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Good morning, and welcome to the Ensco Third Quarter Earnings Results Conference Call. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note, this event is being recorded.
I would now like turn the conference over to Mr. Nick Georgas, Senior Director of Investor Relations & Communications. Please go ahead.
Welcome, everyone, to Ensco's third quarter 2018 conference call. With me today are Carl Trowell, CEO; Carey Lowe, our Chief Operating Officer; Jon Baksht, CFO; as well as other members of our executive management team. We issued our earnings release which is available on our website at enscoplc.com.
Any comments we make about expectations are forward-looking statements and are subject to risks and uncertainties. Many factors could cause actual results to differ materially from our expectations. Please refer to our earnings release and SEC filings on our website that define forward-looking statements and list risk factors and other events that could impact future results. Also, please note that the company undertakes no duty to update forward-looking statements.
During this call, we will refer to GAAP and non-GAAP financial measures. Please see the earnings release on our website for additional information.
In correction with our planned merger with Rowan, Ensco and Rowan have filed a preliminary joint proxy statement with the SEC. Investors are advised to carefully read the preliminary proxy statement because it contains important information about the transaction, the parties, and the associated risks. Investors may obtain a free copy from the SEC's website and from each company. For more information, please read the legend at the end of the press release we issued yesterday.
As a reminder, we issued our most recent Fleet Status Report on October 29th. An updated investor presentation is also available on our website.
Now, let me turn the call over to Carl Trowell, CEO and President.
Thanks, Nick, and good morning, everyone. Before Carey takes us through our recent contract awards and Jon gives us an overview of our financial results and outlook, I will discuss recent developments, including our planned merger with Rowan, and provide some commentary on current market conditions.
Starting with an update of our planned combination with Rowan, we filed our preliminary merger proxy on Monday, October the 29th. As is customary in these types of transactions, we are now waiting on feedback from the SEC and will work with them to resolve any comments as we finalize the proxy. Additionally, we will be making customary filings in certain jurisdictions where we operate, including the U.S., U.K., and Saudi Arabia, to satisfy regulatory requirements. Following the regulatory and court approvals and Ensco and Rowan shareholder meetings to approve the transaction, we expect to close during the first half of 2019.
As we discussed on our conference call earlier this month, we are very excited about the merger with Rowan for several reasons. First, the combined company will be a premier offshore driller, with greater geographic and customer diversity, a proven track record of safety and operational excellence, and the ability to continue investing in technology and innovation to differentiate our services and lower costs.
Second, we will have an industry-leading fleet of high-specification assets capable of operating across all water depths, with particular strength in the highest-specification seventh generation drillships, as well as harsh environment and modern jackups, where we are seeing higher levels of customer demand.
Third, the combined company will have an even stronger financial position with greater liquidity and improved access to the capital markets. And finally, as a result of identified synergies from the transaction, the merger will create significant long-term value for shareholders.
In short, the merger between Ensco and Rowan will better position the combined company to capitalize on opportunities, and shareholders of both companies will benefit from a stronger franchise and even greater upside to improving market conditions as the industry recovery continues gaining momentum.
Several recent contracting wins are evidence that the recovery is underway. While Carey will expand on these in greater detail, I want to highlight a few new contracts of note. In terms of our floaters, we signed contracts for ENSCO DS-9 and ENSCO DS-12, two of our seventh generation drillships in South America and West Africa, respectively. We continue to see increasing demand for these types of highest-specification rigs for technically demanding deepwater work around the world. Additionally, we executed contracts for ENSCO 8503 and ENSCO 8505 offshore Mexico, underscoring customer interest for frontier projects in deeper water.
Moving to our shallow-water jackups, new work for high-spec harsh environment rigs, ENSCO 121 and ENSCO 122, are indicative of increased customer demand in the North Sea. These contracts demonstrate a clear preference from customers for high-quality rigs that can deliver increased efficiencies for their well programs, and we expect that this will remain the case for both floaters and jackups as the offshore recovery plays out.
Moving to broader market conditions; despite a recent pullback, spot Brent crude oil prices have moved higher since our July earnings conference call. Our future Brent contracts, with settlement dates over the next few years, are priced above $65 per barrel. Further, Brent crude has remained above $60 per barrel for over a year, and customers are continuing to generate significant cash flow to strengthen balance sheets, pay dividends, and begin to evaluate investment in future production.
Coupled with lower breakevens, increasing oil prices have given customers greater confidence in their offshore projects, and they are adjusting their oil price expectations higher as they set their 2019 budgets with an eye toward securing rigs for their offshore programs. This has led to increased tendering, and there are now over 100 open tenders worldwide, which translates to roughly 120 years of work in total for floaters and jackups; and approximately 40% of these tenders are for projects of at least one year. More than 40 of these open tenders are for floaters and the remaining 60 are for jackups, which is the most we've seen for shallow-water rigs in over a year.
