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Transocean Ltd
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Good day and welcome to the Q1 2019 Transocean earnings conference call. Today’s conference is being recorded, and at this time it is now my pleasure to turn today’s call over to Mr. Bradley Alexander. Please go ahead, sir.
Thank you, Carrie. Good morning and welcome to Transocean’s first quarter 2019 earnings conference call. A copy of our press release covering financial results along with supporting statements and schedules, including reconciliations and disclosures regarding non-GAAP financial measures are posted on our website at deepwater.com.
Joining me on this morning’s call are Jeremy Thigpen, President and Chief Executive Officer; Mark Mey, Executive Vice President and Chief Financial Officer; and Roddie Mackenzie, Senior Vice President of Marketing and Contracts.
During the course of this call, Transocean management may make certain forward-looking statements regarding various matters related to our business and company that are not historical facts. Such statements are based upon the current expectations and certain assumptions and are therefore subject to certain risks and uncertainties. Many factors could cause actual results to differ materially. Please refer to our SEC filings for more information regarding our forward-looking statements, including the risks and uncertainties that could impact our future results. Also, please note that the company undertakes no duty to update or revise forward-looking statements.
Following Jeremy and Mark’s prepared comments, we will conduct a question and answer session. During this time, to give more participants an opportunity to speak on this call, please limit yourself to one initial question and one follow-up. Thank you very much.
I’ll now turn the call over to Jeremy.
Thank you, Brad, and welcome to all of those participating in today’s call. As reported in yesterday’s earnings release for the first quarter, Transocean generated adjusted EBITDA of $253 million on $799 million in adjusted revenue. These results were driven by exceptional uptime performance across our global fleet which resulted in first quarter revenue efficiency in excess of 98%.
As many of you will know, the first quarter of 2019 marked our first full quarter of operations with the assets acquired through the Ocean Rig transaction. Of note, these recently acquired ultra deepwater rigs delivered operational uptime of 99%, a true testament to the condition of the fleet, the experience and professionalism of the crews, and a near seamless integration of operations.
Speaking of the legacy Ocean Rig fleet, in February we announced that Petrobras awarded the Ocean Rig Corcovado and the Ocean Rig Mykonos with contracts with a combined total of 3.2 rig years of firm work in Brazil and a combined option period of over four years. These two ultra deepwater drill ships have performed extremely well for Petrobras in recent years, which made them the preferred candidates for these longer term tenders. Once on contract, we will have three rigs working for Petrobras in Brazil, providing us with the opportunity to spread our shore-based support costs across more revenue generating assets. Needless to say, we look forward to growing our active fleet in country as the world’s historically largest deepwater market begins to recover.
As a final comment on the Ocean Rig transaction, the team has been acutely focused on safely, professionally and efficiently integrating the two companies as we pursue the $70 million in annualized cost synergies that we committed to realize as part of this transaction. Among other things, we have rationalized their corporate structure and closed the Athens corporate office. We have consolidated our offices and operations in both Norway and Brazil, we have brought the Ocean Rig assets into our insurance programs, and we are in the process of extending the coverage of our O&M agreements to the two active ultra deepwater drill ships and the two soon-to-be-active Ocean Rig assets destined for Brazil. As we continue to contract additional legacy Ocean Rig assets, we will work to quickly bring them under our O&M care agreements as well. Overall, I’m extremely proud of the team and the speed with which they are executing this integration.
Looking at our recent contract awards, in addition to the previously discussed awards in Brazil, our ultra deepwater fleet picked up additional work in a number of basins around the world. In the U.S. Gulf of Mexico, Murphy has again contracted the Deepwater Asgard for a two-well project beginning next month. In Equatorial Guinea, Exxon Mobile exercised a six-month option on the Development Driller III that will now keep her working in-country into early 2020. In Angola, Eni exercised a two-well option for the Ocean Rig Poseidon. In Malaysia, Shell has again contracted the Deepwater Nautilus for a six-well program beginning next month, and just this morning we signed a 120-day contract with six prized 120-day options for the Deepwater India with [indiscernible] in Egypt. We also received confirmation that Reliance is picking up the one-year option on the KG2 in India.
Turning now to our harsh environment fleet, during the quarter in Norway, Lundin exercised a one-well option for the Leiv Eiriksson. Also, we’re excited that our most recent addition to the harsh environment fleet, the Transocean Norge, has almost completed her journey to Norway where she will begin her maiden contract in just over two months. Between the Norge and the Songa Offshore and Ocean Rig acquisitions, over the past 15 months we have added five high specification harsh environment semisubmersibles and nine high specification ultra deepwater drill ships to our fleet. These additions have helped us to assemble the largest, most capable and most marketable floater fleet in the industry. As such we believe that we are uniquely positioned to continue to benefit from the recovery in the harsh environment markets and to take advantage of what we believe to be the early stages of a recovery in the ultra deepwater markets around the world.
