Transocean Ltd.
Q3 2017 Earnings Call Transcript

Published: 2 Nov 2017

[Operator:]

Good day, and welcome to the Third Quarter 2017 Transocean Earnings Call. Today's conference is being recorded. And at this time, I'd like to turn the conference over to Bradley Alexander, Vice President of Investor Relations. Please go ahead, sir.

[Bradley Alexander:]

Thank you, Levi. Good morning, and welcome to Transocean's third quarter 2017 earnings conference call. A copy of the press release covering our financial results, along with supporting statements and schedules, including reconciliations and disclosures regarding non-GAAP financial measures, are posted on the company's website at deepwater.com. Joining me on this morning's call are Jeremy Thigpen, President and Chief Executive Officer; Mark Mey, Executive Vice President and Chief Financial Officer; and Roddie Mackenzie, Vice President of Marketing and Contracts. During the course of this call, 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 of management 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. When we get to our question-and-answer segment of the call, to give more participants an opportunity to speak, please limit your questions to one initial question and one follow-up question. Thank you very much. I'll now turn the call over to Jeremy.

[Jeremy D. Thigpen:]

Thank you, Brad. And a warm welcome to our employees, customers, investors and analysts participating in today's call. Before delving into the quarter, I'd like to introduce and welcome Roddie Mackenzie to our call today. As many of you know, Terry Bonno, our long time Senior Vice President of Marketing and Contracts recently moved into the newly created role of Senior Vice President of Industry and Community Relations, where, among other things, she will help me to lead Transocean's effort around corporate sustainability. In her place, Roddie, who has served in numerous technical, operational and marketing roles over his nearly 20-year tenure with Transocean, has now assumed the role of Vice President of Marketing and Contracts, and will support Mark and I during the question-and-answer portion of today's call. I'd like to begin by thanking the entire Transocean team for delivering another quarter of strong operational results. As reported in yesterday's earnings release, for the third quarter, the company generated adjusted normalized EBITDA of $349 million on $709 million in adjusted normalized revenue, resulting in a third quarter adjusted normalized EBITDA margin of 49%. These results were driven by a combination of solid uptime performance with revenue efficiency of 97.1% in the quarter, and continued cost control. Needless to say, we're again pleased with our operating results as they reflect our unwavering commitment to continuous improvement across the enterprise, including creating an incident-free workplace, high grading our fleet, maximizing uptime performance for our customers, reducing the time required to construct a well, and as evidenced by our strong and consistent EBITDA margin performance, doing all of this while realizing efficiencies in every aspect of our business. Let's start with safety. I'd like to recognize the entire Transocean team for achieving what is now approaching 19 consecutive months without a single lost time incident. Because of your focused efforts, we continue to improve our safety performance, which was, according to the International Association of Drilling Contractors, already industry-leading in both the first and the second quarters of this year. In addition to continuous improvements in safety, we also continue to improve the overall quality of our fleet. In August, we entered into an agreement to acquire Songa Offshore and its fleet of seven floaters, including four new harsh environment, high-specification Cat-D semisubmersibles. As a reminder, these Cat-D rigs were designed in collaboration with Statoil and are currently contracted to Statoil with a total backlog of approximately $4 billion, which extends into 2024. It's important to note that this $4 billion in backlog does not include the follow-on multi-year options, which could add an incremental 12 years of work for each of the four rigs. Since the transaction will add four new harsh environment assets to our fleet, in a target market with a strategic customer, while also adding to our industry-leading backlog, we are excited to finalize the combination and to welcome Songa Offshore to Transocean. While the Songa Offshore acquisition is keeping us busy, we continue to evaluate additional opportunities to upgrade our fleet through both corporate M&A and individual asset purchases. However, as previously stated and as evidenced by the Songa Offshore transaction, we will continue to carefully consider both rig capability and the impact to near term liquidity when assessing any prospect. In addition to acquisitions, we continue to high grade our fleet with the delivery of newly constructed rigs. The Deepwater Pontus recently arrived in the Gulf of Mexico, where she has just commenced operations on her 10-year contract with Shell. The Deepwater Poseidon will arrive in the Gulf of Mexico in the coming months, where she too will begin a 10-year contract with Shell early next year. Of note, the Deepwater Pontus and the Deepwater Poseidon are the fourth and fifth contract-backed newbuild drillships delivered to our fleet in the past two years. With the addition of these five new builds and the four Cat-D Songa rigs that will soon become part of our fleet, we will have a total of nine assets contracted with investment grade operators for terms extending through at least the end of 2021 and as far as 2028. Continuing the focus on our fleet, you may have read in our latest Fleet Status Report that we agreed with SembCorp Marine's Subsidiary Jurong Shipyard, to enhance our two remaining newbuild drillships with an industry-best 3 million pound hook load. As many of you know, some wells in the Gulf of Mexico and other deepwater plays around the world, require very heavy casing strings, which in turn necessitate higher hook load capacities. These two rigs will be the only rigs in the industry capable of running the heaviest big strings while maintaining spare over-pull capacity. These upgrades also position these rigs to be excellent candidates for future 20K conversions. While certainly not as exciting as acquisitions, newbuilds, or upgrades, purging some of our older assets remains vital to assembling the strongest fleet in the industry. As such, during the third quarter, we announced our intent to remove six additional assets from our fleet, including five ultra-deepwater assets, which we deemed to be challenged. This will bring the total number of rigs retired from our fleet since the start of the downturn to 39. As previously demonstrated, we will continue to objectively evaluate our assets, and we will continue to recycle rigs that, we believe, will struggle to compete as the market recovers. As a result of these retirements and upon completion of the Songa transaction and the delivery of our two remaining drillships in the shipyard, 40 of our 49 assets, or about 80%, will be either ultra-deepwater or harsh environment floaters with 25 of those being delivered since 2007. Additionally when looking specifically at our ultra-deepwater assets, we will own 9 of the 28 most capable drillships in the world. And when looking at harsh environment assets, we will own 6 of the 28 most capable assets in the world. Through this high grading of our fleet, we are better positioning Transocean for further improvement, including maximizing uptime performance for our customers and reducing the time required to construct a well. Regarding uptime, we continue to consistently deliver excellent uptime performance, ranging between 96% and 98%. However, we know that there's still more that we can do. As such, we recently entered into two additional care agreements