In addition to the tenders I just mentioned, we continue to see a meaningful amount of opportunities that are not visible in open tenders. We are currently in discussions with customers on another 35 opportunities, and while these discussions are at varying stages and some may not materialize, they represent a total of roughly 35 rig years of work.
While signs of increasing customer demand are becoming more visible, we continue to expect that the recovery in the offshore drilling sector will be protracted and phased. The shallow-water recovery is further along this process, with increasing jackup utilization in several regions leading to broad-based improvements in the contracting environment.
The deepwater recovery is still in its early stages, as the majority of the floater tenders, both visible and not, are for work starting in the second half of 2019 or later. However, it is clear that we are now in a strengthening phase of the recovery where customers are increasingly evaluating investment in offshore projects.
As operators are in the midst of a budgeting season, oil price stability will be a key factor for offshore drilling demand in the years to come. While operators remain focused on generating cash flow before they meaningfully increase their capital expenditures, our recent customer conversations indicate attention has begun to shift towards meeting future production needs. As a result, we anticipate an increasing number of offshore projects will be sanctioned in the short- and medium-term, which will lead to additional tenders for offshore rigs and help to continue building a stronger pipeline of future contracting opportunities in the years to come.
While the exact trajectory of this improvement is difficult to predict, we expect market conditions will remain competitive in the short-term, as the structural oversupply of offshore rigs persists. However, given positive leading indicators for the medium- and longer-term, we will continue to be judicious in contracting our most technically capable rigs to preserve our exposure to better market conditions in the future.
We will also maintain our capital discipline as we evaluate investments in our rig fleet, including the decision to reactivate preservation stacked rigs. We will carefully assess the expected impact of additional supply against the potential financial benefit from returning a rig to our active fleet.
Further, rig reactivation costs will continue to be a key consideration as we evaluate contracting opportunities. And while competitors may choose to speculatively reactivate rigs, we expect to only reactivate rigs if a customer is willing to cover a significant portion of our reactivation costs via either a mobilization fee or through the day rate. Given this strategy, we currently have no intention of reactivating any of our preservation stacked floaters in the near-term.
As the offshore recovery unfolds, we remain focused on winning work for our marketed high-specification rigs and preserving our liquidity by proactively managing costs so we are well-positioned to benefit financially during the recovery.
Now, I'll turn the call over to Carey.
Thanks, Carl. As Carl mentioned, we won several recent contracts and extensions that have helped to improve our rig utilization as the market recovery continues to progress.
Starting with our drillships, we signed a contract for ENSCO DS-9 offshore French Guiana beginning in the first quarter 2019, with an expected duration of approximately four months. Importantly, this will place one of our most capable assets in a key deepwater region where customers are demonstrating higher levels of interest, better positioning the rig for follow-on contracting opportunities.
Additionally, ENSCO DS-12 has been awarded a two-well contract offshore Senegal that is expected to commence in second quarter 2019 and keep the rig on contract for most of the year. Similarly, ENSCO DS-12 will be well-positioned for future opportunities offshore West Africa, given the rig's capabilities. Both of these ultra-deepwater drillships are equipped with some of the latest drilling technology that customers are preferring for their deepwater projects, including 2.5 million pound hook-load capacities and dual blowout preventers.
In addition, we signed multiple contracts and extensions in the Gulf of Mexico that will improve utilization for our semisubmersibles and jackups. ENSCO 8505 signed a multi-well contract that is expected to be nearly one year in duration, with operations offshore the U.S. and Mexico. Under the contract, the rig will utilize both moored and dynamically positioned configurations, and its ability to operate in both configurations was key to securing this work.
Sister rig ENSCO 8503 will see a previously-announced 100-day contract transferred to a project offshore Mexico where it will appraise an exciting new opportunity for a client. Also in the Gulf, all four of our jackups in the region received either short-term contracts or contract extensions. ENSCO 75 and ENSCO 87 received contract extensions that are expected to work both rigs into September 2019. ENSCO 102 won an extension and a new contract that together are expected to add eight additional months of work. And finally, ENSCO 68 was extended and signed a new contract that is expected to work the rig through mid-2019.
While opportunities in the Gulf of Mexico have typically been shorter-term since the start of the downturn, our marketing team continues to successfully combine multiple projects and has already contracted all of our available jackups in the region through the middle of next year.
Moving to the North Sea, two of our highest spec jackups in the region saw additions to their backlog. ENSCO 121 won a five-month contract that is expected to last into second quarter 2019, and ENSCO 122 received multiple extensions that will see it work through April of next year with opportunities for additional work currently being evaluated. We also won a short-term job for ENSCO 72 in the region that will absorb its remaining 2018 availability.
These recent backlog additions leave us with just one jackup with availability in the North Sea, and we continue discussions with customers on shallow-water programs beginning in 2019 and beyond for our jackups in the region.