Regarding the recovery, we are encouraged by the start to 2019 with a floating active rig count up 7% in the first quarter. Importantly, when including future rigs contracted, the floating count is nearing 168 assets, which would drive overall market utilization to a level approaching 80%. The story becomes even more encouraging when delving into our two primary markets: the high specification Norwegian-compliant harsh environment market, and the high specification ultra deepwater market. For the Norwegian market, there is effectively no availability of high-spec assets until the second quarter of 2020, and for the ultra deepwater market, the number of sixth and seventh generation drill ships on contract has increased by 20% over the past six months, and we see a clear path for the utilization of these assets to exceed 90% by early 2020.
This increase in demand is not surprising. To begin with, our customers generated robust operating cash flow in 2018 and with the quick recovery of oil prices following last year’s fourth quarter dip, 2019 is shaping up to be strong for them as well. This cash flow has provided our customers with the ability to solidify their balance sheets, return capital to shareholders, and invest in longer cycle projects offshore as opposed to being almost exclusively focused on the quick cash-on-cash returns on shale. As important as supportive oil prices are customers around the world are touting very favorable breakeven levels on offshore projects, often below $40 per barrel. While discounted service costs have certainly played a role, it’s important to recognize that the entire industry has worked together to realize sustainable cost savings, including but certainly not limited to increased efficiencies in drilling, more tailored field design, and greater equipment and facility standardization. This is significant as it enables through the cycle investing that has often been elusive for offshore projects.
As evidence of this improvement in offshore economics and our customers’ growing confidence in the future for offshore drilling, one need look no further than the recent Gulf of Mexico lease sale, which achieved its largest total in four years. While not as public as the recent Gulf of Mexico lease sale, our recent customer engagements provide further support that confidence in the offshore market is growing around the world. Our marketing department continues to field more interest focused on rig availability, suggesting a much tighter market as we move through 2019 and into 2020. As the market tightens, we believe that it’s important for us to remain steadfast in our disciplined approach to bidding as we endeavor to recognize maximum value for our fleet.
Focusing in on the markets around the world, in the U.S. Gulf of Mexico for the first time since the start of the downturn, we are engaged 9in conversations with multiple customers around upcoming projects which would require incremental rigs in the region. Additionally, since announcing that we were recently awarded the industry’s first ultra deepwater 20,000 PSI drilling work, we have been approached by other operators to explore similar opportunities. While I would not go so far as to say that another 20K award is imminent, our customers recognize that the equipment capable of developing these challenging reservoirs does not currently exist and will require commitments in the near term to ensure production can be achieved by the middle of the next decade.
In Mexico, we recently completed our second exploration campaign, this one for Murphy, and are looking forward to a third campaign, this time a multi-well project with Shell which is currently scheduled to begin near the end of 2019. We expect activity to increase in this market as we enter 2020.
In the Caribbean, the Invictus continues to perform well for BHP in Trinidad. We are also encouraged by opportunities in Guyana and the trends emerging in neighboring Suriname that should further increase ultra deepwater rig demand.
In Brazil, we expect Petrobras to award more tenders in the coming months, helping to reverse the declining rig count we have seen in country over the past four years. We expect this is just the beginning of Petrobras as years of curtailed investment has created a need for significant re-engagement to enable the achievement of their ambitious production targets. We are also encouraged with the IOC activity that we believe is soon to materialize in the region.
In West Africa, we see opportunities emerging in Angola, Nigeria, Ghana, Equatorial Guinea, and Senegal. As you well know, new opportunities here have been scarce over the past five years, but based on our current marketing intelligence, awards in this region would likely represent a significant number of rig years, potentially locking up a number of assets in the global fleet.
In Asia Pacific, activity is also picking up, driving material increase in day rates. Rigs in Australia are now commanding well in excess of $200,000 per day and operators are now showing a willingness to contract these assets for multiple years as their project economics are strong and they see that asset scarcity is likely to result in even higher day rates for future projects.
Concluding this walk around the global floating markets, in the harsh environment markets of both Norway and Canada, the high specification floaters that are most desired are practically sold out. Day rates including bonuses have largely remained in the mid-300s; however, we anticipate another step up in rates for work beginning in mid-2020. In the U.K., our customers are demonstrating a clear preference for hot rigs and experienced crews. As a result, we have recently been awarded contracts with day rates eclipsing $200,000 and terms that run through the year, thus eliminating much of the off-hire time we’ve experienced over the past few winter seasons.
