Q2 2019 Earnings Call
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Good day, everyone and welcome to the Q2 2019 <unk> earnings Conference call Trans Ocean Limited today's conference is being recorded at this time I would like to turn the conference to Brad Alexander Vice President of Investor Relations. Please go ahead Sir.
Thank you all got stuff.
Good morning, and welcome to transaction 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 a deepwater dot 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 Rob 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 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 marks prepared comments, we will conduct a question and answer session.
During the time to get 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 will 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 2019 transactions generated adjusted EBITDA of $207 million on $805 million and 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 as resulted in revenue efficiency of approximately 98%, which is a testament to the superior operating performance from both the legacy transaction fleet and the assets we've acquired over the past two years.
Well, our crews and shore based support staff deserves a great deal of the credit for this 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 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 return additional rigs to work.
At this point, we have effectively completed the integration of this transaction and expect to fully recognize the anticipated synergies as we move through the balance of the year.
I'd like to take this opportunity to thank the entire transition team for delivering another solid quarter I'd also like to recognize those employees, who played an integral role in a timely and seamless integration of ocean rig.
In addition to strong execution during the day.
Since our last call, we secured a couple of contracts, which we believe to be notable.
Two weeks ago murky selected the deepwater as GARP to drill two wells in the Gulf of Mexico at a rate of $185000 per day.
With the opportunity to earn a performance bonus which could result in total compensation approaching $200000 today.
Well, we certainly need and expect for rates to move higher over the coming months. This fixture demonstrates that we are clearly moving in the right direction for high specification ultra deepwater drillships.
As another positive data point, just last week the transition Barents 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 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 downtime bank as part of this contract.
Needless to say, we're 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, dayrates must improve to levels that enable us to generate meaningful free cash flow.
In fact to demonstrate our resolve and elevating day rates on a go forward basis and consistent with our most recently filed fleet status report and less restricted by our customers. We will 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 reactivations well to better demonstrate that our contracting philosophy is aligned with our investors expectations for appropriate returns.
Turning to the market overall, the floating active rig count increased 6% in the first half of the year.
Importantly, when including future rigs contracted the total number of floaters under contract remains near 160 assets, keeping overall marketed utilization at a level above 80%.
And while ultra deepwater 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 a 14% year over year increase in the number of working ultra deepwater drillships.
Well, we would certainly prefer 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 $40 per barrel.
Reserve replacement ratios for many of our customers continued 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 the bottom in every major operating bases 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 20000 PXI 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 tightened our strong technical and operations teams and the fact that we have the tightened sister rig currently under construction in the Jurong 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, and multi well program with shell later this year with activity running well into 2020.
Additionally, we anticipate drilling a second exploration well in the trial infield for BHP during the third quarter.
In the Caribbean, we are encouraged to see a recent fixture award answering them.
This however is not surprising in light of the successive programs over the past couple of years in neighboring Guiana, and hopefully just the first of numerous awards here.
Moving to Brazil, the Ocean rig corcovado and the ocean rig, making those remain on schedule to commence operations in Brazil in the fourth quarter at which time, we will have three ships operating in country.
With this installed base our history of performance in this region, our industry, leading fleet and Petrobras contracting the remaining available local drilling rigs, we feel that we are well poised to take advantage of the future opportunities that will undoubtedly arrive in the coming quarters and years.
In Africa, the opportunities, we discussed last quarter emerging in Angola, Nigeria, Ghana equity of getting in Senegal are continuing to progress in Egypt. The discover India will begin her campaign Liberalise in August .
This follows the successful campaign with CRL in the Ivory Coast.
And as stated on past calls it's important to note that awards in this region would likely represent a significant number of rig years as developments here are typically longer cycle in nature, and therefore can impact the marketed 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 out the Golden triangle.
In Asia Pacific shells, again contracted the deepwater novelist six well program and 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 rate solidly in the mid to high $200000 per day range with additional opportunities on the horizon.
Turning now to the harsh environment market region, North Sea remains strong.
In fact, our newest additions to the fleet the transition in Oregon is on schedule to commence its maiden contract later today.