In the Middle East, jackup ENSCO 141 commenced a three-year contract in August, and ENSCO 108 is scheduled to start its three-year contract later this quarter. In addition to current contracts, we are actively bidding on additional work in the region, and we expect that the Middle East will continue to be the strongest region for jackup demand.
Finally, in the Asia Pacific region, ENSCO 8504 will return to work in April 2019 for a one-well contract offshore Japan that is expected to last four months. ENSCO 8504 is also capable of operating in both moored and dynamically positioned modes, and the rig has a strong operating track record in the region, improving its competitiveness for follow-on opportunities. While overall market conditions remain competitive, we have been successful in winning new contracts for our rig fleet and have added a total of 22 years of backlog since the beginning of this year.
In terms of global demand, we continue to see better utilization for assets that deliver the greatest efficiencies for customers' offshore well programs. For example, utilization for the delivered highest-specification drillships in the global fleet has increased to nearly 80% from 65% less than 12 months ago.
Similar dynamics are at play for shallow-water jackups where we also see better utilization for more modern assets as compared to older ones. While high-specification rigs provide efficiencies for their well programs, customers continue to choose service providers that consistently deliver exceptional operational performance. To this end, Ensco is positioned at the leading edge of the industry. Our offshore crews and onshore personnel continued to deliver high levels of operational and safety performance to our customers.
Year-to-date operational utilization across our fleet was a solid 98%, and our total recordable incident rate was 0.22, 40% better than industry average. By maintaining a balanced, high-quality rig fleet capable of meeting customer demand across water depths, we are well-positioned for both near-term work and longer-term opportunities. Our diversified fleet, which includes 7 of the 44 highest-specification drillships in the global fleet and 22 modern jackups, provides us with exposure to segments of the offshore market that are already beginning to improve.
Further, our highly confident crews, enhanced operational and safety systems, and ongoing investments in technology and innovation help to lower costs for Ensco and our customers. We are confident that these strengths differentiate us from the competition and make us a key service provider to offshore customers around the world. This strengthens our ability to continue winning new work and positioning Ensco for future growth opportunities.
Now, I'll turn it over to Jon.
Thanks, Carey, and good morning, everyone. Today I'm going to cover third quarter 2018 financial results, our outlook for the fourth quarter and capital expenditures, a summary of our financial position, and finally, I'll provide some additional details on our planned merger with Rowan.
Our third quarter financial results compared favorably to the outlook from our prior earnings conference call. We beat our guidance for revenues and contract drilling expense as a result of higher number of operating rig days and disciplined cost control. Adjusted EBITDA for the quarter was $74 million, approximately 12% higher than the implied outlook from our prior conference call.
On a sequential quarter basis, total third quarter revenue was $431 million versus $459 million in the prior quarter. In the floater segment, revenue declined to $242 million from $285 million in the second quarter, primarily due to the completion of contracts for ENSCO 6001, ENSCO MS-1, and ENSCO 8503, as well as an idle period for ENSCO DS-12. As a consequence, utilization decreased by 7 percentage points to 46%, while the average day rate increased slightly to $239,000 from $238,000.
Operational utilization for the floater segment, which adjusts for uncontracted days and planned downtime, was 97% compared with 98% in the second quarter. In the jackup segment, revenue increased to $173 million from $159 million in the prior quarter, primarily due to the contract start-ups for ENSCO 140 and ENSCO 141, a full quarter of operations for ENSCO 107, and fewer scheduled shipyard days in the third quarter. This was partially offset by ENSCO 80, which worked for much of the second quarter and was sold during the third quarter. Reported utilization was 66%, equal to the prior quarter, while the average day rate increased slightly to $80,000 from $78,000.
Operational utilization for the jackup fleet was 98% compared with 99% in the second quarter. These results underscore the broader industry dynamics with conditions for shallow-water jackups continuing their steady improvement while floater utilization remains choppy as the deepwater market bottoms.
Excluding integration-related transaction costs, contract drilling expense declined 4% sequentially to $325 million in third quarter 2018, primarily due to the sale of ENSCO 6001 early in the third quarter, and lower utilization for our floater fleet, partly offset by higher costs from contract start-ups in our jackup fleet. This was slightly better than our prior conference call guidance of approximately $330 million, as we continue to proactively lower costs for rigs during uncontracted periods.
Third quarter depreciation expense of $121 million was consistent with the prior quarter. Excluding transaction costs, general and administrative expense declined to $24 million from $25 million in the prior quarter, primarily due to lower personnel expenses.
Other expense was $9 million compared to $13 million in the prior quarter. The sequential comparison was impacted by: a $7 million loss related to a bargain purchase gain; adjustment from the Atwood acquisition in third quarter 2018 compared with an $8 million loss in the prior quarter; and a $2 million loss on foreign currency during the third quarter compared with a $5 million loss in the second quarter.