Industry-wide, as confidence grows in our ability to exceed drilling plans and reduce breakeven levels, our customers are increasing the number of economically viable targets they are considering for activity. Essentially, we are drilling ourselves into more opportunities, which has been the thesis that has driven our strategy for the past four years and is the reason that we have systemically high graded our fleet while continuing to invest time and resources into technologies that will compress the time to drill and complete offshore wells. If we can help our customers make more of their offshore projects economically viable, then we create incremental demand, and if we can clearly demonstrate that the combination of Transocean’s fleet, crews and shore-based support is superior to our customers’ other options, then we position ourselves to capture both market share and market-leading rates.
Before handing the call over to Mark, I would just like to take a moment to thank the entire Transocean team for delivering another strong quarter. I’d also like to reiterate the following points. At $70 per barrel Brent, our customers are generating sufficient cash flows to service debt, return cash to shareholders, and invest in the longer cycle offshore projects that provide the strongest overall returns while addressing longer term production requirements and reserve replacement. At $70 per barrel Brent, sub-$40 per barrel breakeven levels and compressed time to first oil around the world, offshore projects are becoming some of the most attractive investment opportunities across many of our customers’ portfolios. As such, we fully expect to see heightened demand for offshore drilling rigs.
Speaking of demand, the gap between supply and demand for the highest specification assets on both the harsh environment and ultra deepwater markets is tightening. This has already led to a doubling of day rates in the harsh environment markets and improvements in ultra deepwater day rates in Brazil, West Africa, and Australia. Finally, through our new build program and three strategic transactions, Transocean has assembled the largest and most technically capable floater fleet in the industry, and as evidenced by our recent contract awards, our customers recognize and appreciate our fleet and the manner in which we safely and efficiently operate it.
In short, we believe that a broader recovery offshore is underway. Our customers are demonstrating a clear preference for the high specification assets, and we have strategically positioned ourselves as the clear leader in harsh environment and ultra deepwater drilling. As such, we expect that utilization and day rates for our fleet are both poised to improve as we move through 2019 and into 2020.
Mark?
Thank you, Jeremy, and good day to all. During today’s call, I will briefly recap our first quarter results and then provide guidance for the second quarter 2019 and updates to our prior full year expectations. Lastly, I’ll provide an update on our 2019 shipyard projects as well as our liquidity forecast through 2020.
As reported in our press release yesterday, for the first quarter of 2019 we’re reporting an operating [indiscernible] $171 million or $0.28 per diluted share. After adjusting for favorable items associated with tax and unfavorable items associated with retirement of debt, we reported an adjusted net loss of $181 million or $0.30 per diluted share. Further details are included in our press release.
In the first quarter, we delivered adjusted EBITDA of $253 million with an adjusted EBITDA margin of 32% from almost $800 million of adjusted revenue. These results showcase the strength of both our initial [indiscernible] backlog and strong operational performance. Driven mainly by the inclusion of Ocean Rig for the entire first quarter, sequential operating days increased by 80 for our ultra deepwater fleet and 21 for our harsh environment fleet.
For the first quarter 2019, we are operating a maintenance expense of $508 million, slightly below our guidance due to timing of in-service maintenance and project costs in the first quarter. General and administrative expense was $49 million for the quarter, relatively in line with our guidance.
Turning to cash flow and the balance sheet, we ended the first quarter with total liquidity of approximately $2.9 billion, including cash and cash equivalents of $1.9 billion and $1 billion from our undrawn revolving credit facility. Despite ongoing recovery in the harsh environment market and continued signs of recovery in the ultra deepwater segment, extending our liquidity runway remains a priority. We maintain our focus on both enhancing our cash position while opportunistically addressing our near and midterm debt maturities.
Let me now provide an update on our second quarter 2019 financial expectations. For the second quarter of 2019, we are assuming revenue efficiency of 95% on our active fleet. We expect our adjusted total drilling revenues to be down approximately 2% for the quarter. Our forecast reflects our expected time between contracts for both the Deepwater Asgard and Deepwater Nautilus, in addition to the Actinia rolling off contract in May. I’d like to note that in our most recent fleet status report, for the first time we have included the average day rate of $467,000 being recognized for the Ocean Rig Skyros. This reflects the accounting treatment of the step day rate adjustment associated with this [indiscernible] contract and the lower day rate on its price contract options.