[Mark Mey:]

Thank you, Jeremy and good day to all. During today's call, I will recap our third quarter results and discuss our balance sheet and liquidity position. I'll also provide an update to our 2017 guidance, an early look at our 2018 cost expectations and discuss our liquidity forecast. Finally, I will provide an update on the Songa Offshore acquisition. For the third quarter 2017, we reported net loss attributable to controlling interest of $1.42 billion or $3.62 per diluted share. As detailed in our earnings press release, third quarter results included net unfavorable items principally related to our previously announced $1.39 billion impairment on the retirement of six floaters. Excluding the net unfavorable items, adjusted net income was $64 million, or $0.16 per diluted share. Contributing to these results was another stellar quarter of revenue efficiency at 97.1%. We've now delivered 95% or better revenue efficiency for 14 of the last 15 quarters. This consistent trend in our uptime performance has enabled a successful conversion of our industry-leading backlog into operating cash flow. As mentioned earlier, our adjusted normalized EBITDA margin was 49% for the third quarter, unchanged sequentially and for the year. Recognizing that we are now in the fourth year of this industry downturn, this is very impressive. We ended the quarter with liquidity of $5.7 billion, including our $3 billion undrawn revolving credit facility. In early October, we successfully accessed the debt markets, issuing $750 million of priority guaranteed senior secured (sic) [unsecured] (16

[Bradley Alexander:]

Thanks, Mark. Levi, we're ready to take questions now. And as a reminder to the participants, please limit yourself to one question and one follow-up.

[Operator:]

Thank you. And we'll take our first question from Angie Sedita with UBS.

[Angie Sedita:]

Hi, good morning, guys.

[Jeremy D. Thigpen:]

Hey, Angie.

