Good day everyone, and welcome to Ensco plc's Fourth Quarter and Full Year 2018 Financial Results Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today's presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note that this event is being recorded.

I will now turn the call over to Mr. Nick Georgas, Senior Director of Investor Relations, who will moderate the call. Please go ahead, sir..

Welcome everyone to Ensco's fourth 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. As a reminder, we issued our most recent Fleet Status Report on February 20. 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. I will start today's call with an update of our planned merger with Rowan before providing an overview of current market conditions and the evolution of the offshore market recovery. Carey, will then comment on our operational achievements and summarize recent contract awards.

Finally, Jon, will conclude with an overview of our financial results and outlook along with some commentary on the financial implications of the pending Rowan merger. Last week we received overwhelming shareholder approval to merge with Rowan, a significant milestone on our path to closing the transaction. We've also received clearance from the U.S.

and UK regulatory authorities and are working toward obtaining approval from Saudi authorities. As a result, we expect the transaction will close in the coming months as planned. By bringing Ensco and Rowan together, we will solidify the combined company's position as a key offshore service provider.

This transaction will create an industry-leading offshore driller with an expanded geographic footprint, a broader customer base and a modern high quality rig fleet that is well positioned to meet customer demand across all water depths.

A combined company will have 28 floating rigs including 25 ultra-deepwater capable assets with an average age of just six years. Making this fleet, one of the youngest and most capable in the industry.

Floater fleet will contain 11 of the 44 highest specification seventh generation drillships in the global fleet, which is a segment of the market that has experienced increasing utilization over the past 12 months.

The 54-rig jackup fleet will include 38 units that are equipped with many of the advanced features requested by clients with shallow-water drilling programs, such as increased leg length, expanded cantilever reach and greater hoisting capacity.

Within this jackup fleet, 16 modern harsh environment rigs that give the combined company a meaningful presence in a segment of the shallow-water market that is showing tangible signs of recovery.

In addition to a diverse high quality fleet, Ensco and Rowan shareholders are expected to benefit from $165 million of annual expense synergies from the transaction, creating approximately $1.1 billion of capitalized value. We are confident in our ability to deliver on these synergies because Ensco and Rowan have similar cultures and philosophies.

Both companies have a shared focus on safety and operational excellence that has resulted in industry-leading customer satisfaction for nine consecutive years in an independent survey by EnergyPoint Research.

As we move forward, the combined company will continue its commitment to delivering industry-leading service quality to the broadest customer base in the offshore drilling sector. We are also dedicated to deploying new technologies and innovative solutions that differentiate our services and help to lower customers offshore project costs.

With a larger more diversified fleet, the combined company can economically develop and deploy these technologies across a wider asset base and global footprint.

From a financial perspective, the combined company's balance sheet will be strengthened by the transaction and our credit profile will benefit from increased scale and significantly enhanced diversification across regions, customers and rig types.

Jon, will provide further details on the financial highlights of the transaction during his prepared remarks.

In summary, we believe that the combination of Ensco and Rowan, will create an industry-leading offshore driller that is ideally positioned to capitalize on opportunities as the industry recovery unfolds, while creating meaningful long-term value for shareholders. For these reasons, we look forward to closing the transaction soon.

Moving now to broader market conditions. Despite the recent pullback in oil prices, the recovery in the offshore drilling sector continues steadily progressing. Given the lead – longer lead times for offshore production, customers generally look through short-term commodity price volatility and evaluate new projects based on longer term fundamentals.

For example, we did not see a significant increase in customer demand when spot Brent crude prices increased meaningfully during a six week period last year, despite reaching highs of $85 per barrel. Similarly, we did not experience a widespread decline in tenders and inquiries.

The spot prices declined rapidly during the fourth quarter, as longer term pricing remained above $60 per barrel. With spot prices rebounding above $65 per barrel to start the year and longer term prices above $60 per barrel, customer demand continues to grow at a measured pace.

Recent conversations and public commentary suggest the customers are prioritizing projects that are on the lower end of the cost curve when they evaluate their production portfolios. With much of the offshore work that is expected to begin in the short-term screening as economic at Brent crude prices of $50 a barrel or less.