We expect second quarter O&M expense to be $545 million, including reimbursable expenses of approximately $24 million. Additionally and including operations for the Ocean Rig Corcovado and Ocean Rig Mykonos, under their respective Petrobras contracts in Brazil, we expect full year O&M to be between $1.9 million and $2.1 million. This sequential increase in O&M expense is driven by the following: reactivation expenses associated with the Ocean Rig Corcovado and Ocean Rig Mykonos of $18 million and $23 million respectively, operating expenses in the fourth quarter associated with commencement of these contracts is approximately $10 million in total. Additionally, we anticipate higher shipyard costs on a DD1 of $7 million primarily to thruster replacement, on the Transocean Arctic approximately $9 million largely due to customer change orders, and $3 million in a DD3 due to extended pre-contract equipment testing. We also now expect our reimbursable expenses to increase by $16 million relative to our prior guidance.
We will provide you with updated reactivation cost estimates for our four cold stack drill ships in Greece. We have recently conducted a thorough analysis on these rigs and excluding any contract-specific requirements or contract mobilization, we estimate costs ranging from $45 million to $50 million. Recognizing that these estimates exceed our previous guidance provided immediately post the Ocean Rig acquisition, the increases are attributed to mobilization from the Gulf of [indiscernible] in Greece to the shipyard, project management team costs, expanded scope for equipment overhauls and recertification, and Transocean-specific operational upgrades. Please note and as previously indicated, we do not plan to reactivate any stacked assets on speculation.
We expect G&A expense for the second quarter to be approximately $47 million or relatively flat quarter over quarter. We also reiterate our full year G&A expectation of $190 million.
Net interest expense for the second quarter is expected to be approximately $152 million. This forecast includes capitalized interest of approximately $10 million and interest income of $7 million. Full year net interest expense is now expected to be $645 million with the increase due to our recent debt issuance and liability management activities.
Capital expenditures, including capitalized interest for the second quarter, are anticipated to be approximately $123 million. This includes approximately $70 million for the four new build drill ships under construction, with approximately $57 million for the [indiscernible] ships and approximately $13 million for the Ocean Rig Santorini and Ocean Rig Crete. Additionally, we expect maintenance capex of $53 million. Our full year capital expense is estimate to be approximately $470 million with the increase related primarily to Ocean Rig Corcovado and Ocean Rig Mykonos reactivations.
Our cash taxes are expected to be approximately $50 million for the second quarter.
Now I’d like to provide an update on our prospective shipyard projects. Consistent with the 2021 start date for Chevron’s 20,000 PSI work in the Gulf of Mexico, the recently named Deepwater Titan’s delivery has been deferred to early 2021. Also in second quarter, the Transocean Spitsbergen will undergo a 10-year SBS that will result in an estimated 44 out of service days. Lastly, the DD1 began contract preparation in February for its fixture with Chevron. Due to the aforementioned shipyard delay, we now expect her to commence activity in May, slightly behind the original schedule.
Turning now to projected liquidity at December 31, 2020, including our $1 billion revolving credit facility which matures in June 2023, our end-of-year 2020 liquidity forecast is estimated to be between $1.3 billion and $1.5 billion. This liquidity forecast includes an estimated 2019 capex of $470 million and 2020 capex of $800 million. The 2020 capex includes $600 million related to the two new build drill ships [indiscernible] and $86 million for the two Ocean Rig new builds at Samsung, and maintenance capex of $115 million. Please note that our capex guidance excludes any speculative rig reactivations.
Being mindful of maintaining our strong liquidity position, we continue to monitor the market recovery. As I have previously mentioned, we have multiple levers available to further bolster our balance sheet and extend our liquidity run rate. These include but are not limited to unencumbered assets with long term contracts, capacity to issue additional priority guaranteed notes, and upsizing our revolving credit facility. We are excited by the tangible indications of a rebound in the ultra deepwater market and look forward to contracting our newly acquired drill ships. Through our disciplined approach to M&A and fleet management combined with our prudent balance sheet management, we have positioned Transocean to maintain its leadership position in the market recovery.
This concludes my prepared comments. I will now turn the call back over to Brad.
Thanks Mark. Carrie, we are now ready to take questions, and as a reminder to all participants, please limit yourself to one initial question and one follow-up question.
[Operator instructions]
Our first question will be from James West from Evercore ISI. James, your line is live.
Carrie, you go can go to the next caller.
Our next question will be from Angie Sedita with Goldman Sachs.
Good morning, guys.
Morning, Angie. How are you?
Good, good. I’m not on mute, so it works. One of your peers yesterday talked about over-supply in the sixth and seventh gen market. In part, they were talking about this is due to lack of attrition and that it could limit day rate upside. I’d love to hear your views on supply and demand in sixth-seventh gen market, do we need to see attrition or not, and then thoughts on rates going into 2020.