Tax expense declined to $23 million in third quarter 2018 from $25 million in the prior quarter due to $8 million of discrete tax benefit included in the third quarter 2018 tax provision compared to $2 million of discrete tax benefit recognized in the prior quarter. Adjusted EBITDA for the third quarter 2018 was $74 million compared to an adjusted EBITDA in the second quarter 2018 of $85 million. A reconciliation of net loss to adjusted EBITDA is presented in our earnings press release.
Moving to our outlook for fourth quarter 2018. We expect revenue will be $395 million to $400 million in fourth quarter 2018, with a sequential quarter decline primarily due to idle periods between rigs completing contracts and commencing new work. Despite a projected 4% decline in utilization, we anticipate that fourth quarter contract drilling expense, excluding transaction costs, will decline by only $5 million to $320 million, as we expect that many of the rigs rolling off contracts will commence new work in the near future.
This relationship is expected to have a negative impact on EBITDA over the next couple of quarters, as cost to prepare rigs for future contracts will occur ahead of associated revenues. For purposes of reconciling EBITDA to our income statement, amortization is expected to provide an $8 million net benefit during the fourth quarter, as $19 million of amortized revenue is partially offset by $11 million of amortized expenses.
We expect depreciation expense will be approximately $121 million and G&A expense, excluding transaction costs, will be approximately $23 million, both largely consistent with the third quarter. In addition, fourth quarter 2018 general and administrative expense is expected to include $3 million of transaction costs primarily related to our planned merger with Rowan. Finally, we anticipate the fourth quarter tax provision will be approximately $33 million.
Moving to our capital expenditure outlook, capital expenditures for fourth quarter 2018 are expected to be approximately $95 million, consisting of newbuild construction costs, minor rig enhancements and upgrades, and $10 million of capitalized interest. Beyond 2018, our only remaining significant capital commitments are for newbuilds ENSCO DS-13 and DS-14 which total approximately $250 million in yard payments for both rigs, excluding interest and holding costs. We have an option to defer payment on these rigs until year-end 2022 via shipyard-provided financing at a 5% interest rate.
Turning now to a summary of our financial position. We have just $236 million of debt maturing before 2024. At the end of third quarter 2018, liquidity totaled $2.6 billion, including approximately $630 million of cash and short-term investments and a fully available $2 billion revolving credit facility. Under our credit facility we have borrowing capacity of $2 billion through September 2019, $1.3 billion from October 2019 to September 2020, and $1.2 billion from October 2020 through September 2022.
Importantly, the revolver has no covenants based on operating cash flows and we maintain the flexibility to raise additional capital through asset sales and a secured debt basket of $750 million. Our net debt is approximately $4.4 billion, and we have a net debt to capital ratio of 35%.
Finally, I will provide some further detail on our planned merger with Rowan. As Carl mentioned earlier, we believe that this combination will create an industry-leading offshore driller and those company shareholders will benefit from the transaction. As outlined in our merger announcement, we have identified annual run rate expense synergies of $150 million from the deal. This equates to approximately $1 billion in present value, representing significant value creation when compared with our current combined market capitalization. More than 75% of these synergies are expected to be captured within one year of closing which would make the combination accretive to cash flow per share in 2020, assuming the transaction closes in the first half of 2019.
These annual expense savings are expected to be realized primarily from corporate and regional overlaps, supply chain efficiencies, as well as the standardization of systems, policies, and procedures across the combined organization. We estimate that approximately 50% of targeted synergies will be recognized in contract drilling expense with the other half in G&A expense. While this combination is a merger rather than an acquisition, we feel very confident of achieving these synergy targets based on our recent experience from the Atwood acquisition, and we'll provide updates on synergy realization on quarterly earnings calls following closing.
As of June 30, the combined company would have had liquidity of approximately $3.9 billion, including $1.9 billion of cash and short-term investments, as well as Ensco's undrawn $2 billion revolving credit facility. This liquidity will provide the combined entity with the financial flexibility to continue investing in the fleet and innovations aimed at improving drilling efficiencies for our customers. Further, we expect that the increased geographic and customer diversification will result in greater access to the capital markets that neither company would've had on a stand-alone basis which will improve our competitiveness going forward.
In closing, the outlook for offshore drilling continues to improve as sustained higher commodity prices, coupled with lower breakeven costs make many offshore projects compelling investments for our customers. The recovery in the jackup segment is already well underway, and we are beginning to see a broad-based improvement in all major shallow-water regions. We're also beginning to see some of the increased customer activity for floaters translate into contract awards, and we anticipate the utilization for floaters will begin to increase in the latter part of 2019, particularly for the high specification assets that are most in demand.
The combined companies' rig fleet will contain many of the industries high specification assets, and coupled with meaningful synergies, will provide our shareholders with even greater upside to improving market conditions as the industry recovery continues gaining momentum. For these reasons, we are excited for the merger and look forward to closing the transaction in the first half of 2019.