Additionally, higher oil prices and lower cost per barrel led to significant free cash flow for the largest offshore exploration and production companies during 2017 and 2018. Expectations are that this trend continues in 2019, which will give major offshore customers even greater flexibility to invest in future production.

Further, many national oil companies are focused on maintaining certain levels of production to fund that fiscal budget requirements and commodity prices are at levels currently that are conducive to offshore investments to support these objectives.

Recent contracting activity in tendering data also points to the broader improvement in offshore market conditions. The number of new offshore contract awards in 2018 were approximately 20% higher than 2017, more than 60% higher than the lows experienced during 2016.

Open tenders for offshore rigs at the end of 2018 were more than 70% higher than a year ago. Current tender data shows an approximately 15% increase in both the number of open tenders and the number of rig years that these tenders represent, as compared to October 2018. A frame of reference.

Current open tenders total approximately 120 worldwide, which translates to roughly 140 rig years of work with roughly 60% of these opportunities for jackups and the remaining 40% for floaters.

In the shallow water market, we saw significant improvements in the contracting environment during 2018 in certain regions and we expect to see a more broad based recovery during 2019. Utilization for our marketed jackups is expected to reach levels where we may consider selectively reactivating one or two stacked rigs.

However, any reactivation decisions will be contract dependent and we would only expect to reactivate rigs, if a customer is willing to cover a significant portion of our reactivation costs via a mobilization fee or the day rate.

In terms of floaters, the deepwater recovery is still in its early stages as the majority of floater tenders are for work starting in the second half of 2019 or later.

As a result, day rates for floaters contracts beginning in 2019 continued to be competitive, while pricing for work commencing in 2020 and beyond is more encouraging with day rates that are higher than current spot rates.

While these trends suggest that floater day rates have reached bottom, we will continue to be very disciplined when evaluating potential rig reactivations and we currently have no plans to reactivate any of our preservation stacked floaters during 2019.

As we continue to manage through these dynamic market conditions, our ability to deliver the highest levels of customer service helps to differentiate the Company from the competition and win an outsized share of new work.

To this end, I would like to congratulate our offshore crews and onshore employees on another year of strong operational and safety performance. Their efforts have helped to establish a very strong foundation that we can build upon as we combine with Rowan, so that we continue to be well positioned to thrive as market recovery progresses.

Now, I'll turn the call over to Carey..

Thanks, Carl. Our offshore crews delivered another year of strong operational and safety performance in 2018. They continued to achieve high levels of operational utilization, with 99% uptime for jackups and 98% uptime for floaters during the year.

In terms of safety performance, our total recordable incident rate of 0.25, was approximately 30% better than the industry average. These results are a testament to the exceptional safety culture we developed over three decades and we'll continue to promote going forward.

Our operational results benefit from the investments we have made in proprietary systems, processes and technologies over the past several years. These focused investments helped to differentiate Ensco's assets from their competition through better performance and reliability and lower offshore project cost for our customers.

One example of these efforts is our recently launched Continuous Tripping Technology. This groundbreaking technology is a patented system, that fully automates the pipe tripping process, without stopping to make or break connections, allowing us to achieve continuous movement of the drill string into or out of the well at a constant controlled speed.

We expect that this technology will lead to pipe tripping times that are up to three times faster than current conventional stand-by-stand methods. Continuous Tripping Technology was recently installed on new build jackup, ENSCO 123.

And commissioning of this system is currently under way, ahead of the rig's maiden contract, which is expected to begin in the third quarter.

While several customers have expressed interest in this technology, we plan to use ENSCO 123 as a way to test customer demand for this enhanced service offering before evaluating upgrades to other rigs in the fleet.

By maintaining a high-quality rig fleet with differentiated technology and delivering outstanding operational and safety performance, we are well positioned to capitalize on increasing customer demand, as evidenced by the number of new contracts Ensco won during 2018.

These new contracts and extensions totaled more than 30 rig years of work, a 35% increase from the prior year and added more than $900 million of contract revenue backlog.