The firm contract concludes in May 2020, but has options to extend into September .
This high specification semi submersible marks our seventh world class assets suitable for this market and we anticipate that she will be in high demand as she approaches the end of for term.
As previously mentioned, we are pleased to be keeping the parents in Canada.
We have good visibility to future work to the Barents in Canada and remain encouraged by our prospects as she is clearly the highest specification asset in country.
However, if were 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 or.
And finally in the UK, we continued to see fixtures from the independents and majors alike that suggest the market will again be tightening summer, which bodes well for the likelihood of you round drilling for our fit for purpose assets 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 dayrates are approaching and in some cases exceeding $400000 per day and customers are once again, providing downtime bags and reimbursements for mobilization and demobilization.
And what were 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 in 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 high grade our fleet just as we did these past few months as we added the nor get to our contracted fleet and we made the decision to recycle the actinia.
They are 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 increased the number of economically viable targets within their respective portfolios.
And we will continue to take the necessary actions to extend our liquidity runway and ensure that we have the cash that we need to responsibly invest in our assets, our workforce and the community, which we operate.
We believe that executing against these initiatives best positioned transition for the recovery.
Ill now hand, the call over to Mark.
Thank you Jeremy and good day tool.
During today's call I'll briefly recap our second quarter results and then provide guidance for our third quarter two.
Lastly, I'll provide an update to our 2019 should drop projects as well as our liquidity forecast to between 21.
As reported in our press release for the second quarter 2019.
We reported a net loss attributable to controlling interest of $183 million or 30 cents per diluted share.
After adjusting for favorable items associated with tax unfavorable items associated with the early retirement of debt.
On the sale of an asset we reported adjusted net loss of $210 million.
Or 34 cents per diluted share.
Further details are included in our press release.
In the second quarter, we delivered adjusted EBITDA of $257 million.
What's not adjusted EBITDA margin of 32% from over $805 million of adjusted revenue.
We're very pleased to announce another quarter of efficiency of revenue efficiency outperformance, which includes achieving the majority of our drilling contract bookings opportunities for the quarter.
We've also sort of the long standing customer dispute.
We generated cash flow from operations of $153 million, an increase of $204 million a quarter over quarter Morgan reversing the unexpected cash for an experienced in the first quarter.
For the second quarter operating and maintenance expense of $510 million.
This was below our guidance due to timing of in service maintenance.
And project costs in the second quarter.
These forecasted cost associated with the transaction Spitsbergen 10 year Sps.
Well, we delay to the third quarter.
Turning to cash flow and balance sheet.
We ended the second quarter with total liquidity or flux $73.6 billion, including cash and cash equivalents of $2.2 billion.
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 or did they did that in the open market.
Additionally, during the quarter, we successfully accessed the capital markets issuing $525 million of senior notes due 2023.
Secured by the translation endures and translation equinox.
Two of our high specification harsh environment rigs under long term contracts will take renewal.
As we have proven over the prior several years, we will continue to take the necessary steps to extend our liquidity runway.
Prudently reduce leverage and proactively manage on new dated maturities.
Let me now provide an update on our third quarter 2019 financial expectations.
Well the first quarter of 2019 semi revenue efficiency of 95% active fleet.
We expect adjusted total contract drilling revenues to be approximately $785 million.
Our forecast reflects a transaction or the starting its contract this week.
And the estimated 50 days of out of service time, the Transocean Spitsbergen.
We expect good quarter over them expense to be approximately $575 million, including reimbursable expenses of $28 million.
The sequential increase in or we don't experience is driven by the following.
Expenses associated with the Ocean rig corcovado and ocean rig mykonos renovations, but flux and look at $38 million.
That is a contractually required customer experiences that were initially expected to be amortized over the contract term.
$16 million due to shifting the transition Spitsbergen, taking SBS into the third quarter.
In addition to the SPS shipyard scope also includes the installation and commissioning of the automated drilling Pic technology that is self funding through achieving enhance bonuses as a result of improved performance.
Lastly, the kgs is approximately $6 million of shipyard expenses that will be recognized in the third quarter related to his upcoming campaign with Chevron in Australia.