Now, I'll turn the call back over to Nick.
Thanks, John. Phil, at this time, please open the line for questions.
We will now begin the question-and-answer session. The first question comes from James West with Evercore ISI. Please go ahead.
Hey. Good morning, guys.
Good morning, James.
Morning.
Carl, when we spoke a few weeks ago in New York, you were talking a little bit about the kind of heightened sense of urgency amongst the customer base. I think we talked mostly about, kind of, the deepwater tenders coming in, but I suspect it's happening kind of across the board, shallow and deepwater. Could you provide perhaps an update on the customer interactions now? Is that sense of urgency growing further? Are they starting to get concerned about supply of high-spec assets as we look out into late 2019 and early 2020?
Yeah, James. I don't think anything has drastically changed over those few weeks. What we've started to see, as we outlined in the pre-prepared statement, is that customers are beginning to really build a plan forward now for 2019 and 2020. And those that have a line of sight to contracting are beginning to rush out tenders, and that's driven by two key factors.
The first is, as we said, people are beginning to now turn to really look at production and reserves in the out years after three to four years of really pulling back on capital expenditure. What is also playing into that is that several big projects, several FIDs, are coming towards the end of their life and coming on stream; and therefore, there's a bit of a CapEx shift happening between projects that have been four, five, six years in the making, to now newer projects.
So for many of our customers, you will see that effectively what they're guiding to for next year is close to flat CapEx, which doesn't necessarily gel with the story we're telling you about the number of new tenders, but if you look at that, what you actually see is there's quite a bit of shifting of that CapEx spend away from long-standing, long-running FIDs into newer projects.
The second thing that's driving some of the push to get more tenders out is that some of our customers are beginning to see that the particular rigs that they want in particular classes are beginning to show increased utilization. And there is that a bit of a concern that they're not going to get the rig they want at the time they want it for a particular project. So that's driving it a little bit. I wouldn't describe this as a headlong rush yet, but we are seeing it in a few markets, one (30:10) with a few customers.
Okay. Okay. Fair enough. And would you anticipate a number of these tenders that have been rushed out to be awarded as we kind of finalize budgeting season here for a lot of the majors and the NOCs around year-end?
Yes. I think some of them will be. If I go back to the pre-prepared statements, you'll see that we listed – there was a high number of actual tenders out there, open tenders.
(30:44)
Yeah, 100. But there's actually these additional 35 non-official open tender opportunities that we see. A lot of these are requests for information, request for bids, pricing or in some cases direct negotiations. I think a lot of those will go before investment committees as they go through budget cycle at the end of this year and would be likely turned into tenders as we get through the budget cycle.
Some of them will fall off the table because what we see is regional business units of some of our bigger customers pushing to do more work, and they'll be putting them up in front of their company's budget committees and some of them might not get sanctioned. But in many ways, it's still a good sign because I think that once you get out to the regional levels of some of those super majors and the IOCs, you're seeing a lot of the business units really becoming concerned about production profiles and wanting to go back to drilling next year.
Great. Thanks, Carl.
Thanks.
The next question comes from Jud Bailey with Wells Fargo. Please go ahead.
Thanks. Good morning. Hey, a question kind of on thinking about deepwater day rates. Carl, there seems to be – there's a lot of debate over kind of the day rate structure as it relates to the ultra-deepwater market. You have kind of still weak spot market today for near-term work, but there's a lot of commentary suggesting quite a bit of upside in forward rates starting in late 2019 and 2020. Could you maybe give us your perspective on how you see kind of that rate structure converging or playing out, and kind of how you see it today?
I think broadly, Jud, it's as you've described it. Today, spot rates are still low. People are chasing utilization sort of in the next few quarters. But as you begin to look to the back end of 2019 and into 2020, we see the predominance of deepwater tenders have got start dates at the back of 2019 or early 2020. Therefore, I think we look to that point to start to see utilization begin to pick up and therefore develop a better, more constructive contracting environment. So, I think that we're looking for that. I think the back end of 2019 is when we expect to start to see that utilization and demand really begin to turn based on what we see in-house at the moment.
And that's a bit different from the jackup market, as we've said, where we think the jackup market is beginning to be in a pretty broad-based pick up now. We're seeing utilization and demand increase as we are, and so therefore we're expecting the general contracting environment to look a lot better in 2019. And I think for the floaters, it's 2020. So if you want an easy tagline, I think the jackup story is 2019, and I think the floater story is 2020.
Okay. And if I could follow-up on the jackup comment; you're developing some nice backlog in the Gulf of Mexico, as you pointed out, and I would assume that's at higher rates. Do you anticipate the need to bring more rigs into Gulf of Mexico at some point, or do you think we've kind of satisfied the demand that's out there? How do you see that market playing out?