Recent contracting highlights include awards or extensions for two of the highest specification drill ships, ENSCO DS-7 and ENSCO DS-10, demonstrating growing demand for the most technically capable drillships that deliver efficiencies to customers' offshore projects.

ENSCO DS-7 is expected to commence a six-month contract offshore Egypt in the second quarter of 2019, with customer options that could lead to a further 18 months of work.

We also received a one-year extension for drillship ENSCO DS-10 offshore Nigeria, that will keep the rig under contract through March 2020 with an additional four one-year options remaining. Moving to our semisubmersibles, ENSCO 8503 was recently awarded a four-well contract in the U.S. Gulf of Mexico.

Additionally, ENSCO DPS-1 was awarded a two-well contract offshore Australia, that is expected to commence in February 2020 with the customer option for seven additional wells that if exercised would keep the rig under contract into 2021.

In the shallow water market, we saw significant improvements in the contracting environment during 2018 and we expect this trend will continue into 2019 across all major shallow water regions.

This improvement can be seen in the Fleet Status Report we published last week, which shows all of our marketed jackups either working or contracted for future work.

In the North Sea, we continue to see high levels of customer demand, particularly for high specification jackups like our ENSCO 120 series rigs, as evidenced by a new three-well contract for ENSCO 121 and the maiden contract for ENSCO 123. Also in the North Sea, ENSCO 100 was recently awarded two contracts, totaling an estimated eight months of work.

Moving to the Middle East. We recently signed a four-year contract extension for ENSCO 76, that will see the rig continue to work offshore Saudi Arabia through the end of 2022. This contract extension further increases our backlog in the region and follows three-year contract awards for ENSCO 140, ENSCO 141 and ENSCO 108, which each commenced in 2018.

Additionally ENSCO 96, was recently awarded a six-month extension that will keep the rig under contract until August 2019. In Asia Pacific, ENSCO 67 received a 500-day contract extension offshore Indonesia, that will run into second quarter 2020. And ENSCO 107 was awarded a one-well contract offshore Australia, that is expected to commence next month.

Finally, in the U.S. Gulf of Mexico, ENSCO 102 received a one-well contract, that is anticipated to commence in April 2019. All four of our jackups in the region are currently working under contracts that are expected to keep the rigs busy for the majority of 2019.

In terms of global demand, assets that deliver the greatest efficiencies for offshore well programs continued to be favored by customers.

For example, utilization for the delivered highest specification drill ships in the global fleet has increased to approximately 80% from around 65% at the start of 2018 compared to utilization below 60% for all other drill ships.

While utilization has increased for these rigs, we have yet to see this translate into a meaningful improvement in day rates.

This is because many of the contracts commencing in 2019 are shorter term in nature and drillers are bidding aggressively to keep their highest spec assets working to bridge them to anticipated longer-term contracts starting in 2020 and beyond.

We see a similar customer preference for high-spec assets for shallow water jackups, as utilization for modern jackups is almost 80%, approximately 20 percentage points higher than for jackups greater than 20 years of age.

However, in contrast to drill ships, we saw improvements in jackup day rates during 2018, particularly for high-spec harsh environment units in the North Sea and modern rigs in the U.S. Gulf of Mexico. We expect that these improvements will be more widespread geographically during 2019 for jackups.

At the beginning of the downturn, our expectation was that higher-specification assets, which see utilization improvements and pricing power first. And as a result, we embarked on a multi-year fleet restructuring.

These efforts have repositioned the fleet to focus on the newest most technically capable assets, while maintaining exposure to both shallow and deepwater markets. Our current fleet includes 21 modern floaters, including seven highest specification drill ships and 22 jackups aged less than 20 years.

This modern and diverse fleet enables us to meet a broad spectrum of customers well program requirements, as well as increasing demand for highest specification assets. This helps to position us as a key service provider to the offshore sector and improves our ability to win more than our fair share of work as the recovery unfolds.

Now, I'll turn it over to Jon..

Thanks, Carey, and good morning everyone. Today, I'm going to cover fourth quarter 2018 financial results, our outlook for first quarter 2019, full-year 2019 CapEx guidance, summary of our financial position and finally, I will provide an update on our planned merger with Rowan.