I don’t think that we necessarily need to see attrition. Obviously if you look at a spreadsheet and you look t the total number in terms of supply, it gets a little bit scary for those that are not closely connected to the space, but our customers are clearly showing a preference for the highest spec assets, and if you start to really segment the market by the high specification assets in the sixth and seventh gen market, what you’ll find is that supply and demand are pretty tight, and our customers recognize that. Our customers are very astute - they understand all the technical specs of all of these rigs and they know which rigs they want to contract, and as a result we’re starting to see tightening in that market, which is why we said earlier in the prepared remarks we’re taking a disciplined approach, which means we’re pushing day rates.
Roddie, I don’t know if you want to add anything to that?
Yes, I’d just say that a lot of the third party analysis would demonstrate that you do--you’re already at the 80% level in terms of utilization of warm assets, and then if we look forward to 2020, we’re going to get essentially full utilization on those higher spec units for sure, so we’re certainly not concerned about it. We’re actually excited about the prospects that lay ahead of us.
The other thing I’d offer, Angie, is as you look at a lot of these assets that are out there and they’ve been stacked for a number of years, the reactivation costs are going to be a real challenge for a lot of companies out there, and so there are many that while they not officially be retired, they’re never going to see another contract.
Then if you think about the tightness in the market, do you think that extends beyond these top 50, top 49 subs and rigs as far as utilization gains going into 2020 and potential for day rate power?
Yes, I think especially when you start thinking about 2020 and ’21, that’s the case, that everything really begins to tighten up. What we’ve seen is fit for purpose rigs that work very well in certain basins are already very tight in utilization, and then as Jeremy pointed out, you’re going to get to that position where there is a very significant hurdle to bring older, inactive rigs back to market, and that’s actually going to help utilization or help drive rates. Of course, when the rates get to that level of sustainable economics for reactivations, then you’ll see those rigs come back; but of course, that’s a pretty significant number and that’s going to be pushing up towards the 300s and beyond.
If I could add just one thing, if we add to it the stranded new builds at the shipyards that require [indiscernible] to be delivered, that too will be a great catalyst for day rates to be increased to allow drillers to bring those rigs out against a contract.
That’s helpful. Could I slip in one more on the consolidation? Obviously you’ve been very busy on the consolidation side, but do you think you’re going to see, or we will see more consolidation across the industry as far as major consolidation, and do we need to, to see better pricing discipline?
I think consolidation would be helpful. I’m not sure what you’re going to see over the near term. We’ve constructed our fleet, we’re happy with what we have now from a harsh environment and ultra deepwater standpoint. We need to put some of these assets that we recently acquired to work on longer term and high day rate contracts before we go and look at further enhancing the fleet at this point in time. Obviously we get approached with every opportunity that’s out there and we take a look, but I think at this point in time we’re satisfied with what we have. I can’t really speak for the other players at this point in time, but it’s kind of challenging to figure out who would be the acquirer over the course of the next several months.
I’ll pick up your comment around pricing discipline. Not that we can really discuss that publicly, but all I’d point out is what is available in public data, we’ve already seen that pricing discipline, so Diamond announced just last week that they had pushed the rates up towards 300 for Africa. We had talked about our 450 rate in the Gulf of Mexico, and then of course you’re seeing in Australia that there’s a few published rates there that are now up in the 270 range. Basically what that says is that rates are--you’re doubling between what the short term spot market is and what the long term vision is, so I think you are actually seeing some pretty decent discipline amongst rates for longer term.
The other thing helping us is all of the offshore drillers need to generate cash, and sticking around the $135,000, $150,000 a day just doesn’t do it. It’s important and incumbent for all of us to push rates and generate cash.
Great, thanks. I’ll turn it over.
Thanks Angie.
Thank you. Our next question will be from James West with Evercore ISI.
Hey, good morning guys. Sorry about the mute. Apparently I need Angie to teach me how to use the mute button, so sorry about that. One question I had, looking at the majors and their budgets for this year, is exploration spending is up very significantly year over year, and significantly over the last four years. That’s something that could really get the drill ship market going. Are you seeing that in current tendering activity?
Yes, absolutely. Our tendering activity continues to go up, and what we’re looking at is lots of interesting things in expansion basins around the world. We have talked previously about the next frontier of 20K drilling and that kind of stuff, so we’ve got several customers that are interested in moving into that, but also places like Mexico - really seeing a lot of interest there going forward, and in Brazil as well. The other real highlight for us this quarter has been significant uptick in the number of tenders we expect to see in West Africa, so that golden triangle is really coming back pretty hard. As you said, it’s exploration wells at first, but I have to tell you there’s already some plans for development in Mexico because there’s been some pretty decent results so far, and then in Africa it’s about getting back to developing assets and then also Mexico, where we’re seeing a lot of activity there in terms of even some of the big guys bringing ships that they have overseas are going to be brought back to the Gulf of Mexico to continue further development. I think all of those things are pointing in the right direction.
