing is this direct negotiations stuff is around the best-performing assets or unique specifications that really help. So you would have seen that ice fell in South Africa. You know, ourselves and Canada and the US and a few other that are typically not tendered opportunities in terms of the mobilization fees. We are seeing that across the board now. So we're aware that there is a mobilization cost. Then we are seeing mobilization fees getting paid. So, I mean, I can't speak for my competitors, obviously, but from our point of view, that's very important in the new dynamics that these contracts become cash flow positive.
Sean Makeum -- JP Morgan
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? Is that not as favorable as a strategy of trying to get the best terms for each rig at this point, the cycle?
Brad Alexander -- Vice president
Yes, I think you always got to balance that depending on how competitive things are. But, you know, I mean, you saw there you're talking about baskets already saw that extra brush picked 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 that same contract for more than one rig with the same operator. But I don't think there's a volume cash discount. Certainly, I think it really is a case of you shoot, each asset is earning the best you can.
Sean Makeum -- JP Morgan
Got it. Okay, great. Thank you.
Operator
Our final question will come from Daniel Boyd with BMO Capital Markets.
Daniel Boyd -- BMO Capital Markets. -- Analyst
Good morning. This is Ken going on for Dan. Could you just clarify if your revenue guidance of 785 million includes amortization revenue?
Mark Mey
Yes.
Daniel Boyd -- BMO Capital Markets. -- Analyst
Thank you. That is it for me
Jeremy Lake
Thanks.
Operator
I'd like to now turn the conference back. Excuse me, back to Mr. Alexander for any additional or closing remarks.
Brad Alexander -- Vice president
Thank you, our guests, and thank you to all of our participants on today's call. If you have any further questions, please feel free to contact me. We look forward to talking with you again when we report our third quarter 2019 results. Have a good day.
Operator
[Operator Closing Remarks]
Duration: 50 minutes
Call participants:
Brad Alexander -- Vice president
Jeremy Lake
Mark-Anthony L. Mey -- CFO
Taylors Archer
Mark Mey
Unidentified Speaker
Taylors Archer -- rig
Ian MacPherson -- Simmons & Company -- Analyst
Analyst
Chase Melville -- Bank of America
Unidentified Participant
Kurt Fleet -- RBC. -- Analyst
Cole Sullivan -- Wells Fargo
JB Lowe -- Citi
Sasha Stone Wall -- UBS
Craig Bliss -- ETG
Craig Biss -- ETIG
Sean Makeum -- JP Morgan
Daniel Boyd -- BMO Capital Markets. -- Analyst