[Angie Sedita:]

Hi, Jeremy. So on the North Sea, could you talk a little bit – I mean, it's become a tight market and can you talk a little bit about what you're thinking or what you're hearing on the dayrate side as far as where we could be moving forward going into 2018? And then, part two of that is if we think forward about other rig categories or regions of the world, there certainly will be other markets that start to tighten before the general market. So if we think through either on a region specific basis or a rig specific basis, where do you think would be the next segment that we could start to see tightening and eventually some dayrate power?

[Jeremy D. Thigpen:]

Thanks, Angie. I'm going to let Roddie answer that for us.

[Roddie Mackenzie:]

Hi, Angie. Thanks for the question. Okay, so your first question was around the North Sea and Norway. So specifically to dayrates, so while we can't speculate on what we would bid, I can certainly tell you what happened recently. So what we've had in Q2, we saw rates around the 200 (25

[Angie Sedita:]

Okay. Okay. Thank you. That's helpful. And then I know it's been not a millisecond that we've seen $60 Brent, and we need to see some duration to that before we see much change in behavior. But has there been any change in the conversations with your E&Ps? Has there been any pickup or change in tone with the conversations now that we're moving into this level of Brent?

[Roddie Mackenzie:]

Yes, there has. So I think what we're seeing now is you'll see many headlines where the operators are talking about essentially their ex-E&P costs, so their economic investment thresholds being anywhere from in the 20s and 30s, up to the $50 (27

[Angie Sedita:]

Okay, thanks, guys. I'll turn it over.

[Jeremy D. Thigpen:]

Thanks, Angie.

[Operator:]

And we'll take our next question from Gregory Lewis with Credit Suisse. Gregory Lewis - Credit Suisse Securities (USA) LLC Hey, thanks, and good morning, guys.

[Jeremy D. Thigpen:]

Good morning, Greg. Gregory Lewis - Credit Suisse Securities (USA) LLC Just like a two-part question just because clearly you made the decision to upgrade the newbuilds to 3 million pounds hook loads. I guess, I'm just wondering if you could provide a little color on the decision to do that and just with that, you also, earlier this year, you announced that you were going to upgrade the India. And just so, is this something where this is the cost of doing business? This is what customers want? Are they just wanting more of everything? And with that, are we getting any sense that they're going to be willing to pay for that?

[Jeremy D. Thigpen:]

Yeah, thanks, Greg. In the current market, are they willing to pay for it? Probably not. In the current market, they can have their choice of high-specification assets at really competitive dayrates. We've taken a position, we've talked about this before on past calls, where we've gone through and we force ranked every asset in the world. We've then taken a position that, hey, when we get back to a more normalized market, whatever normalized is in this industry, how many floaters do we think the industry will need. We've segmented that by ultra-deepwater and harsh environment. And so we took a really, I think, thoughtful view about this, a very sober view of this, and we looked at our own fleet and we said, all right, if the – this new normal is only going to be somewhere between 180 and 220 floaters in the world, how do we make sure that we have the highest quality fleet to fit into that new market? And so as we've looked around, we've looked at some of our existing assets like the India, and we said, listen, we can move this, which, I think, we had it right in the 70s range (29

[Roddie Mackenzie:]

So, Greg, I'll take that one. Yes, so we do have several opportunities for the rig, and it's possible that she would leave Brazil but it's also possible she would stay there. So you're probably aware there are several tenders in Brazil, but there's also ones elsewhere. So we're cautiously optimistic that we'll be placing the KG1 in 2018. Gregory Lewis - Credit Suisse Securities (USA) LLC Okay. Perfect. Thank you for the time.

[Jeremy D. Thigpen:]

Thanks, Greg.

[Operator:]

And we'll take our next question from Blake Hancock with Howard Weil.

[K. Blake Hancock:]

Thanks. Good morning, guys. Roddie, welcome to the firing squad. Jeremy, maybe first off, you mentioned some of these long-term contracts that have been signed here in the last, call it, six months or so. Just wanted to get your opinion, is that kind of you guys signaling that the rates are going to be here at these levels for the next two or three years, A. And B, just kind of the approach to why one of your better assets for up to five years and how you're thinking about the fleet from a portfolio perspective?