For the full year, we now expect earn an 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 your Corcovado and mykonos screen experience in 2019.
As opposed to amortized over the term of the districts of contracts through 2021.
We expect you to expense will be approximately $48 million in line with the second quarter.
Net interest expense for the third quarter, we expect it to be.
And $60 million.
This forecast includes capitalized interest of approximately $10 million.
Interest income of $7 million.
Capital expenditures, including capitalized interest for the third quarter August spread to be 100, approximately $215 million.
With approximately $65 million for the trees are wrong drill ships and up to $55 million for the Samsung rigs.
Additionally, we expect maintenance capex of $95 million.
Our cash taxes are expected to be approximately $10 million.
The third quarter.
Turning now to our projected liquidity at December 31, 2021.
Including $1.37 billion revolving credit facility, which matures in June of 2023.
Our end of year 2021 liquidity estimate between 1 billion and $1.2 billion.
This liquidity forecast includes an estimated 2020 capex.
The others and turning to any one capex of $900 million.
The Capex estimates include a month.
For our Newbuild Drillships as was fleet maintenance.
Please note that our capex guidance excludes any future congratulations.
Being mindful of the importance of maintaining a strong liquidity position, we continue to carefully manage our balance sheet for remaining focused on generating cash and reducing leverage.
As Jamie mentioned and subject to customer consent, we intend to disclose all day rates going forward.
Increasing transparency and further demonstrating our commitment to generating positive cash flow.
This approach will separate that aligns our interests with those of our shareholders.
We continue to witness increased utilization and day rates in both the harsh environment ultra deepwater segments.
And we remain steadfast in our commitment to generate free cash flow through the cycle.
Best in class rig fleet.
This concludes my prepared comments.
I'll now turn the call back over to Brad.
Thank you Mark.
Our dust that 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. Erik Alexander the question and answer session will be conducted electronically to ask a question. Please press star one on your phone at this time.
If you're already speakerphone. Please make sure your mute function is turned off to allow us.
Excuse me I love a signal to reach our equipment.
Our first question will come from.
Macpherson with Simmons. Please go ahead.
Thanks, Good morning, everybody.
Certainly love the new look on the fleet status report thanks for that.
Yes, Jeremy you made a couple of comments about.
Additional opportunities under review for.
Hi 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 how you know.
What the odds are that you could land additional work in that domain within the next several quarters, where do you think it's further out in time.
So there are multiple customers are exploring this possibility I'd say that there is one that is very close to a decision that decision.
And that decision could come before year end and in terms of the others are probably a little farther out maybe next year or even even the year after for a decision.
And in terms of our positioning as a stated we've got the only 20 K. award thus far.
We think we're uniquely positioned with the second jurong rig in that had the 3 million pound hook load.
And so I think the combination of our experience our breadth and depth of expertise and the fact that we've got a rig under construction that could be upgraded to 20 K puts us in a very unique position.
Yes, yes, just tied into that to say that.
So we do expect one picture this year, but we also expect another tend to come out of this year. So thats pretty good to see not only fixed is taking place but.
Future work as well so.
Could be one or two tenders, we'll see.
Okay. Thanks, Rodney can I ask you a follow up just on the fleet side. It's you've got a couple of rigs Rolling later this year that I was curious about.
The Henry Goodrich Encana, obviously, we're seeing.
Good day rates, there for tier one rigs goodrich being.
Tier two.
What are the prospects there and then also I think the ocean rig Poseidon is rolling off contract in Angola pretty soon as well any comments on those.
Yes, sure Bill day yet.
As you as you pointed out the tier one rigs really in demand so.
We are completely sold out there for the good mix itself and she's going to finish up probably with a husky program. Later this year towards the end and then we'll move on to the UK. So we're looking at a couple of things that we plan to build or is over.
During the wintertime.
And in terms of.
Ryan as well, we actually just same day yesterday, we signed a contract to extend the rig by yet.
45 days for another well in Angola, and that's with the cycle.
I don't think I can really say any of the other information because we don't have permission from the operator, yet but.