Our fourth quarter 2018 financial results were in line with the outlook from our prior conference call with adjusted EBITDA of $45 million for this quarter. On a sequential quarter basis, total fourth quarter revenue was $399 million versus $431 million in the prior quarter.

In the Floater segment, revenue declined to $228 million from $242 million in the third quarter, primarily due to idle periods for ENSCO 8503, ENSCO 8505 and ENSCO DS-12 between completing contracts and commencing new works. As a consequence, marketed utilization decreased by six percentage points to 64%.

Operational utilization for the Floater segment, which adjusts for uncontracted days and planned downtime, was 97% and consistent with the prior quarter. In the Jackup segment, revenue declined to $156 million from $173 million in the prior quarter.

This is due in part to a seven percentage point decline in marketed utilization, which was driven by idle time for ENSCO 72, ENSCO 100 and ENSCO 115, after completing contracts during the fourth quarter and an increase in shipyard days, due to a planned inspection for ENSCO 54.

These declines were partially offset by ENSCO 141 and ENSCO 108, which commenced new three-year contracts in the Middle East in the third and fourth quarters, respectively. Operational utilization for the jackup fleet during the fourth quarter was 97%, compared with 98% in the third quarter. Moving now to costs.

Excluding transaction costs, contract drilling expense declined sequentially by $3 million to $322 million. This is $2 million higher than our prior conference call guidance, due to slightly higher repair and maintenance costs during the quarter.

In fourth quarter 2018, we recognized a non-cash asset impairment charge of $40 million related to one of our older jackup rigs. Fourth quarter depreciation expense increased to $122 million, primarily due to the addition of ENSCO DS-9 and ENSCO 141, to the active fleet.

Excluding transaction costs and other significant non-recurring items, general and administration expense declined to $23 million from $24 million in the prior quarter.

During the fourth quarter, we incurred $4 million of transaction costs, related to our planned merger with Rowan, and received $3 million from the recovery of certain costs related to an ongoing legal matter. These items are excluded from adjusted EBITDA and the adjusted loss per share presented in the earnings press release.

Other expense was $5 million, compared to $9 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 the third quarter. From fourth quarter 2018 onwards, there will be no further bargain purchase adjustments related to the Atwood transaction.

Finally, tax expense was $23 million, consistent with the prior quarter. Adjusted EBITDA for fourth quarter 2018 was $45 million compared to an adjusted EBITDA in the third quarter 2018 of $74 million. A reconciliation of net loss to adjusted EBITDA is presented in our earnings press release.

Before I discuss our outlook, I’d like to note that these are expectations for ENSCO on a stand-alone basis and do not include the impact of our pending combination with Rowan.

Moving to our outlook, we expect revenue will be approximately $405 million in first quarter of 2019 with the sequential quarter increase, primarily due to new contract start-ups and fewer shipyard days.

This is expected to result in high utilization for both our Floater and Jackup fleets, which will be partially offset by a lower fleet wide average day rate.

We anticipate that first quarter contract drilling expense will increase to approximately $350 million, primarily due to a full quarter of operations for ENSCO DS-9 and contract preparation costs for rigs that will commence new work in the near future.

As mentioned on our prior conference call, this dynamic is expected to be transitory and will be – it will have a negative impact on EBITDA during the first quarter as cost to prepare rigs for future contracts will occur ahead of associated revenues.

However, we expect that revenue will increase by approximately 10% in the second quarter and the majority of this increased revenue is expected to flow through to the bottom line and lead to a meaningful improvement in EBITDA on a sequential quarter basis.

For purposes of reconciling EBITDA to our income statement, amortization is expected to provide a $14 million net benefit during the first quarter, as $22 million of amortized revenues is partially offset by $8 million of amortized expenses.

We expect depreciation expense will increase to approximately $125 million, due to ENSCO DS-9, which joined the active fleet late in the fourth quarter, partially offset by lower depreciation expense related to the previously mentioned impairment charge. G&A expense, excluding transaction costs, is expected to be approximately $24 million.