[Jeremy D. Thigpen:]

Yeah, so I'll answer the rig question first. I don't think you should read anything into it in terms of what we think about rates going forward. We've seen contracting activity, generating activity pick up over the course of the last 12 months. We expect that to continue as we get into 2018 and 2019. As you see more of that, you see more of the higher specification rigs going back to work, we would hope to see dayrate improvement as we get into 2019, but we don't know that yet. So that's kind of how we feel about rigs going forward. Increasing activities as we move into 2018 and 2019 with dayrates then moving up. With respect to the Invictus in particular, we were responding to three different tenders simultaneously. All three operators, one of our best assets, which they can demand now. All three wanted to lock them up for at least two years plus additional two to three years in options. So as we looked across that, there was only one opportunity, where we actually had the ability to move dayrates upward in a meaningful way in the outer years. And so we aggressively pursued that opportunity and we won it. And we did not aggressively pursue the other two opportunities. So this one was the best way to keep one of our best assets on contract with an operator that that rig has been with since it came out of the shipyard. So there were a number of factors that led into that one, but certainly still maintaining some optionality with some of our other better assets.

[K. Blake Hancock:]

That's great (32

[Roddie Mackenzie:]

I would also – Blake, I'll also add a little color there. The other part of this was it's a multi-jurisdiction possibility on that contract. So it's very interesting for us because we've not only did Gulf of Mexico but Trinidad & Tobago as well. It's probably the first location for it. But most interestingly it could lead into a segue into Mexico for us, which should be a very good way for us to enter that market.

[K. Blake Hancock:]

That's great. Thank you. And then, Mark, maybe one for you on the 2018 cost guidance. Can you kind of give us some color on how you guys are thinking about it? It looks like it would kind of assume that rigs that are working today are kind of recontracted at some point next year, but it doesn't seem like there is a whole lot of cold stacked rigs getting reactivated in that number. Can you just kind of walk through how you guys are thinking about that?

[Mark Mey:]

Yeah, sure, Blake. So you're right. As I mentioned, we don't include any rig reactivations in that. What we do assume is that some speculative revenue and associated costs associated with rigs that will roll over next year, so you could assume that we included about 20% of operating days associated with those rigs. And that's included in the guidance I provided you earlier.

[K. Blake Hancock:]

That's great. Thank you guys. I appreciate it.

[Jeremy D. Thigpen:]

Thanks, Blake.

[Operator:]

And we'll take our next question from Ian Macpherson with Simmons.

[Ian Macpherson:]

Hey, thank you. Jeremy, I wanted to ask another question about the 3-million-pound hook load upgrades. If could expand a little bit on, just from a technical or engineering perspective, what that entails to get that level of capability. I assume it's not a retrofittable quality for the other rigs in the world, if you could comment on that. And whether this was pooled by specific customer requests or if it's an innovation that you're trying to take the lead with.

[Jeremy D. Thigpen:]

Ian, you're asking me an engineering question? I'm going to defer to Roddie to answer that one and I'll chime in as well.

[Ian Macpherson:]

All right.

[Roddie Mackenzie:]

All right. Thanks, Ian. Yes, so your first question was about what do you have to do to enact that. So basically there is modifications that you make to the draw-works and, obviously, the traveling equipment. But essentially that the rigs are in a stage of construction, where there is an option for us that's relatively cost effective way of doing it. In terms of a retrofit to other rigs, that's quite tricky especially if the derricks will be finalized, there will be equipment in place, then they will not be rated to that kind of levels, but, yeah, so for us it's an opportunity to really put a marker out there and be the first 3-million-pound rigs in the world.

[Jeremy D. Thigpen:]

And it wasn't driven by a specific customer rig, as we (35

[Ian Macpherson:]

Okay. And then I think you've kind of spoken with your wallet here with regards to staying committed to those rigs. Small but incrementally spending a little more to make them more capable. But the go forward CapEx, including all of this here and the next three years is still, I think, about $600 million of the $800 million for those rigs. And so the return thresholds for those assets compared to the M&A marker that's out there today, it's a wide gap. So, I guess, how do you get comfort with the return profile of these newbuilds on the go-forward capital compared to your opportunity set in the M&A environment?