That said positive data point for us is to keep a busy a bit longer.
Okay.
Hey, Thanks, I'll pass it over.
Thanks.
Our next question will come from Taylor researcher with Tudor Pickering Holt.
Hey, good morning. Thanks.
Morning.
But maybe I'll start a question on the fleet status.
I'll Echo his comments that the day rate disclosures exactly with what the market is looking for but as it relates to discover a clear leader I know that rig has been idle for quite some time now but in the latest fleet status looks like Youve now stacked that rig so just curious.
Any more color as it relates to that decision and then as we think about that rig going back to work in the future. It's a really highly capable rig how quickly could you return it to active status and what sort of costs would be required.
Yes, so again today the market for the rig and so having a sixth gen rig that.
Basically prioritizing the seventh Gen head of IR. So in the meantime, we expect to keep our stacked for a little bit of time until as Jeremy said, we're looking to see that the day rate and the contract terms support the full payback of the Reactivations at a net.
Not only that but seeing prospects going forward beyond that just add to that Taylor and this was really the result of the acquisition of Ocean rig and where we've got four four stacked high specification seventh Gen rigs, we feel are going to be priorities for our customer before that clearly there will be.
Our next year Christmas through costs through retrograde.
For those type of rigs electrically theater, we've indicated in the past between 40 and $50 million should kick that rig back off.
And ready to work.
Okay great.
And then a question on some of the Newbuilds.
We already covered the 20 K P type opportunities, but for the century in the Creed.
You still have.
Pretty 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 are looking forward to bring those rigs out clearly you are looking for.
A good rate but.
It is a one year term something you're comfortable bringing of those rigs out even if the rates are good enough.
Yes, So let me take that as you know the final payments on those rigs are between 360.
Million to $560 million.
In addition to that you have the cost to bring the rig off which could be anywhere between $75 million to $85 million. So im looking at a substantial check to ride.
Recognizing those payments only do it to enter 23 and 24.
We would still need to have a multiyear contract that generates a sufficient return on those assets for reported GAAP.
Clearly we have assets that are similar to the sense really.
That are currently sitting in Greece stack, which we could bring on for a lot less.
So those will be prioritized over the central Reni.
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.
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.
Yes. Good question. So we were looking at.
So where we are from like the number of contracted rigs utilization level, what that's doing daily so what we see and couple of different but all answers, let let's look real quickly the Gulf of Mexico fixtures, because that seems to be.
I really optimistic in terms of when we see the comedy so since the beginning of the year.
We've kind of seen a pretty significant increase in times of the day rate said, but we put all of these charts and essentially what we're showing it days of increase anywhere between 30% to 50% based on weather and the lower part of that.
Is that in turn which really the last kind of low level fixtures seem to have been made in late 2018. So you know when we see the you asked are getting boot.
Great approaching 200.
And then we see several of our competitors are.
170, and above in the Gulf of Mexico, but it's very encouraging to see that.
Has moved up pretty quickly so if if we think about it.
We're frustrated that its not moving even faster there is actually a very nice progression in that.
When we look at the overall around the world and that's essentially what we're seeing is the day rates 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 seven gen rigs or or is there just still not not that much tightness on the 17 and to be able to see the the premium there for between six and seven.
Yeah, well I mean, just seven gen at the moment and.
It's effectively sold out but because as a few of the shorter term contracts associated with that you're not seeing the big Paul appreciate to what city hundred yet.
But.
Certainly the premium I think is more for a hot rig with a great record that said performing well I mean, it doesn't necessarily have to be a seven gen but.
Typically as said the way that works is the highest spec goes to work for us.
As things tighten up what do you think would be an appropriate premium a seventh gen versus the sixth Gen rig.
It really depends on the targets that you're trying to hit, but I mean, 30% or something like that.
Okay.
One quick follow up for Mark if I may I'm, Mark do you have any free cash flow targets that you might would like to share.
Maybe over the medium to longer term.
Yes positive.
[laughter].
Yeah, well 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.
Hi, there, Thanks, Hey, Hey, Jeremy you mean.