Finally, we anticipate that first quarter tax provision will be approximately $29 million. Moving to our capital expenditure outlook. Full-year 2019 capital expenditures for stand-alone Ensco will be influenced by three items. First, we anticipate $70 million of cost for minor rig enhancements and upgrades.

Second, we expect an additional $60 million of CapEx, primarily for the new build and recently delivered Jackups. Most of these costs are related to the start-up and mobilization of ENSCO 123, including cost to complete the commissioning of Continuous Tripping Technology, on the rig prior to commencing its maiden contract.

Finally, we are contractually scheduled to take delivery of ENSCO DS-13 in the third quarter, which would result in a final milestone payment to the shipyard of approximately $85 million, excluding accrued interest.

However, we have the option to finance the milestone payment and accrued interest through a promissory note with the shipyard for the rig. The promissory note will bear interest at 5% per year with maturity at year-end 2022. If we were to opt to use the shipyard financing, we would not expect to incur capital expenditures for the rig in 2019.

With respect to 2019 CapEx, we will continue to prudently deploy capital with the focus on managing our cash outlays in light of market conditions. Turning now to the summary of our financial position. We have just $236 million of debt maturing before 2024.

At year-end 2018, liquidity totaled $2.6 billion, including approximately $600 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 19 through 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 an additional capital through asset sales and a secured debt basket of $750 million. Finally, I’ll provide an update on our planned merger with Rowan.

As Carl mentioned earlier, we are pleased that both Ensco and Rowan shareholders have approved the transaction as we believe that this combination will create an industry-leading offshore driller. And both companies’ shareholders stand to benefit from the enhanced capabilities of the combined company.

Following months of integration planning, we now expect to realize annual expense synergies of approximately $165 million, which represents a 10% increase from the figure we provided when we announced the transaction in October 2018.

In total, these synergies are expected to result in approximately $1.1 billion of capitalized value, creating significant value for shareholders.

More than 75% of these synergies are expected to be captured within one year of closing, which will make the combination accretive to cash flow per share in 2020, assuming that transaction closes in the first half of 2019. We would then expect to reach full run rate synergies of $165 million from the transaction by year-end 2020.

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 the targeted synergies will be recognized in contract drilling expense with the other half in G&A expense. We feel very confident that we can achieve these synergies based on our experience and as evidenced recently by our synergy achievement with the Atwood acquisition.

And we will provide updates on synergy realization on quarterly earnings calls upon closing. As of our most recent company filings, the combined company would have pro forma contracted revenue backlog of approximately $2.8 billion, excluding the revenue backlog from our owned ARO joint venture.

At year-end 2018, the combined company had $1.6 billion of cash and short-term investments on a pro forma basis. Further, we expect that increased geographic and customer diversification will result in greater access to the capital markets than either company would have on a stand-alone basis, which will improve our competitiveness going forward.

In closing, offshore industry fundamentals continue to improve. New contracts and open tenders for offshore rigs have increased despite recent oil price volatility, demonstrating customers’ willingness to focus on long-term fundamentals when evaluating new offshore projects.

We expect that customers will continue to prefer the high specification assets that deliver efficiencies for their offshore programs and these assets will experience higher levels of utilization and improved pricing ahead of the broader fleet.

As our fleet contains many of the industries’ high specification assets and will be enhanced even further by our merger with Rowan, we believe we are well positioned to capitalize on opportunities as the industry recovers. Now, I will turn the call back over to Nick..

Thanks, Jon. Gary, at this time, please open the line for questions..

We will now begin the question-and-answer session. [Operator Instructions] The first question comes from James West with Evercore ISI. Please go ahead..

Hey, good morning guys..

Good morning, James..

Good morning, James..

Carl, good to hear about the fourth quarter volatility didn’t really change much in terms of planning for offshore projects.

I’m curious, though, of the tenders that you’re working on or working through, and the activity levels or the activity, which you see out there for late this year and 2020, how much of that remains, kind of development type of work versus exploration and really I guess the key is – are we starting to see exploration, kind of show a rebirth at this point?.

I would say that at the moment, the majority is still tilted towards development. Exploration spending and planning seems to still be subdued, certainly versus where it was in the 2013, 2014 time period. But we are seeing a few areas begin to pick up on the exploration side, particularly around existing petroleum basins and things like that.