[Mark Mey:]

Ian, this is Mark. And you're absolutely spot on. We could certainly go out and buy uncontracted newbuilds at a very high specification level today at the shipyard. However, we have to bear in mind that we have very strong contracts from both sides' perspective with regard to those two newbuild drillships. So those contracts will be honored by Transocean irrespective of the fact that it's going to cost us a little bit more. But remember, these are 30 to 40-year assets. So we're not looking out over the next three years for return profile. We're looking out over a 30-year horizon. And we feel highly confident that over that period, that would return a level of cash flow that would justify the decisions to build those high-specification assets, especially given the fact that we do have a lead in the market right now with regard to any kind of really deep wells in the Gulf of Mexico given the increased workload.

[Ian Macpherson:]

Good. I appreciate that. And, yeah, the idea of honoring contracts is sometimes a long forgotten ideal. Thanks for the answers. I'll pass it over.

[Operator:]

And we'll go next to Scott Gruber with Citigroup.

[Scott A. Gruber:]

Yes, good morning, gentlemen.

[Jeremy D. Thigpen:]

Good morning, Scott.

[Scott A. Gruber:]

You guys have done a great job in reducing maintenance spending through your various initiatives. When I look at your fleet, though, you have a number of sixth-gen rigs that were delivered in 2009 and 2010. How should we think about the costs of the second five-year surveys on those assets under your new maintenance regime?

[Mark Mey:]

So Scott, one of the initiatives, which John and Keelan and the team have put in place at Transocean over the last couple of years was to eliminate out-of-service days and associated costs with regard to five-year surveys. And I want to say about a year ago, we managed to succeed with our initiatives. So then we challenged the organization

[Scott A. Gruber:]

Can you provide some rough guidance on how much the 10-year survey would cost?

[Mark Mey:]

I'm not going to go to that level of detail at this stage.

[Scott A. Gruber:]

Would you be willing to offer how many surveys are included in your maintenance guidance for 2018 and 2019?

[Mark Mey:]

So for 2018, we don't have any surveys of any magnitude. In 2019, I think, we have two that are included in that. Most of these we see coming due in 2020 and 2021.

[Scott A. Gruber:]

And would you be willing to provide any rough guidance on maintenance then in 2020 as more of the surveys kick in? I know we're getting a few years out, but...

[Mark Mey:]

Yeah, we're getting a little far out there for our guidance.

[Scott A. Gruber:]

Okay. Okay. That's it for me. Thank you.

[Mark Mey:]

Thanks, Scott.

[Operator:]

We'll go next to Haithum Nokta with Clarksons Platou Securities.

[Haithum Nokta:]

Hi, good morning.

[Jeremy D. Thigpen:]

Good morning.

[Haithum Nokta:]

Jeremy, I think I just wanted to ask a couple of quick clarifications. Did you say a new contract for the KG2? And then also around the Invictus options, did you say that those were escalating rates with the market links in year four and five?

[Jeremy D. Thigpen:]

So yes on both. So KG2 with Woodside in Myanmar, which we just completed their campaign, a very successful campaign with Woodside, and so they're picking her up again. And then, yes, to the question around the Invictus.

[Haithum Nokta:]

Okay. And did you say a term for the new contract for the KG2?

[Mark Mey:]

Yeah.

[Jeremy D. Thigpen:]

Oh, yeah. It was – it should last between...

[Mark Mey:]

150 and 400.

[Jeremy D. Thigpen:]

150 to 400 days, yeah.