Interesting point about the requirements that you will need to get to activate rigs.
On on a go forward basis.
I think you mentioned something along the lines of getting some element of commitments from some of your customer base.
And I think clearly by the way the.
Stocks have been behaving even with the improvement in the underlying fundamentals of the market.
It seems like investors would prefer that companies like yours would get the cash upfront from.
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 a kind of a long way to set up a question of.
Do you think it's possible.
Where the companies like yourselves could start to have productive discussions with the major oil companies that are generating this record cash flow.
And convince them that if they really want the rig.
They can afford to prepay.
To get it out of the yard in and kind of.
Accelerate that process any any thoughts on that be you appreciate it.
Yes, we look forward to that day, I would say that right now, we'll probably there and we've demonstrated that there is some of the contracting terms in harsh environments base sort of the high specification harsh environment asset I believe were there with our customers I believe you could.
Command, an upfront payment or reimbursement payment for.
For reactivating, a rig mobilizing that rig to location and we've demonstrated that already with the most recent contract.
But but with the ultra deepwater.
We're not we're not quite there yet.
But as we start to see the market continue to tighten as Rodney said.
Hello.
Basically a 100% utilization.
And so you could start to see that.
Materialize in the ultra deepwater space in the not too distant future and that's what really hope for yes.
I think where you will see that is it will show up in mobilization fees. So for example.
You know the the mobilization fee that we get with it tied to essentially pays for that movement of the rig over there that's not something that we're recovering over that.
Yeah. So.
Jeremy we have already seen it in several instances and our bottom it's been a good example, but.
I think you're spot on that debt.
You know most folks recognize a including our customers that it is not entirely reasonable to ask for all things to be amortized over the contract and that cash flow is an important and they're getting paid for mobilizations upfront is that we intend to push it.
Yeah, Dan I appreciate that you know.
And that's definitely helpful and then step in the right direction in that same context, if you know.
Demand exceeding supply in these oil companies are asking the industry to kind of pull rigs off the beach and you guys got to foot the upfront bill of that $50 million or whatever at the end of the day, they should be putting that bill not necessarily the drillers, but thats.
It's for me talking on a soap box than anything else, but it'd be great to see the industry.
Kind of a kind of press for that.
Which brings and congrats from me.
Jeff bridges.
Yes, Alex with you.
Yeah for sure.
So second secondly, just in the context of the.
Quit any forecast by the end of 2021, maybe following up on Chase's question for Mark what.
What free cash flow is associated with that liquidity dynamic it.
On a cumulative basis out through 2021.
Yes, you're 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 weve got a couple of almost $2 billion of Capex.
And we get pretty close to doing that during that time period.
Obviously this is based upon a day rate 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 hear next from Cole Sullivan with Wells Fargo.
Hi, good morning, and I'll say, thanks again for a publishing the rates I know you've heard that a few times, but I'm sure you'll keep hearing that from us.
On on.
On just discussions today, how are you seeing the progression of duration and new tenders in private discussions are you seeing.
That begin to stretch out at all versus prior prior levels.
Yes, so in terms of the open demand we would flooding. This this week actually still.
From the beginning of the year I or the numbers on open demand have increased 35% towns and number of rig years.
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.
So the number of.
Rigs that we picked up.
You asked about.
What's kind of direct negotiation so the numbers that we cite the ones that are not just the public tenders, but also the things that we know are happening.
Perhaps on the site so.
Yes.
There's definitely a shift toward direct negotiations when the customer is realizing that they don't have much choice of specific assets that we want. So if you have a program. This is not just the bread and butter deepwater drilling they know that 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 data in 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 your.
Parse a 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 poll the Lloyd how do you kind of see that.
Over the fourth quarter were a little bit more seasonality coming in do you see do you see some visibility there behind the current contracts.
Yes, so far for several of them, we do and for others, it's going to be a little bit more challenged but what we've seen happen is that that we are pretty conservative in how we report mutations on our contracts.
So typically the programs run a little bit longer so with programs running a little bit longer combined with some gap fill the work that we expect to close in the next month or two and hopefully they won't be too many gaps between now and next spring.