No. I think that we're still coming off several years of the market being oversupplied, and I don't think that we would be rushing to bring new capacity into that market. We still would like to see utilization and demand come up another level there.
Okay. Great. Thanks. I'll turn it back.
Okay. The next question comes from Greg Lewis with BTIG. Please go ahead.
Yes. Thank you, and good morning, everybody. I guess maybe for Carl or for Carey, as we think about these tenders out there, obviously a lot of it has to do with timing. And so, as we think about maybe when these tenders actually become fixtures and then sort of when they become actual rigs working, could you kind of talk a little bit about that, or a little bit more color around these 100 tenders actually becoming rigs drilling?
I'll take that first, and then maybe Carey can add anything if I miss it. But it depends on which segment you're talking about. So in the jackup segment, I think the lag time certainly is a lot shorter. What we're seeing now is the tenders that are out there are turning into new awards quite quickly, and we're seeing that pace pick up a bit.
There's certainly some very long-lived, exhausting processes ongoing in places like the Middle East, but outside of that area in now the North Sea, GOM, Asia Pacific, we're seeing things beginning to turn now quite quickly from tendering exercises into awards.
The floater market is still different, and we still see the lag time. One is just the natural process by which the planning cycle, the ordering of long lead items, and the tendering process for deepwater is just by nature longer. And we're also seeing the industry wake up after four very low level years, and it's taking time for that to play through. And accordingly, I think that's why we think that for the floater market, it's the back end of 2019 where we need to look to see a lot of these tenders turn into actual rigs on contract.
Carey, anything you want to add?
No, I think that's a good description.
Okay. Great. And then on the ENSCO DS-9, that's, say, one of the best rigs in the world. My question about that is that rig was delivered in 2015 and has just been sitting there waiting for its maiden contract, could you talk a little bit about – and I'm trying to understand as we think about other rigs that have kind of just been delivered across the industry – how difficult was it getting that rig to work? What was the process like, or was it really just, hey, this was a newbuild rig that was kind of delivered; whether it was delivered three years ago or last week, it was kind of viewed the same way by the customer?
You're right, Greg. I think the history there is important. That rig was delivered in 2015 and went through its full integration testing and acceptance testing with another customer, so it already done that. Now that customer elected to terminate the contract with a large termination fee. The rig has been kept warm since then. But we didn't – so actually putting it to work was not terribly difficult for two reasons. One, the rig was not brand-new delivery out of the shipyard; but secondly, the client who took it had, had excellent experience and was delivering the sister rig, ENSCO DS-8, out of the yard brand-new to West Africa with less than 1% downtime in its first year of working. So, there was a – first of all, a real faith in our ability to deliver a rig of that type and put it to work straight out of the box; and secondarily, on the performance of that rig class.
Okay. Great.
I think Carey wants to add something.
Yeah. Greg, in addition to that initial acceptance testing, the rig has done a couple of other pretty significant parts of the acceptance testing process for the client that we're going to work for in French Guiana. And it's been well taken care of, well maintained, and we've had people on it the whole time. So the rig is ready to go with confidence.
Yeah, and I'll add a little bit more on ENSCO DS-9, I think because we wouldn't have brought that rig out for just that one contract if we didn't think there was a very good chance it could go on and work afterwards. So, we very much see this as its kind of first shakedown contract and put it ready, warm, and in a key market where we're fully expecting that it will be able to get some follow-on work in that Latin America or Atlantic margin afterward.
Okay. Great. Hey, thank you very much for the color, guys.
Thanks.
Okay. The next question comes from Ian Macpherson with Simmons. Please go ahead.
Thanks. Good morning, everyone.
Morning.
So I wanted to ask, as the reactivation cycle and the contracting cycle unfolds, do think it's possible that the early customers that buy are the ones who will be rewarded with the best rigs at the lowest prices? And then the converse would be true; those who come to market later are going to get second-tier sixth-gen rigs and pay more for them? Or alternatively, do you guys expect that – are you marking your assets in such a way that the highest technical capability ultimately will earn out the best over the next five years? I mean is that a strategy that you can lead, or do you just have to kind of take what the market gives you?
Well, I think, Ian, first because of the size of our fleet, we have the ability to run a bit of a portfolio. So our emphasis at the moment is on getting utilization in 2019 on the key technical assets such that they're ready to work and be placed into what we think will be a better contracting environment end of 2019, 2020, 2021. But remember, we do have some swing capacity there.
We have ENSCO DS-13 and ENSCO DS-14 we can bring out. And as we said in the pre-prepared statements, we're not going to be doing that until we see a better environment. And contracts will – rigs that we have that are higher capacity will be rolling off contract, ready to place them into what we think is a better contract environment.
So I think given our fleet size, we have the ability to leverage ourselves to any upside as the market unfolds. And we at this stage don't intend putting out the preservation stacked rigs until we see a better environment and, as we said, a pricing environment or a mobilization fee that will pay at least a significant portion of the cost to reactivate those rigs.