[Haithum Nokta:]

Okay. Very nice. Okay, I wanted to ask about the strength you're seeing in harsh environment. And I'm trying to see – is that something – the mechanics that are driving those rates higher, is that something that could be transferable to the deepwater market down the road? And is it as simple as harsh environment is two or three years ahead [Technical Difficulty] (41

[Jeremy D. Thigpen:]

Sure, you broke up a little bit in the question there, but I think what you're asking was could we see the same kind of dayrate progression in ultra-deepwater that we've seen here recently with harsh environment. And the answer is yes. The question is around timing. And so if you look at the harsh environment market, you go back a year ago, I mean, we were bidding at $150,000 a day. And you listened to Roddie's comments, the last fixture awarded was a $250,000 a day plus a $50,000 a day performance bonus. So I mean, really, you're looking at almost a $300,000 a day dayrate for some high-specification harsh environment assets. If we were sitting here 12 months ago, you wouldn't have believed that that kind of dayrate appreciation was possible, and I'm not sure that we would've. But it's really an indication of there are only a few really high-specification assets that are out there in harsh environment. You could make a similar argument for the high-specification ultra-deepwater rigs, and as customers start to see those rigs locked into longer-term contracts, all of a sudden they become a little more valuable. And that's when you can start to push dayrates up.

[Haithum Nokta:]

Yeah, naturally. Okay, and then just on the $1.4 billion of new financing that you expect for the last two Shell rigs, would it be safe to assume those are going to be bonds or other kind of tools on the table for secured financing?

[Mark Mey:]

Haithum, that could be anything, because we're sitting right now on probably 20 different proposals to finance those assets. So we're got to look at a combination of advanced rate, the cost of the financing, the amortization associated with that and the security package beyond just the rig to make those decisions. And you can see us active doing this in early 2018.

[Haithum Nokta:]

Great. I'll turn it back. Thank you.

[Operator:]

And we'll take our next question from Kurt Hallead with RBC Capital Markets.

[Kurt Hallead:]

Hey, good morning.

[Jeremy D. Thigpen:]

Good morning, Kurt.

[Kurt Hallead:]

You guys are getting me all jacked up, so to speak, good to hear. You're a little bit different tone than some of your other peers earlier this week. But it does seem like things are starting to at least improve at the margin. So kudos to how you've managed through the downturn.

[Jeremy D. Thigpen:]

Thanks, Kurt.

[Kurt Hallead:]

Sure. My question relates to prospective M&A and further consolidation. I know you've been very active on that front and you have the Songa transaction coming to a close here at year end. Just kind of curious at this juncture with prospective demand improving, you think the M&A push is going to stall out as some of your competitors get a little bit more optimistic about the market?

[Jeremy D. Thigpen:]

Yeah, a good question, Kurt. I'm not sure what our competitors are going to do with respect to M&A. From our standpoint, we continue to look at opportunities to hybrid our fleet, and specifically focusing on ultra-deepwater and harsh environment. So we, again, have taken a position on how many floaters the industry's going to need in a more normalized environment. We want to have a significant portion of the high-spec assets that fall into that. And so we're looking around at certainly at different assets, whether they be distressed assets in the shipyard or corporate opportunities. But for us it really is, it's rig capabilities, it's technical capability in the ultra-deepwater and harsh environment side, but it's also the impact that the acquisition would have to near term liquidity. We are more optimistic today than we were a year ago, but we still don't know when we're going to be able to pull out of this downturn. We're seeing it in harsh environment. We're seeing positive signs in ultra-deepwater, but it's still really competitive out there. And so as we look at any acquisition, it's really around asset quality and the impact to near term liquidity, and we've got a – we'll only pursue opportunities that fit that criteria.

[Kurt Hallead:]

Okay, great, great. And then just in the context you mentioned a lot of the operators have been able to get their cost levels down to sub $50, you referenced $30 in the North Sea. And now the dayrates are at depressed levels, which in prior cycle dynamics, this was the turning point of the cycle when operators would take advantage of low rates and try to lock them in. It sounds like some of that is starting to happen. I'm just curious from where you sit, like do the operators still need to get an element of conviction that a $50 or $60 handle on crude is more sustainable than what they've seen for this year? Or do you think the operators are now at that level and with dayrates coming down this is really the start of that push to get all these companies to lock in rates at current levels. What's your take?