Also starting--well, certainly outside of the golden triangle in the ultra deepwater market, we’re starting to see a lot of opportunity emerging in the U.K. as well It’s across the board, James. It’s encouraging. Obviously everything is relative, so it’s far better than we’ve seen over the course of the last four years.
Okay, that’s great Good to hear. One thing I had to follow up on was Brazil. It seems to me there’s a number of FIDs and tenders and thi8ngs that have been held up by, I guess, first the elections, now Carnival. Are we at a point here where we could see a flurry of contracts announced out of that market, and perhaps that rig count that was an all-time low, at this point surging over the next 12 to 18 months?
James, did you sound surprised that things were somewhat delayed in Brazil?
Not at all!
You know, it can be a bit frustrating at times that things don’t materialize as quickly as we would like them to materialize, but I think you’re spot on. I think we do expect as we move through 2019, and especially as we get into 2020 to see more tendering activity not only from Petrobras but also from the IOCs for work starting in the back half of 2020 and into 2021 and 2022.
I’d add to that, that our projections show at least a doubling of the rig count by 2022, and then if you think about the transfer of rights license [indiscernible] that’s going to come up later this year, that would add another 10-plus rigs in the 2023 time frame, so prospects in Brazil do look very positive.
Okay, great. Thanks guys.
Thank you. Our next question will be from Scott Gruber with Citigroup.
Good morning, guys.
Morning.
This is Justin on behalf of Scott. Earlier you guys took a question, the first one, but you guys keep speaking a lot about this--in the DP market, having 40 or so rigs that are classified as top tier, and you guys continue to upgrade your fleet to be able to compete with those. How much more bifurcation in day rates could we expect to see in that top tier market, and then at what spread in those day rates would eventually cause operators to consider trading down?
Well, I think that’s kind of how this thing works, that typically you see the push on rates for the better spec assets. I would say that even just in the short term, what we would call the near term spot market, we’ve observed a 20 to 30% increase in rates just over the last six months, but then going forwards on that, the longer term programs that you’ve seen out there, the rates have shot up to 300 and, in our case, 450 for the 20K rig. You’ll see some of that happen for sure, but ultimately as that sector gets sold out, and we expect that to happen when rates are up at those kind of ranges, then when you have to trade down a little bit, then you start looking at upgrading slightly lesser rigs, but then of course the costs could be even higher. So usually the last man standing gets the highest day rates, but certainly significant growth in near term and then there’s potential for a lot more rate upside after that.
The other thing I’d add to that is our customers are always going to try to keep rigs suppressed somewhat. Having said that, they have experienced the efficiencies of these latest generation rigs with the higher hook load, the dual activity, the dual BOPs, and they really see the value in it. In fact, we have one customer that tells us all the time, our partners love the well costs, they just don’t like the day rate, because these rigs are drilling so much more efficiently. I think they’re going to push hard, obviously, to try to keep day rates in check, but they are going to prefer the more efficient assets, there’s no doubt.
Okay, thanks. Appreciate that. Just for a follow-up, you guys are pursuing the delivery, I guess, of four ultra deepwater ships, and it seems that some of your peers are doing the same. With multiple near finish ships still sidelined, how many deliveries do you expect to reach the market, let’s say over the next one to two years? How do you guys monitor this and how do you balance a pursuit of delivering new builds and finding work for your existing fleet?
The pace is going to be entirely dependent on what happens with day rates. As Mark alluded to earlier or pointed out earlier, just because the rigs are mostly constructed, there’s still a lot of cost and a lot of cash that’s being utilized to actually mobilize those rigs, make sure they have the spares they need, crew them, get them trained. I mean, it’s tens of millions is not approaching $100 million to bring one of these rigs out, and so you’re going have to have and term a contract that supports that, so it’s all going to depend on the trajectory of the recovery and how day rates move to the pace of the new builds entering the market.
Okay, thank you. I’ll turn it over.
Our next question will be from Greg Lewis from BTIG.
Yes, thank you, and good morning everybody.
Hey Greg.
I just have a question about--clearly post the Ocean Rig acquisition, the company now has a lot more, let’s say stacked rigs in the fleet. It looks like maybe there’s around seven or eight stacked high end, or call them sixth, seventh gen drill ships. It looks like the Clear Leader is idle. Realizing you have a couple rigs that roll off contract in the near, medium--over the next couple quarters, how should we think about the cadence of reactivation just given your comments around an improving market? Is it something where hey, we need to have one idle hot rig ready to go just because we don’t want to miss out, or is that maybe not the right way to think about it?