Okay. Thanks, Carl. We're hearing from you and from your peers the demand recovery is most evident in the Americas and the U.S., Mexico, South America and increasingly and I guess now on a leading (42:20) leading edge in West Africa as well. I meant to say the Americas ex U.S. Gulf of Mexico. That was actually what's been confounding to me, that we haven't seen much yet in the U.S. Gulf. When you describe the visibility that's outside of open tenders, it's direct negotiations, et cetera, is the Gulf of Mexico also beginning to reawaken with the majors coming out for rigs?
To a limited extent, Ian, but I wouldn't call it out as a huge developing area. But we are seeing increasing discussions now from several customers about deeper-water work. Actually, the area that is still the most buoyant at the moment in the GOM is the ones that's been served by our ENSCO 8500. So, this is in sort of mid-water ranges where it's both moored and maybe DP around existing infrastructure. That's the area where there's most activity and discussion of most activity at the moment. But we are beginning to see the leading edge now of clients talking about work in the more open water, deepwater area that require drillships.
Got it. Well, thanks for the good color. Appreciate it. Good results. I'll pass it over.
Thank you.
Okay. The next question comes from James Wicklund with Credit Suisse. Please go ahead.
Hey. Good afternoon, guys. It's actually Radi on for Jim. My first question was on the reactivation strategy. I mean obviously you already spoke to the floater side, but maybe more on the jackup side; it looks like in the proxy filing today the forecast does contemplate some reactivations over the next couple years. I was wondering if you could provide an update on your strategy when it comes to jackup reactivations and what the outlook is for that in 2019.
Yeah. That's a good point of differentiation. The point we refer to in the prepared remarks was relevant to the floaters. For the jackups, given that we're seeing a more broad-based pick-up in activity and 2019, we're starting to see quite a few new contracting opportunities develop, I think it's likely that we would look to reactivate between one and three of the jackups that we currently have stacked as we go through 2019.
We're right in the middle of our planning cycle at the moment, and we'll give more guidance on that on the 2019 plan when we report next quarter. But the way we're viewing this, particularly for the jackups, is we'll effectively have an H1 and an H2 plan depending on how we see the market development. And I think as compared to the floaters, we are prepared to bring more jackups into the market if we see the right conditions because actually the jackup market is unfolding a little bit better than we maybe anticipated 6, 12 months ago.
And, Radi, I think the other thing to note is the reactivation costs for the jackups isn't nearly as high as some of the floaters might be. And from an outlook standpoint, if you look at the proxy or if you look at our current guidance, it's probably somewhere between $10 million to $15 million per jackup. And those jackups are still continuing to generate some good margins, so the payback on that reactivation is much easier to justify than on the floaters.
Yeah. I think we'll be much more guided here by what our customers want and the demand driven by our customers as we go through the next 12 months.
Okay. Great. And then just quickly on the ENSCO DS-13 and ENSCO DS-14 now you'll have the Rowan floaters in the fleet, I'm curious what the strategy is for the newbuilds? Have you considered maybe delaying and adding some additional upgrades to those two rigs? I mean, any color there you could provide would be helpful.
Well, yeah. First of all, just to make it clear, we're operating as two separate companies, and we won't be getting into a combined fleet strategy until the deal closes. But what we've always said is that we may have the option to delay those rig deliveries, and I think there's a good chance we will look at that.
As far as any upgrades are concerned, these are two of the best drillships in the world, and I don't think we need to actually upgrade them with anything at this stage to put them at the top of the list. So, I'm not sure we will put more money into them, but we may consider delaying their delivery into the market. But we would've done that and will do that on a stand-alone basis.
All right. Good stuff, guys. Thank you.
Okay. The next question comes from Taylor Zurcher with Tudor, Pickering, & Holt. Please go ahead.
Good morning. Thanks, guys. Carl, appreciate all the color on the visible tenders you're seeing out there. For the, I guess, nonvisible piece or the 35 opportunities you called out, I'm just curious on the direct negotiated piece. Obviously, that's probably trended higher over the last, call it, three to six months. But if we think about a more normalized environment, could you frame for us what that number typically looks like, either in absolute terms or maybe a percentage of total tenders relative to what it looks like today?
Yeah. So in typical times, so in 2014, 2015, about 25% of the work that Ensco did was not open tender in the sense that it was either direct negotiation or it was one or two parties invited to the table to negotiate. That went away, largely, through the down cycle for the last few years, and now we're beginning to see it reemerge a little bit. It's not at that 25% level yet, certainly not in the number that have been awarded. But we're currently in direct negotiations between – on or about five different opportunities of some materiality. And so, that's interesting to start to see that develop.
The two things I draw from that: the first is that we're beginning to move back to a more normalized situation; but the second is, I think it's indicative of customers beginning to be a little bit more concerned about being able to get the rigs they want from the contractor they want at the right time, and also feeling that they might get a better overall cost result if they direct negotiate.