[Jeremy D. Thigpen:]

Yeah, it's a good question, Kurt, and I think you have to segment it by customer. So I think if you look at our independents, those customers are actually looking at the current oil price, and they're looking at their cost per barrel and they're thinking, gosh, this is a great opportunity to go and capitalize on some lower dayrates and lower service costs and they see great opportunity there. But if you look at the majors, they've made a commitment to the Street to fund the dividend out of cash flow from operations, reduce their CapEx requirements, and then their spend for 2018. And so for them they've set their budgets for the most part for 2018. My belief is unless we see a material change upward in oil prices, that the activity with the majors is going to be few and far between, but the independents and the NOCs would expect to ramp up. And I think that, Roddie, is that consistent with what we're seeing?

[Roddie Mackenzie:]

Yeah, I think so. And when we track the contracting activity, basically at the moment half of it is coming from the independents, which is disproportionate to the number of leasees (47

[Kurt Hallead:]

Yeah, that's great color. Really appreciate it. Thanks.

[Jeremy D. Thigpen:]

Thanks.

[Operator:]

As a reminder, we do ask that you please limit yourself to one question and one follow-up. We'll go next to Waqar Syed with Goldman Sachs.

[Waqar Syed:]

Thank you for taking my question. In terms of Gulf of Mexico, could you guide us what you see in terms of activity into 2018 and 2019? And also, just want to ask that, we are seeing rig efficiency improvements being about companies able to drill wells a lot faster. So if we were to drill the same number of wells that we drilled back in 2014 in the ultra-deepwater, how many fuel rigs would be needed to do that given the rig efficiencies? Thank you.

[Jeremy D. Thigpen:]

Waqar, thanks for the question. I'll let Roddie answer the question about the Gulf of Mexico and activity that he is seeing. But just to your question around how many floaters would you need to deliver the same number of wells as 2014, I'm not sure if we've gone through that thoughtful of an analysis on that in particular. But I'd tell you, we did think about that as we were trying to set our expectations for what a more normalized floater count could be, and we segmented that by ultra-deepwater and harsh environment. And we certainly factored into efficiency gains when we came down to that lower number. I mean, if you remember back to the peak in 2014, I think there were 270-ish floaters under contract and operating around the world. We're now saying that we think that that range could be somewhere between 180 to 220. We'll be wrong, but just a lot of that is based on the more efficient drilling machines and better operations. I'll turn it over to Roddie to answer the specific question about Gulf of Mexico activity over the course of the next couple of years.

[Roddie Mackenzie:]

Sure. So right now in the Gulf of Mexico, it's the independents that are carrying the torch. So the BHPs, (49

[Waqar Syed:]

Thank you. Just to follow-up, Jeremy, this 180 to 220 rig number that you have versus 270, that assumes the same number of wells being drilled as in 2014, or it assumes higher or lower number of wells being drilled?

[Jeremy D. Thigpen:]

I'm not sure if we've got that scientific, so I'm sorry, I can't answer your question.

[Waqar Syed:]

Okay. I appreciate that. Thank you so much.

[Operator:]

And we'll go to our next question from Eduardo Royes with Jefferies.

[Eduardo B. Royes:]

Hey guys, good morning.

[Jeremy D. Thigpen:]

Good morning.

[Eduardo B. Royes:]

Question for you, as I think about your overall floater fleet, obviously, the market remains quite over supplied, but I think we've seen over the last year or so, so there's a lot of nuisances and niches that we can't see and all of a sudden a rig that we may be overlooking comes back out. I guess, I'm curious if you think that there's still – are there still some opportunities within your fleet, for, again, rigs and maybe we didn't think of as being particularly niche and coming back out. And I ask because it helps us think about maybe the longer-term earnings power, some of these rigs can come back after being down for a year versus a couple more years, or something like that. So really, I think of rigs like bringing out the Goodrich, and the rig going to Australia, do you feel like there's more opportunities along those lines, or should it be a little bit more straightforward with rigs like the Asgard, being rigs we'd obviously look for getting employment in the relative foreseeable future?