All right. Thank you I'll turn it back.
Well go next to JB Lowe with Citi.
Hey, good morning, guys.
I wanted to start with a question on on drilling efficiency offshore.
We've seen.
Really solid improvements in onshore rig efficiency in terms of.
Drilled per rig 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 rigs that are operating today, how much more can we see that efficiency improve over the next couple of years and as a quick follow up to that.
Does that put a cap or at least a limit on on the upside in the floating rig count.
That you would normally see in a more normalized environment. Thanks.
So Jamie let me, let me caveat this by saying.
Due to the due to the downturn in the energy industry, It's our best assets in our best crews working in the same is true for our competitors and so you're getting optimal efficiency plus all the time that we put into it so we probably seen and.
Incremental affirmative about 30% in some cases on the on some of our high spec rigs operating in the Gulf of Mexico.
And around and around the world for that matter. So I'd say I'd say, 30% is probably a good 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 at we're looking at new technologies, and so yes, there will be ways to continue to improve efficiency.
What I'd say to that is as the market starts to recover and we start to bring assets at a stack status.
We are reactivating crews, bringing new people in or we're going to lose some of that efficiency as an industry, absolutely obviously will endeavor to get those rigs and crews up to the standard we've established so far.
So yes, we have 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 peak I think 2014, we had almost 270 floaters.
Under contract and operation.
We've kind of been out there publicly for the last four years and so that the new go forward number maybe closer to 200.
And so thats, what weve really taken the effort to high grade our fleet and focus only on those high specification assets. Because we think those are the ones. They are going to work in the market.
As it starts to 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 demo been low costs are going to be so we can kind of get a cleaner.
Right for that Rick.
Well.
So we can we we we discussed this with that customer and they would prefer that the.
Actual daily not be doing precisely so.
All I would indicate that would indicate to you that Dan.
It's a pretty good day rate so.
No I have respect, but definitely we certainly I can't divulge that they ask us not to.
All right thanks, very much guys.
Well go next to Sasha.
Thank you and good morning.
One is that.
Yes, well I can tell 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 2020 here and so are you.
You had pretty forceful comments, I think about kind of climate to kind of get a full payback on reactivation cost might be.
Just.
Right just kind of wanted to get a sense of.
Or any kind of benchmarks you can put out there.
In terms of how much of that reactivation, you've kind of like to be essentially pay back within the first contract term and just.
Essentially any guideposts, you kind of help us get a sense of that.
Well, so I should say, it's a good question and when we talk about internally and if you. If you look at the cost of reactivation, we've been public about this let's say, it's a 50 million dollar ticket.
You can back into the day rate and term acquired just to pay back that initial investment of $50 million.
And then you'd have to have confidence that either do 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.
Right. Okay. That's helpful. And then maybe just kind of touch on.
Hey, I'm just essentially the.
I think you mentioned this the Spitsbergen, just the installation of the automatic drilling technology right. So maybe the question as to what extent are essentially customers requesting that.
And would you be willing to share even a rough range of how we should think about your rate uplift.
Yes, again, so on the dairy uplift I'm not sure we can really share the details of that because its a confidential contract but.
Yeah in terms of customers interested in it yes customers are very interested in that because if you'd able to two.
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 thats why these that kind of self funding bonus easily work well for both sites.
So I mean, we've been collecting very nice bonuses over the last couple of quarters. So.
We expect that to continue.
But it sounds like the absolute number.
I don't think I can really develop but we have we did say in the last call I mean, as we look at the specific relationship that we have with equity installation of the automated drilling controls. If we perform as we think we will these 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 fixtures that were announced.
Can you maybe give us a sense of how competitive that was far and maybe just your general thoughts.
Hi, how are you kind of see.
Essentially the disappointing from the other contractors playing out thank you.
Yes, So we would love to see lots more disciplined from a competition.
But that.
Yes, really it's about it's.
You haven't seen anybody book any long term.
Fixtures that low day rates, so that kind of tells you what where everybody's head is in terms of the future. So that's good and then the short term is a bit more competitive.