And also, several of these negotiated tenders are coming with some other additional element to them; either they're asking us to take on some additional responsibilities or they're asking us to align with project deliveries in a different way, which is difficult to do in a normal open contracting model. And therefore, I think the direct negotiation with the Tier 1 driller is appropriate for some customers and some projects.
Okay. That's helpful. Thanks. And then, a follow-up just on the ENSCO 8500 Series rigs. You've obviously had pretty good success or really good success finding incremental term for the handful of rigs that you're marketing today. Just given that the niche capability – and I know they're different than a traditional six- or seven-gen floater, just given the water depth and hybrid capability, but have you seen any pricing momentum on that asset class in particular for this work that you've been awarded both over the past couple of quarters and looking forward into 2019?
Well, in the sense that we've been at kind of bottom of cycle pricing levels, we have seen it start to come off bottom, and we are beginning to see some improved pricing there. I think we'd like to see better demand and customer demand before we would look at ever bringing out another ENSCO 8500.
I could see us doing it at the right time because we've been very pleased with the uptake of that hybrid mooring conversion that we've done, and we've been very pleased with the ability of those rigs to work in this mode where they drill some wells DP, some wells bored, some wells under a DP-assist mode. And so I think that we will continue that strategy with at least the next rig that we would bring out. So we will get around to it. I think we've found that those rigs have now a key place in the global market, but it's just not yet.
Great. Thanks.
The next question comes from Colin Davies with Bernstein Research. Please go ahead.
Good morning. I was just wondering if you – as we're starting to see the increase in tenders, whether you're starting to see a shift in the balance of where those tenders are coming from, particularly between the majors, NOCs, international NOCs, independents, and so on, and whether there is any difference across rig types within that. Because I think in the past, you've said that it was a little bit more led by independents and NOCs in the past, but is it more balanced at this point?
A little bit more. I mean certainly, the uptick in the market was driven initially by the independents and the NOCs, and we're still seeing that quite strong in certain markets. The Asia Pacific would be one good example of that. Of course, the Middle East is very much driven by the NOCs. But we have more recently seen more tenders and more tender inquiries coming from the next – so the more global players in the sense of the super majors and the IOCs. So, a little bit more balanced, but I think that we're still seeing a lot of tenders coming at the NOCs and E&P companies, more than you might imagine, actually.
Okay. Okay. And then just a follow-up on the earlier question on the ENSCO 8500s. It does seem intriguing that, that asset class is getting some traction, although it seems quite tactical at this point. I was intrigued by the decision to do a one-well deal in Japan with a (53:20) from Singapore. Perhaps give us a little bit more color about how you think about bidding those particular units and what the strategy is going forward.
Yeah. So, let me just circle a little bit around to the ones in the Gulf of Mexico. As you've seen from our latest Fleet Status Report, those rigs are proving to be really well suited to the – not only that U.S. GOM but also the mid-water depth ranges in Mexico where there's quite a lot of activity coming over the next few years. So we think that the combined market of the wider Gulf of Mexico between the U.S. and Mexico is going to be a really good market there for them going forward. And it's nice to see them start to win some longer-term work. I still think there's more to come there, particularly on the Mexico side for those rigs.
The ENSCO 8500 – the ENSCO 8504 in Asia it's a little bit like the story I said on the ENSCO DS-9. You should anticipate that we didn't bring that rig out of Singapore with the intention of just doing one well and then it not working again. We made that decision because of the forecast we have for upcoming work mid- and later-2019 in Asia Pacific for that class of rig, and that rig particularly. And therefore, we are using that to bring it out, get it warm, do a difficult well for a good client and have it well-positioned for follow-on work. And we are hopeful and very hopeful that it will get follow-on work straight after that project. So you should see really that one-well project as a springboard to more longer-term work thereafter
That's very helpful. Thank you.
Okay. The next question comes from Ryan Pfingst with B. Riley FBR. Please go ahead.
Hey. Good morning, guys. There's been some commentary out there that the North Sea semi market is becoming sold out maybe in the next year or two. Are you guys seeing that; and if so, would you consider possibly moving some of your semi assets to that region?
First of all, Ryan, we're not present in that market at the moment and we have limited rigs that have that colder water, harsh environment characteristics to work in the North Sea. So, it's not particularly a question for us. We see the market – I mean, that market is one where it's been tightening there's a lot of forecasts around whether it's going to be over or undersupplied in the future. We've got maybe one rig that we might look at moving there. I'm not sure we're at that point yet.
Got you. Thanks. I'll turn it back.
Okay. There are no further questions. I'll hand the call back over to Nick Georgas.
Thank you, Phil, and thank you to everyone on the call today for your interest at Ensco. We look forward to speaking with you again when we report fourth quarter 2018 results. Have a great rest of your day.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.