[Jeremy D. Thigpen:]

Yeah, I'll answer that in this way. We've been very active, I think, in terms of retiring rigs that we thought would be challenge to really compete in the market recovery. And so – it's been 39 to-date. We said on this call and in previous calls, we continue to evaluate our fleet on an ongoing basis. And as we look at rigs, as they roll off contract or as we kind of look at future prospects, if we think that they're not going to be able to compete for whatever reason that this market recovers then we recycle them. And so I think there are certainly a few more in our fleet that are currently on contract that may not be able to earn kind of a next contract. And in that case, we'll evaluate and we'll retire them. So, we'll just continue to look at the fleet and those rigs that we don't think will be competitive, we'll recycle but I'd say anything that we have that we've invested in back in to-date, it's because we think they're going be marketable rigs.

[Eduardo B. Royes:]

Got it, thanks. And then, I guess, just a quick one. It's probably more for Mark. You mentioned the step up in the fourth quarter guidance, curious – I think you mentioned retirement costs or something like that, if you could give any perspective on the impact of the different components that lead to that step up sequentially in the fourth quarter?

[Mark Mey:]

So, Eduardo, I mentioned four reasons why the O&M costs will be increased from the fourth quarter but bear in mind, this is not an increase from our previous guidance for the full year. So we do have the startup of the Deepwater Pontus, we have the reactivation costs associated with two rigs, we also have certain timing of maintenance costs that are due to be spent in the third quarter, and in some cases, a little earlier. And we expect to catch up in the fourth quarter. So all of that combined, would be actually about a $15 (53

[Eduardo B. Royes:]

Yeah. I mean, I guess, do you have a sense – is the reactivation portion of that is more or less how much? Are you willing to get (53

[Mark Mey:]

It's about half of it.

[Eduardo B. Royes:]

Okay.

[Mark Mey:]

And then half of the – of the other half is going to be the Pontus for the quarter.

[Eduardo B. Royes:]

Got it and everything else. Okay, great. Thank you. I'll turn it over.

[Operator:]

And we'll go to our final question from J.B. Lowe with Bank of America Merrill Lynch.

[J.B. Lowe:]

Hey, guys. Thanks for fitting me in here at the end.

[Jeremy D. Thigpen:]

Hey, J.B.

[J.B. Lowe:]

How you doing?

[Jeremy D. Thigpen:]

Good.

[J.B. Lowe:]

I just wanted to get a quick clarification, I think, Mark, on your OpEx guidance for 2018. Did you say that that assumes that – of the rigs that are rolling off of the end of this year and the eight or nine that are rolling off next year, that you assume 20% uptime for the non-contracted times? Is that what I understood?

[Mark Mey:]

Yeah, so what I indicated we that we have about a 3% reduction in operating days from 2017 forecast to 2018 budget. And that 3% reduction translates into about a 20% of the days that are uncontracted on rigs that do come with contract over the next 12 months, getting recontracted at lower dayrates.

[J.B. Lowe:]

Okay, perfect. And then my other one was just of the retirement candidates that you have and making the decision between whether you're going to retire them or not, if you were to decide to reactivate some of the rigs, do you think that they would require upgrades like we've seen some other people in the market doing in terms of an extra BOP or putting some extra functionality on them? Or do you think they would be able to come out just kind of as is?

[Jeremy D. Thigpen:]

I think they'll be able to come out as is. Now we have identified in addition to the India, a few other candidates that have similar profile, which we could add to their marketability with a few enhancements. But for the most part, the rig that we have stacked is just the reactivation cost and mobilization to get them back out.

[J.B. Lowe:]

Okay. All right, guys. Thanks very much.

[Jeremy D. Thigpen:]

Thanks, J.B.

[Operator:]

And that concludes today's question-and-answer session. Mr. Alexander, at this time, I'd like to turn the conference back to you for any additional or closing remarks.

[Bradley Alexander:]

Thank you to everyone for your participation and questions today. If you have further questions, please feel free to contact me. We look forward to talking to you again next year when we report our fourth quarter and full year 2017 results. Have a good day.

[Operator:]

This concludes today's conference. We appreciate your participation. You may now disconnect.