No, I think as we have those rigs that are rolling off contract, those are Roddie and his team’s top priority, is to try to place those rigs so we don’t have a gap and don’t incur the costs associated with that gap. To Mark’s point earlier, we have no intention of speculatively reactivating any of the rigs in the fleet at this point in time. We feel like with the rigs rolling off contract, we’re well positioned to pursue other contracts and the rest will be driven by future contracts.
Okay, great. Then with your acquisition and one of your competitors doing an acquisition, it looks like maybe 15% of the high end drill ship market was put in stronger hands. I guess maybe this is for Roddie - Roddie, have you seen a noticeable difference in how pricing has trended post these acquisitions? Is there a building momentum with two less arguably weaker players out of the market?
Yes, so we can only speculate on what others have contracted at, but the industry rumors would suggest that pretty much all sectors are up. I think one of the barometers is always the U.S. Gulf of Mexico, so we’ve seen several contract been awarded and we understand that the rates are steadily improving, so if you think about rates previously being down at cash breakeven levels, you’re now 20 or 30% higher than that in the Gulf of Mexico for the spot market, so that would suggest that you’re seeing that as well. Certainly from our point of view, especially anything that’s more than just a well to well basis, we are definitely pushing sustainable long term rates, and we understand that most of our competitors are doing the same because you’ve seen a few announcements come out with those kind of headline rates attached to them.
And there’s no question that having these assets in fewer hands and having those be the more established, more balanced, more financially secure organizations certainly helps with discipline.
Okay, thank you very much for the time, gentlemen.
Thank you. Our next question will be from Eirik Rohmesmo from Clarkson.
Thanks. Just a follow-up on the new builds and the potential reactivations. How do you think about prioritizing marketing, comparing Santorini versus some of the higher spec cold stack rigs that you have?
I’m not quite sure - the question was how do we prioritize Santorini against [indiscernible]. I would say--well I mean, it does depend on what project you’re going for, but the Santorini is a pretty high spec rig.
Eirik, could you put your phone on mute? There’s a lot of background noise.
Sorry about that.
Yes, so in terms of prioritization, we’re just looking for the right rig for the job. They all have slightly different specifications, so we kind of navigate it that way; but also, we look at what are the costs to bring the rig out from cold stack, but as Jeremy and Mark have said several times, we will be patient waiting for the right opportunity to do that. There really is no need to push rigs forward without getting that full recovery.
All right, and then just a question on the harsh environment market. The rates for the Tier 1 rigs have sort of leveled off a bit, as you mentioned, but it seems like the rates for the Tier 2 and Tier rigs might have been up, but at the same time the Tier 1 rigs have basically been sold out, as you mentioned as well, and you think that the rates will keep on moving higher. Can you say anything on why do you think the rates have leveled off a bit for the Tier 1 rigs, even in a market where it’s basically sold out?
That’s the reason - the market is sold out, so there’s just not new fixtures coming to bear. The next round of fixtures will show another increase, we believe. We certainly think that rates will pop up another 15, 20%, so that’s essentially what happens, is we had a flurry of activity with a lot of bids out there around the 300 mark, and now as the operators look at the programs again, we expect that for the summer of 2020 you’re going to see several more fixtures with higher rates again. That’s kind of just how it plays - it tends to go in a little wave as it steps up each subsequent tier.
Right, great. Thank you very much.
Your next question will be from Taylor Zurcher from Tudor, Pickering and Holt.
Hey, good morning. Jeremy, I just wanted to touch on the reactivation costs that you mentioned for the Ocean Rig floaters. I realize you went over it in prepared remarks, but could you give us a little bit more color what’s driving the difference? I think you said $45 million to $50 million per floater, and it sounds like there’s some mobilization costs in there, but main buckets of what’s driving the difference and how much of that would be capex versus opex.
Taylor, as I mentioned, we have $18 million for the Corcovado and $23 million for the Mykonos, which we expect to be expensing in 2019, in addition, about $9 million each for the two rigs that is going to be capitalized. You add to that we’ve got about $7 million in mobilization costs for each of those two rigs. A lot of this is the re-crewing of the rigs, it is the project management costs which are typically not included in the Ocean Rig estimates. There’s a few more pieces of heavy equipment which we’re overhauling and recertifying. That pretty much covers the majority of it.
And for the four rigs in Greece, one is in mobilization to the shipyard because we’re not allowed to perform work where they’re currently sitting, and so--and then some other things that are specific to Transocean that Ocean Rig certainly hadn’t accounted for as they were looking at their reactivation costs and we were doing our preliminary reviews.