Depends on what spacing out which we are.
But.
I would just say that if you look at the average fixtures and you see where things are going.
It's not just does that.
Our increasing to 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 a little catch up I think the important thing to note. There is what what really led with which was that no real long term contracts have been awarded at low day rates and it's really just people or people are scrambling in some cases to 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.
Well go next to Greg Bliss with etiology.
Yes, Thank you and good morning, everybody.
I guess Robby Robin just following up on 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 transmission, which is more focused on pricing over utilization versus maybe some of the competitors how much that sort of bid ask has come in at the high end versus the low one is kind of converge.
Yes, so yes, they are converging theres no doubt, it's right I mean, the as you see the fixtures are much more closely grouped as a basket. If you look at like the Gulf of Mexico. The last season fixtures basically at CES. This year apart from kind of one outlier with than the Ensco 85 with Citi.
The u.
Pacific and our sales.
Seasonal at all bookings stuff 160, 571, 80, 185 that kind of range. So.
And then maybe one or two outliers, but.
For the most part of the discipline seems to be there.
Okay, Great and then just totally shifting gears I mean, I guess free cash flows.
It's been a little bit of a theme on this on this call.
Yeah, I guess, there right now out in the market, there's a tender in the north sea potentially for a rig into the future now realizing that this is still years away is this something that we think transition is actively looking at pursuing.
Yes, we are and just another.
Okay, and just sort of if you could give a little bit of color around how we should be thinking about when that start up can be and sort of.
Like they went.
Thinking about that I mean, let me stress it would not be on a speculative basis.
[laughter] areas.
Yes. It so that prospect is several years in the future and that really is that if you look at it and normally what you have is like at a rig like the cat. These are fit for purpose designed exactly to do what they 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 you look like.
And in terms of actually delivering that rig it's nothing that program, we think thats, probably four or five years away. So there's a lot of time thinking about it but.
And in any given Sunday, we are always looking at what is the latest technology what does the future look like so I mean, our teams are looking at rigs of the future on a continual basis. It's just at this moment in time, you would have to see a very significant investment from the operate that upfront to see any of those to take off in a specific opportunity you're referencing is driven by one customer who is 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 if 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.
Well go next to Sean Meakim with JP JP Morgan.
Thanks, Good morning.
Good morning, Jeff.
So just a couple of things.
Wanted to get your thoughts are around how contract negotiations are evolving how you 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, our low cost becoming more common place or is it something still on select tenders just regular more of a feel for how that's how that's going on as you're negotiating these new contracts.
Yeah, so lot of the debate negotiation stuff, you're going to see is either because the the already are already has the rig or the rig is.
How do you see that in the region immediately available.
So in that case mobilization costs are pretty low practically deal.
But what we're definitely seeing is direct negotiations stuff is around the best performing asset or unique specifications that really help. So you would have seen that.
Always fail and South Africa.
You know our sales in Canada and in the U.S. and a few others that.
They are typically not tendered opportunities.
In terms of the mobilization fees, we are seeing that across the board not so.
Where that is a mobilization costs, they and 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 a very important in the dynamic that debt.
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 or 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.
Yes, I think you always got to balance that depending on how competitive things are but.
You know I mean, you saw that you're talking about the baskets of rigs you saw that Petrobras picked up seven rigs I mean, that's fantastic to see that kind of activity from.
Brazil Dems of other operators looking at multiple rigs there are a couple of multiple rig opportunities idea.
There's always a kind of a synergy when you when you pick up that same contract for more than one rig with the same all pretty good but I don't think those oh volume cash discount certainly I think it really is a case you should each asset is adding the best you can.
Got it okay, great. Thank you.
Our final question will come from Daniel Boyd with BMO capital markets.
Good morning. This is killing him on for Dan could you just clarify if your revenue guidance of 785 million includes amortization revenue.
Yes.
Thank you.
But for me.
Thanks.
[laughter].
I'd like to now turn the conference back.
Give me back to Mr. Alexander for any additional or closing remarks.
Thank you our guest 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.
That does conclude our call for today. Thank you all for your participation you may now disconnect.
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