So, we’re seeing a bit in the North Sea, you’re seeing some come in West – sorry, South America around Brazil. Of course, the new – the area that’s really quite hot at the moment is the new frontier around the Northern Atlantic margins of French Guyana and the contingent coastline on Mauritania and Senegal.

And of course, the one place that has really taken off is Mexico on the back of the recent license rounds. So, it’s there – it’s looking better than it did, but a lot of the tenders we have are still biased towards development project..

Right. Okay, fair enough. And then with respect to the pending transaction with Rowan, it’s obviously been out there for a while now.

Are your customers already coming to you and asking about some of the Rowan assets or asking you to – how much you can actually do this, but to use those assets when you tender for – when you’re bidding for projects?.

No. James, we absolutely can’t until we close the deal. From a competition’s regulation point of view, we have to continue to remain completely independent. But actually, we have a full Chinese wall in the two companies between the marketing, pricing, selection, some tactical issues around rig and fleet placement.

So, while we’ve been working on integration planning around structure, synergies and things like that, we’ve absolutely stayed remote on that and we won’t do until we close..

Okay. got you. Okay. thanks guys..

[Operator Instructions] The next question comes from Greg Lewis with BTIG. Please go ahead..

Yes. thank you and good morning everyone..

Good morning.

Good morning, Greg. Welcome back..

Thanks.

Could you – can we talk a little bit about the tripping technology and just sort of how you’re thinking about introducing that to the market, i.e., is this something where we think – I mean is the goal to sort of start to generate a positive margin on this? Do we think – is it just, hey, we want to get the payback for the installation, which based on some of the CapEx was, it sounded like it was significant, just sort of – how we should think about rolling this out and potentially, how we think this could actually help drive some pricing?.

Okay. Maybe, I’ll take it first and then see if Carey wants to add anything. First of all, Greg, in the commentary that Carey made, he mentioned – it was actually Jon on the CapEx. There is a figure in there for new builds and technology of around about $60 million. That’s actually spread across several things. That’s not all CTT.

CTT costs a lot less than that to actually install even for the first version, which we put out. And we expect the cost to come down over time. We are working on that already. But that $60 million that you saw was actually some of the final integration testing, mobilization, crewing up of ENSCO 123, plus the finalization of continuous stripping.

And it’s actually some of the bits and bobs in that for some of the other rigs that we brought out recently and sort of closing out for those. So, don’t take that as a guideline figure.

But that said, what we – we are actually going to reserve a little bit of judgment on how we’re going to treat this and do the financial model for the technology until we run it in anger. ENSCO 123 is going to be going to the North Sea.

It has a maiden contract there, but we’re in pretty advanced negotiations with a couple of customers to take it after that.

And those programs are specifically aimed at utilizing the Continuous Tripping Technology, because the development programs were some pretty extended reach wells, where this really has a meaningful cost reduction on the overall well cost. In the early stages, we will shake down the technology.

But our intention on the first contract is to actually run it as a – maybe, probably an upgrade, as an optional extra that the client pays as if they use it. So, we do see it as an enhanced service at this point. But once we have run it on these maiden contracts, we will reassess how we intend to price it.

But we absolutely intend this is a premium service that gives higher return on the day rate..

And Greg, this is John. I might just add. In terms of – if we’re going to spend capital to upgrade further rigs, we’re absolutely going to be disciplined in that regard and wouldn’t upgrade additional rigs. And this is again, it is something we can retrofit our existing fleet with it at a minimal upfront CapEx.

But we wouldn’t do it unless we get a return and a payback on that in pretty short order. But based on some of the math that we’ve worked, ultimately, the average well cost that we’ve seen could come down 10% on average. We back tested this on well that we’ve drilled over very long periods of time.

But the real benefit is on the deepest wells, where you can get overall well savings up to 15%. And if you look at the overall savings on our clients’ well program for that type of savings, the savings are very meaningful.

And so we will still develop a commercial model for it, but we think the payback on installing this equipment could be pretty short..