Okay, understood. Maybe just from a more high level perspective, you painted a fairly broad picture for ultra deepwater recovery, at least going into 2020 and beyond, and certainly in the deepwater golden triangle. If we think about maybe the next 12 to 24 months from a rate of change perspective, is there one region in particular where you expect to see the most growth? I suspect Brazil is probably high up there, or is it really going to be sort of a broad based, balanced recovery across geo-markets moving forward?
We’re seeing in our projections Brazil, as we discussed previously, is definitely on the way up, but very interesting, West Africa is just doing better and better. Nigeria has got couple of tenders coming out. There’s enough work in Angola that not only would fill the four [indiscernible] rigs but add a couple more on top of that, and then of course you saw the Senegal thing being awarded for a couple of rigs. So I would say you will see the golden triangle all across the board is going to increase, and then the other markets are actually just constrained by the supply because if we look at appropriate assets for harsh environment, there’s not that many available, and then as we go into the other places like Australia, then trying to get those high spec moored rigs, again there’s just not that many of them available.
So I think you’ll probably see a concentration of assets or growth in the traditional golden triangle, which is a very good barometer for our future.
Very helpful, thanks guys.
Thank you. Our last question will be coming from Sean Meakim with JP Morgan.
Thanks, hi. Good morning. Jeremy, to your earlier point about the efficiencies of the latest drill ships, as those get contracted out, how much of the next round of contracting lead to operators settling for lower rates with a bit less efficiency on those rigs, or would you expect them to pursue rigs with upgrades beyond just reactivation to try to match some of those efficiencies? How viable are those type of upgrade opportunities?
It’s a good question. Look - the reality of the situation is if you’re delivering a program 30% faster because of a more efficient rig operation, that not only gains you 30% of your spread cost back but it gets you to first oil a year ahead of schedule - instead of three years, it becomes two years. The actual compounding value of delivering efficiently is very significant for the operator, to the point in fact that with some of our big operators in the Gulf of Mexico, we’re delivering hundreds of millions of dollars lower and delivering programs nine to 12 months early.
When you talk about the benefits to the operators, it’s in the billions on these developments, so paying a bit more for the rig rate is certainly a justifiable expense, and if you believe that a certain operator is going to deliver you that efficiency, then they really are a no-brainer when it comes down to it when you’re looking at long term developments.
So in terms of the viability of those types of upgrades for, say, sixth gen rigs, how do we think about the availability of rigs that could try to upgrade into that level of efficiency?
If we look at the sixth and seventh gen, we’re already at the 80% level utilization, and if you think about adding the ones that are inactive, we’re still at that 70 percentile range, so you will see those rigs get soaked up and you will then see attractive upgrade options for most of them, I would imagine, because certainly as you get closer and closer to sold out, then you need to look at where can we deploy capital funded by the operators to deliver more efficient wells.
It will be a challenge, though, for the industry to do something like that. You think specifically about hook load capacity, going from 2.5 to 2.8, you’ve got top drives--it’s all going to require a lot of out-of-service time in addition to the capex you’d have to invest in the equipment, and so that all leads to pretty high cost. So it’s possible, but it’s going to command much higher day rates than what we’re seeing today.
And on the innovation side of things, we’re focusing on a lot of projects and upgrades that are to existing equipment rather than wholesale changing out handling equipment and the existing fleet. We’re looking at add-ons, clever ways of doing things. We’ve previously announced the ADC system on the Norwegian rigs, so those little things there now become very cost effective upgrade options for delivering that higher efficiency.
That’s very helpful. I appreciate all that feedback. One more for Mark - you referenced your liquidity profile on the prepared comments, but just curious how you’re--your latest thoughts on the maturities in 2020 and ’21 and thinking about the new build payments that you have coming in ’20 as well. How we think about the cadence of cash in and out over the next couple of years would be helpful.
Yes, thanks Sean. As you’re probably well aware, we’ve taken three runs through various tenders at the ’20, the ’21 and the ‘22s, in fact ‘23s for the first time as well this last quarter. In addition, we’ve had active open market repurchase programs ongoing for a vast majority over the last couple years, so I think we’ve taken as much of that debt as we can, given the reluctance by some investors to hold onto the paper. The plan right now is to retire the ’20 and ‘21s upon maturity. We do have $1.9 billion in cash, as you’re well aware, but that doesn’t mean we will not go out and look for opportunities to raise additional debt if we needed to, but then we’d be focused more towards the ‘23s because the ‘22s, as you know, is a pretty low coupon debt stack. That’s the plan for now, it’s just a matter of waiting until we can get that opportunity to repay that debt sometime in the near future.
Makes sense. Thank you very much.
Thank you. I’m showing no further questions in queue at this time.
Thank you Carrie, and thank you to all 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 second quarter 2019 results. Have a good day.
Thank you ladies and gentlemen, this concludes today’s teleconference. You may now disconnect.