Yes. And if you don’t mind. I’m going to achieve a little bit into just our view as we go into 2019 on capital expenditures. Now, I’m definitely talking about Ensco alone at this point and how we viewed the year going into it outside the merger. But I do think that this approach will carry over post closing the transaction.

And that is that we are in the mode at the moment, have been very careful on capital allocations and cash outlays. And at this point, we do not envisage putting more cash or CapEx out there, other than what is required to service the contracts that we got any necessary upgrades or sustaining.

And we are not in the mode of putting pre-emptive or proactive cash onto additional upgrades, all proactively bringing out additional rigs, other than maybe the one or two Jackups that we drew attention to.

And to be clear, on a – certainly, on our own – talking to our own fleet, not the combined fleet, we do not see bringing out any of the drill ships that are in – that we have preservation stacked at this stage and certainly not doing it for short-term contracts at the kind of price – the upgrade costs or the reactivation costs that we’re seeing until we see pricing and utilization pick up.

That also carries on a bit to the DS-13, where we have an option on how to finance that. But I think what you can also read through from what we’ve said is that we don’t intend to bring that rig out of the yard and actually market it or putting it into action this year either.

On the Jackups, just to reiterate what we said, we do see that broader-base pickup of the Jackup market building. If it continues as it is, then we will probably bring back one or two of our stacked rigs. But as we said, we will – that will be contract specific.

And on the back of a contract, we’d only do it if we felt the day rate or the mobilization fee when part way or a significant way towards some of the costs. So that’s more to outline the kind of mode we’re in. And to circle it back to the technology, we don’t intend upgrading an additional rig at this point with continuous tripping.

We intend to run the ENSCO 123 with it, really understand it, work on the cost version for Version 2 and then take decisions after that..

Okay, great. And then just one more from – but just one more from me. We’ve seen a lot of rigs have been put on the sidelines. You mentioned – obviously, you guys have your preservation stacked rigs that’s pulled down like I guess hot supply.

So, as we think about this and how – what you’re seeing in the markets, are we at a point now where as rigs are being bid and as contracts are getting done, are we back to a point, where the days of the indifference rate are gone and now we’re at a point now, where we’re starting to actually see at least – at least maybe, some positive margin or at a minimum sort of cash OpEx break-even?.

Well, I’d draw you back to what we said in the prepared comments. I think in the jackup market, simplistically the answer is yes. We started to see – actually in the jackup market, rates certainly, for our fleet, didn’t bottom out at zero cash impact.

In fact the bottom point in the jackup pricing was still cash generative on most contracts and it started to build up as we went through 2018. So as we said, we saw pickup in some key markets in 2018 and we are anticipating based on what we see today that that will broaden.

So, I think as we go through 2019, we would be expecting to see certainly in the back half of the year, the margin, particularly, the cash margin element from the Jackup segment starting to build. In the Floater segment, we’re not there yet, certainly not on how I see 2019 pricing, but rates do seem to have bottomed. People are not chasing rates down.

People are eager to fill white space on the drillship, particularly, the drillship outlook in 2019. And therefore, rate is still competitive and I would say, marginally above costs – capital costs break-even, depending on how you roll in – you roll in mob costs.

But what we do see is that, if you brought forward the number of tenders that we have coming now for 2020 and beyond and then 2021 starts, you start to see that there is a increased utilization, particularly on the very high-end drillships.

And we’re seeing people – we’re seeing pricing points been put into tenders and people holding out for future, higher pricing in the back year. So – to rather round that off, if I were you, I wouldn’t expect materially pick up in cash margin on Floaters in 2019.

But if we see the pricing points that we see out there at the moment for discussion and intend for 2020 and 2021, then that’s when we’d be looking to start to see that margin increase on the Floater segment..

Okay. thank you very much for the timing. Congratulations on closing the merger..

Thank you, Greg..

Thanks, Greg..

Showing no further questions, this concludes our question-and-answer session. I would like to turn the conference back over to Nick Georgas for any closing remarks..

Thank you, Gary. And thank you to everyone on the call today for your interest in Ensco. We look forward to speaking with you again when we report first quarter 2019 results. Please have a great rest of your day..

The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect..